# embeddings_queue

created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4cb30-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/urtec-2019-123-ms.pdf", "page": 31, "chroma:document": "URTeC 123   32 \n\ud835\udc36\ud835\udc53\ud835\udc37=\ud835\udc36\ud835\udc53\n0.5\ud835\udc58\ud835\udc3f\ud835\udc53,           (20) \nwhere \ud835\udc36\ud835\udc53 is fracture conductivity and Lf is fracture length. Fractures are \u2018infinit e conductivity\u2019 when \ud835\udc36\ud835\udc53\ud835\udc37 is \nabove approximately 300 (some authors use a lower threshold). From the cubic law, fracture conductivity \nis equal to (Witherspoon et al., 1980):  \n\ud835\udc36\ud835\udc53=\ud835\udc4a3\n12.           (21) \nFor a fracture with half -length of 150 ft and matrix permeability of 100 nanodarcies, the fracture will be \ninfinite conductivity as long as fracture aperture is greater than just 2 5 microns  (equivalent to conductivity \naround 1 md -ft). Zhang et al. (2013) measured the conductivity of unpropped fra ctures in the Barnett Shale \nand found that conductivity remained above 1 md -ft until effective normal stress exceeded 1000s of psi. \nFor unaligned fractures, the conductivity was even higher, and in -situ, fractures are probably rougher than \nin small -scale f ractures induced in the lab."}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4cbb2-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/urtec-2019-123-ms.pdf", "page": 31, "chroma:document": "in small -scale f ractures induced in the lab.  \nFor permeability on the order of microdarcies or millidarcies, it becomes less likely that the fracture will \nremain infinitely conductive after contact. If dimensionless fracture conductivity drops sufficiently rapidly \nwith co ntact, then it is conceivable that nonnegligible pressure gradient could develop in the fracture. If this \noccurs, then contact would cause an apparent reduction in the \u2018leakoff rate,\u2019 \ud835\udc51\ud835\udc49\n\ud835\udc51\ud835\udc3a, and this could potentially \ncause the pressure derivative to de crease, rather than increase, with contact.  \nIn the worst case, stiffness and leakoff rate could change in approximately equal amounts and result in no \nchange in \ud835\udc51\ud835\udc43\n\ud835\udc51\ud835\udc3a with contact. This scenario is probably uncommon because it requires coincidental equ ality \nof two opposing effects, but probably occurs occasionally. Decreasing \ud835\udc51\ud835\udc43\n\ud835\udc51\ud835\udc3a with contact (due to decreased \ndimensionless fracture conductivity) has been confirmed by numerical simulation (McClure et al., 2016)."}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4cc2a-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/urtec-2019-123-ms.pdf", "page": 31, "chroma:document": "If this occurred, \ud835\udc51\ud835\udc43\n\ud835\udc51\ud835\udc3a may decre ase monotonically after contact. If the fracture begins to become finite \nconductivity, it is possible that the conductivity could be spatially variable along the fracture area.  \nA.6. Impulse flow  \nCraig and Blasingame (2006) pointed out that the late time be havior of a DFIT can be described with \nimpulse flow solutions from conventional well test analysis. The impulse flow solution can be found by \ntaking the dimensionless time derivative of the nondimensionalized solution for constant -rate injection \n(Houze et al, 1988; Ayoub et al., 1988; Gu et al, 1993). For example, constant rate injection into an infinite \nconductivity fracture yields a scaling of \u0394\ud835\udc43\u221d(\u0394\ud835\udc61)1\n2 (Gringarten et al., 1974) . Therefore, the impulse \nsolution for an infinite conductivity fracture is \u0394\ud835\udc43\u221d(\u0394\ud835\udc61)\u22121\n2. Late-time impulse transients can be used to \ninfer permeability and fluid pressure (Sections A.10.iii and 3.1.6). \nA.7 Near -wellbore pressure drop"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4ccac-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/urtec-2019-123-ms.pdf", "page": 31, "chroma:document": "A.7 Near -wellbore pressure drop  \nIn field DFIT\u2019s in horizontal wells , there is usually always  a period of rapid pressure drop immediate ly after \nshut-in. At very early time, this pressure drop is due to the end of wellbore and perforation friction  (if the \nwell is perforated) . But subsequently, there can be  a period of rapid pressure drop  that may last tens of \nminutes or longer. During this  time, pressure commonly drops  by 1000s of psi. This behavior  is apparent  \nin most of the field data reviewed in this study.  \nNear -wellbore pressure drop can be modeled as a pressure difference between the wellbore and the fracture \n(Wright, 2000):  \n\u0394\ud835\udc43\ud835\udc5b\ud835\udc64=\ud835\udc36\ud835\udc5b\ud835\udc64\ud835\udc44\ud835\udefd,          (22) \nwhere \ud835\udc36\ud835\udc5b\ud835\udc64 is a constant, Q is the volumetric flow rate from the well into the fractur e, and \ud835\udefd is an exponent \n(typically equal to 0.5).  Downloaded from http://onepetro.org/URTECONF/proceedings-pdf/19URTC/2-19URTC/D023S030R001/1138462/urtec-2019-123-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4cd2e-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/urtec-2019-123-ms.pdf", "page": 32, "chroma:document": "URTeC 123   33 \nAfter shut -in, flow at the wellhead is zero, but fluid continues to flow into the formation because of wellbore \nstorage. The flow rate Q can be estimated as:  \n\ud835\udc44=\ud835\udc36\ud835\udc64\ud835\udc51\ud835\udc43\n\ud835\udc51\ud835\udc61.            (23) \n\u0394\ud835\udc43\ud835\udc5b\ud835\udc64 can be estimated from the equation:  \n\u0394\ud835\udc43\ud835\udc5b\ud835\udc64~\ud835\udc43\u2212\ud835\udc43\ud835\udc52\ud835\udc53\ud835\udc53,           (24) \nwhere P is the bottomhole pressure of the well and Peff is the \u2018effective\u2019 pressure estimated by extrapolating \nback to G -time equal to zero from the point of minimum dP/dG ( Section 3.1 .1). Peff is an estimate for the \nfluid pressure in the fracture, on the \u2018other side\u2019 of the near -wellbore pressure drop from the wellbore.  \nThese relations make it possible to plot the difference between well pressure and fracture pressure versus \nvolumetric flow rate and directly infer \ud835\udc36\ud835\udc5b\ud835\udc64.    \nA.8 The h -function  \nNolte (1979) derived the G -function to be proportional to the cumulative leakoff volume after shut -in and \nderived the g -function to be proportional to the total volume of fluid leaked off after the start of injection."}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4cda6-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/urtec-2019-123-ms.pdf", "page": 32, "chroma:document": "Both functions are derived assuming Carter leakoff.  Following a similar approach, it is convenient to define \nan \u2018h\u2019 function that is proportional to the cumulative leakoff volume  from the start of injection , but unlike \nthe g -function, accounts  for deviation fro m Carter leakoff caused by pressure change over time . This is \naccomplished using  a time -convolution integral of the  one-dimensional  constant pressure solution  (given \nby Equation 18). This approach is related to the method described by Mayerhofer and Economides (1993) \nand Mayerhofer et al. (1995) , who proposed a procedure  for estimating permeability using  an \napproximation to the leakoff rate and the n a convolution integral of the constant rate solution  (Section \nA.3.vii) , and is also related to the relative stiffness relations developed by Wang and Sharma (2018) .  \nThe cumulative leakoff from the start of pumping can be estimated as: \n\ud835\udc49\ud835\udc3f=4\ud835\udc34\u221a\ud835\udc58\ud835\udf19\ud835\udc50\ud835\udc61\n\ud835\udf0b\ud835\udf07 \u222b(\ud835\udc43(\ud835\udf0f)\u2212\ud835\udc43\ud835\udc5f\ud835\udc52\ud835\udc60)\n\ud835\udc51\ud835\udf0f\u221a\u0394\ud835\udc61+\ud835\udc61\ud835\udc52/2\u2212\ud835\udf0f\ud835\udc51\ud835\udf0f\u0394\ud835\udc61+\ud835\udc61\ud835\udc52/2\n0=4\ud835\udc34\u210e(\u0394\ud835\udc61)\u221a\ud835\udc58\ud835\udf19\ud835\udc50\ud835\udc61\n\ud835\udf0b\ud835\udf07 .   (25)"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4ce28-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/urtec-2019-123-ms.pdf", "page": 32, "chroma:document": "\ud835\udc51\ud835\udf0f\u221a\u0394\ud835\udc61+\ud835\udc61\ud835\udc52/2\u2212\ud835\udf0f\ud835\udc51\ud835\udf0f\u0394\ud835\udc61+\ud835\udc61\ud835\udc52/2\n0=4\ud835\udc34\u210e(\u0394\ud835\udc61)\u221a\ud835\udc58\ud835\udf19\ud835\udc50\ud835\udc61\n\ud835\udf0b\ud835\udf07 .   (25) \nThus, the h -function is defined as:  \n\u210e(\u0394\ud835\udc61)=\u222b(\ud835\udc43(\ud835\udf0f)\u2212\ud835\udc43\ud835\udc5f\ud835\udc52\ud835\udc60)\n\ud835\udc51\ud835\udf0f\u221a\u0394\ud835\udc61+\ud835\udc61\ud835\udc52/2\u2212\ud835\udf0f\ud835\udc51\ud835\udf0f\u0394\ud835\udc61+\ud835\udc61\ud835\udc52/2\n0.       (26) \nIf pressure versus time  is known , cumulative leakoff can be calculated  as: \n\ud835\udc49\ud835\udc3f(\u0394\ud835\udc61\ud835\udc58)\u22484\ud835\udc34\u221a\ud835\udc58\ud835\udf19\ud835\udc50\ud835\udc61\n\ud835\udf0b\ud835\udf07 [(\ud835\udc430\u2212\ud835\udc43\ud835\udc5f\ud835\udc52\ud835\udc60)\u221a\u0394\ud835\udc61\ud835\udc58+\ud835\udc61\ud835\udc52\n2+\u2211 (\ud835\udc43\ud835\udc56\u2212\ud835\udc43\ud835\udc56\u22121)\ud835\udc58\n\ud835\udc56=1 \u221a\u0394\ud835\udc61\ud835\udc58\u2212\u0394\ud835\udc61\ud835\udc56].   (27) \nThe h -function is calculated  as: \n\u210e(\u0394\ud835\udc61\ud835\udc58)\u2248(\ud835\udc430\u2212\ud835\udc43\ud835\udc5f\ud835\udc52\ud835\udc60)\u221a\u0394\ud835\udc61\ud835\udc58+\ud835\udc61\ud835\udc52\n2+\u2211 (\ud835\udc43\ud835\udc56\u2212\ud835\udc43\ud835\udc56\u22121)\ud835\udc58\n\ud835\udc56=1 \u221a\u0394\ud835\udc61\ud835\udc58\u2212\u0394\ud835\udc61\ud835\udc56.     (28) \nAnalogous to the G -function, an H -function can be defined that is proportional to the volume of fluid leaked \noff since shut -in: \n\ud835\udc3b(\u0394\ud835\udc61)=\u222b(\ud835\udc43(\ud835\udf0f)\u2212\ud835\udc43\ud835\udc5f\ud835\udc52\ud835\udc60)\n\ud835\udc51\ud835\udf0f\u221a\u0394\ud835\udc61+\ud835\udc61\ud835\udc52/2\u2212\ud835\udf0f\ud835\udc51\ud835\udf0f\u0394\ud835\udc61+\ud835\udc61\ud835\udc52/2\n\ud835\udc61\ud835\udc52/2.       (29) \nThe H-function is calculated as:  \n\ud835\udc3b(\u0394\ud835\udc61\ud835\udc58)\u2248(\ud835\udc430\u2212\ud835\udc43\ud835\udc5f\ud835\udc52\ud835\udc60)(\u221a\u0394\ud835\udc61\ud835\udc58+\ud835\udc61\ud835\udc52\n2\u2212\u221a\ud835\udc61\ud835\udc52\n2)+\u2211 (\ud835\udc43\ud835\udc56\u2212\ud835\udc43\ud835\udc56\u22121)\ud835\udc58\n\ud835\udc56=1 \u221a\u0394\ud835\udc61\ud835\udc58\u2212\u0394\ud835\udc61\ud835\udc56.    (30) \nCumulative leakoff after shut -in can be written as:  Downloaded from http://onepetro.org/URTECONF/proceedings-pdf/19URTC/2-19URTC/D023S030R001/1138462/urtec-2019-123-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4ceaa-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/urtec-2019-123-ms.pdf", "page": 33, "chroma:document": "URTeC 123   34 \n\ud835\udc49\ud835\udc3f\ud835\udc60(\u0394\ud835\udc61\ud835\udc58)\u22484\ud835\udc34\ud835\udc3b(\u0394\ud835\udc61\ud835\udc58)\u221a\ud835\udc58\ud835\udf19\ud835\udc50\ud835\udc61\n\ud835\udf0b\ud835\udf07 .         (31) \nThe h -function can be calculated directly from pressure versus time data  and an  estimate of the reservoir \npressure, \ud835\udc43\ud835\udc5f\ud835\udc52\ud835\udc60. Estimation of reservoir pressure is discussed in Section 3.1 .6. \nUnlike the G -function, Equation 25 does not rigorously account for the effect of the propagation of the \nfracture over time. Instead, leakoff during injection is approximated by assuming the fracture formed \ninstantaneously after a duration of injection of te/2. Although simple, this is a rea sonably accurate \napproximation. Equation 25 implies that the volume of fluid leaked off at shut -in is equal to:  \n\ud835\udc49\ud835\udc3f(\u0394\ud835\udc61=0)\u22484\ud835\udc34\u221a\ud835\udc58\ud835\udf19\ud835\udc50\ud835\udc61\n\ud835\udf0b\ud835\udf07 [(\ud835\udc430\u2212\ud835\udc43\ud835\udc5f\ud835\udc52\ud835\udc60)\u221a\ud835\udc61\ud835\udc52\n2]=2\ud835\udc34\ud835\udc36\ud835\udc3f\u221a\ud835\udc61\ud835\udc52 \u221a2.     (32) \nThe factor \u221a2 in Equation 32 is analogous to \ud835\udc54(\u0394\ud835\udc61=0)=\ud835\udc540 in Equation 13 (which is taken from the \nmore d etailed derivations of Nolte, 1979, and Gulrajani and Nolte, 2000). \ud835\udc540 is bounded within the range \n4/3 and \ud835\udf0b\n2, and \u221a2 lies within this range .   \nA.9 Relative stiffness"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4cf22-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/urtec-2019-123-ms.pdf", "page": 33, "chroma:document": "2, and \u221a2 lies within this range .   \nA.9 Relative stiffness  \nUsing Equation  3 and Equation 25, it is possible to derive a \u2018relative stiffness\u2019 value ( Srel) that is linearly \nproportional to fracture stiffness:  \n\ud835\udc51\ud835\udc43\n\ud835\udc51\ud835\udc61=(1\n\ud835\udc36\ud835\udc61 \ud835\udc51\ud835\udc49\n\ud835\udc51\ud835\udc61)\u221d1\n\ud835\udc36\ud835\udc61\ud835\udc51\u210e\n\ud835\udc51\ud835\udc61.          (33) \n1\n\ud835\udc36\ud835\udc61\u221d\ud835\udc51\ud835\udc43\n\ud835\udc51\ud835\udc61\n\ud835\udc51\u210e\n\ud835\udc51\ud835\udc61=\ud835\udc46\ud835\udc5f\ud835\udc52\ud835\udc59.           (34) \nUsing tabular data of pressure versus time and an estimate for formation fluid pressure, it is possible to \ndirectly calculate the relative stiffness:  \n\ud835\udc46\ud835\udc5f\ud835\udc52\ud835\udc59(\ud835\udc61\ud835\udc58)=\ud835\udc51\ud835\udc43\n\ud835\udc51\ud835\udc61(\ud835\udc61\ud835\udc58)\n\ud835\udc51\u210e\n\ud835\udc51\ud835\udc61(\ud835\udc61\ud835\udc58)=\ud835\udc51\ud835\udc43(\ud835\udc61\ud835\udc58)\n\ud835\udc51\u210e(\ud835\udc61\ud835\udc58).         (35) \nA plot of relative stiffness versus pressure can be used to identify contact . When the relative stiffne ss \nincreases, this indicates that the fracture walls have come into contact (Wang and Sharma, 2018) .  \nBecause of near -wellbore pressure drop, the measured wellbore pressure after shut -in is typically higher \nthan the actual pressure in the far -field fractur e. To address this problem, the relative stiffness and the h -"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4cfa4-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/urtec-2019-123-ms.pdf", "page": 33, "chroma:document": "function can be calculated using an \u2018effective pressure,\u2019 Peff, that represents a best estimate for the true \npressure in the fracture (Section 3.1 .1).  \nA.10 Methods of estimating permeability  \nThe following sections describe methods for estimating permeability and leakoff coefficient. We \nrecommend estimating permeability from multiple techniques: the G -function technique, the h -function \ntechnique, impulse linear, and/or impulse radial. These estima tes use different parts of the data and can be \ncompared for consistency. At the end of this section, we review several common methods that are not \nrecommended.  \nA.10.i G -function technique  \nCombining with Equations 4 and 17: \n\ud835\udc51\ud835\udc43\n\ud835\udc51\ud835\udc3a=1\n\ud835\udc36\ud835\udc61 \ud835\udc51\ud835\udc49\n\ud835\udc51\ud835\udc3a=\u2212\ud835\udf0b\n2 \ud835\udc34\ud835\udc36\ud835\udc3f\ud835\udc46\ud835\udc61\u221a\ud835\udc61\ud835\udc52=\u2212\ud835\udf0b\n2\ud835\udc34\ud835\udc36\ud835\udc3f\u221a\ud835\udc61\ud835\udc52\n\ud835\udc36\ud835\udc64+\ud835\udc34\n\ud835\udc46\ud835\udc53+\ud835\udc49\ud835\udc53\ud835\udc50\ud835\udc53\ud835\udc59.       (36) Downloaded from http://onepetro.org/URTECONF/proceedings-pdf/19URTC/2-19URTC/D023S030R001/1138462/urtec-2019-123-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4d01c-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/urtec-2019-123-ms.pdf", "page": 34, "chroma:document": "URTeC 123   35 \n\ud835\udc51\ud835\udc43\n\ud835\udc51\ud835\udc3a can be directly estimated from the data. \ud835\udc49\ud835\udc53\ud835\udc50\ud835\udc53\ud835\udc59 is negligibly small and is omitted from the following \nequations. Assuming a radial crack, the leakoff coefficient can be calculated as:  \n\ud835\udc36\ud835\udc3f(\ud835\udc5f\ud835\udc4e\ud835\udc51\ud835\udc56\ud835\udc4e\ud835\udc59 )=\u2212\ud835\udc51\ud835\udc43\n\ud835\udc51\ud835\udc3a \ud835\udc36\ud835\udc64+16\ud835\udc45\ud835\udc533\n3\ud835\udc38\u2032\n\ud835\udf0b2\n2\ud835\udc45\ud835\udc532\u221a\ud835\udc61\ud835\udc52=\u2212\ud835\udc51\ud835\udc43\n\ud835\udc51\ud835\udc54 \ud835\udc36\ud835\udc64+16\ud835\udc45\ud835\udc533\n3\ud835\udc38\u2032\n2\ud835\udf0b\ud835\udc45\ud835\udc532\u221a\ud835\udc61\ud835\udc52.       (37) \nAssuming a fixed -height (PKN) crack, the leakoff coefficient can be calculated as:  \n\ud835\udc36\ud835\udc3f(\ud835\udc43\ud835\udc3e\ud835\udc41 )=\u2212\ud835\udc51\ud835\udc43\n\ud835\udc51\ud835\udc3a 2\ud835\udc36\ud835\udc64\n\ud835\udf0b+\ud835\udc3f\ud835\udc53\u210e\ud835\udc532\n\ud835\udc38\u2032\n\ud835\udc3f\ud835\udc53\u210e\ud835\udc53\u221a\ud835\udc61\ud835\udc52=\u2212\ud835\udc51\ud835\udc43\n\ud835\udc51\ud835\udc54 2\ud835\udc36\ud835\udc64+\ud835\udc3f\ud835\udc53\u210e\ud835\udc532\ud835\udf0b\n\ud835\udc38\u2032\n4\ud835\udc3f\ud835\udc53\u210e\ud835\udc53\u221a\ud835\udc61\ud835\udc52.       (38) \nEquations 37 and 38 cannot be solved direct ly because they require estimation of the fracture size, either \nradius or length. In addition, the PKN calculation requires an assumption of fracture height. It is not possible \nto estimate height solely from the DFIT. It needs to be estimated from ancillar y information, such as \nknowledge of a stress contrast creating height confinement. If wellbore storage is neglected and height is \nassumed, Equation 38 reduces to an equation that can  be solved directly for leakoff coefficient (Marongiu -"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4d09e-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/urtec-2019-123-ms.pdf", "page": 34, "chroma:document": "Porcu et al., 2011).  \nRadius and length in Equations 37 and 38 can be estimated by writing a mass balance equation for the entire \nsystem:  \n\ud835\udc49\ud835\udc56\ud835\udc5b\ud835\udc57=\ud835\udc36\ud835\udc64(\ud835\udc43(\u0394\ud835\udc61)\u2212\ud835\udc43\ud835\udc64,\ud835\udc56\ud835\udc5b\ud835\udc56\ud835\udc61)+\ud835\udc34\n\ud835\udc46\ud835\udc53(\ud835\udc43(\u0394\ud835\udc61)\u2212\ud835\udc46\u210e\ud835\udc5a\ud835\udc56\ud835\udc5b )+2\ud835\udc34\ud835\udc36\ud835\udc3f\u221a\ud835\udc61\ud835\udc52\ud835\udc54(\u0394\ud835\udc61).    (39) \nEquation 39 states that the volume of fluid injected is equal to wellbore storage, fluid store d in the fracture, \nand leakoff. Equation 39 forms a system of two equations (with Equation 37 or 38) and two unknowns ( \ud835\udc36\ud835\udc3f \nand Rf or Lf). These equations can be solved to estimate leakoff coefficient and fracture extent. \ud835\udc43\ud835\udc64,\ud835\udc56\ud835\udc5b\ud835\udc56\ud835\udc61 is the \nmeasured pressure at the beginning of inje ction. The term \ud835\udc36\ud835\udc64(\ud835\udc43(\u0394\ud835\udc61)\u2212\ud835\udc43\ud835\udc64,\ud835\udc56\ud835\udc5b\ud835\udc56\ud835\udc61) accounts for the net flow \ndue to wellbore stora ge. \nEquations 37, 38, and 39 must be evaluated at a particular point in time. We recommend evaluating dP/dG  \nat the minimum point in dP/dG . Because dP/dG is never constant, this point is probably distorted by both  \nnear-wellbore pressure drop and contact. As a result , it is an upper bound  on the true value of dP/dG and"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4d120-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/urtec-2019-123-ms.pdf", "page": 34, "chroma:document": "may lead to an overestimate of leakoff coefficient. Nevertheless, it is the best  available point in  time to \nestimate dP/dG.  \nWe recommend evaluating Equation 39 at the effective ISIP ( Section 3.1 .1) in order to minimize the relative \nimpact of the Shmin uncertainty on the calculation of net pressure. Eq uation 39 is evaluated from the \nestimate of the effective ISIP, rather than the literal ISIP, because near -wellbore pressure drop elevates the \nliteral I SIP far above the actual pressure in the fracture at shut -in. \nOnce leakoff coefficient has been calculated, permeability can be calculated from Equation 19. \nA.10.ii h -function technique  \nThe assumption of Carter leakoff is a limitation of the G -function method. This limitation can be overcome \nusing the h -function method. Similar to Equation 39, we can write a mass balance on the system using the \nh-function to calculate leakoff:  \n\ud835\udc49\ud835\udc56\ud835\udc5b\ud835\udc57=\ud835\udc36\ud835\udc64(\ud835\udc43(\u0394\ud835\udc61)\u2212\ud835\udc43\ud835\udc64,\ud835\udc56\ud835\udc5b\ud835\udc56\ud835\udc61)+\ud835\udc34\n\ud835\udc46\ud835\udc53 (\ud835\udc43(\u0394\ud835\udc61)\u2212\ud835\udc46\u210e\ud835\udc5a\ud835\udc56\ud835\udc5b )+4\ud835\udc34\u210e(\u0394\ud835\udc61)\u221a\ud835\udc58\ud835\udf19\ud835\udc50\ud835\udc61\n\ud835\udf0b\ud835\udf07 .    (40)"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4d1de-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/urtec-2019-123-ms.pdf", "page": 34, "chroma:document": "\ud835\udc46\ud835\udc53 (\ud835\udc43(\u0394\ud835\udc61)\u2212\ud835\udc46\u210e\ud835\udc5a\ud835\udc56\ud835\udc5b )+4\ud835\udc34\u210e(\u0394\ud835\udc61)\u221a\ud835\udc58\ud835\udf19\ud835\udc50\ud835\udc61\n\ud835\udf0b\ud835\udf07 .    (40) \nAfter selecting appropriate values for A and Sf (for either rad ial or PKN geometry), Equation 40 contains \ntwo unknowns: permeability and fracture radius (or length). The problem is solved by evaluating the \nequation at two different points in time: at shut -in (using the effective I SIP) and at the point of maximum \nG*dP/dG. The point of maximum G*dP/dG is reached a significant period of time after  the fracture walls Downloaded from http://onepetro.org/URTECONF/proceedings-pdf/19URTC/2-19URTC/D023S030R001/1138462/urtec-2019-123-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4d256-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/urtec-2019-123-ms.pdf", "page": 35, "chroma:document": "URTeC 123   36 \ncome into contact . The fracture still retains some aperture, but it is reasonable to assume that the great \nmajority of f luid has leaked off from the system. Specifically, we assume that 10% of the total injection \nvolume remains stored in the fracture at this point in time (the calculation is not strongly dependent on the \nprecise percentage that is assumed). This assumption yields:  \n0.9\ud835\udc49\ud835\udc56\ud835\udc5b\ud835\udc57=\ud835\udc36\ud835\udc64(\ud835\udc43\ud835\udc5d\ud835\udc52\ud835\udc4e\ud835\udc58 \u2212\ud835\udc43\ud835\udc64,\ud835\udc56\ud835\udc5b\ud835\udc56\ud835\udc61)+4\ud835\udc34\u210e(\u0394\ud835\udc61\ud835\udc5d\ud835\udc52\ud835\udc4e\ud835\udc58 )\u221a\ud835\udc58\ud835\udf19\ud835\udc50\ud835\udc61\n\ud835\udf0b\ud835\udf07 .      (41) \nRearrangement yields an equation for \ud835\udc34\u221a\ud835\udc58:  \n\ud835\udc34\u221a\ud835\udc58=0.9\ud835\udc49\ud835\udc56\ud835\udc5b\ud835\udc57\u2212\ud835\udc36\ud835\udc64(\ud835\udc43\ud835\udc5d\ud835\udc52\ud835\udc4e\ud835\udc58 \u2212\ud835\udc43\ud835\udc64,\ud835\udc56\ud835\udc5b\ud835\udc56\ud835\udc61)\n4\u210e(\ud835\udee5\ud835\udc61\ud835\udc5d\ud835\udc52\ud835\udc4e\ud835\udc58 )\u221a\ud835\udf19\ud835\udc50\ud835\udc61\n\ud835\udf0b\ud835\udf07 .         (42) \nEquation 40 can be solved for area:  \n\ud835\udc34=(\ud835\udc49\ud835\udc56\ud835\udc5b\ud835\udc57\u2212\ud835\udc36\ud835\udc64(\ud835\udc43(\u0394\ud835\udc61)\u2212\ud835\udc43\ud835\udc64,\ud835\udc56\ud835\udc5b\ud835\udc56\ud835\udc61)\u2212\ud835\udc34\u221a\ud835\udc58(4\u210e(\u0394\ud835\udc61)\u221a\ud835\udf19\ud835\udc50\ud835\udc61\n\ud835\udf0b\ud835\udf07 ))\ud835\udc46\ud835\udc53\n\ud835\udc43\u2212\ud835\udc46\u210e\ud835\udc5a\ud835\udc56\ud835\udc5b.    (43) \n\ud835\udc34\u221a\ud835\udc58 can be calculated from Equation 42 and plugged into Equation 43. Appropriate r elations for A and Sf \nare plugged into Equation 43, assuming either radial or PKN geometry , and  the equation can be  solved for \neither radius or fracture length. Then, it is trivial to calculate area and permeability."}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4d2ce-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/urtec-2019-123-ms.pdf", "page": 35, "chroma:document": "We recommend evaluating Equation 40 at \u0394\ud835\udc61 equal to zero (using the effective ISIP) in order to minimize \nthe relative effect of uncertainty in the estimate of Shmin. For the case of \u0394\ud835\udc61=0, Equation 40 reduces to:  \n\ud835\udc49\ud835\udc56\ud835\udc5b\ud835\udc57=\ud835\udc36\ud835\udc64(\ud835\udc43\ud835\udc3c\ud835\udc46\ud835\udc3c\ud835\udc43 ,\ud835\udc52\ud835\udc53\ud835\udc53\u2212\ud835\udc43\ud835\udc64,\ud835\udc56\ud835\udc5b\ud835\udc56\ud835\udc61)+4(\ud835\udc34\u221a\ud835\udc58)(\ud835\udc43\ud835\udc3c\ud835\udc46\ud835\udc3c\ud835\udc43 ,\ud835\udc52\ud835\udc53\ud835\udc53\u2212\ud835\udc43\ud835\udc5f\ud835\udc52\ud835\udc60)\u221a\ud835\udc61\ud835\udc52\n2\u221a\ud835\udf19\ud835\udc50\ud835\udc61\n\ud835\udf0b\ud835\udf07 +\ud835\udc34\n\ud835\udc46\ud835\udc53 (\ud835\udc43\ud835\udc3c\ud835\udc46\ud835\udc3c\ud835\udc43 ,\ud835\udc52\ud835\udc53\ud835\udc53\u2212\ud835\udc46\u210e\ud835\udc5a\ud835\udc56\ud835\udc5b ). (44) \nFor radial geometry, the radius is calculated as:  \n\ud835\udc45\ud835\udc53=\u221a3\ud835\udc38\u2032[\ud835\udc49\ud835\udc56\ud835\udc5b\ud835\udc57\u2212\ud835\udc36\ud835\udc64(\ud835\udc43\ud835\udc3c\ud835\udc46\ud835\udc3c\ud835\udc43 ,\ud835\udc52\ud835\udc53\ud835\udc53\u2212\ud835\udc43\ud835\udc64,\ud835\udc56\ud835\udc5b\ud835\udc56\ud835\udc61)\u22124(\ud835\udc34\u221a\ud835\udc58)(\ud835\udc43\ud835\udc3c\ud835\udc46\ud835\udc3c\ud835\udc43 ,\ud835\udc52\ud835\udc53\ud835\udc53\u2212\ud835\udc43\ud835\udc5f\ud835\udc52\ud835\udc60)\u221a\ud835\udc61\ud835\udc52\n2\u221a\ud835\udf19\ud835\udc50\ud835\udc61\n\ud835\udf0b\ud835\udf07 ]\n16(\ud835\udc43\ud835\udc3c\ud835\udc46\ud835\udc3c\ud835\udc43 ,\ud835\udc52\ud835\udc53\ud835\udc53\u2212\ud835\udc46\u210e\ud835\udc5a\ud835\udc56\ud835\udc5b ) 3\n     (45) \nFor PKN geometry, the fracture length is calculated as:  \n\ud835\udc3f\ud835\udc53=2\ud835\udc38\u2032[\ud835\udc49\ud835\udc56\ud835\udc5b\ud835\udc57\u2212\ud835\udc36\ud835\udc64(\ud835\udc43\ud835\udc3c\ud835\udc46\ud835\udc3c\ud835\udc43 ,\ud835\udc52\ud835\udc53\ud835\udc53\u2212\ud835\udc43\ud835\udc64,\ud835\udc56\ud835\udc5b\ud835\udc56\ud835\udc61)\u22124(\ud835\udc34\u221a\ud835\udc58)(\ud835\udc43\ud835\udc3c\ud835\udc46\ud835\udc3c\ud835\udc43 ,\ud835\udc52\ud835\udc53\ud835\udc53\u2212\ud835\udc43\ud835\udc5f\ud835\udc52\ud835\udc60)\u221a\ud835\udc61\ud835\udc52\n2\u221a\ud835\udf19\ud835\udc50\ud835\udc61\n\ud835\udf0b\ud835\udf07 ]\n\u210e\ud835\udc532\ud835\udf0b(\ud835\udc43\ud835\udc3c\ud835\udc46\ud835\udc3c\ud835\udc43 ,\ud835\udc52\ud835\udc53\ud835\udc53\u2212\ud835\udc46\u210e\ud835\udc5a\ud835\udc56\ud835\udc5b ).     (46) \nA.10.iii Impulse linear  \nThe late time behavior of a DFIT can be interpreted like an impulse test from classical well test analysis \n(Craig and Blasingame, 2006). The late -time analytical solution for linear flow with constant rate injection \nis (Gringarten et al., 1974):  \n\ud835\udc43=\ud835\udc43\ud835\udc5f\ud835\udc52\ud835\udc60+\ud835\udc44\n\ud835\udc34\u221a\ud835\udf07\n\ud835\udf0b\ud835\udc58\ud835\udc50\ud835\udc61\ud835\udf19\u221a\u0394\ud835\udc61,         (47)"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4d33c-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/urtec-2019-123-ms.pdf", "page": 35, "chroma:document": "\ud835\udc43=\ud835\udc43\ud835\udc5f\ud835\udc52\ud835\udc60+\ud835\udc44\n\ud835\udc34\u221a\ud835\udf07\n\ud835\udf0b\ud835\udc58\ud835\udc50\ud835\udc61\ud835\udf19\u221a\u0394\ud835\udc61,         (47) \nwhere Q is the volumetric injection rate. Taking the derivative of the nondimensionalized form of th e \nequation, we can find the solution for injection of a volume of fluid Vslug into the system  (Houze et al, 1 988; \nAyoub et al., 1988; Gu et al, 1993 ). \ud835\udc49\ud835\udc60\ud835\udc59\ud835\udc62\ud835\udc54 should take wellbore storage into account:   \n\ud835\udc43=\ud835\udc43\ud835\udc5f\ud835\udc52\ud835\udc60+\ud835\udc49\ud835\udc56\ud835\udc5b\ud835\udc57\u2212\ud835\udc36\ud835\udc64(\ud835\udc43\ud835\udc5f\ud835\udc52\ud835\udc60\u2212\ud835\udc43\ud835\udc64,\ud835\udc56\ud835\udc5b\ud835\udc56\ud835\udc61)\n2\ud835\udc34\u221a\ud835\udf07\n\ud835\udf0b\ud835\udc58\ud835\udc50\ud835\udc61\ud835\udf191\n\u221a\u0394\ud835\udc61.       (48) \nEquation 48 can be rearranged to calculate \ud835\udc34\u221a\ud835\udc58 from the slope of a plot of pressure versus 1\n\u0394\ud835\udc611/2. Once \ud835\udc34\u221a\ud835\udc58 \nhas been estimated, radius (or length) and permeability can be estimated from Equations 45 and 46.  Downloaded from http://onepetro.org/URTECONF/proceedings-pdf/19URTC/2-19URTC/D023S030R001/1138462/urtec-2019-123-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4d3be-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/urtec-2019-123-ms.pdf", "page": 36, "chroma:document": "URTeC 123   37 \nA.10.iv Impulse radial  \nThe late -time analytical solution for radial flow with constant rate injection is (Theis, 193 5; Horne, 1995):  \n\ud835\udc43\u2212\ud835\udc43\ud835\udc5f\ud835\udc52\ud835\udc60=\ud835\udc44\ud835\udf07\n2\ud835\udf0b\ud835\udc58\u210e[0.5(\ud835\udc59\ud835\udc5b(\ud835\udc58\u0394\ud835\udc61\n\ud835\udf19\ud835\udf07\ud835\udc50\ud835\udc61\ud835\udc5f\ud835\udc642)+0.80907 )+\ud835\udc60].      (49) \nTherefore, impulse radial is the derivative of the constant rat e solution ( Houze et al, 1988; Ayoub et al., \n1988; Gu et al, 1993 ): \n\ud835\udc43\u2212\ud835\udc43\ud835\udc5f\ud835\udc52\ud835\udc60=(\ud835\udc49\ud835\udc56\ud835\udc5b\ud835\udc57\u2212\ud835\udc36\ud835\udc64(\ud835\udc43\ud835\udc5f\ud835\udc52\ud835\udc60\u2212\ud835\udc43\ud835\udc64,\ud835\udc56\ud835\udc5b\ud835\udc56\ud835\udc61))\ud835\udf07\n4\ud835\udf0b\ud835\udc58\u210e1\n\u0394\ud835\udc61.        (50) \nEquation 50 can be rearranged to show that the permeability -thickness product , \ud835\udc58\u210e, can be calculated from \nthe slope of a plot of pressure versus 1\n\u0394\ud835\udc61. To calculate permeability, it is necessary to m ake an estimate for \nh, the height of the permeable formation. If well logs indicate that there is a clear \u2018pay\u2019 zone with higher \npermeability than surrounding formations, then the thickness of this zone can be used for h. Alternatively, \nif well logs indica te strong height confinement, then the fracture can be assumed to have known height, and \nthis value can be used for h."}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4d436-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/urtec-2019-123-ms.pdf", "page": 36, "chroma:document": "this value can be used for h.  \nIf there is not clear indication of height confinement and there is a not a single \u2018high permeability\u2019 pay \nzone, we recommend using a ra dial fracture geometry and setting h equal to 2 Rf. For known kh (estimated \nfrom Equation 50), then k is approximately equal to (\ud835\udc58\u210e)\ud835\udc52\ud835\udc60\ud835\udc61\n2\ud835\udc45\ud835\udc53. Equation 44 becomes:  \n\ud835\udc49\ud835\udc56\ud835\udc5b\ud835\udc57=\ud835\udc36\ud835\udc64(\ud835\udc43\ud835\udc3c\ud835\udc46\ud835\udc3c\ud835\udc43 ,\ud835\udc52\ud835\udc53\ud835\udc53\u2212\ud835\udc43\ud835\udc64,\ud835\udc56\ud835\udc5b\ud835\udc56\ud835\udc61)+4(\ud835\udf0b\ud835\udc45\ud835\udc532\u221a(\ud835\udc58\u210e)\ud835\udc52\ud835\udc60\ud835\udc61\n2\ud835\udc45\ud835\udc53)(\ud835\udc43\ud835\udc3c\ud835\udc46\ud835\udc3c\ud835\udc43 ,\ud835\udc52\ud835\udc53\ud835\udc53\u2212\ud835\udc43\ud835\udc5f\ud835\udc52\ud835\udc60)\u221a\ud835\udc61\ud835\udc52\n2\u221a\ud835\udf19\ud835\udc50\ud835\udc61\n\ud835\udf0b\ud835\udf07 + 16\ud835\udc45\ud835\udc533\n3\ud835\udc38\u2032  (\ud835\udc43\ud835\udc3c\ud835\udc46\ud835\udc3c\ud835\udc43 ,\ud835\udc52\ud835\udc53\ud835\udc53\u2212\ud835\udc46\u210e\ud835\udc5a\ud835\udc56\ud835\udc5b ) \n            (51) \nEquation 51 is a cubic equation for Rf. It can be solved with a nonlinear solver and then used to estimate h \nand k.  \nA.11 The linear flow time function  \nSometimes, impulse interpretations are performed with the \u2018linear flow time function\u2019 defined by Gulrajani \nand Nolte (2000) as:  \n\ud835\udc39\ud835\udc3f=2\n\ud835\udf0bsin\u22121\u221a\ud835\udc61\ud835\udc50\n\u0394\ud835\udc61,          (52) \nwhere tc is the shut -in time to \u2018closure.\u2019 \ud835\udc39\ud835\udc3f is only defined for  \u0394\ud835\udc61\u2265\ud835\udc61\ud835\udc50. \ud835\udc34\u221a\ud835\udc58 is estimated from impulse \nlinear flow using a plot of pressure versus \ud835\udc39\ud835\udc3f or \ud835\udc39\ud835\udc3f\u22121. \ud835\udc58\u210e is estimated from impulse radial flow using a plot"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4d4b8-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/urtec-2019-123-ms.pdf", "page": 36, "chroma:document": "of pressure versus \ud835\udc39\ud835\udc3f2 or \ud835\udc39\ud835\udc3f\u22122.  \nEquation 52 can be understood by considering the behavior of the arcsine function as its argument \napproaches zero:  \nlim\n\ud835\udc65\u21920sin\u22121\ud835\udc65=\ud835\udc65.          (53) \nTherefore, once \ud835\udc61\ud835\udc50+\u0394\ud835\udc61 is substantially larger than tc, \ud835\udc39\ud835\udc3f can be approximated as:  \n\ud835\udc39\ud835\udc3f\u22482\n\ud835\udf0b\u221a\ud835\udc61\ud835\udc50\n\u0394\ud835\udc61.           (54) \nFor \u0394\ud835\udc61 equal to 2\ud835\udc61\ud835\udc50, the approximation is accurate within 11%. For \u0394\ud835\udc61 equal to 10\ud835\udc61\ud835\udc50, the approximation is \naccurate within 2%.  Downloaded from http://onepetro.org/URTECONF/proceedings-pdf/19URTC/2-19URTC/D023S030R001/1138462/urtec-2019-123-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4d53a-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/urtec-2019-123-ms.pdf", "page": 37, "chroma:document": "URTeC 123   38 \nThus, for most practical purposes, a plot of pressure ve rsus \ud835\udc39\ud835\udc3f is equivalent to a plot of pressure versus \nreciprocal square root of time, and a plot of pressure versus \ud835\udc39\ud835\udc3f2 is equivalent to a plot of pressure versus \nreciprocal time. A plot of \ud835\udc39\ud835\udc3f\u22122 is equivalent to a plot of pressure versus time.  \nThe FL function is significantly different from 2\n\ud835\udf0b\u221a\ud835\udc61\ud835\udc50\n\ud835\udee5\ud835\udc61 in the period from \u0394\ud835\udc61=\ud835\udc61\ud835\udc50 to \u0394\ud835\udc61=2\ud835\udc61\ud835\udc50 (it is not defined \nprior to tc). Should FL be used if data is not available for \u0394\ud835\udc61 greater than 2\ud835\udc61\ud835\udc50? Possibly, but interpreters \nshould keep in mind the assump tions underlying FL. It is derived assuming that Carter leakoff occurs until \nclosure, and then there is zero leakoff after closure (Nolte et al., 1997; page 76 from Carslaw and Jaeger, \n1959). But in reality, leakoff rate gradually deviates from Carter leak off as pressure decreases in a system \ncoupled with nonlinear evolution of system storage (Section A.13). Because of this simplification, the"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4d5bc-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/urtec-2019-123-ms.pdf", "page": 37, "chroma:document": "period from \u0394\ud835\udc61=\ud835\udc61\ud835\udc50 to \u0394\ud835\udc61=2\ud835\udc61\ud835\udc50 is the period when the assumptions underlying FL are least reliable. After \nthis p eriod, FL is similar to the impulse solution.  \nA.12 Estimating efficiency  \nFracture efficiency, \ud835\udf02, is defined as the volume of fluid remaining  in the fracture at shut -in divided by the \nvolume of fluid injected into the fracture (the total injection volume minus wellbore storage). A classical \nequation for estimating efficiency is (Equation 9 -60 from Gulrajani and Nolte, 2001):  \n\ud835\udf02=\ud835\udc3a\ud835\udc50\n2+\ud835\udc3a\ud835\udc50,           (55) \nwhere \ud835\udc3a\ud835\udc50 is G-time at \u2018closure.\u2019  \nEquation 55 is derived assuming the same assumptions discussed in Section A.11 : Carter leakof f occurs \nuntil \u2018closure,\u2019 at which point there is zero fluid remaining in the fracture. Conventionally, Equation 55 \nwould be applied with the tangent m ethod for picking closure. But there has been substantial deviation from \nCarter leakoff by the time of the tangent closure pick. As discussed in Section 3.1 .9, due to fracture"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4d634-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/urtec-2019-123-ms.pdf", "page": 37, "chroma:document": "roughness, there is likely to be significant fluid remaining the fracture at the  point of contact, and even \nwhen pressure is equal to or less than Shmin. Because of the offsetting effect of different approximations, \nEquation 55 often yields a reasonable approximation  of efficiency in many cases if applied with the tangent \nmethod of picking closure.  \nAlternatively, efficiency can be estimated after estimating leakoff coefficient and/or permeability using the \ntechniques in Section A.10. Then, cumulative leakoff at shut -in can be estimated from Equation 13, and \nefficiency  can be calculated  directly by applying mass balance (including the effect of wellbore storage):  \n\ud835\udf02=\ud835\udc49\ud835\udc56\ud835\udc5b\ud835\udc57\u2212\ud835\udc36\ud835\udc64(\ud835\udc43\u2212\ud835\udc43\ud835\udc64,\ud835\udc56\ud835\udc5b\ud835\udc56\ud835\udc61)\u2212\ud835\udc49\ud835\udc3f(\u0394\ud835\udc61=0)\n\ud835\udc49\ud835\udc56\ud835\udc5b\ud835\udc57\u2212\ud835\udc36\ud835\udc64(\ud835\udc43\u2212\ud835\udc43\ud835\udc64,\ud835\udc56\ud835\udc5b\ud835\udc56\ud835\udc61).         (56) \nA.13 Estimating pore pressure with a short shut -in \nSometimes, DFIT\u2019s are not performed with sufficient shut -in duration to reach impulse linear or radial. A \nsimple numerical simulation and history match can be used to provide a rou gh estimate for fluid pressure."}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4d6a2-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/urtec-2019-123-ms.pdf", "page": 37, "chroma:document": "1. Assume W0 and Pres. \n2. Use the h -function method to integrate the measured pressure data (after conversion to Peff) and use \nthe method in Section A.10.ii to infer leakoff coefficient and fracture surface area. Use the \nestimated  area and assumed fracture geometry to calculate Sf,o. \n3. Numerically solve the following equation for a DFIT pressure transient (derived from Equation 3): \n\ud835\udc51\ud835\udc43\n\ud835\udc51\ud835\udc61(\ud835\udc34\n\ud835\udc46\ud835\udc53+\ud835\udc36\ud835\udc64)=\ud835\udc51\ud835\udc49\ud835\udc3f\n\ud835\udc51\ud835\udc61.         (57) Downloaded from http://onepetro.org/URTECONF/proceedings-pdf/19URTC/2-19URTC/D023S030R001/1138462/urtec-2019-123-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4d724-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/urtec-2019-123-ms.pdf", "page": 38, "chroma:document": "URTeC 123   39 \n\ud835\udc51\ud835\udc49\ud835\udc3f\n\ud835\udc51\ud835\udc61 is the leakoff rate, calculated from Equation 25. When the calculated aperture reaches Wo, the \nfracture stiffness is increased to account for the c ontribution of Sf,c, as discussed in Section A.1.ii. The \nintegration can be solved numerically with explicit Euler:  \n\ud835\udc43\ud835\udc58=\ud835\udc43\ud835\udc58\u22121+(\ud835\udc51\ud835\udc43\n\ud835\udc51\ud835\udc61)\n\ud835\udc58\u0394\ud835\udc61,         (58) \nwhere (\ud835\udc51\ud835\udc43\n\ud835\udc51\ud835\udc61)\n\ud835\udc58 is calculated from Equation 57. \n4. Check to see if the timing and value of the peak in t*dP /dt has been accurately predicted. If not, go \nback to Step 1 and select new values for W0 and Pres. Iterate until convergence.  \nA.14 Generating plots of aperture versus effective normal stress  \nWang and Sharma (2018) propose  a method for estimating aperture versus pressure. The technique in this \nsection is conceptually similar. From Equation 35, the derivative of P with respect to h is proport ional to \nsystem stiffness. Therefore, neglecting wellbore storage, we can write:  \n\ud835\udc51\ud835\udc43\n\ud835\udc51\u210e\n(\ud835\udc51\ud835\udc43\n\ud835\udc51\u210e)\ud835\udc5a\ud835\udc56\ud835\udc5b\ud835\udc46\ud835\udc53\n\ud835\udc34=\ud835\udc51\ud835\udc43\n\ud835\udc51\ud835\udc49.           (59)"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4d792-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/urtec-2019-123-ms.pdf", "page": 38, "chroma:document": "\ud835\udc51\ud835\udc43\n\ud835\udc51\u210e\n(\ud835\udc51\ud835\udc43\n\ud835\udc51\u210e)\ud835\udc5a\ud835\udc56\ud835\udc5b\ud835\udc46\ud835\udc53\n\ud835\udc34=\ud835\udc51\ud835\udc43\n\ud835\udc51\ud835\udc49.           (59) \nThe permeability estimation methods in Section A.10 yield estimates of fracture area and stiffness prior to \ncontact, Sfo. Next, estimate the derivative of pressure with respect to aperture:  \n\ud835\udc51\ud835\udc43\n\ud835\udc51\ud835\udc4a=\ud835\udc34\ud835\udc51\ud835\udc43\n\ud835\udc51\ud835\udc49.           (60) \nIf we assume that aperture at the peak of G*dP/dG  is an arbitrary, small value, 3.28e -5 ft, then we can \nperform an integral to  roughly approximate  average fracture aperture as a function of pressure:  \n\ud835\udc4a(\ud835\udc43)=3.28\u221710\u22125 +\u222b1\n\ud835\udc51\ud835\udc43\n\ud835\udc51\ud835\udc4a\ud835\udc51\ud835\udc43\ud835\udc43\n\ud835\udc43\ud835\udc5d\ud835\udc3a,        (61) \nwhere \ud835\udc43\ud835\udc5d\ud835\udc3a is the pressure at the peak G* dP/dG. Figure 7 shows a result from this procedure.  Downloaded from http://onepetro.org/URTECONF/proceedings-pdf/19URTC/2-19URTC/D023S030R001/1138462/urtec-2019-123-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4d814-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/urtec-3717105-ms.pdf", "page": 0, "chroma:document": "URTeC: 3717105 \n \nImprovement in the Characterization of Vaca Muerta With DFIT Type \nCurves Analysis \n \nCristian F. Gonz\u00e1lez* and Ignacio Arhancet \u2020, YPF S.A. \n\u2020 Now with TotalEnergies \n \nCopyright 2022, Unconventional Resources Technology Conference (URTeC) DOI 10.15530/urtec-2022-3717105 \n \nThis paper was prepared for presentation at the Unconventional Resources Technology Conference held in Houston, Texas, USA, \n20-22 June 2022. \nThe URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitted \nby the author(s). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, \nor timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any \nperson or entity that relies on any information obtained from this paper does so at their own risk. The information herein does not"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4d88c-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/urtec-3717105-ms.pdf", "page": 0, "chroma:document": "necessarily reflect any position of URTeC. Any reproduction, distribution, or storage of any part of this paper by anyone other than the \nauthor without the written consent of URTeC is prohibited.   \n \nAbstract \nNatural decline of conventional fields and the good results in the development of USA shale plays motivated \nYPF, Argentina\u2019s National Oil Company, to start in 2010 the exploitation of unconventional resources. \nVaca Muerta Formation in Neuqu\u00e9n Basin was selected among others because of its excellent petrophysical \nand geomechanical properties. Since then, more than 1000 wells have been drilled and completed across \nthe basin proving that Vaca Muerta is a world-class unconventional play. \nIdentification of sweet spots, optimization in drilling and completion of shale wells and a proper field \ndevelopment plan require a good dynamic characterization of the reservoir. In conventional reservoirs this"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4d90e-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/urtec-3717105-ms.pdf", "page": 0, "chroma:document": "was traditionally performed by a series of tools in which well tests were a key part to get reservoir pressure \nand permeability. Because of the extremely low permeability of shale reservoirs, classical well testing is no \nlonger a practical tool to estimate these parameters. Diagnostic Fracture Injection Tests (DFITs) are one of \nthe few methodologies that allows estimation of reservoir transmissibility and pore pressure in \nunconventional reservoirs. DFITs are also useful to obtain closure pressure, a geomechanical parameter \nnecessary to define the stress state. \nHowever, DFITs interpretation by conventional methodology, also known as holistic approach, is not \nalways successful because it requires specific flow regimes during decline time to correctly estimate \nreservoir parameters. Additionally, as DFIT tests are generally pumped through horizontal well\u2019s toe prior \nto completion stage, they must compete against fracture bundle efficiency given its high costs of standby."}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4d99a-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/urtec-3717105-ms.pdf", "page": 0, "chroma:document": "All of this, results in short shut-in times leading to a poor DFIT interpretation efficiency [i.e., low \npercentage of tests with confident reservoir data (closure pressure, reservoir pressure and transmissibility)]. \nThis paper describes how using type-curves methodology, YPF increased the number of valid results from \nDFITs improving the characterization of Vaca Muerta. Better mapping of pore pressure and knowledge of \ntypical ranges of permeability were possible after reanalyzing more than 100 DFITs. \nDownloaded from http://onepetro.org/URTECONF/proceedings-pdf/22URTC/1-22URTC/D011S012R003/2801994/urtec-3717105-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4da12-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/urtec-3717105-ms.pdf", "page": 1, "chroma:document": "URTeC 3717105  2 \n \nIntroduction \nThe focus towards development of low permeability reservoirs during recent years has changed the way to \nget reservoir parameters from a well testing perspective. Diagnostic Fracture Injection Test (DFIT) has \nemerged as one of the few tools that allows to estimate pore pressure and permeability in unconventional \nreservoirs. Because of this, data acquisition plans usually include DFITs in wells of different locations and \nlanding zones.  \nYPF has led exploration, appraisal, and early development stages of Vaca Muerta shale in Argentina during \nthe first ten years (2010-2020). In that period, 135 DFITs were executed across the Neuqu\u00e9n basin to capture \nkey information (stress state, pore pressure and reservoir permeability) necessary to characterize the \nreservoir and identify sweet spots. Fig. 1 shows the location of DFITs in a map of Vaca Muerta\u2019s area.  \n \nFig. 1- Location of DFITs in Vaca Muerta during 2010-2020."}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4da8a-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/urtec-3717105-ms.pdf", "page": 1, "chroma:document": "Fig. 1- Location of DFITs in Vaca Muerta during 2010-2020. \nThose tests were interpreted following the classical best practices for DFIT analysis known as holistic \napproach (Barree et al, 2007). Analysis of results indicated that almost 90% of tests had a closure pressure \nestimation but only half of them presented a reservoir pressure calculation. Transmissibility values were \nonly present in around 10% of tests. That poor outcome in reservoir parameters can be explained by the \nlimitations of the traditional approach that are described in the following section.  \nConsidering the previous situation and with the objective of improving those numbers and extracting more \nvalue from DFITs, reservoir and stimulation engineering teams evaluated new interpretation techniques. \nDr. David Craig\u2019s work in type curves applied to DFITs (Craig, 2014) was considered a good alternative \nbecause it removes the main limitation of after closure analysis (ACA)."}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4db02-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/urtec-3717105-ms.pdf", "page": 1, "chroma:document": "Downloaded from http://onepetro.org/URTECONF/proceedings-pdf/22URTC/1-22URTC/D011S012R003/2801994/urtec-3717105-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4db7a-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/urtec-3717105-ms.pdf", "page": 2, "chroma:document": "URTeC 3717105  3 \n \nLimitations of Traditional Approach in Unconventionals \nCurrent most common procedure of DFITs interpretation is mainly based on Ken Nolte\u2019s works and it is \nwell described in Barree et al (2007). This approach, known as holistic, relies on proper flow regime \nidentification using different diagnostic graphs and special mathematical functions of time (e.g., G-function \ntime, Squared linear flow time, etc.) \nLeak-off type and closure pressure are not always simple to determine in before closure analysis (BCA) of \nunconventional wells using the holistic approach. Horizontal wells promote complex fracture growth \ngeometries that result in early events that disturb the G-Function plot\u2019s curves and can lead to different \ninterpretations generating uncertainty in in-situ minimum stress estimation. \nIn after closure analysis (ACA), correct estimation of pore pressure requires reaching specific flow regimes:"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4dbf2-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/urtec-3717105-ms.pdf", "page": 2, "chroma:document": "pseudolinear or pseudoradial. On the other hand, transmissibility or permeability calculation is only \npossible in pseudoradial flow. \nPseudolinear flow is expected to be developed in DFITs pumped in unconventional reservoirs after several \nhours of pressure decline while pseudoradial flow would be extremely rare due to its low permeability. \nBecause of this, DFITs in unconventionals are considered a good tool for initial pressure estimation but not \nso much for transmissibility or permeability calculation.  \nIn practice, pseudolinear flow is not always present in unconventional reservoirs DFITs due to lack of \nsufficient shut-in time or because of fracture-rock system complexities that result in non-ideal reservoir \nsignatures. Regarding interpretation, the use of auxiliary lines with characteristic slopes in flow regime \nidentification graphs sometimes promotes that the analysts see that specific flow regime even when it is not"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4dc6a-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/urtec-3717105-ms.pdf", "page": 2, "chroma:document": "present or it is not fully developed yet, leading to wrong estimations in reservoir parameters.  \nOn the operational side, as DFITs are generally pumped through horizontal well\u2019s toe prior to completion \nevent, shut-in times are limited by fracture set\u2019s schedule and its high cost of standby. Consequently, fall \noff registration time is usually lower than desirable for low permeability rocks. \nAll of this, results in many tests with poor interpretation outcomes and it has led some operators to stop \npumping DFITs in horizontal wells and question its validity.  \nType-Curves Methodology in DFITs \nDavid Craig (2014) presented a new method for DFIT analysis based on type curves whose main advantage \nis that no specific flow regime is needed to estimate reservoir pressure and permeability overcoming the \nprincipal problem of the holistic approach. This new methodology also provides an alternative way to \nestimate closure pressure which is particularly useful in horizontal wells where classic technique is"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4dce2-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/urtec-3717105-ms.pdf", "page": 2, "chroma:document": "sometimes ambiguous. \nDFIT type-curves analysis is analogous to classic well testing, i.e., it uses special derivatives to aid the \nmatching process between field data and different theoretical models (type curves) and, in contrast to the \ntraditional method, integrates all data in a unique analytical solution. Downloaded from http://onepetro.org/URTECONF/proceedings-pdf/22URTC/1-22URTC/D011S012R003/2801994/urtec-3717105-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4dd64-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/urtec-3717105-ms.pdf", "page": 3, "chroma:document": "URTeC 3717105  4 \n \nAs DFITs consist of a small injection of fluid followed by a long shut-in time, it could be practically \nconsidered as a slug test or short-flow transient test. Craig and Blasingame (2006) demonstrated that DFITs \ncould be modeled with a variable-storage slug test solution. Additionally, slug tests pressure response could \nbe transformed into an equivalent constant-rate drawdown by deconvolution (Peres et al, 1989). This allows \nthe use of conventional constant-rate type curves for DFIT analysis. \n \nFig. 2- Schematic of DFIT transformation into an equivalent constant-rate drawdown. \nThe problem is that cited transformation requires knowing the initial pressure which it is one of DFIT\u2019s \nobjectives. In 2008, David Craig found out, after differentiating the slug test solution, that the same semi-\nlog derivative used in the log-log plot of holistic approach can be matched to a special derivative of"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4ddd2-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/urtec-3717105-ms.pdf", "page": 3, "chroma:document": "constant-rate type curves (Eq. 1). This was the missing part that made possible to calculate the initial \npressure and completed the matching process. \n \n\ud835\udc61\u0bbd\u0bd7\u0be3\u0ce2\u0cb5\n\u0bd7\u0be7\u0cb5\u11e3\u11e7\u11e4\u11e7\u11e5\n\u0bbd\u0bbf\u0bc2\u0bcd \u0be6\u0bd8\u0be0\u0bdc\u0b3f\u0b6a\u0b6d\u0b65\u0bd7\u0bd8\u0be5\u0bdc\u0be9\u0bd4\u0be7\u0bdc\u0be9\u0bd8= \u2212\ud835\udc5d\u0bea\u0be6\u0bbd(\u0b34) \u00d7 \ud835\udc36 \u0be6\u0bbd\u0e15\n\u0be6\u0be7\u0be2\u0be5\u0bd4\u0bda\u0bd8\n\u0bd6\u0be2\u0bd8\u0bd9\u0bd9\u0bdc\u0bd6\u0bdc\u0bd8\u0be1\u0be7 \u00d7 \ud835\udc61 \u0bbd\u0bd7\u0c2e\u0be3\u0ce2\u0cce\u0cb5\n\u0bd7\u0be7\u0cb5\u0c2e\u11e3\u11e7\u11e7\u11e4\u11e7\u11e7\u11e5\n\u0bd6\u0be2\u0be1\u0be6\u0be7\u0bd4\u0be1\u0be7\u0b3f\u0be5\u0bd4\u0be7\u0bd8  \u0bd7\u0be5\u0bd4\u0bea\u0bd7\u0be2\u0bea\u0be1\n\u0b36\u0be1\u0bd7 \u0be2\u0be5\u0bd7\u0bd8\u0be5 \u0bd7\u0bd8\u0be5\u0bdc\u0be9\u0bd4\u0be7\u0bdc\u0be9\u0bd8 (Eq. 1) \nAnother important conclusion of Craig\u2019s work is that fracture closure is a storage phenomenon. Storage \neffects are recognized by unit-slope and superposition of pressure and first derivative curves in well testing \ndiagnostic plots.  Hence, fracture closure pressure could be identified as the point where both curves \nseparate from each other and deviates from unit slope. This provides an alternative to tangent method \n(holistic technique), and it is especially useful in horizontal wells where complex signatures during closure \nare common. \nThe procedure for analyzing DFITs with type curves can be resumed as: \n1. Match semi-log derivative of DFIT data with a constant-rate second order derivative type"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4de4a-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/urtec-3717105-ms.pdf", "page": 3, "chroma:document": "curve. Different constant storage coefficients can be used to construct the set of type curves. \n2. Calculate initial pressure from a matching point (MP) using the following equation: \n\ud835\udc5d\u0bdc= \ud835\udc5d\u0bea(\u0be7\u0cd0)\u2212\u0b35\n\u0be3\u0ce2\u0cde\u0cb5(\u0c2c)\u0bbc\u0cde\u0cb5\u124e\u0be7\u0ccf\u0cdb\u0ce2(\u0cdf)\n\u0ccf\u0cdf\n\u0b3f\u0be7\u0cb5\u0ccf\u0c2e\u0cdb\u0ce2\u0cce\u0cb5(\u0cdf\u0cb5)\n\u0ccf\u0cdf\u0cb5\u0c2e\u124f\n\u0bc6\u0bc9(Eq. 2) \n3. Once initial pressure has been estimated, constant-rate pressure and first derivative can be \ncalculated. The slug test (DFIT) has been transformed into an equivalent constant-rate \ndrawdown. \nDownloaded from http://onepetro.org/URTECONF/proceedings-pdf/22URTC/1-22URTC/D011S012R003/2801994/urtec-3717105-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4dec2-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/urtec-3717105-ms.pdf", "page": 4, "chroma:document": "URTeC 3717105  5 \n \n4. Overlap preceding curves with type curves. Perhaps, it could be necessary to slightly adjust \ninitial pressure to refine matching. \n5. Transmissibility can be calculated from a matching point over the pressure curve.  \n\u0bde\u0bdb\n\u0c13= (141.2)(24) \ud835\udc5d\u0bea\u0be6\u0bbd(\u0b34)\ud835\udc36\u0be6\u0bbd(\ud835\udc5d\u0b34\u2212\ud835\udc5d\u0bdc)\u1248\u0be3\u0ce2\u0cce\u0cb5(\u0cdf\u0cb5)\n\u222b\u0d6b\u0be3\u0ce2(\u0cdf)\u0b3f\u0be3\u0cd4\u0d6f\u0bd7\u0be7\u0cdf\n\u0c2c\u1249\n\u0bc6\u0bc9(Eq. 3) \n6. Fracture closure pressure is determined from the point where pressure and first derivative \ndeviate from unit slope and separate from each other. \nPrevious workflow considers a constant storage coefficient. In cases when variable storage is evident (e.g., \nnon-ideal leak-offs during fracture closure), the effect could be incorporated in type curves and equations \n(Craig, 2014). \nExamples of Application \nIn this section, two examples of application to Vaca Muerta\u2019s wells are presented and compared with the \nholistic approach. Detailed discussion about how well compared both methodologies for each parameter is \npresented in the following section adding more wells to the analysis."}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4df30-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/urtec-3717105-ms.pdf", "page": 4, "chroma:document": "Well A is an exploratory vertical well where a 3 barrel-DFIT was pumped in the lower section of Vaca \nMuerta and pressure decline was registered for 64 hours. Fig. 4 groups the set of graphs that are normally \nused for DFIT holistic interpretation. ACA shows a long pseudolinear flow period; hence, initial pressure \ncan be estimated with confidence using traditional technique and can be compared with type-curve method. \nAdditionally, a pump-in flowback rebound test (PIFBRT) was executed in well A after the DFIT providing \nan alternative estimation of closure pressure for comparison.  \nFig. 3 shows the type-curve match using Craig\u2019s methodology and Table 1 resumes the results of \ninterpretation by both methods. Pore pressure estimation is consistent between methods, being slightly \ngreater (+1%) for type-curve analysis. Regarding closure pressure, the tangent-line technique (holistic \napproach) does not provide an easy way to determine closure in this case because of a tip extension leak-"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4dfa8-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/urtec-3717105-ms.pdf", "page": 4, "chroma:document": "off signature (no local maximum in dP/dG derivative and tangent line on GdP/dG does not pass through \nthe origin). The interpreted value is slightly lower (-2%) than the PIFBRT estimation but it has a high \ndegree of uncertainty. Type-curve closure pressure is in contrast a little bit greater (+1%). Despite the small \ndifference, the type-curve analysis yielded an acceptable estimation of closure pressure, and it is a simple \nalternative when the classical approach is ambiguous.  Downloaded from http://onepetro.org/URTECONF/proceedings-pdf/22URTC/1-22URTC/D011S012R003/2801994/urtec-3717105-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4e016-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/urtec-3717105-ms.pdf", "page": 5, "chroma:document": "URTeC 3717105  6 \n \n \nFig. 3- DFIT type-curve match for well A. \n \nFig. 4- Conventional DFIT analysis of well A. Upper left: Log-log diagnostic plot. Upper right: G-function plot. Lower left: ACA diagnostic plot. \nLower right: Linear flow function plot. \n \nMethod Closure Pressure \n[psi] Closure Gradient \n[psi/ft] Initial Pressure \n[psi] Pressure Gradient \n[psi/ft] Transmissibility \n[mD.ft/cP]  \nHolistic 9118 0.978 8258 0.887 - \nType Curve 9378 1.006 8348 0.895 1.4 \nPIFBRT 9278 0.995 - - - \nTable 1- DFIT interpretation results for well A. \nWell A \nWell A Downloaded from http://onepetro.org/URTECONF/proceedings-pdf/22URTC/1-22URTC/D011S012R003/2801994/urtec-3717105-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4e098-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/urtec-3717105-ms.pdf", "page": 6, "chroma:document": "URTeC 3717105  7 \n \nSecond example corresponds to Well B, a horizontal well landed in a high TOC section of Vaca Muerta. \n36 barrels of fresh water were injected at 6 barrels per minute and shut-in lasted around 120 hours.  Fig. 6 \nshows the different specialized plots that were used for analyzing that DFIT under traditional workflow. A \nclear and long-lasting pseudoradial flow could be observed after fracture closure, then transmissibility and \ninitial pressure were estimated with a high degree of confidence (Table 2). \n \nFig. 5- DFIT type-curve match for well B. \n \nFig. 6- Conventional DFIT analysis of well B. Upper left: Log-log diagnostic plot. Upper right: G-function plot. Lower left: ACA diagnostic plot. \nLower right: Radial flow function plot. \n \nWell B \nWell B Downloaded from http://onepetro.org/URTECONF/proceedings-pdf/22URTC/1-22URTC/D011S012R003/2801994/urtec-3717105-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4e110-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/urtec-3717105-ms.pdf", "page": 7, "chroma:document": "URTeC 3717105  8 \n \nFig. 5 is the plot of DFIT type-curve analysis for well B and results are presented in Table 2. Initial pressure \nestimation is almost identical in both methods and transmissibility is very similar, being slightly greater for \ntype-curve analysis but consistent with traditional estimation. Closure pressure was also determined with \nboth techniques. In this case, the closure point is very clear on the G-function plot hence its value is a good \nreference for comparison. Type-curve estimated a closure pressure 2% greater than the tangent line method. \n \nMethod Closure Pressure  \n[psi] Closure Gradient \n[psi/ft] Initial Pressure  \n[psi] Pressure Gradient \n[psi/ft] Transmissibility \n[mD.ft/cP]  \nHolistic 8146 0.851 7496 0.783 12.83 \nType Curve 8341 0.871 7507 0.784 14.21 \nTable 2- DFIT interpretation results for well B. \nValidation \nDFIT type-curve methodology was validated by comparison with holistic method results before further"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4e192-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/urtec-3717105-ms.pdf", "page": 7, "chroma:document": "application. DFITs with clear pseudolinear or pseudoradial flow regimes were selected for this purpose so \nits results were reliable for validation. The comparison was divided considering the main parameters of \nDFITs interpretation: initial pressure, transmissibility, and closure pressure.     \n\u25cf  Initial Pressure \nInitial pressure estimations from 35 DFITs with pseudolinear flow and 7 with pseudoradial flow were \ncompared and plotted in Fig. 7. As it can be seen, linear regression gives practically unit slope and R2=1 \nindicating that both methods estimate almost identical values.   \n \nFig. 7- Crossplot and linear regression of initial pressure estimations with both methods. \n \n \nDownloaded from http://onepetro.org/URTECONF/proceedings-pdf/22URTC/1-22URTC/D011S012R003/2801994/urtec-3717105-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4e200-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/urtec-3717105-ms.pdf", "page": 8, "chroma:document": "URTeC 3717105  9 \n \n\u25cf  Transmissibility  \nDue to few tests with pseudoradial flow in Vaca Muerta, 8 DFITs from tight sands were included in the \ncomparison. Fig. 8 shows the crossplot and linear regression. R-squared is 0.9972 and slope of the line is \naround 1.02. In general, type-curve transmissibilities are slightly greater than holistic\u2019s but are very close \nsince data practically lies in the 45\u00ba line. Considering the uncertainty in this parameter, these differences \nare totally acceptable for engineering use.   \n \nFig. 8- Crossplot and linear regression of transmissibility estimations with both methods. \n\u25cf  Closure Pressure \nClosure pressure estimations of 87 DFITs from both methods are plotted in Fig. 9. R-squared is 0.9998 and \nslope of the line is around 1.01 indicating that values for type-curves are on average slightly greater (+70-\n100 psi).  \nClosure pressure estimation from DFITs has generated a lot of debate in the industry since the fracture-"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4e282-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/urtec-3717105-ms.pdf", "page": 8, "chroma:document": "compliance method was presented by McClure et al (2016). This method results in closure pressures \nsignificantly greater (500 psi or more in some cases) than the tangent-line technique (holistic approach).  \nResults from Fig. 9 would preliminarily indicate intermediate values but closer to the tangent-line method \nsince differences are small. Nevertheless, application of fracture-compliance method to this dataset must \nbe performed to correctly compare between all these methods. Comparison with other techniques like \nPIFBRT, whenever it is available, would be desirable. \nDownloaded from http://onepetro.org/URTECONF/proceedings-pdf/22URTC/1-22URTC/D011S012R003/2801994/urtec-3717105-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4e2fa-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/urtec-3717105-ms.pdf", "page": 9, "chroma:document": "URTeC 3717105  10 \n \n \nFig. 9- Crossplot and linear regression of closure pressure estimations with both methods. \nAnalysis of Type Curves Non-uniqueness  \nAs it is well known in well testing interpretation, type-curve matching is usually non-unique (i.e., data could \nbe matched with several type curves). This is also true for DFIT type curves, therefore, the impact of curve \nselection in pressure and transmissibility estimation was evaluated. \nA DFIT with a not fully developed post-closure flow regime (Fig. 10) was selected to evaluate a case of \nhigh uncertainty. Flow regime identification after fracture closure shows a slope of -0.15 in semi-log \nderivative after 80 hours that could be interpreted as a slow transition to pseudolinear flow. Conventional \nACA cannot be applied because pseudolinear flow is not developed.   \nTwo extreme type curves were selected to test sensitivity. Dimensionless storage coefficient of 0.09 (Fig."}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4e372-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/urtec-3717105-ms.pdf", "page": 9, "chroma:document": "10) implies transition to a long pseudolinear flow regime (realistic case) and dimensionless storage \ncoefficient of 0.36 (Fig. 11) means short pseudolinear flow followed by pseudoradial flow (unlikely case). \nIn both cases, an acceptable match can be performed.  \nDownloaded from http://onepetro.org/URTECONF/proceedings-pdf/22URTC/1-22URTC/D011S012R003/2801994/urtec-3717105-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4e3ea-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/urtec-3717105-ms.pdf", "page": 10, "chroma:document": "URTeC 3717105  11 \n \n \nFig. 10- Type-curve match with lower storage coefficient. \n \nFig. 11- Type-curve match with higher storage coefficient. \nTable 3 resumes the results of both interpretations. Closure pressure and initial pressure are independent of \nthe type curve selected for analysis since estimations are practically identical. This proves that type-curve \nmethodology is an excellent tool for closure and initial pressures estimations.  \n \nDimensionless \nStorage \nCoefficient  Closure \nPresure  \n[psi] Closure Gradient \n[psi/ft] Initial Pressure  \n[psi] Pressure Gradient \n[psi/ft] Transmissibility \n[mDft/cP]  \n0.09 8339 0.913 7474 0.818 1.22 \n0.36 8339 0.913 7489 0.820 3.38 \nTable 3- Results of different type curves interpretations. \nTransmissibility estimation, in contrast, does depend on what curve is used. For this example, a factor of 3 \nwas obtained between cases. This sensitivity can be seen as a weakness of the method but must be"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4e458-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/urtec-3717105-ms.pdf", "page": 10, "chroma:document": "considered that there are not many other alternatives to estimate transmissibility from DFITs, especially in \nCSD=0.09 \n-tDd2pwcD/dtD2 CSD=0.09 \npwcD \ntDdpwcD/dtD \n-tDd2pwcD/dtD2 \nClosure \nCSD=0.36 \n-tDd2pwcD/dtD2 CSD=0.36 \npwcD \ntDdpwcD/dtD \n-tDd2pwcD/dtD2 \nClosure Downloaded from http://onepetro.org/URTECONF/proceedings-pdf/22URTC/1-22URTC/D011S012R003/2801994/urtec-3717105-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4e4da-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/urtec-3717105-ms.pdf", "page": 11, "chroma:document": "URTeC 3717105  12 \n \nunconventional reservoirs where pseudoradial flow is extremely rare. In any case, transmissibility \nestimations from different type curves will result in the same order of magnitude.  \nResults \nFig. 12 shows the improvement in the percentage of DFITs with valid estimates for different parameters \nafter applying the type-curve methodology to over 100 tests in Vaca Muerta.   \nClosure pressure percentages were slightly improved from 87% to 91%. Type curves allowed reinterpreting \na few tests where closure was not clear or impossible to estimate with the tangent-line method.  \nBefore type-curve application only half of tests had an estimation of initial pressure. Type-curves rise the \npercentage to 80%, adding tests where no pseudolinear or pseudoradial flow were seen. \nSince transmissibility is only possible to be calculated in pseudoradial flow using the traditional approach, \nthe percentage of test was too low (roughly 1 of 10) before type curves implementation. That number"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4e552-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/urtec-3717105-ms.pdf", "page": 11, "chroma:document": "improved to 6 of 10 because of type-curves methodology. \n \nFig. 12- Comparison of percentage of DFITs with closure pressure, initial pressure, and transmissibility estimations before and after type-curves \napplication. \nApplications \nThe results presented in the previous section increased the data available for Vaca Muerta characterization. \nBetter areal coverage of closure and initial pressures across Neuqu\u00e9n basin resulted in better mapping of \nstress state and pore pressure. For pore pressure mapping, more data availability allowed to construct maps \nfor the different landing zones. All of this is key information for sweet spots identification. \nAnother example of application is knowledge of permeability ranges for Vaca Muerta. Permeability that \ncontributes to production in unconventionals [i.e., system permeability (matrix + fissures)] is impossible to \nestimate from classical tools such as well testing. Rock cores offer an alternative to knowing permeability,"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4e5ca-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/urtec-3717105-ms.pdf", "page": 11, "chroma:document": "but they are not very representative because of its small volume of investigation. DFIT type-curves analysis \nis an excellent tool for permeability estimation in unconventional reservoirs. \nFig. 13 shows a S-curve of DFIT\u2019s permeabilities for Vaca Muerta calculated from type-curves \ntransmissibilities. Error bars have been included in the graph to indicate the estimated uncertainty of \ncalculated permeabilities. \nDownloaded from http://onepetro.org/URTECONF/proceedings-pdf/22URTC/1-22URTC/D011S012R003/2801994/urtec-3717105-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4e642-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/urtec-3717105-ms.pdf", "page": 12, "chroma:document": "URTeC 3717105  13 \n \n \nFig. 13- S-curve of Vaca Muerta DFIT permeability. \n \nConclusions \n\uf0b7 Application of type-curves analysis allowed YPF S.A. to improve DFITs\u2019 interpretation \nefficiency resulting in better characterization of Vaca Muerta. \n\uf0b7 Type-curves methodology was validated by comparing results with classic approach in DFITs \nof reference (clear pseudolinear and pseudoradial flow). \n\uf0b7 Closure and initial pressure estimations are practically insensitive to the selected type curve. \nThis puts the type-curves method as one of the best ways to estimate reservoir pressure in \nunconventional reservoirs.    \n\uf0b7 Transmissibility estimation does depend on the type curve used in the analysis. Different \ninterpretations can differ as much as a factor of 3. Being one of the few methods to get \ntransmissibility in unconventional reservoirs, the authors consider it acceptable despite the \nrange of uncertainty.  \n\uf0b7 Type-curves method provides an alternative way to estimate closure pressure which is"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4e6ba-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/urtec-3717105-ms.pdf", "page": 12, "chroma:document": "particularly useful in horizontal wells where complex pressure signatures are common. \n\uf0b7 Type curves are an excellent tool for improving the analysis of DFITs in unconventional \nreservoirs like Vaca Muerta. \nAcknowledgments \nThe authors would like to thank YPF S.A. for the permission to publish this paper and Dr. David Craig for \ncreating and sharing this powerful tool for DFITs analysis. \nNomenclature \nACA After Closure Analysis  \nBCA Before Closure Analysis  \nDFIT Diagnostic Fracture Injection Test  \nDownloaded from http://onepetro.org/URTECONF/proceedings-pdf/22URTC/1-22URTC/D011S012R003/2801994/urtec-3717105-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4e732-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/urtec-3717105-ms.pdf", "page": 13, "chroma:document": "URTeC 3717105  14 \n \nMP Matching Point  \nPIFBRT Pump-In Flowback Rebound Test  \nTOC Total Organic Carbon  \nUSA United States of America  \n  \n\ud835\udc36\u0be6\u0bbd Dimensionless storage coefficient \n\ud835\udc3a G-function time \n\u210e Height \n\ud835\udc58 Permeability \n\ud835\udf07 Viscosity \n\ud835\udc5d\u0bdc Initial pressure \n\ud835\udc5d\u0b34 Pressure at end of injection \n\ud835\udc5d\u0bea Wellbore pressure \n\ud835\udc5d\u0bea\u0bbd Dimensionless wellbore pressure  \n\ud835\udc5d\u0bea\u0bd6\u0bbd Dimensionless constant-rate wellbore pressure  \n\ud835\udc5d\u0bea\u0be6\u0bbd Dimensionless slug-test wellbore pressure  \n\ud835\udc61 Time \n\ud835\udc61\u0bbd Dimensionless time \n\ud835\udc61\u0bd8 Time at end of injection \n \nReferences \nBarree, Robert David, Barree, Valencia L., and David Craig. \"Holistic Fracture Diagnostics.\" Paper \npresented at the Rocky Mountain Oil & Gas Technology Symposium, Denver, Colorado, U.S.A., April \n2007. doi: https://doi.org/10.2118/107877-MS  \nCraig, David P. \"New Type Curve Analysis Removes Limitations of Conventional After-Closure Analysis \nof DFIT Data.\" Paper presented at the SPE Unconventional Resources Conference, The Woodlands, Texas,"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4e7aa-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/urtec-3717105-ms.pdf", "page": 13, "chroma:document": "USA, April 2014. doi: https://doi.org/10.2118/168988-MS  \nCraig, David P., and Thomas Alwin Blasingame. \"Application of a New Fracture-Injection/Falloff Model \nAccounting for Propagating, Dilated, and Closing Hydraulic Fractures.\" Paper presented at the SPE Gas \nTechnology Symposium, Calgary, Alberta, Canada, May 2006. doi: https://doi.org/10.2118/100578-MS  \nCraig, David P., and Robert A. Jackson. \"Calculating the Volume of Reservoir Investigated During a \nFracture-Injection/Falloff Test DFIT.\" Paper presented at the SPE Hydraulic Fracturing Technology \nConference and Exhibition, The Woodlands, Texas, USA, January 2017. doi: \nhttps://doi.org/10.2118/184820-MS  \nMcClure, Mark W., Jung, Hojung, Cramer, Dave D., and Mukul M. Sharma. \"The Fracture-Compliance \nMethod for Picking Closure Pressure From Diagnostic Fracture-Injection Tests.\" SPE J. 21 (2016): 1321\u2013\n1339. doi: https://doi.org/10.2118/179725-PA  \nNolte, Kenneth G., and Michael B. Smith. \"Interpretation of Fracturing Pressures.\" Paper presented at the"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4e822-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/urtec-3717105-ms.pdf", "page": 13, "chroma:document": "SPE Annual Technical Conference and Exhibition, Las Vegas, Nevada, September 1979. doi: \nhttps://doi.org/10.2118/8297-MS  \nNolte, Kenneth G. \"Determination Of Fracture Parameters From Fracturing Pressure Decline.\" Paper \npresented at the SPE Annual Technical Conference and Exhibition, Las Vegas, Nevada, September 1979. \ndoi: https://doi.org/10.2118/8341-MS  \nNolte, Kenneth G.. \"Fracturing-Pressure Analysis for Nonideal Behavior.\" J Pet Technol 43 (1991): 210\u2013\n218. doi: https://doi.org/10.2118/20704-PA  Downloaded from http://onepetro.org/URTECONF/proceedings-pdf/22URTC/1-22URTC/D011S012R003/2801994/urtec-3717105-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4e89a-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/urtec-3717105-ms.pdf", "page": 14, "chroma:document": "URTeC 3717105  15 \n \nNolte, K.G., Mack, M.G., and W.L. Lie. \"A Systematic Method for Applying Fracturing Pressure Decline: \nPart I.\" Paper presented at the Low Permeability Reservoirs Symposium, Denver, Colorado, April 1993. \ndoi: https://doi.org/10.2118/25845-MS  \nNolte, K.G., Maniere, J.L., and K.A. Owens. \"After-Closure Analysis of Fracture Calibration Tests.\" Paper \npresented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, October 1997. doi: \nhttps://doi.org/10.2118/38676-MS  \nPeres, A. M. M., Onur, M., and A. C. Reynolds. \"A New General Pressure Analysis Procedure for Slug \nTests.\" Paper presented at the SPE California Regional Meeting, Bakersfield, California, April 1989. doi: \nhttps://doi.org/10.2118/18801-MS  \nTalley, G.R., Swindell, T.M., Waters, G.A., and K.G. Nolte. \"Field Application of After-Closure Analysis \nof Fracture Calibration Tests.\" Paper presented at the SPE Mid-Continent Operations Symposium,"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4e912-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/urtec-3717105-ms.pdf", "page": 14, "chroma:document": "Oklahoma City, Oklahoma, March 1999. doi: https://doi.org/10.2118/52220-MS  \n Downloaded from http://onepetro.org/URTECONF/proceedings-pdf/22URTC/1-22URTC/D011S012R003/2801994/urtec-3717105-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4e994-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 0, "chroma:document": "SPE-201413-MS\nDFIT Analysis and Simulation: A Utica Shale Field Study\nJeffery Hildebrand, Jr. and Yu Liang , The University of Texas at Austin\nCopyright 2020, Society of Petroleum Engineers\nThis paper was prepared for presentation at the SPE Annual Technical Conference & Exhibition originally scheduled to be held in Denver, Colorado, USA, 5 \u2013 7\nOctober 2020. Due to COVID-19 the physical event was postponed until 26 \u2013 29 October 2020 and was changed to a virtual event. The official proceedings were\npublished online on 21 October 2020.\nThis paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents\nof the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4ea0c-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 0, "chroma:document": "any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written\nconsent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may\nnot be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.\nAbstract\nSince 2010, hydrocarbon production from long horizontal wells targeting shales has become the norm for\nindustry leaders. Because of the steep decline rates, it is vital to understand the reservoir and its properties\nbefore going through with a full-scale fracture stimulation. Through the application of Diagnostic Fracture\nInjection Tests (DFIT), one can determine accurate estimates of closure pressure, net pressure, pore pressure,\nformation permeability, and induced fracture geometry. The Utica shale is among the most promising"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4ea8e-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 0, "chroma:document": "reservoirs of the future, but there is limited information available discussing its properties. In SPE-196149-\nMS, we analyzed a DFIT from one horizontal well targeting the Utica. However, in order to fully understand\nthe Utica shale at scale, further analysis is required. In this study, we will present three additional horizontal\nwells targeting the Utica, and analyze the pressure and its derivative to accurately estimate the properties\nmentioned above.\nDFIT analysis is an advanced technique to accurately predict stress regimes and reservoir properties.\nHowever, interpretation of DFIT data is challenging, especially in shale formations. In this study, we\noverview the geologic properties of the Utica shale, discuss the development of DFIT analysis and its\ngoverning equations, then present the three data sets and resulting conclusions. We specifically discuss\nthe Tangent Line Method, the Compliance Method, and the Variable Compliance method in detail, while"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4eb06-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 0, "chroma:document": "comparing their underlying equations and assumptions to determine closure pressure. After-Closure analysis\nis then performed in order to verify fracture closure and identify flow regimes. Through linear regression\nof this data, pore pressure from a linear flow regime is extrapolated, and through numerical simulation, key\nreservoir properties, such as permeability and fracture geometry, are estimated for the Utica shale.\nThe DFIT interpretation and simulation results from this study are very insightful. Interpreting the GdP/\ndG function, the closure pressure ranges from 4,943 psi to 6,141 psi, contributing to a closure pressure\ngradient of 0.797 to 0.891 psi/ft for the Utica shale. Based on the pressure transient analysis, the pore\npressure ranges from 3,238 psi to 4,064 psi, contributing to a pore pressure gradient of 0.486 to 0.616\npsi/ft for the Utica shale. Additionally, field wide ranges of reservoirs properties are presented, allowing"}


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topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4eb88-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 0, "chroma:document": "industry to further optimize their drilling and fracing techniques in the Utica shale. Two of the wells in this\nstudy are close in proximity and show very similar results both in After-Closure analysis and in pressure\nresponse curves. The third well displays a different GdP/dG response, leak off characteristics, pressureDownloaded from http://onepetro.org/SPEATCE/proceedings-pdf/20ATCE/2-20ATCE/D022S061R029/2371481/spe-201413-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4ec00-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 1, "chroma:document": "2 SPE-201413-MS\ntransient behaviors, formation permeability, and fracture geometry. This variance in results can be attributed\nto regional differences in geology, stresses, and pressures. Therefore, operators need to consider regional\ndifferences in reservoir properties in order to enhance the development of Utica shale and unlock all potential\nrecoverable hydrocarbons.\nIntroduction\nSince 2010, hydrocarbon production from long horizontal wells targeting shales has become the norm for\nindustry leaders. Because of the steep decline rates, it is vital to understand the reservoir and its properties\nbefore going through with a full-scale fracture stimulation. Through the application of Diagnostic Fracture\nInjection Tests (DFIT), one can determine accurate estimates of closure pressure, net pressure, pore pressure,\nformation permeability, and induced fracture geometry. The Utica shale is among the most promising"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4ec78-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 1, "chroma:document": "reservoirs of the future, but there is limited information available discussing its properties. In SPE-196149-\nMS, we analyzed a DFIT from one horizontal well targeting the Utica. However, in order to fully understand\nthe Utica shale at scale, further analysis is required. In this study, we will present three additional horizontal\nwells targeting the Utica, and analyze the pressure and its derivative to accurately estimate the properties\nmentioned above.\nGeological Overview of Utica Shale\nUnderlying many parts of the Northeast United States lies a vast, organic rich laminated shale that spans an\napproximate 115 square miles. Upper Ordovician in age, the Utica shale was deposited in the Appalachian\nbasin around 450 million years ago. The play has thickness ranging from less than 100 feet to over 500 feet\nand depths ranging from 14,000 feet to just 2,000 feet below sea level. Outcrops of the Utica can even be"}


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topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4ecfa-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 1, "chroma:document": "observed in Quebec; however, this area is far outside of the producing zone. All of the major rock units in\nthe Appalachian basin follow the same basic trend: thickness and depth to the southeast, while progressively\nthinning and uplifting with northwestward progression.\nCreated by some 1,182 wells logs, Figure 1 illustrates the stratigraphic nature of the Utica shale. The\nmajority of drilling activity has occurred in eastern Ohio for two main reasons: the Utica is at optimal depth\nranging from 6,000 ft - 9,000 ft and it's home to the wet gas/condensate region. Additionally, the Marcellus\noverlies the Utica in this area and the existing wellbores can serve as a re-entry point to the shallower target\nafter the Utica wells become uneconomic. The oil window resides to the west of the production wells in\nFigure 1  and corresponds with GOR's of less than 10,000 scf/bbl. Conversely, the gas window resides to\nthe east of the production wells and corresponds with GOR's greater than 10,000 scf/bbl. The three defined"}


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topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4ed7c-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 1, "chroma:document": "hydrocarbon windows in the Utica can be defined by vitrinite reflectance (Ro), which is directly related\nto thermal maturity. The oil window has Ro values between 0.6% and 1.1% while the dry gas window\nhas values between 1.4% and 3.2%. A Ro value above or below these ranges suggests that no producible\nhydrocarbons exist in that interval. Because the Utica is Ordovician in age, the vitrinite reflectance is\ncalculated from bitumen and conodont reflectance data (U.S. Energy Information Administration, 2017 ).\nConodonts are microfossils of small marine animals that lived from the Cambrian through Triassic periods.\nThese tiny, eel like animals are most frequently found in marine sedimentary rocks. When the surrounding\nrock is heated, the color of the conodonts change from light to dark. This is known as the conodont alteration\nindex or CAI. Because the change in color is irreversible, studying conodonts is a great way to determine"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4ee76-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 1, "chroma:document": "the maximum temperature a rock has endured. Oil generation is associated with a CAI range from 1 to 2\nand anything greater is likely to be gas dominated. Similar to vitrinite reflectance, the western Utica has\nCAI values between 1 and 2 while the eastern portion has values greater than 2.5.Downloaded from http://onepetro.org/SPEATCE/proceedings-pdf/20ATCE/2-20ATCE/D022S061R029/2371481/spe-201413-ms.pdf/1 by University of Houston user on 27 October 2023"}


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topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4ef02-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 2, "chroma:document": "SPE-201413-MS 3\nFigure 1\u2014Structure map of the Utica formation ( U.S. Energy Information Administration, 2017).\nThe Utica was deposited on a carbonate shelf in a shallow marine environment, experiencing frequent\nalgal blooms and storms. Fossils suggest that the depositional environment was shallow, well oxygenated,\nand exposed to sunlight (West Virginia Geological and Economic Survey, 2020). However, due to the\ndominant presence of amorphinite in Utica cores, the region must have gone through seasonal anoxic periods\nin which dissolved oxygen in the sea plummeted and marine algae flourished. Interestingly enough, areas\nwith high organic material deposition had similar water depths to areas with low organic material deposition.\nThis was likely due to small moving currents and erosional surfaces created by storms throughout the region\n(U.S. Energy Information Administration, 2017 ).\nThe Utica has an average total organic content (TOC) of about 3.5% and an average carbonate content"}


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topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4ef7a-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 2, "chroma:document": "of 25%. Due to the low carbonate content and high clay content, fracturing the Utica proves difficult. In\nreality, the majority of wells drilled in eastern Ohio are actually targeting the underlying Point Pleasant\nformation. The Lower Point Pleasant has an average TOC around 4.5% and has a much higher carbonate\ncontent of 40%-60%, making it a more productive and much easier rock to induce fractures (West Virginia\nGeological and Economic Survey, 2020 ).\nGenerally speaking, Gamma Ray (GR) and TOC are directly related when plotted against each other.\nOrdovician shales are unique in the sense that they do not follow this trend. The gamma ray values from these\nshales correlate almost exactly with carbonate content instead of TOC, unlike the overlying Marcellus shale.\nThe implications of this unique characteristic can be hugely beneficial to operators in the region if analyzed\ncorrectly. Because carbonate rich rocks are more brittle, they respond better to hydraulic fracturing. From"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4effc-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 2, "chroma:document": "Figure 2 , it seems that the Lexington/Trenton Formation may be the best target in this organic rich interval\ndue to the high carbonate and TOC content. However, the presence of clay particles creates matrix porosity,\nso the optimal target here is the lower organic rich member of the Point Pleasant Formation. In general, there\nis an increasing carbonate content and a decreasing clay content with depth in this organic rich interval.Downloaded from http://onepetro.org/SPEATCE/proceedings-pdf/20ATCE/2-20ATCE/D022S061R029/2371481/spe-201413-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4f074-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 3, "chroma:document": "4 SPE-201413-MS\nFigure 2\u2014GR log, carbonate content and TOC from the Eichelberger No. 1,\nAshland County, Ohio ( West Virginia Geological and Economic Survey, 2020).\nHigh in both calcite and clay content, the Utica shale is an extremely tight reservoir. With an average\npermeability range of 0.00008 to 0.003 mD and an average porosity range of 3.7% to 6%, data analyzation is\nparamount in the pursuit to unlock untapped reserves in the Utica shale. Through the utilization of diagnostic\nfracture injection tests, this goal can be achieved.\nDFIT Theory and Methods\nDiagnostic fracture injection tests (DFITs) have been referred to as a number of different names including\nfracture calibration tests, mini-frac tests, and injection fall-off tests. The test involves pumping a small\namount of fluid down a cased and perforated wellbore at a constant rate to induce a small fracture in the\nnear wellbore region. The well is then shut in and the pressure transient data is analyzed to obtain reservoir"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4f0f6-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 3, "chroma:document": "properties and in situ stresses. Historically, DFITs were conducted to estimate frac design parameters such as\nleak off coefficient, fluid efficiencies, and minimum principal stress. In recent years, it has become possible\nto predict reservoir pore pressure, permeability, and fracture geometry through numerical simulation. DFITs\nlend countless advantages, which allow the industry to have a more comprehensive understanding of the\nreservoir before continuing with a full-scale frac stimulation.\nFigure 3  illustrates an idealized version of what a typical DFIT pressure as a function of injection rate\nwould look like. The bottom hole pressure increases linearly until the leak off pressure (LOP) and is usually\nassociated with a slope change, meaning a small fracture has been induced in the near wellbore rock matrix.\nThe formation fully fractures at the formation breakdown pressure and the fractures propagate at the fracture"}


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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 3, "chroma:document": "propagation pressure until injection ceases. The well is then shut in and the pressure drops to the ISIP due\nto the loss of friction in the wellbore and in the newly induced fractures. The bottom hole pressure will then\ndecline into a linear and then into a radial flow regime. The closure pressure, which is defined by whenDownloaded from http://onepetro.org/SPEATCE/proceedings-pdf/20ATCE/2-20ATCE/D022S061R029/2371481/spe-201413-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4f1e6-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 4, "chroma:document": "SPE-201413-MS 5\nthe planes of the newly induced fracture come into contact, is a proxy for minimum in situ stress and is\nestimated by the variable compliance method on a GdP/dG vs. G-time graph. It should be noted that it could\ntake months after a DFIT test for a well to exhibit a radial flow regime, which makes estimation of reservoir\npore pressure difficult.\nFigure 3\u2014Typical DFIT test data plotted with pressure vs. time ( Wang and Sharma, 2017).\nDFIT pressure data is generally split into two distinct groups: Before-Closure data (BC) and After-\nClosure data (AC), separated by the fracture closure pressure. Before-Closure data is used to estimate leak\noff and fracture geometry, assuming normal leak off behavior according to Carter's leak off. However,\nCarter's leak off oversimplifies leak off behavior and generally leads to severe over or underestimation\nof the minimum in situ stress. After-Closure data is mainly used to predict formation pore pressure and"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4f25e-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 4, "chroma:document": "permeability. Because only half of the data is being used in each case, the results can be misleading. Attempts\nhave been made in the past to bridge the gap between the two sets of data but the models were based on\nthe fundamentally flawed G-function assumptions. Up until the development of the variable compliance\nmethod, which assumes variable fracture stiffness and pressure dependent leak off, no mathematical model\nwas able to seamlessly integrate both regions of data.\nThe basic mathematical model underlying DFIT analysis contains two important components. The first\ncomponent assumes that the pressure derivative is constant with time throughout the induced entire fracture\nnetwork and is based on the material balance ( Hildebrand and Liang, 2019). Through derivation, it is found\nthat the leak off rate is proportional to the pressure derivative with respect to time. The second component,\nwhich is in a similar form to 1D diffusivity equation with constant pressure boundaries, is the Carter Leak"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4f2e0-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 4, "chroma:document": "Off Theory (Hildebrand and Liang, 2019). The Carter Leak Off Theory suggests that the leak off rate is\nproportional to the inverse of the square root of time, and assumes that the single-phase fluid in the fracture\nand in the formation are identical (Howard and Fast, 1957). Carter Leak Off Theory also assumes that fluid\npressure in the fracture is constant over time and that spurt loss is neglected ( Hildebrand and Liang, 2019).\nWith the integration of these two components, the basic mathematical model underlying DFIT analysis can\nbe written asDownloaded from http://onepetro.org/SPEATCE/proceedings-pdf/20ATCE/2-20ATCE/D022S061R029/2371481/spe-201413-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4f362-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 5, "chroma:document": "6 SPE-201413-MS\n(1)\nwhere \u0394 P is the change in pressure after shut-in time, C is a constant that relates to comprehensive\ncompressibility and the leak off coefficient, \u0394t is the change in time after shut-in, A is the fracture surface\narea and Sf is the fracture stiffness/compliance. The basic mathematical model assumes that the fracture is\nformed at the time of shut-in and that the fracture stiffness Sf stays constant before fracture closure, varying\nonce the fracture walls initially come into contact. Consequently, the closure pressure is picked at the point\non the plot where pressure as a function of the square root of \u0394t first deviates from linearity. However,\nbecause of the underlying assumptions in the basic mathematical model, correct identification of closure\npressure by this method is not feasible.\nIn the following years, Nolte (1986a, 1986b , 1979 ) modified the leak off equation by assuming the"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4f3e4-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 5, "chroma:document": "fractures form over a period of time instead of instantaneously at the time of shut in. Still used today for\nanalysis, the model is known as the G-function. Assuming power law fracture growth, negligible spurt loss,\nconstant fracture stiffness, constant fracture surface after shut in, and Carter Leak Off Theory, Nolte was\nable to provide an equation for fracture pressure as a function of dimensionless time and can be written as\n(2)\nwhere P is the pressure in the fracture, ISIP is the instantaneous shut-in pressure, CL is Carter's leak\noff coefficient that is a constant, te is the shut-in time, and G (\u0394tD) is the G-function as a function of a\ndimensionless time \u0394 tD. The dimensionless time \u0394 tD is defined as\n(3)\nThen G-function is defined as the following\n(4)\nFluid efficiency is defined as the ratio of the pumped fluid that is stored in fractures to the total fluid that\nis pumped into the well. High fluid efficiency indicates that more fluid is stored in the fracture due to the"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4f466-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 5, "chroma:document": "low leak off rate, and vice versa.\nFor high fluid efficiency, g (\u0394 tD) is defined by\n(5)\nFor low fluid efficiency, g (\u0394 tD) is defined by\n(6)\nNot long after the development of the G-function, Castillo (1987) began analyzing Nolte's pressure versus\nG-function plot under the assumption of normal leak off behavior (constant Carter leak off coefficient, leak\noff area, and stiffness). Similar to the basic mathematical model, Castillo determined that fracture pressure\nshould scale with G-function linearly before the fracture closure ( Hildebrand and Liang, 2019). As a result,\nhe interpreted the closure pressure should be picked at the point where the pressure first deviates from\nlinearity, and the slope of the line is used to calculate the leak off coefficient CL (Hildebrand and Liang,\n2019 ).\nHowever, when interpreting plots of pressure versus G-function, initial linearity is highly uncommon.\nUsually, these plots contain many points of inflection due to a multitude of factors and identifying a linear"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4f4e8-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 5, "chroma:document": "trend is generally not clear. Due to the ambiguous nature of the straight-line method, correct identification\nof closure pressure is also not feasible. Recognizing the straight line method was unreliable, Barree et al.\n(2009 , 1996 ) developed a new way to estimate closure pressure by the Tangent Line Method. In this method,Downloaded from http://onepetro.org/SPEATCE/proceedings-pdf/20ATCE/2-20ATCE/D022S061R029/2371481/spe-201413-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4f560-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 6, "chroma:document": "SPE-201413-MS 7\nBarree plotted GdP/dG versus G time and determined the closure pressure was the line tangent to the GdP/\ndG curve that also passed through the origin. Integrating this method with Castillo's pressure versus G time\ngraph, estimating the closure pressure became much more consistent. The tangent line method is still a\nwidely accepted method today, however the method has not been scientifically proven, which makes for an\ninteresting research topic (Wang and Sharma, 2017). By taking the derivative of pressure with respect to\nthe G-function of Equation 2, the equation of GdP/dG can be written as\n(7)\nNon-ideal transient behaviors are commonly observed when using the G-function to process field DFIT\ndata, including pressure dependent leak off, fracture tip extension, and height recession/transverse storage\nbehaviors, as depicted in Figure 4 .\nFigure 4\u2014Signatures of non-ideal leak off behaviors (a,b,c) on the G-function plots ( Barree et al., 2009 )."}


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topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4f5e2-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 6, "chroma:document": "Advancing this topic, McClure et al. (2016 , 2014 ) developed the Compliance method to estimate the\nfracture closure pressure at the point on the G-function plot where the trend starts to deviate from its original\nlinearity. Based on the Compliance method, Wang and Sharma (2019, 2018a, 2018b , 2017 ) suggest the\nVariable Compliance method to estimate the fracture closure pressure by addressing that fracture stiffness\ngradually increases as the fracture walls come into contact. As a result, the Variable Compliance method\nidentifies closure pressure at the average G-function time of the Tangent Line and Compliance methods.\nDFIT numerical simulation is an advanced method to estimate matrix permeability and fracture geometry,\nwhich are important to the development of unconventional assets. The DFIT numerical simulation of this\nmanuscript is based on the algorithm by Wang and Sharma (2019, 2018a , 2018b , 2017 )."}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4f664-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 6, "chroma:document": "The differential form of mass balance, with the assumption of 1D leak-off into a semi-infinite formation,\ncan be presented as\n(8)\nWhere Ct is the total compressibility, k is the formation permeability and \u00f8 is the formation porosity. The\nboundary condition of Equation 8 can be written as\n(9)\nThe initial conditions of Equation 8 are written as\n(10)\n(11)\nWhere ISIP is the instantaneous shut-in pressure, Po is the initial reservoir pressure and Sf is the fracture\nstiffness. The net pressure is written asDownloaded from http://onepetro.org/SPEATCE/proceedings-pdf/20ATCE/2-20ATCE/D022S061R029/2371481/spe-201413-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4f6e6-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 7, "chroma:document": "8 SPE-201413-MS\n(12)\nWhere Shmin is the minimum principal stress and wf is the average fracture width. The minimum principal\nstress is assumed to be the closure pressure, and ISIP is estimated by extrapolation in this paper. Pnet and Sf\nare used to evaluate the induced fracture geometry based on expressions in Table 1 , as shown below.\nTable 1\u2014Fracture stiffness by different fracture geometry models (Wang and Sharma, 2017).\nFracture Geometry PKN KGD Radial\nFracture Stiffness\nThe pressure decline and GdP/dG behaviors during DFITs are simulated by Equation 8 with Equation\n9 constraining as the boundary condition; Equation 10 and 11 are governing Equation 8 as the initial\nconditions. One essential feature of this numerical simulation algorithm, which is based on the Variable\nCompliance method, is that this model is able to capture variable fracture stiffness and pressure-dependent\nleak-off during the progressive fracture closure process. The fracture geometry is estimated by Equation\n12 and Table 1 ."}


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topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4f768-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 7, "chroma:document": "12 and Table 1 .\nThree DFIT Cases Targeting Utica Shale\nAccurate estimations of closure pressure, pore pressure, and permeability are essential to the successful\ndevelopment of a shale play. However, permeability of shale formations are low, thus interpretation of DFIT\ndata targeting shale formations is challenging. The Utica shale is one of the most promising unconventional\nplays in the United States, but there are not many publications discussing its closure pressure, pore pressure,\nand permeability. In SPE 196149-MS, we presented one set of DFIT data and its related interpretation. Here,\nthree additional DFIT cases are presented to give a comprehensive, field wide estimation of stress regimes\nand reservoir properties of the Utica shale.\nDFITs are performed on Well-A, Well-B, and Well-C with the locations of these three wells shown in\nFigure 5 . They are all horizontal wells with their horizontal intervals all being stimulated by hydraulic"}


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topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4f7ea-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 7, "chroma:document": "fracturing into multiple stages. The TVD and MD for the wells are as follows: 6,600 feet and 12,500 feet\nfor Well-A, 6,200 feet and 9,300 feet for Well-B, and 6,900 feet and 12,600 feet for Well-C. During each\nDFIT, water is injected into the targeted wellbore for approximately 15 minutes at a constant rate of around\n3.5 bbl/min. Figures 6  through 8 display the wellhead pressure and pump rate vs. time for Well-A, Well-\nB, and Well-C, respectively.Downloaded from http://onepetro.org/SPEATCE/proceedings-pdf/20ATCE/2-20ATCE/D022S061R029/2371481/spe-201413-ms.pdf/1 by University of Houston user on 27 October 2023"}


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topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4f8b2-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 8, "chroma:document": "SPE-201413-MS 9\nFigure 5\u2014DFITs targeting the Utica shale were carried out on Well-A, Well-B and Well-C.\nFigure 6\u2014WHP and pump rate vs. time for the DFIT on Well-A.\nFrom Figure 6 , it can be determined that the leak off pressure (LOP), the fracture breakdown pressure\n(FBP), and the fracture propagation pressure (FPP) of Well-A are estimated to be 8,467, 9,126 and 8,938 psi.\nWhen the pump is shut down and the pump rate reads zero, the instantaneous shut-in pressure (ISIP) after\nadding hydrostatic reads 8,206 psi and quickly drops to 7,657 psi after one minute. This significant drop in\nISIP indicates that the friction and the tortuosity inside the wellbore are high and the fracture complexity near\nthe wellbore is significant, therefore the true ISIP is estimated by extrapolation to calculate net pressure andDownloaded from http://onepetro.org/SPEATCE/proceedings-pdf/20ATCE/2-20ATCE/D022S061R029/2371481/spe-201413-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4f948-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 9, "chroma:document": "10 SPE-201413-MS\nanalyze the G-function. At end of the DFIT, the pressure of Well-A drops to 4,762 psi, which is magnified\nin the inserted image. Similarly, Figures 7 and 8 show wellhead pressure and pump rate vs. time for wells B\nand C. Based on the plots, LOP, FBP, FPP, and ISIP are estimated to be 8,121, 8,629, 8,480, and 7,744 psi for\nWell-B, and 7,854, 8,668, 8,642, and 7,926 psi for Well-C. It should be noted that high wellbore tortuosity\nand significant fracture complexity are also observed in Well-B and Well-C due to the significant drop in\npressure after shut-in, therefore the extrapolated ISIPs are applied to the following analysis and simulation.\nFigure 7\u2014WHP and pump rate vs. time for the DFIT on Well-B.\nFigure 8\u2014WHP and pump rate vs. time for the DFIT on Well-C.\nBased on the field DFIT data from three wells, a plot of pressure and GdP/dG vs. G-function can be\nseen in Figure 9 . There is quite a bit of noise in GdP/dG response after the closure time, represented by"}


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topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4f9ca-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 9, "chroma:document": "the blue line, which is commonly observed in DFIT analysis. The noise in the data is smoothed by the\nButterworth filter with a smoothing coefficient of 0.11, and the filtered data is represented by the red line.\nThe G-functions of wells A and C experience a similar trend, while well B does not. Further analysis on\nthese trends is explained with the simulation results.Downloaded from http://onepetro.org/SPEATCE/proceedings-pdf/20ATCE/2-20ATCE/D022S061R029/2371481/spe-201413-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4fa56-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 10, "chroma:document": "SPE-201413-MS 11\nFigure 9\u2014G-function plots for Wells A, B, and C, respectively.\nFigures 10  through 12 show closure pressure determination by the Tangent Line method, the Compliance\nmethod, and the Variable Compliance method for the three wells, as depicted by red, blue and turquoise\ndotes, respectively. The Compliance method suggests that fracture closure pressure is determined when\nGdP/dG response starts to deviate from expected linearity, and the Variable Compliance method is an\naverage result of the Tangent Line method and the Compliance method. Therefore, the Compliance method\nshows an upper bound while the Tangent Line method suggests a lower bound of closure pressure estimation.\nAs shown in Figure 10 , the closure pressure by the Tangent Line method for Well-A is estimated to be\n5,690 psi, contributing to a stress gradient of 0.862 psi/ft; 6,125 psi with 0.928 psi/ft by the Compliance\nmethod, and 5,973 psi with 0.905 psi/ft by the Variable Compliance method. As shown above, the true ISIP"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4fad8-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 10, "chroma:document": "is extrapolated to 6,300 psi when the square root of time reaches to zero, compared to the estimated ISIP\nof 8,206 psi from the pump schedule presented above. A net pressure of 327 psi is determined and applied\nto the fracture geometry estimation, which is discussed in the following simulation section. As a result, the\nWell-A DFIT analysis estimates that the closure pressure ranges from 5,690 psi to 6,125 psi, contributing\nto the stress gradient of 0.862 \u2013 0.928 psi/ft in this area.\nFigure 10\u2014Closure pressure determination by the Tangent, the Compliance\nand the Variable Compliance methods using the filtered Well-A DFIT data.Downloaded from http://onepetro.org/SPEATCE/proceedings-pdf/20ATCE/2-20ATCE/D022S061R029/2371481/spe-201413-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4fb5a-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 11, "chroma:document": "12 SPE-201413-MS\nFigure 11\u2014Closure pressure determination by the Tangent, the Compliance\nand the Variable Compliance methods using the filtered Well-B DFIT data.\nFigure 12\u2014Closure pressure determination by the Tangent, the Compliance\nand the Variable Compliance methods using the filtered Well-C DFIT data.\nFigure 11  demonstrates the closure pressure by the Tangent Line method for Well-B is estimated to be\n4,692 psi, contributing to a stress gradient of 0.757 psi/ft; 5,154 psi with 0.831 psi/ft by the Compliance\nmethod, and 4,943 psi with 0.797 psi/ft by the Variable Compliance method. The true ISIP is extrapolated\nto 5,700 psi when the square root of time reaches to zero, compared to the estimated ISIP of 7,744 psi from\nthe pump schedule. A net pressure of 757 psi is determined and applied to the fracture geometry estimation.Downloaded from http://onepetro.org/SPEATCE/proceedings-pdf/20ATCE/2-20ATCE/D022S061R029/2371481/spe-201413-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4fbdc-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 12, "chroma:document": "SPE-201413-MS 13\nAs a result, the Well-B DFIT analysis estimates that the closure pressure ranges from 4,692 psi to 5,154 psi,\ncontributing to the stress gradient of 0.757 \u2013 0.831 psi/ft in this area.\nFigure 12  presents the closure pressure by the Tangent Line method for Well-C is estimated to be 5,662\npsi, contributing to a stress gradient of 0.821 psi/ft; 6,416 psi with 0.929 psi/ft by the Compliance method,\nand 6,141 psi with 0.891 psi/ft by the Variable Compliance method. The true ISIP is extrapolated to 6,250\npsi when the square root of time reaches to zero, compared to the estimated ISIP of 7,926 psi from the\npump schedule. A net pressure of 109 psi is determined and applied to the fracture geometry estimation. As\na result, the Well-C DFIT analysis estimates that the closure pressure ranges from 5,662 psi to 6,416 psi,\ncontributing to the stress gradient of 0.821 \u2013 0.929 psi/ft in this area. Overall, the closure pressure ranges"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4fc5e-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 12, "chroma:document": "from 4,943 psi to 6,141 psi in the Utica shale, contributing to the closure pressure gradient of 0.797 to 0.891\npsi/ft by the Variable Compliance method.\nA log-log pressure derivative plot vs. shut in time is used in this analysis to verify fracture closure and\nestimate the pore pressure, as shown in Figure 13 . Well-A, Well-B, and Well-C all experience similar after\nclosure-flow patterns: after the pump is shut down, the afterflow rate is greater than the leak-off rate in the\nfracture, causing the fracture to propagate in all directions. This signature is marked by a unit slope in the\nfigures. Once the injected fluid reaches the fracture tip, the fracture is propagating only into its longitude\ndirection and fracture length is increased, signaled by a zero slope. Following that, leak-off phenomenon\nstarts to govern the process, and fractures starts to close progressively. The peaks of the pressure derivative"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4fce0-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 12, "chroma:document": "in the figures clearly indicate that the induced fracture is mechanically closed, verifying the fracture closure\ndetermination in the analysis above. After fracture closure time, reservoir flow starts to dominate the process\nand the pore pressure is estimated by pressure transient analysis. The adjacent reservoir fluid first flows in\nthe induced fracture by a 1D flowing pattern, resulting in a linear flow regime and implied by a slope of\n\u22120.5 on the pressure derivative plot, as shown by the red line in Figure 13. Well-B is a bit unique in the sense\nthat the pressure derivative experiences a significant drop after the peak pressure, and then reaches a linear\nflow regime marked by a \u22120.5 slope, where Well-A and Well-C reach linear flow immediately after the\nderivative peak. This observed signature could indicate that there are natural or secondary fractures existing\nnear Well-B, which is consistent with observations from its G-Function plot."}


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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 12, "chroma:document": "Figure 13\u2014Before-Closure (BC) and After-Closure (AC) analyses by pressure derivative log-log plots for\nWell-A, Well-B and Well-C. Signature of linear flow regime is slope of \u22120.5 after the fracture closure time.\nTo estimate pore pressure, the pressure data in a linear flow regime is regressed linearly in a log-log\nplot of pressure vs. the inverse of square root of time, as shown in Figures 14 through 16. In general, pore\npressure by radial flow regime gives an upper bound estimation while linear flow gives a lower bound.\nFigure 14  demonstrates that the pore pressure of Well-A by linear flow regime is estimated to be 28.03 MPa\nor 4,064 psi, contributing to a pore pressure gradient of 0.616 psi/ft. Similarly, Figure 15  shows that the\npore pressure of Well-B by linear flow regime is estimated to be 22.33 MPa or 3,238 psi, contributing to a\npore pressure gradient of 0.522 psi/ft. Figure 16 indicates that the pore pressure of Well-C by linear flow"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4fde4-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 12, "chroma:document": "regime is estimated to be 23.1 MPa or 3,351 psi, contributing to a pore pressure gradient of 0.486 psi/ft.Downloaded from http://onepetro.org/SPEATCE/proceedings-pdf/20ATCE/2-20ATCE/D022S061R029/2371481/spe-201413-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4fe66-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 13, "chroma:document": "14 SPE-201413-MS\nAs a result, the pore pressure ranges from 3,238 psi to 4,064 psi, contributing to a pore pressure gradient\nof 0.486 to 0.616 psi/ft for the Utica shale.\nFigure 14\u2014Pore pressure of Well-A is estimated by pressure transient analysis.\nFigure 15\u2014Pore pressure of Well-B is estimated by pressure transient analysis.Downloaded from http://onepetro.org/SPEATCE/proceedings-pdf/20ATCE/2-20ATCE/D022S061R029/2371481/spe-201413-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4fed4-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 14, "chroma:document": "SPE-201413-MS 15\nFigure 16\u2014Pore pressure of Well-C is estimated by pressure transient analysis.\nBy inputting the rock properties and fracture parameters into the simulator developed by Wang and\nSharma (2019 , 2018a , 2018b, 2017 ), DFIT numerical simulations are performed to match the historical\npressure and GdP/dG data for DFITs from Well-A, Well-B, and Well-C. The input parameters include\nporosity, viscosity, Poisson's ratio, injection volume, total compressibility, Young's modulus, and wellbore\nstorage coefficient. Figures 17 to 19 demonstrate that the simulated pressures and derivatives match with the\nfield DFIT data well. It should be noted that although the shape of the simulated results may not be exactly\nthe same, the most important aspect is making sure that the peaks of the GdP/dG (blue) and simulated\nresults (red) agree. This will validate that the closure pressure and permeability are accurate estimates. The"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4ff42-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 14, "chroma:document": "simulated reservoir permeability for Well-A is 0.000041 mD, 0.002 mD for Well-B, and 0.000025 mD\nfor Well-C. The fracture geometry simulation is performed based on the material balance, the net pressure\ncalculation by Equation 12, and the fracture geometry calculation from Table 1 . With an assumption of a 50-\nfoot fracture height, the simulation results of fracture geometry are summarized in Table 2 . It should be noted\nthat the simulation results are consistent with the estimations from our reservoir and petrophysics studies.\nFigure 17\u2014Numerical simulation and history match of pressure and pressure derivative for Well-A DFIT data.Downloaded from http://onepetro.org/SPEATCE/proceedings-pdf/20ATCE/2-20ATCE/D022S061R029/2371481/spe-201413-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae4ffba-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 15, "chroma:document": "16 SPE-201413-MS\nFigure 18\u2014Numerical simulation and history match of pressure and pressure derivative for Well-B DFIT data.\nFigure 19\u2014Numerical simulation and history match of pressure and pressure derivative for Well-C DFIT data.\nTable 2\u2014Fracture length and width with different fracture geometries.\nWell A Well B Well C\nFracture Geometry Radial PKN Radial PKN Radial PKN\nEstimated Frac\nLength (ft)72.95 263.62 50.87 89.39 82.43 380.3\nFracture\nAverage Width\nat Shut-in (ft)0.01406 0.00891 0.02165 0.01969 0.00736 0.00413Downloaded from http://onepetro.org/SPEATCE/proceedings-pdf/20ATCE/2-20ATCE/D022S061R029/2371481/spe-201413-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae50028-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 16, "chroma:document": "SPE-201413-MS 17\nThe G-function signatures of these DFITs, as depicted in Figure 9, are insightful. At the very beginning\nof the shut-in time, a minor hump in GdP/dG in Well-A and Well-C is seen, corresponding to an accelerated\nand considerable pressure drop. As discussed above, these wells are long horizontal wells and this minor\nGdP/dG hump results from wellbore tortuosity and fracture complexity. Therefore, it should be excluded\nfrom the closure pressure determination. After that, a major hump in GdP/dG appears and follows a\nclassic concave-up trend, which is a characteristic signature of pressure-loss-acceleration. Indicating that\nthe induced fracture is closed progressively and, thus closure pressure can be determined by the Compliance\nmethod. Height recession and transverse storage are the two main mechanisms contributing to the pressure-\nloss-acceleration signature. However, they are two different mechanisms from the perspective of physics."}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae500aa-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 16, "chroma:document": "Height recession occurs when the induced fracture grows into overlying and/or underlying formations\nduring a DFIT, causing increasing stiffness and thus accelerating pressure drop rate. Transverse storage takes\nplace when fluid, expelled from transverse fractures due to fracture closure, enters into the induced fracture,\nand contributes to the increasing leak-off rate and accelerated GdP/dG. Besides these two mechanisms,\nMcClure (2016 , 2014 ) states that fracture closure is a dynamic process, and the concave upward trend is\nactually an indication that two fracture planes come into contact and stiffness is therefore increased. It is\ndifficult to confirm which mechanism is dominating without further supporting data, but the methodology to\ndetermine the closure pressure of a concave-up trend is consistent. On the contrary, Well-B does not display\na hump at the beginning of shit in time. Instead, we observe a consistent concave down trend throughout the"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae50136-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 16, "chroma:document": "test. This is a typical signature of pressure dependent leak off in a naturally fractured formation and generally\noccurs in a dual porosity system when the fluid loss rate varies with the pressure dependent permeability. The\npotential existence of secondary fractures near Well-B is also verified by the pressure derivative analysis, as\nshown in Figure 13 . It is common to observe a signature of tip extension in DFIT targeting shale formations,\nwhich usually leads to a questionable estimation of closure pressure. However, the DFIT results presented\nin this paper do not show characteristics of tip-extension, which is an indication of productive shale quality.\nAs seen from the simulated fracture geometries in Table 2 , we again see similarities between wells A\nand C. In both radial and PKN geometry, the fractures exhibit the similar lengths and widths. These two\nwells are very close in proximity to each other and share similar depths, so it's physically meaningful that"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae501ae-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 16, "chroma:document": "these two wells experience similar results. Well-B is located further north on the trend and the results from\nthis study show that the differences in DFIT behaviors and simulation, including GdP/dG response, leak off\ncharacteristics, pressure transient behaviors, formation permeability, and frac geometries, can be attributed\nto regional geology, stresses, and pressures. Therefore, operators need to consider regional differences in\nreservoir properties in order to enhance the development of the Utica and unlock all potential producible\nhydrocarbons.\nConclusion\nThe objective of this study was to continue analysis on the Utica shale and its properties through multiple\nDFITs across the extent of the play. In this study, we presented three additional wells to perform analysis\nand determined field wide ranges of closure pressure, pore pressure, net pressure, formation permeability,\nand fracture geometry. In this study, we first gave a geological overview of the Utica shale, then explained"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae50226-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 16, "chroma:document": "the theories and methods behind DFITs, and finally presented a field wide range of reservoir characteristics\nand properties. The results from this study are encouraging and insightful, showing that there are regional\ndifferences across the shale and can be identified through the application of DFITs. The knowledge resulting\nfrom this study indefinitely creates value for the industry in the pursuit of unlocking hydrocarbons in the\nUtica shale. The analysis and results from this study provide the following conclusions:\n\u2022As observed by all three wells, the sharp breakdown of pressure after shut in indicates that the\nfriction and the tortuosity inside the wellbores are high, and the fracture complexity near the\nwellbore is significant for horizontal wells and the Utica shale.Downloaded from http://onepetro.org/SPEATCE/proceedings-pdf/20ATCE/2-20ATCE/D022S061R029/2371481/spe-201413-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae5029e-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 17, "chroma:document": "18 SPE-201413-MS\n\u2022Interpreting the GdP/dG data by the Variable Compliance Method, the closure pressure ranges\nfrom 4,943 psi to 6,141 psi in the Utica shale, contributing to a closure pressure gradient of 0.797\nto 0.891 psi/ft.\n\u2022Calculating based on the closure stress and ISIP, the net pressure in the fractures from wells A, B,\nand C are 327, 757, and 109 psi, respectively.\n\u2022Based on G-function analysis, Wells A and C follow a classic concave-up trend, which is a\ncharacteristic signature of pressure-loss-acceleration, indicating that the induced fracture is closed\nprogressively. Well-B displays a consistent concave down trend, which is a typical signature of\npressure dependent leak off in a naturally fractured formation and generally occurs in a dual\nporosity system when the fluid loss rate varies with the pressure dependent permeability. This\nobservation is consistent with the pressure derivative analysis.\n\u2022On the log-log plots of pressure derivative, Well-A, Well-B, and Well-C experience similar After-"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae50320-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 17, "chroma:document": "Closure flow patterns in general. The sharp decline in pressure derivative on the log-log plot after\nits peak indicate that there are natural and secondary fractures near Well-B. This observation is\nconsistent with the G-function analysis.\n\u2022From the linearly regressed log-log plot of pressure vs. the inverse of square root of time, the pore\npressure ranges from 3,238 psi to 4,064 psi, contributing to a pore pressure gradient of 0.486 to\n0.616 psi/ft for the Utica shale.\n\u2022Through numerical simulation, the formation permeability for Well-A is 0.000041 mD and\n0.000025 mD for Well-C. The numerical simulation shows that the formation permeability for\nWell-B is 0.002 mD, which is higher than Well-A and Well-C.\n\u2022Wells A and C show similar fracture geometries with an average frac length of 77.69 feet and width\nof 0.01071 feet in radial geometry, and an average frac length of 321.96 feet and width of 0.01304\nfeet in PKN geometry. For Well-B, the frac length is estimated 50.87 feet in radial geometry and"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae50398-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 17, "chroma:document": "89.39 feet in PKN geometry. The difference in fracture geometry indicates that Wells A and C are\nlocated in an area where induced fractures tend to propagate into longitude direction.\n\u2022As shown above, Wells A and C are very close in proximity and thus they display similar DFIT\nresults and reservoir properties. Well-B is well north of wells A and C, and it shows different\nGdP/dG response, leak off characteristics, pressure transient behaviors, formation permeability,\nand frac geometries. This variance can be attributed to regional differences in geology, stresses,\nand pressures.\nAcknowledgment\nThe authors wish to thank Dr. Mukul Sharma and Dr. Hanyi Wang for their continued support and guidance.\nNomenclature\nASurface area of fracture\nCA constant relevant to leak off coefficient and comprehensive compressibility\nCAI Conodont alteration index\nCLCarter's leak off coefficient\nCtTotal compressibility\nE\u2019Plane strain for Young's Modulus\nGR Gamma ray\nGOR Gas Oil Ratio\nhfFracture height"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae5041a-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 17, "chroma:document": "GR Gamma ray\nGOR Gas Oil Ratio\nhfFracture height\nISIP Instantaneous shut-in pressure\nkFormation permeabilityDownloaded from http://onepetro.org/SPEATCE/proceedings-pdf/20ATCE/2-20ATCE/D022S061R029/2371481/spe-201413-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae5049c-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 18, "chroma:document": "SPE-201413-MS 19\nLOP Leak off pressure\nPPressure in fracture\nPoInitial reservoir pressure\nPnetNet pressure\nRfFracture radius\nRoVitrinite reflectance\nSfFracture stiffness\nShminMinimum principal stress\nteShut-in time\nTOC Total organic content\nwfAverage fracture width\nxfFracture half-length\n\u0394PPressure difference after shut-in\n\u0394tTime difference after shut-in\n\u2206tDDimensionless time that is discussed in Equation 3\n\u03d5Formation porosity\nReference\nBarree, R.D.,  Barree, V .L.,  Craig, D., 2009 . Holistic Fracture Diagnostics: Consistent Interpretation of Prefrac Injection\nTests Using Multiple Analysis Methods. SPE-107877-PA 24, 396\u2013406. https://doi.org/10.2118/107877-PA\nBarree, R.D.,  Mukherjee, H., 1996 . Determination of Pressure Dependent Leakoff and Its Effect on Fracture Geometry, in:\nSPE-36424-MS. Presented at the SPE Annual Technical Conference and Exhibition, Society of Petroleum Engineers,\nSPE, p. 10. https://doi.org/10.2118/36424-MS"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae50528-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 18, "chroma:document": "SPE, p. 10. https://doi.org/10.2118/36424-MS\nCastillo, J.L.,  1987 . Modified Fracture Pressure Decline Analysis Including Pressure-Dependent Leakoff, in: SPE-16417-\nMS. Presented at the Low Permeability Reservoirs Symposium, Society of Petroleum Engineers , SPE, p. 9. https://\ndoi.org/10.2118/16417-MS\nHildebrand, J.Jr.,  Liang, Y .,  2019 . DFIT Analysis and Simulation in Shale Formations: A Utica Case Study, in:\nSPE-196149-MS. Presented at the SPE Annual Technical Conference and Exhibition, Society of Petroleum Engineers ,\nSPE, p. 20. https://doi.org/10.2118/196149-MS\nHoward, G.C., Fast, C.R., 1957 . Optimum Fluid Characteristics for Fracture Extension, in: API-57-261. Presented at the\nDrilling and Production Practice, American Petroleum Institute, API, p. 10.\nMcClure, M.W.,  Blyton, C.A.J., Jung, H., Sharma, M.M., 2014 . The Effect of Changing Fracture Compliance on Pressure\nTransient Behavior During Diagnostic Fracture Injection Tests, in: SPE-170956-MS. Presented at the SPE Annual"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae505aa-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 18, "chroma:document": "Technical Conference and Exhibition, Society of Petroleum Engineers, SPE, p. 23. https://doi.org/10.2118/170956-MS\nMcClure, M.W.,  Jung, H.,  Cramer, D.D., Sharma, M.M., 2016 . The Fracture-Compliance Method for Picking Closure\nPressure From Diagnostic Fracture-Injection Tests (see associated supplementary discussion/reply) . SPE-179725-PA\n21, 1321 \u20131339 . https://doi.org/10.2118/179725-PA\nNolte, K.G.,  1986a . Determination of Proppant and Fluid Schedules From Fracturing-Pressure Decline. SPE-13278-PA\n1, 255\u2013265. https://doi.org/10.2118/13278-PA\nNolte, K.G., 1986b . A General Analysis of Fracturing Pressure Decline With Application to Three Models . SPE-12941-\nPA 1, 571\u2013583. https://doi.org/10.2118/12941-PA\nNolte, K.G.,  1979 . Determination Of Fracture Parameters From Fracturing Pressure Decline, in: SPE-8341-MS. Presented\nat the SPE Annual Technical Conference and Exhibition, Society of Petroleum Engineers, SPE, p. 16. https://\ndoi.org/10.2118/8341-MS"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae5062c-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 18, "chroma:document": "doi.org/10.2118/8341-MS\nU.S. Energy Information Administration, 2017 . Utica Shale Play Geology Review.\nWang, H.,  Sharma, M.M.,  2019 . A Novel Approach for Estimating Formation Permeability and Revisit After-Closure\nAnalysis from DFIT, in: SPE-194344-MS. Presented at the SPE Hydraulic Fracturing Technology Conference and\nExhibition, Society of Petroleum Engineers, SPE, p. 32. https://doi.org/10.2118/194344-MS\nWang, HanYi,  Sharma, M.M., 2018a. Estimating Unpropped Fracture Conductivity and Compliance from Diagnostic\nFracture Injection Tests, in: SPE-189844-MS. Presented at the SPE Hydraulic Fracturing Technology Conference and\nExhibition, Society of Petroleum Engineers, SPE, p. 28. https://doi.org/10.2118/189844-MSDownloaded from http://onepetro.org/SPEATCE/proceedings-pdf/20ATCE/2-20ATCE/D022S061R029/2371481/spe-201413-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae506ae-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-201413-ms.pdf", "page": 19, "chroma:document": "20 SPE-201413-MS\nWang, Hanyi,  Sharma, M.M.,  2018b . Estimating Fracture Closure Stress in Naturally Fractured Reservoirs With\nDiagnostic Fracture Injection Tests, in: ARMA-2018-225. Presented at the 52nd U.S. Rock Mechanics/Geomechanics\nSymposium, American Rock Mechanics Association, ARMA, p. 12.\nWang, H.,  Sharma, M.M.,  2017 . New Variable Compliance Method for Estimating In-Situ Stress and Leak-Off from DFIT\nData , in: SPE-187348-MS. Presented at the SPE Annual Technical Conference and Exhibition, Society of Petroleum\nEngineers , SPE, p. 40. https://doi.org/10.2118/187348-MS\nWest Virginia Geological and Economic Survey, 2020 . A Geologic Play Book for Utica Shale Appalachian Basin\nExploration [WWW Document] . URL http://www.wvgs.wvnet.edu/utica/playbook/index.aspx (accessed 8.2.20).Downloaded from http://onepetro.org/SPEATCE/proceedings-pdf/20ATCE/2-20ATCE/D022S061R029/2371481/spe-201413-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae50726-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 0, "chroma:document": "SPE-199690-MS\nDFIT Analysis and Interpretation in Layered Rocks\nShuang Zheng, Ripudaman Manchanda, HanYi Wang, and Mukul Sharma, The University of Texas at Austin\nCopyright 2020, Society of Petroleum Engineers\nThis paper was prepared for presentation at the SPE Hydraulic Fracturing Technology Conference and Exhibition held in The Woodlands, Texas, USA, 4-6 February\n2020.\nThis paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents\nof the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect\nany position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae50794-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 0, "chroma:document": "consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may\nnot be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.\nAbstract\nDiagnostic fracture injection tests (DFITs) are often used to estimate formation properties such as closure\nstress, pore pressure, and matrix permeability. These estimations are typically based on analysis of pressure\ndata assuming the closure of simple planar fractures in homogeneous reservoirs. These interpretations\nare incorrect when dealing with complex reservoir environments such as layered reservoirs with different\nproperties and stresses. This paper investigates the impact of such complex environments on DFIT\ninterpretation and presents a systematic method to analyze the data.\nA 3-D implicitly integrated poroelastic fracture-reservoir-wellbore model is used to simulate DFITs."}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae5080c-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 0, "chroma:document": "DFIT fracture propagation and well shut-in are simulated with implicitly computed fluid leak-off and\nfracture closure. The model is validated by simulating a DFIT for a homogeneous reservoir and the implicitly\ncalculated surface pressure is interpreted to obtain the simulation inputs (stress, pore pressure, permeability,\netc.). A multi-layer reservoir model is then built in the numerical simulation domain and a DFIT is simulated\nin the target layer. The properties and thickness of the layers are varied to analyze their impact on the\nobserved DFIT signature.\nWe analyze the impact of layer thicknesses, layer stresses, pressure and permeability of each layer, stress\ncontrast between the layers, fracture interaction with bedding planes and the rock roughness and hardness\nof each layer on the DFIT pressure signature. We show that the layer property variations can cause different\nbut characteristic DFIT pressure responses. Fracture propagation into layers with different stresses induces"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 0, "chroma:document": "multiple closure events in the observed pressure signature, which provides a quantitative representation of\nthe fracture height growth. The emergence of these closure events in the pressure signature are found to be\ndependent on the hardness and modulus of the rock layers and the fluid communication between the closing\nparts of the fracture. The DFIT signature patterns are also found to correlate with the interaction of the\nfracture with bedding planes (cross/arrest/divert) and provide valuable insights into fracture containment.\nIn this work we present best practices for performing DFIT analysis in layered reservoirs. Results from\nsimulated DFITs in layered reservoirs clearly show the effect of key heterogeneity parameters on DFIT\nresponses. The results from this work can be used to more accurately determine reservoir closure stress,\npore pressure, reservoir permeability, fracture compliance, fracture conductivity, and fracture containment"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae50906-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 0, "chroma:document": "in heterogeneous reservoirs.Downloaded from http://onepetro.org/SPEHFTC/proceedings-pdf/20HFTC/2-20HFTC/D022S016R001/2428479/spe-199690-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae50988-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 1, "chroma:document": "2 SPE-199690-MS\nIntroduction\nThe technology of multi-stage hydraulic fracturing in horizontal wells plays a key role in creating highly\nconductive flow channels connecting the wellbore with ultra-tight formations and this has led to the shale\nrevolution in North America. Diagonostic Fracture Injection Test (DFIT) has been an efficient method for\ndetermining formation properties, for example, fracture closure stress and pore pressure. A DFIT is usually\nperformed on a vertical data well or after the horizontal well is drilled and cemented and before the main\nhydraulic fracturing treatments start. A small amount of water is injected at low rate aiming to create a\nfracture and then the well is shut-in for several days while the pressure is recorded. During the shut-in, water\ngradually leaks into the reservoir and the fracture gradually closes. The fracture closure stress and pore\npressure can then be inferred from the closure and post-closure pressure data. Both analytical approaches"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae50a0a-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 1, "chroma:document": "(summarized in the Appendix) and numerical approaches (e.g., Zheng et al., 2019b; Zheng et al., 2019g; Ji\net al., 2019 ; Kamali and Ghassemi, 2019 ) have been developed for DFIT data interpretation.\nPrevious researchers have mainly focused on DFIT interpretations and simulations assuming a planar\nfracture geometry in a homogeneous reservoir, however, it is not uncommon for the fracture that is\ncreated to intersect several layers with different stress and mechanical/flow properties. This can have a\nbig impact on the DFIT signature since the mechanical properties (rock Young's modulus, Poisson's ratio,\nfracture touchness, rock surface roughness, stress state) and the flow properties (permeability, porosity, pore\npressure) may vary a lot between different layers. Bedding planes are commonly seen in shale formations.\nDuring a DFIT, bedding planes may be connected and opened by the hydraulic frcature and the hydraulic"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae50a82-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 1, "chroma:document": "fracture may be arrested by the bedding planes or cross them and propagate further ( Tang and Wu, 2018).\nDFIT fractures interacting with bedding planes will significantly impact the final fracture geometry and\nleakoff rate during shut-in, and thus influence the pressure response (Wang and Sharma, 2019b). Very\ncomplicated DFIT pressure signals are commonly observed in field data. For example, a field example of\na G-function plot of the pressure and pressure derivative ( Figure 1) shows multiple humps. However, most\nDFIT interpretations in the past did not take the layer effect into consideration. The traditional analytical\ninterpretation approaches (as summarized in the Appendix) are inadequate in these complicated but real\nscenarios. Other numerical models (e.g. Ji et al., 2019 ; Kamali and Ghassemi, 2019) also fail to capture\nthese complex behaviors due to their inability to model rock heterogeneity.\nFigure 1\u2014Field example case of complex DFIT pressure response ( Zheng et al., 2019g )."}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae50afa-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 1, "chroma:document": "In this paper, we apply our fully integrated reservoir-fracture-wellbore simulator to DFIT simulations.\nThrough the fully integrated fracturing and reservoir simulation, we can for the first time, study the behavior\nof the DFIT pressure response in layered formations. To fully understand the impact of the layer properties\nwe vary different layer properties with the ultimate aim of identifying the key parameters that affect the\nDFIT interpretation. The effect of layer stress contrast, layer permeability, layer thickness, rock asperity\nroughness, rock hardness, bedding planes on the closure stress and pore pressure estimation are clearly\nshown. Many of these factors are found to have a significant impact on the DFIT analysis. The paper isDownloaded from http://onepetro.org/SPEHFTC/proceedings-pdf/20HFTC/2-20HFTC/D022S016R001/2428479/spe-199690-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae50b7c-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 2, "chroma:document": "SPE-199690-MS 3\nstructured as follows: First, we provide a brief summary to our fully integrated simulator in the Model\nDescription section with the model domains, model physics and solution algorithms. Sensitivity studies\nand discussions of the effect of different layer properties on the DFIT response and interpretation are then\nprovided in the Results and Discussions section. A Conclusion section summarizing the key findings of this\npaper is included at the end of this paper.\nModel Description\nA fully integrated hydraulic fracturing and reservoir simulator is used in this paper to simulate a DFIT:\nhydraulic fracture propagation and shut-in. This simulator has been developed for designing and evaluating\npad scale fracturing treatments previously ( Zheng et al., 2019a; 2019b ; 2019c; Manchanda et al., 2019a;\n2019b ). It was then extended from a single-phase flow model to multi-phase black-oil flow model and from"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae50bf4-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 2, "chroma:document": "single well fracturing simulator to an integrated fracturing and reservoir simulator. An energy balance model\nwas inporporated into the simulator to consider temperature changes ( Zheng et al., 2019d). The fully implicit\ngeomechanical hydraulic fracturing simulator was also extended to an integrated Equation-of-State based\ncompositional fracturing and reservoir simulator in recent work (Zheng et al., 2019e ; Zheng et al., 2019f).\nThis simulator couples the reservoir-fracture-wellbore system ( Figure 2) and has the capability to\nsimulate the lifecycle of wells: hydraulic fraturing, shut-in, flowback, primary production, and improved\noil recovery. Multiple physics in each domain are tightly coupled. Solid deformation, flow in the rock\nmatrix and the fracture, and temperature are modeled and solved in the reservoir domain. Fracture fluid\nand proppant flow, and fracture width change are solved in the fracture domain. Slurry and proppant"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae50c6c-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 2, "chroma:document": "distribution, wellbore storage, hydrostatic and friction pressure drops are considered in the wellbore domain.\nThe coupled, non-linear system of equations is solved using the Newton-Raphson method. An Implicit\npressure, explicit saturation/concentration based (IMPES/IMPEC) solution algorithm is shown in Figure\n3. After the solutions to the coupled system of equations are obtained, mesh topology change (fracture\npropagation, dynamic mesh refinement) is checked and looped until no more mesh topology changes are\nneeded. Then the fluid mass conservation equations and temperature equations in the reservoir and fracture\ndomain as well as the the proppant volume equations in the fracture domain are solved. The simulation enters\nthe next time step after the phase behavior analysis (using correlations if black-oil model and using Equation-\nof-State if using a compositional model) is performed. Although only the IMPES/IMPEC algorithm is"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae50ce4-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 2, "chroma:document": "shown here, different sets of equation for different physics can be chosen to be coupled into the main Newton\niteration block or removed from the block with great flexibility. For example, the fluid mass conservation\nequations can be coupled into the main Newton iteration block, making the simulation fully implicit and\nthe solid deformation equation can be removed from the iteration block, making it a non-geomechanical\nreservoir simulator. A detailed formulation of the simulator can be found in the references cited above.Downloaded from http://onepetro.org/SPEHFTC/proceedings-pdf/20HFTC/2-20HFTC/D022S016R001/2428479/spe-199690-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae50d52-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 3, "chroma:document": "4 SPE-199690-MS\nFigure 2\u2014The coupled domains and physics of the fully integrated simulator ( Zheng et al., 2019d ).\nFigure 3\u2014The IMPES/IMPEC solution algorithm of the fully integrated simulator.\nThis simulator was first applied to fracture closure and DFIT modeling in Zheng et al., 2019b in which\nthe Barton-Bandis contact correction was incorporated to model fracture closure on asperities/proppants.\nThis simulator was successfully validated for DFIT simulation and applied to study the effect of depletionDownloaded from http://onepetro.org/SPEHFTC/proceedings-pdf/20HFTC/2-20HFTC/D022S016R001/2428479/spe-199690-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae50dca-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 4, "chroma:document": "SPE-199690-MS 5\ninduced stress and pore pressure heterogeneity on DFIT closure stress and pore pressure estimation ( Zheng\net al., 2019g ). Readers are encouraged to read Zheng et al., 2019g for more details on the model validation.\nBase Case\nIn the Base Case, a small amount of fluid (2 m3) is injected into the wellbore in 5 minutes and then the well\nis shut-in for 10 days to mimic a DFIT job. The simulation domain is 400 \u00d7 400 m2 in the horizontal plane\nand 200 m in the height direction (Figure 4). The perforation clusters are placed in the middle of the domain.\nOther reservoir properties and completion design parameters are summarized in Table 3. The bottom hole\npressure versus time is computed and plotted in this simulation. The simulation involves propagation of a\nsingle vertical fracture from a horizontal wellbore drilled in a formation with layered stress heterogeneity.\nThe stress distribution with the DFIT fracture initiation point is shown in Figure 5. The initial mesh size is 40"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae50e42-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 4, "chroma:document": "\u00d7 10 \u00d7 10 m3 and is dynamically refined as can be seen from Figure 6. Grid convergence analysis (Zheng et\nal., 2019g ) is performed to determine the correct mesh size for a grid converged solution and it is found that\nwhen the smallest grid size reached 0.625 \u00d7 1.25 \u00d7 1.25 m3 by three levels of static refinement perpendicular\nto the wellbore direction and three levels dynamic refinement in all directions, the results will not change\nwith further mesh refinement. A plot of the fracture geometry with width distribution and pore pressure\ndistribution at the end of shut-in (t  = 10 days) is shown in Figure 6. In this figure, each fracture segment\nhas an area of 1.25 \u00d7 1.25 m2 and the length of the smallest grid perpendicular to the wellbore direction is\n0.625 m. During fracture propagation and shut-in, fracturing fluid in the fracture leaks into the reservoir,\ncausing a pressure increase in the reservoir matrix adjacent to the fracture. The fracture width shows good"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae50eba-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 4, "chroma:document": "agreement with the input layer stresses, with smaller widths being computed in the high stress layers.\nFigure 4\u2014Illustration of simulation domain, well location, and cluster locationDownloaded from http://onepetro.org/SPEHFTC/proceedings-pdf/20HFTC/2-20HFTC/D022S016R001/2428479/spe-199690-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae50f3c-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 5, "chroma:document": "6 SPE-199690-MS\nFigure 5\u2014Stress distribution in a vertical slice of the reservoir\nFigure 6\u2014Fracture geometry with width distribution and pore pressure distribution at the end of shut-inDownloaded from http://onepetro.org/SPEHFTC/proceedings-pdf/20HFTC/2-20HFTC/D022S016R001/2428479/spe-199690-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae50fb4-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 6, "chroma:document": "SPE-199690-MS 7\nTable 1\u2014Reservoir properties and completion design in the Base Case\nParameter Value Unit Parameter Value Unit\nLength of the domain in the x-direction 400 m Initial stress in the x-direction ( Shmin) 35/36 MPa\nLength of the domain in the y-direction 400 m Initial stress in the y-direction ( Shmax) 51 MPa\nLength of the domain in the z-direction 200 m Initial stress in the z-direction ( Sv) 70 MPa\nPermeability 2e-19 m2 Vertical stress gradient 0.02262 MPa /m\nPorosity 0.08 Young's modulus of the rock 20 GPa\nCritical energy release rate 1000 Pa \u2219 m Poisson's ratio of the rock 0.25\nContact width 2e-4 m Fluid viscosity 0.001 Pa \u2219 s\nAsperity initial stiffness 5e8 Pa/m Total injection time 300 s\nWellbore volume 55 m3 Total injection volume 2 m3\nWell diameter 0.1397 m Number of perforations per cluster 2\nShut-in time 10 days Perforation diameter 0.0127 m\nFigure 7  shows the fracture contact area and fracture width distribution when shut-in time equals to"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae5102c-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 6, "chroma:document": "57, 67, 77, 87, 97, and 107 hours, respectively. As can be seen from Figure 7, the fracture maintains the\nlargest width in the middle low stress region and the two low stress regions below and above the middle\nlow stress region also have a large width as compared to the fracture tip regions and the high stress regions.\nThe fracture surfaces first fall in contact around the tips of the high stress regions followed by the internal\nfracture surface area in the high stress region. At about 97 h, all the fracture surfaces in the high stress region\ncome into contact on the rough asperities. During fracture closure, fracture width decreases, however, the\nfracture width in the low stress region is always higher than in the high stress region. Between time 97 h\nand 107 h, the fracture in the upper and lower low stress region closes first. The fracture in the middle low"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae510ae-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 6, "chroma:document": "stress region closes last.Downloaded from http://onepetro.org/SPEHFTC/proceedings-pdf/20HFTC/2-20HFTC/D022S016R001/2428479/spe-199690-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae51126-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 7, "chroma:document": "8 SPE-199690-MS\nFigure 7\u2014Fracture contact area and fracture width at selected times during shut-in.Downloaded from http://onepetro.org/SPEHFTC/proceedings-pdf/20HFTC/2-20HFTC/D022S016R001/2428479/spe-199690-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae5119e-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 8, "chroma:document": "SPE-199690-MS 9\nThe resulting pressure and G-function plot is shown in Figure 8. Since the stress contrast in the case is\nnot significantly large (1 MPa ), the fracture closure sequence in the high stress and low stress regions is\nnot very different. No double humps are observed in the G-function plot (they are not visually obvious).\nHowever, one can still observe that there is a small change in the pressure derivative between a G-time of 80\nand 100, which is caused by the non-uniform fracture closure event in different stress layers. By applying\nthe variable compliance method, the estimated closure stress value is about 35.6 MPa, which is an averaged\nvalue of the high stress value (36 MPa) and the low stress value (35 MPa ) input into the simulation.\nFigure 8\u2014G-function plot for the Base Case.\nResults and Discussion\nIn this section, we apply our numerical DFIT model to study the effect of different layer properties on the"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae5120c-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 8, "chroma:document": "DFIT signature and its interpretation. Based on the Base Case setup, we vary the layer properties including\nlayer stress contrast, layer permeability, layer thickness, layer rock stiffness and simulate DFIT fracture\npropagation during injection and fracture closure during shut-in. Bottom hole pressure is obtained and\nanalyzed. We also study the effect of bedding planes on the DFIT signature. From the simulation results, it\nis found that most of the layer properties have a very big impact on the DFIT signature and interpretation.\n1. Effect of layer stress contrast\nIn this subsection, we show two sets of simulations to investigate the effect of layer stress contrast on DFIT\nsignature and interpretation. In the first set of simulations, we modify the base case, in which the low stress\nis fixed at 35 MPa  and the stress contrast is varied. Figure 9 shows the DFIT fracture geometry at the end\nof injection with a stress contrast of 1 MPa in Case (a) (Base Case), 3 MPa in Case (b), and 5 MPa in Case"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae5127a-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 8, "chroma:document": "(c). The color scale depicts the fracture width distribution. It is observed that the magnitude of the stress\ncontrast significantly affects the DFIT fracture geometry and fracture width. In Case (a), the stress contrast\nis the smallest and it does not have a very big influence on fracture containment. The fracture grows in both\nlength and height in Case (a). By comparison, Case (b) has an intermediate stress contrast which limits the\nfracture height growth. Case (c) has the highest stress contrast, resulting in mainly length propagation of\nthe fracture in the low stress region. In the central low stress layer, Case (a) shows the largest fracture width\nwhereas Case (c) shows the smallest fracture width.Downloaded from http://onepetro.org/SPEHFTC/proceedings-pdf/20HFTC/2-20HFTC/D022S016R001/2428479/spe-199690-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae512f2-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 9, "chroma:document": "10 SPE-199690-MS\nFigure 9\u2014Fracture geometry with color scale showing the fracture width distribution for\nstress contrast comparison. The stress contrasts are 1MPa in (a), 3MPa in (b), and 5MPa\nin (c), respectively. The middle layer where the fracture is initiated is a low stress layer.\nAfter injection, the well is shut-in for 20 days leaving the fracture to close gradually. The G-function plots\nof pressure and pressure derivative for each case are shown in Figure 10 . From the pressure plot, one can\nobserve different Instantaneous Shut-in Pressure (ISIP) for these three cases: the larger stress contrast case\ngives a large ISIP and vice versa, which is reasonable since more energy is needed to open the rocks under\nlarger compressive stress. One can also observe that cases with larger stress contrast close faster than the\ncases with low stress contrast. Double humps are observed in the pressure derivative plots in Case (b) and"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae51360-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 9, "chroma:document": "Case (c) because of the lag time between fracture closure in the different stress layers are distinguishable\nwhile in Case (a) this time is not distinguishable and the two peaks merge into a single peak. Through DFIT\ninterpretation, the closure stresses correspond to the first and second humps in Case (b) are determined to be\n35.9 MPa  and 34.6 MPa , and the closure stresses correspond to the first and second humps in Case (c) are\ndetermined to be 36.7 MPa and 34.7 MPa using the tangent line method. In Case (b) and Case (c), the lower\nclosure stresses are almost same, but lower than the input low stress value (35 MPa). The higher closure\nstresses are 35.9 MPa  and 36.7 MPa , which are also lower than their input values (38 MPa and 40 MPa). As\nexpected, the tangent line method underestimates the closure stress. When the variable compliance method\nis used to estimate the layer closure stresses, better agreement with the input stresses is obtained: The closure"}


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topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae51400-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 9, "chroma:document": "stress in Case (b) and Case (c) are 37.4 MPa and 35.1 MPa, 38 MPa and 35.1 MPa, respectively. A very\ngood estimation to the lower stress is obtained and the estimation to the higher stress is improved. Table\n2 summarizes these results.\nFigure 10\u2014G-function plots of stress contrast comparison. The\nmiddle layer where the fracture is initiated is a low stress layer.Downloaded from http://onepetro.org/SPEHFTC/proceedings-pdf/20HFTC/2-20HFTC/D022S016R001/2428479/spe-199690-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae5146e-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 10, "chroma:document": "SPE-199690-MS 11\nTable 2\u2014Estimated closure stress corresponding to cases shown in Figure 9\nTangent\nline methodCompliance\nmethodVariable\ncompliance\nmethod\nCase (b)35.9 MPa\n34.6 MPa38.4 MPa\n35.5 MPa37.4 MPa\n35.1 MPa\nCase (c)36.7 MPa\n34.7 MPa38.5 MPa\n35.4 MPa38 MPa\n35.1 MPa\nIn the second set of simulations, we inverse the stress in the first set of simulations, while all other things\nremain the same. This means that the old high stress layers become the low stress layers and the old low\nstress layers become the high stress layers. In this set of simulations, the fracture is initiated in the high\nstress layer. The fracture geometries for different stress contrasts are shown in Figure 11 . Similarly, since\nthe stress contrast in Case (a) is only 1 MPa, it does not have a big restriction on the fracture geometry and\nfracture height growth, but one can still observe the the low width value in the central high stress layer."}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae51824-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 10, "chroma:document": "From Case (b) and (c), one can see that the DFIT fracture breaks through into the upper and lower low stress\nlayers and grows preferentially in the two low stress layers. Case (c) shows a better fracture containment\nand longer fracture length than Case (b) because of its higher layer stress contrast.\nFigure 11\u2014Fracture geometry with color scale showing the fracture width distribution for\nstress contrast comparison. The stress contrasts are 1MPa in (a), 3MPa in (b), and 5MPa\nin (c), respectively. The middle layer where the fracture is initiated is a high stress layer.\nThe G-function plots for the second set of simulations are shown in Figure 12 . It is observed that larger\nstress contrast gives early fracture closure. However, in this case, the fracture in the high stress layer closes,\nand consequently the wellbore will lose its hydraulic connection to the fracture. Compared to the previous\nset of simulations, in the current simulation set, the time lag between the two closure events is larger. This"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae518ba-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 10, "chroma:document": "is because of the bottleneck in the fracture geometry which makes it easier to isolate the fracture portions\nin different stress layers. The closure stresses using tangent line method, the compliance method and the\nvariable compliance method are shown in Table 3. The tangent line method gives the best estimation of the\nlower closure stress. The closure stresses estimated from the variable compliance method area is overall\ncloser to the input layer stresses. In these three cases in Figure 12 , the fracture closes first in the high stress\nlayers, including the middle high stress layer where the wellbore goes through. This limits the hydraulic\nconnectivity between the fracture in other layers and the wellbore and leads to a slow fracture closure, which\ncan be seen in Figure 12 where the stiffness keeps increasing slowly even at late G time. This \"slowly rising"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae51928-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 10, "chroma:document": "tail\" is comparable to the similar \"slowly rising tail\" as shown in Figure 1.Downloaded from http://onepetro.org/SPEHFTC/proceedings-pdf/20HFTC/2-20HFTC/D022S016R001/2428479/spe-199690-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae51996-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 11, "chroma:document": "12 SPE-199690-MS\nFigure 12\u2014G-function plots of stress contrast comparison. The\nmiddle layer where the fracture is initiated is a high stress layer.\nTable 3\u2014Estimated closure stress corresponding to cases shown in Figure 11\nTangent\nline methodCompliance\nmethodVariable\ncompliance\nmethod\nCase (b)36.2 MPa\n35.3 MPa37.9 MPa\n35.7 MPa37.3 MPa\n35.5 MPa\nCase (c)37.2 MPa\n35.1 MPa38.4 MPa\n36.5 MPa38 MPa\n36.3 MPa\n2. Effect of layer thickness\nIn this subsection, we vary the layer thickness from the the Base Case. The stress contrast is fixed at 3 MPa\n(35 MPa  for low stress and 38 MPa for high stress). Different layer thickness has been tested: 5 m in Case\n(a), 10 m in Case (b), and 15 m in Case (c) as shown in Figure 13 . The fracture is initiated in the low stress\nlayer and it can be summarized that smaller layer thickness gives larger fracture surface area, longer fracture\nlength, smaller fracture height and smaller fracture width. The ratio of the area of the fracture portion in the"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae51a04-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 11, "chroma:document": "low stress layer to the total fracture area are 46.7%, 72.8%, and 87.7%, respectively.\nFigure 13\u2014Fracture geometry with color scale showing the fracture width distribution for layer\nthickness comparison. The stress contrast is 3MPa. The layer thicknesses are (a) 5m, (b) 10m,\nand (c) 15m, respectively. The middle layer where the fracture is initiated is a low stress layer.\nThe DFIT plots of the first set of simulations are shown in Figure 14. We observe that double humps\nare more likely to occur if more of the fracture area is in the high stress layer. In Figure 12, Case (a) hasDownloaded from http://onepetro.org/SPEHFTC/proceedings-pdf/20HFTC/2-20HFTC/D022S016R001/2428479/spe-199690-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae51a72-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 12, "chroma:document": "SPE-199690-MS 13\nthe largest proportion of fracture area in high stress layer whereas Case (c) has the smallest proportion of\nfracture area in the high stress layer. Case (b) lies between Case (a) and Case (c). As observed from Figure\n13 and Figure 14 , the time when fracture starts to closure follows the sequence Case (a) < Case (b) < Case\n(c), which is caused by the fact that under the same condition, the fracture width of Case (a) is the smallest\nwhile the width of Case (c) is the largest. More fracture propagates into high stress layer in Case (a), making\nthe signal from the high stress closure more pronounced and comparable to the low stress layer fracture\nclosure signal. This results in two humps in the pressure derivative plot. Comparatively speaking, most of\nthe fracture stays in the low stress layer in Case (b) and Case (c). For this reason, the ISIP also follows Case\n(a) > Case (b) > Case (c). The closure of the high stress layer fracture does not give a large enough fracture"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae51af4-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 12, "chroma:document": "stiffness increase and there is not a large enough gap between the different fracture areas, which leads to\nonly one hump in the pressure derivative plot for Case (b) and Case (c).\nFigure 14\u2014G-function plots of layer thickness comparison. The\nmiddle layer where the fracture is initiated is a low stress layer.\nIn the second simulation (Figure 15), the high stress layers and low stress layers are reversed, which\nmeans the fracture is initiated in the high stress layer. It can be observed the DFIT fracture tends to break out\nof the high stress layer and preferentially propagate in the low stress layer. The proportions of the fracture\nin the low stress layer are 54.1%, 75.1%, and 75.9%, respectively.\nFigure 15\u2014Fracture geometry with color scale showing the fracture width distribution for layer\nthickness comparison. The stress contrast is 3MPa. The layer thicknesses are (a) 5m, (b) 10m,"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae51b6c-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 12, "chroma:document": "and (c) 15m, respectively. The middle layer where the fracture is initiated is a high stress layer.Downloaded from http://onepetro.org/SPEHFTC/proceedings-pdf/20HFTC/2-20HFTC/D022S016R001/2428479/spe-199690-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae51bee-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 13, "chroma:document": "14 SPE-199690-MS\nAll the three cases show two humps in the pressure derivative plots in Figure 16. In all the three cases,\nthe first hump corresponds to the closure of the fracture in the high stress layer whereas the second hump\ncorresponds to the closure of the fracture in the low stress layer. A larger proportion of fracture surface in\nthe high stress layer leads to a larger stiffness increase in the first closure event (fracture in high stress layer\ncloses). The magnitudes of the first hump are: Case (a) > Case (b) = Case (c), which agrees well with the\nfracture surface area ratio under high stress layer in the three cases. The fracture starts to close earliest in\nCase (c) and lastest in Case (a), as observed in Figure 15 . In these three cases in Figure 15 , the fracture\ncloses first in the high stress layers, including the middle high stress layer where the wellbore goes through.\nThis limits the hydraulic connectivity between the fracture in other layers and the wellbore and leads to a"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae51c66-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 13, "chroma:document": "slow fracture closure, which can be seen from Figure 15 where the stiffness keeps increasing slowly even\nat late G time.\nFigure 16\u2014G-function plots showing the effect of layer thickness.\nThe middle layer where the fracture is initiated is a high stress layer.\n3. Effect of rock stiffness and hardness\nIn this subsection, we study the effects of rock asperity stiffness on DFIT interpretation. The stress is uniform\nin all the layers. The rock asperity stiffness is varied by varying the initial normal stiffness parameter in\nthe Barton-Bandis contact correlation. Three cases have been run. In the small and large stiffness cases,\nthe initial normal stiffnesses are fixed at uniform values of 100 MPa/m and 500 MPa/m, respectively. In\nthe mixed stiffness case (Figure 17 ), the initial normal stiffness value varies between 100 MPa/m and 500\nMPa /m in different layers. The DFIT G-function plot is shown in Figure 18 , from which one can see that the"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae51ce8-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 13, "chroma:document": "asperity stiffness has no impact on the fracture propagation but greatly affects the fracture closure period.\nThe DFIT fracture is found to close much faster in the small stiffness case than in the large stiffness case and\nthe mixed stiffness case lies in between the two uniform cases. From the Barton-Bandis correlation, one can\nsee that smaller initial normal stiffness will result in a smaller contact force. The contact force applied on\neach other's rough surface by the soft rock is much smaller than the hard rock, which lead to a fast fracture\nclosure in the soft rock. This is also obvious from Figure 17: The fracture residual width is much larger in\nthe high asperity stiffness layers than that in the low asperitiy stiffness layers.Downloaded from http://onepetro.org/SPEHFTC/proceedings-pdf/20HFTC/2-20HFTC/D022S016R001/2428479/spe-199690-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae51d60-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 14, "chroma:document": "SPE-199690-MS 15\nFigure 17\u2014Fracture geometry showing the effect of rock asperity stiffness. The\ncolor scale shows (a) rock asperity initial normal stiffness and (b) fracture width.\nFigure 18\u2014G-function plots of asperity stiffness comparison.\nThe effect of rock stiffness (Young's modulus) is also studied. Two cases using Young's modulus values\nof 20 GPa and 10 GPa are studied, but it not found to have a big impact on fracture propagation and fracture\nclosure if the Young's modulus is not significantly different. So, the effect of rock stiffness will not be\ndiscussed in detail in the paper.\n4. Effect of Bedding plane\nIn this subsection, we study the effects of bedding planes and their relationship (arrest/cross) to the\nDFIT signature and interpretation. In this DFIT simulation with a bedding plane, we do not simulate the\npropagation of the fracture but rather assume a fracture and bedding plane geometry and open the fracture"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae51de2-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 14, "chroma:document": "and bedding plane using a uniform fracture pressure value and then perform the shut-in and fracture closure\nsimulation. Two simulations have been setup as shown in Figure 19 . In Case (a), the propagating DFIT\nfracture is arrested by the bedding planes. In Case (b), the DFIT fracture interacts with the bedding planes\nand finally crosses the two bedding planes. In both cases, the minimum horizontal stress is set to 35 MPa\nwhereas the vertical stress is set to be 36 MPa. The simulation results show large fracture width in the vertical\nfracture section and small width in its connected bedding plane. On the fracture-bedding plane intersection\npoint, the fracture width is low because of the shear displacement of the bedding plane ( Tang and Wu, 2018).Downloaded from http://onepetro.org/SPEHFTC/proceedings-pdf/20HFTC/2-20HFTC/D022S016R001/2428479/spe-199690-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae51e5a-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 15, "chroma:document": "16 SPE-199690-MS\nFigure 19\u2014Fracture geometry with bedding plane. The color scale shows the fracture width distribution.\n(a) DFIT fracture is arrested by the bedding planes. (b) DFIT fracture crosses the bedding planes.\nThe G-function plots of the DFIT simulation with the bedding plane are shown in Figure 20. It can be\nseen that the crossing DFIT fracture and the arrested DFIT fracture give very different DFIT signatures. In\nboth cases, the opened bedding planes close first followed by the DFIT fracture. In the case in which the\nthe fracture was arrested by the bedding plane, the corners of the bedding plane close first followed by the\ninner side of the bedding plane and the DFIT fracture. Thus, there is an initial sharp increase in its pressure\nderivative, which depicts the closure of the bedding plane. Then a sharp drop is observed which means the\ncomplete closure of the bedding plane, which is further interrupted by a reincrease which infers the closing"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae51ec8-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 15, "chroma:document": "of the main DFIT fracture starts to happen. In the case in which the fracture crosses the bedding plane,\nthe intersection points of the bedding plane and fracture close first due to its small width, which cutoff the\nhydraulic connectivity between the DFIT fracture and the bedding planes. This explains the slow increase\nof the system stiffness in the first hump in the pressure derivative curve. The closure in the rest part of the\nbedding planes has been successfully blocked by the conductivity cutoff. The system stiffness restarts to\nincrease in the second hump, when the DFIT fracture starts to close.\nFigure 20\u2014G-function plots in the presence of of bedding planes (fracture crossing or dilating the bedding plane).Downloaded from http://onepetro.org/SPEHFTC/proceedings-pdf/20HFTC/2-20HFTC/D022S016R001/2428479/spe-199690-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae51f36-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 16, "chroma:document": "SPE-199690-MS 17\n5. Effect of layer permeability and pore pressure estimation\nIn this subsection, we study the effect of layer permeabilities on DFIT interpretation. As shown in Figure\n21, in Case (a), the permeability is uniform 0.2 \u03bcD where as in Case (b) and Case (c), the background\npermeability is fixed at 0.2 \u03bcD and the interlayer permeability is 0.5 \u03bcD and 0.8 \u03bcD, respectively. The stress\nis uniform 35 MPa everywhere. By applying the variable compliance method, the closure stress obtained\nfrom the G-function plots are the same as the input minimum horizontal stress value. The G-function plots\nfor the three cases are collected and plotted on the same figure shown in Figure 21(d) . It can be concluded\nthat the fracture closes earlier and faster in high permeability cases, but the closure stress estimation is not\naffected by the rate of fracture closure.\nFigure 21\u2014G-function plots with permeability layer heterogeneity. (a) Layer perm=0.2\u03bcD,"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae51ffe-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 16, "chroma:document": "(b) Layer perm=0.5\u03bcD, (c) Layer perm=0.8\u03bcD, (d) Overall plot for the three cases.\nWe then analyze the initial pore pressure using the pressure response from Case (b) and Case (c) in Figure\n21 to investigate the effect of permeability layers on pore pressure estimation. The plot of the pressure\nderivative versus time in a log-log scale for the two cases are shown in Figure 22. Before-closure and after-\nclosure linear flow regimes are observed in both casese, which happen earlier in the high permeability\ncase because of the high leakoff rate. The pressure data in the post-closure linear flow period are picked\nand plotted against one over square root of time in Figure 23. The straight lines are fitted using the linear\nregression and intercept pressure values of 24.574 MPa and 24.631 MPa are obtained. The deviations from\nthe initial pore pressure (25 MPa) are 1.704% and 1.476%, respectively. The results indicate that formation"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae52076-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 16, "chroma:document": "layer permeability may not have a big impact on the pore pressure estimation, as long as the post-closure\nlinear flow regime is clearly observed. However, it is also shown that if the layer permeability is too low,\nit will take a very long time for the fracture to close completely and the post-closure linear flow to occur.\nOperators or service companies may not want to wait for such a long time to obtain the data for pore pressure\nestimation. The novel Rapid Injection Flowback Test (RFIT) (Wang 2019) can be a fast way to obtain a\nquicker estimation of both closure stress and pore pressure.Downloaded from http://onepetro.org/SPEHFTC/proceedings-pdf/20HFTC/2-20HFTC/D022S016R001/2428479/spe-199690-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae520ee-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 17, "chroma:document": "18 SPE-199690-MS\nFigure 22\u2014Identifying the linear flow regime before and after fracture closure.\nFigure 23\u2014Initial pore pressure estimation.\nConclusions\nThis paper presents results that clearly show the impact of layer properties on the response of a DFIT. The\neffect of key heterogeneity parameters on the DFIT plots including layer stress contrast, layer thickness,\nlayer rock stiffness and hardness, bedding plane, and layer permeability are demonstrated. The main\nconclusions are:\n1.The complex fracture closure behavior as indicated by the G-function plot is a combined result of the\nDFIT fracture geomery and layer properties.Downloaded from http://onepetro.org/SPEHFTC/proceedings-pdf/20HFTC/2-20HFTC/D022S016R001/2428479/spe-199690-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae52166-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 18, "chroma:document": "SPE-199690-MS 19\n2.The number of humps shown in the pressure derivative curve depends on the the relative difference in\nmagnitude between the closure stress in different layers. If only one peak is observed in the pressure\nderivative, the estimated closure stress corresponds to an averaged stress value in layers that the\nfracture penetrates. If multiple peaks are observed, then the estimated closure stress values correspond\nto the minimum horitontal stress in different layers.\n3.Early near wellbore fracture closure leads to a shadow effect and long-time fracture closure which is\nindicated by a slow increase in the pressure derivative plot.\n4.Rock stiffness plays an important role in fracture closure. Hard asperities on the fracture surface result\nin gradual fracture closure whereas softer asperities result in fast fracture closure. Simply varying the\nYoung's modulus of the rock matrix does not play a significant role in controlling the pressure fall-"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae521de-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 18, "chroma:document": "off behavior. However, it should be noted that the stiffness of the fracture asperities is closely related\nto the Young's modulus of the rock.\n5.Higher layer peameability leads to earlier and faster fracture. Hoever, permeability heterogeneity does\nnot substantially affect the closure stress estimation.\n6.Post-closure pore pressure estimation may not be affected by the layer permeability heterogeneity as\nlong as the post-closure linear flow period is observed. However, it may take a very long time for\nthe linear flow regime to be observed from the field if the rock matrix is very tight. Rapid Injection\nand Flowback Tests (RIFT) can be a much faster method to estimate closure stress and pore pressure\nsimultaneously.\n7.Pre-existing bedding planes interacting with a DFIT fracture significantly alters the final fracture\ngeometry and leakoff rate during shut-in and results in very different DFIT responses and\ninterpretation. Hydraulic connectivity in this complex geometry also significantly affects the pressure"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae52260-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 18, "chroma:document": "response.\nAcknowledgements\nWe would like to thank the Hydraulic Fracturing and Sand Control Industrial Affiliates Project at the\nUniversity of Texas at Austin for the financially supporting this research.\nReferences\nBandis, S.C. , Lumsden A.C. and Barton N.R. , 1983 . Fundamentals of rock joint deformation. International Journal\nof Rock Mechanics and Mining Sciences & Geomechanics Abstracts . V ol. 20. No. 6. Pergamon. https://\ndoi.org/10.1016/0148-9062(83)90595-8\nBarree, R.D.  and Mukherjee, H., 1996 . Determination of pressure dependent leakoff and its effect on fracture geometry. In\nSPE Annual Technical Conference and Exhibition. Society of Petroleum Engineers. https://doi.org/10.2118/36424-MS\nKamali, A.  and Ghassemi, A. , 2019 . DFIT Considering Complex Interactions of Hydraulic and Natural Fractures .\nIn SPE Hydraulic Fracturing Technology Conference and Exhibition. Society of Petroleum Engineers. https://\ndoi.org/10.2118/194348-MS"}


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topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae522e2-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 18, "chroma:document": "doi.org/10.2118/194348-MS\nJi, L., Sen, V . , Min, K.S. and Sullivan, R., 2019 . Numerical Simulation of DFITs Within a Coupled Reservoir Flow\nand Geomechanical Simulator-Insights into Completions Optimization. In SPE Hydraulic Fracturing Technology\nConference and Exhibition. Society of Petroleum Engineers. https://doi.org/10.2118/194352-MS\nManchanda, R., Zheng, S. , Hirose, S., Sharma, M.M. , 2019a. Integrating Reservoir Geomechanics with Multiple Fracture\nPropagation and Proppant Placement. Accepted in SPE Journal .\nManchanda, R. , Zheng, S., Gala, D.P. and Sharma, M.M.  2019b . Simulating the Life of Hydraulically Fractured Wells\nUsing a Fully-Coupled Poroelastic Fracture-Reservoir Simulator. In Proceedings of the 7th Unconventional Resources\nTechnology Conference, Denver, Colorado. https://doi.org/10.15530/urtec-2019-490\nMcClure, M.W., Jung, H. , Cramer, D.D.  and Sharma, M.M. 2016 . The Fracture-Compliance Method for Picking Closure"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae52364-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 18, "chroma:document": "Pressure from Diagnostic Fracture-Injection. SPE Journal, 21(04), pp.1-321. https://doi.org/10.2118/179725-PA\nNolte, K.G. , 1979 . Determination of fracture parameters from fracturing pressure decline. In SPE Annual Technical\nConference and Exhibition. Society of Petroleum Engineers. https://doi.org/10.2118/8341-MSDownloaded from http://onepetro.org/SPEHFTC/proceedings-pdf/20HFTC/2-20HFTC/D022S016R001/2428479/spe-199690-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae523e6-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 19, "chroma:document": "20 SPE-199690-MS\nTang, J.  and Wu, K. , 2018. A 3-D model for simulation of weak interface slippage for fracture height containment\nin shale reservoirs . International Journal of Solids and Structures, 144, pp.248- 264. https://doi.org/10.1016/\nj.ijsolstr.2018.05.007\nWang, H. , 2019 . New approaches to model and analyze diagnostic fracturing injection tests (Doctoral dissertation). http://\ndx.doi.org/10.26153/tsw/3098\nWang, H.  and Sharma, M.M. , 2017 . New Variable Compliance Method for Estimating In-Situ Stress and Leak-Off\nfrom DFIT Data . In SPE Annual Technical Conference and Exhibition. Society of Petroleum Engineers. https://\ndoi.org/10.2118/187348-MS\nWang, H.  and Sharma, M.M. , 2018 . Estimating Unpropped-Fracture Conductivity and Fracture Compliance from\nDiagnostic Fracture-Injection Tests. SPE Journal . https://doi.org/10.2118/189844-PA\nWang, H.  and Sharma, M.M. , 2019a. A Novel Approach for Estimating Formation Permeability and Revisiting After-"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae5245e-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 19, "chroma:document": "Closure Analysis of Diagnostic Fracture-Injection Tests. SPE Journal. https://doi.org/10.2118/194344-PA\nWang, H.  and Sharma, M.M., 2019b . Determine In-Situ Stress and Characterize Complex Fractures in Naturally\nFractured Reservoirs from Diagnostic Fracture Injection Tests. Rock Mechanics and Rock Engineering, pp. 1-21.\nhttps://doi.org/10.1007/s00603-019-01793-w\nZheng, S., Manchanda, R. and Sharma, M.M., 2019a. Development of a fully implicit 3-D geomechanical\nfracture simulator . Journal of Petroleum Science and Engineering , 179, pp. 758-775. https://doi.org/10.1016/\nj.petrol.2019.04.065\nZheng, S. , Manchanda, R.  and Sharma, M.M. , 2019b. Efficient incorporation of a contact model into a fully\nimplicit geomechanical fracture simulator . In 53rd US Rock Mechanics/Geomechanics Symposium. American Rock\nMechanics Association.\nZheng, S. , Manchanda, R. , Shrivastava, K. and Sharma, M.M. , 2019c. Linearized Predictor Method for the Efficient"}


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topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae524e0-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 19, "chroma:document": "Iterative Solution of Coupled Geomechanics \u2013 Fracture Flow Problems. In 53rd US Rock Mechanics/Geomechanics\nSymposium. American Rock Mechanics Association.\nZheng, S. , Hwang, J., Manchanda, R. and Sharma M.M. , 2019d . Development of an Integrated Model for multi-phase\nflow, geomechanics and fracture propagation. Journal of Petroleum Science and Engineering under review.\nZheng, S., Manchanda, R. , Gala, D.P.  and Sharma, M.M. , 2019e. Pre-loading Depleted Parent Wells to Avoid\nFrac-Hits: Some Important Design Considerations. SPE Annual Technical Conference and Exhibition. https://\ndoi.org/10.2118/195912-MS\nZheng, S. , Kumar, A. , Gala, D.P. , Shrivastava, K. and Sharma, M.M., 2019f. Simulating Production from Complex\nFracture Networks: Impact of Geomechanics and Closure of Propped/Unpropped Fractures. In Proceedings of the 7th\nUnconventional Resources Technology Conference, Denver, Colorado. https://doi.org/10.15530/urtec-2019-21"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 19, "chroma:document": "Zheng, S., Manchanda, R., Wang, H. and Sharma, M.M., 2019g . Fully 3D Simulation of Diagnostic Fracture Injection Tests\nwith Application in Depleted Reservoirs. In Proceedings of the 7th Unconventional Resources Technology Conference,\nDenver, Colorado. https://doi.org/10.15530/urtec-2019-314Downloaded from http://onepetro.org/SPEHFTC/proceedings-pdf/20HFTC/2-20HFTC/D022S016R001/2428479/spe-199690-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 20, "chroma:document": "SPE-199690-MS 21\nAppendix\nThe traditional DFIT analysis approach employs the G-function model and uses the tangent line method to\nestimate closure stress (Nolte, 1979 ; Barree and Mukherjee, 1996). A G-function is calculated to represent\nthe shut-in time. The G-function is defined by Eq. (1), (2) and (3).\n(1)\n(2)\n(3)\nwhere \u03b1 is assumed to be 1.0, \u2206 tD = \u2206t/te, \u2206t is the time since shut-in and te is the shut-in time.\nThe pressure ( P) versus G and the pressure derivative GdP/dG versus G are plotted on the same chart.\nIn the tangent line method, the closure point is picked by drawing a tangent line from the origin to the\npressure derivative curve. The pressure corresponding to the G-time of the tangent point is identified as the\nclosure pressure. McClure et al. (2016) proposed the \"compliance method\" in which they suggest picking\nfracture closure at the initial deflection point from the linear portion on the pressure derivative curve. Wang"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae5265c-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 20, "chroma:document": "and Sharma (2017) proposed the \"variable compliance method\" which further refines the analytical DFIT\nmethod by averaging the G-time (or the square root of time) of the closure point given by the tangent line\nmethod and the compliance method and uses the extrapolated value at the averaged G-time (the square\nroot of time) to identify the fracture closure stress. They clearly showed that the tangent line method\nunderestimates the closure stress, the compliance method overestimates the closure stress while the variable\ncompliance method consistently provides the lowest error in this estimate. An example G-function plot is\nshown in Figure 24 to illustrate these three methods.\nFigure 24\u2014Illustration of three analytical methods in identifying closure stress from a G-function plot.\nWang and Sharma (2019a)  also demonstrated that both the G-function model and square root of time\nmodel are just special cases of their general time-convolution solutions. After closure analysis focuses on the"}


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topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae526e8-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 20, "chroma:document": "post-closure linear and pseudo-radial flow to estimate the reservoir initial pore pressure, matrix permeability,\nleakoff coefficient and fracture compliance (Wang and Sharma, 2019a). For example, a log-log plot of the\npressure derivatives versus shut-in time clearly distinguishes the different flow regimes in the reservoir,\nbefore and after fracture closure. The intercept of pressure versus the inverse of the square-root of shut-Downloaded from http://onepetro.org/SPEHFTC/proceedings-pdf/20HFTC/2-20HFTC/D022S016R001/2428479/spe-199690-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae52756-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-199690-ms.pdf", "page": 21, "chroma:document": "22 SPE-199690-MS\nin time straight line in the post-closure linear flow regime gives the initial pore pressure in the reservoir\n(Figure 25 ).\nFigure 25\u2014Initial pore pressure estimation using post-closure linear flow data.Downloaded from http://onepetro.org/SPEHFTC/proceedings-pdf/20HFTC/2-20HFTC/D022S016R001/2428479/spe-199690-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae527d8-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 0, "chroma:document": "SPE-189826-MS\nDFIT Analysis in Low Leakoff Formations: A Duvernay Case Study\nBehnam Zanganeh, Mason K. MacKay, and Christopher R. Clarkson, University of Calgary; Jack R. Jones, NSI\nFracturing LLC\nCopyright 2018, Society of Petroleum Engineers\nThis paper was prepared for presentation at the SPE Canada Unconventional Resources Conference held in Calgary, Alberta, Canada, 13-14 March 2018.\nThis paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents\nof the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect\nany position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae5285a-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 0, "chroma:document": "consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may\nnot be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.\nAbstract\nDiagnostic Fracture Injection Test (DFIT) responses in some shale reservoirs, such as the Duvernay shale\nin western Canada, are not consistent with those interpreted through traditional analysis methods. Indeed,\ninterpretation with traditional techniques may result in significantly incorrect estimates of closure pressure,\npore pressure and formation permeability. The goal of this paper is to explain the observed DFIT behaviours\nfor selected Duvernay shale wells in terms of low leakoff of fracturing fluid to the formation, activation of\npre-existing fractures, and tip extension during the test.\nDFIT data in the Duvernay shale are analyzed using pressure transient analysis methods. Two scenarios"}


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topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae528c8-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 0, "chroma:document": "are presented to explain the overall falloff behavior; moving-hinge closure with tip extension, and activation\nof secondary natural fractures. The validity of each scenario is examined using rigorous coupled flow-\ngeomechanical simulation, geological information and geomechanical settings in the Duvernay Formation.\nDue to extremely low leakoff, the main mechanism affecting pressure falloff during the DFIT is pressure\ndissipation through the primary fracture created during injection. This results in significant tip extension or\nactivation of secondary fractures. The fluctuations and spikes observed on G-function or pressure derivative\nplots are explained in the context of these scenarios. The leakoff rate varies with the pressure change, and\nthe enhanced fracture surface area, during tip extension. Therefore, the assumption of Carter leakoff, and\nthe traditional closure picks based on a straight-line tangent to the semi-log derivative on a G-function plot"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae52940-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 0, "chroma:document": "or 3/2 slope on Bourdet-derivative plot are not valid. Due to very low matrix permeability and the additional\nfracture length created through tip extension, it is unlikely that formation radial flow is established during\nthe test, compromising the ability to obtain a valid pore pressure or formation permeability.\nIntroduction\nA Diagnostic Fracture Injection Test (DFIT), also known as a minifrac or fracture calibration test, has\nbecome the standard pre-stimulation method for determining fracturing treatment properties, effective\nreservoir permeability and initial reservoir pressure in unconventional reservoirs. A DFIT is an injection-\nfalloff test conducted before the main hydraulic fracturing treatment. The DFIT procedure involves\nbreakdown of the rock and creation of a short fracture during the injection of high pressure fluid (usuallyDownloaded from http://onepetro.org/SPEURCC/proceedings-pdf/18URC/1-18URC/D011S002R001/1236476/spe-189826-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae529b8-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 1, "chroma:document": "2 SPE-189826-MS\nwater), and recording of the pressure response for long enough that the created fracture closes, and the\ntransient associated with this closure event is dissipated before the onset of reservoir flow regimes.\nIn the following, a brief overview of the Duvernay Formation geological and geomechanical\ncharacteristics is provided, with a focus on those characteristics favoring episodic fracture growth. A\nhydraulic fracturing treatment example with microseismic observations is presented to illustrate this\nconcept. A Theory and Methods section is then provided, including a brief review of DFIT interpretation\nmethods. The appropriateness of interpreting Duvernay DFITs with the conventional interpretation methods\nis then examined. Two simulation models are built to generate synthetic DFIT responses. Finally, in the\nResults and Discussion section, field data are interpreted in the context of simulation results.\nGeological Overview\nDuvernay Formation"}


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topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae52a3a-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 1, "chroma:document": "Geological Overview\nDuvernay Formation\nThe Duvernay Formation is a Devonian aged shale exploited for hydrocarbons within the Western Canadian\nSedimentary Basin (WCSB). Depositional conditions within shales results in marked vertical heterogeneity,\nwhich leads to mechanical complexity (Harris et al. 2011). Within the Duvernay Formation, at least ten\nmicrofacies are identified, each with their own natural fracture fabrics and elastic properties (Knapp et al.\n2017 ). This vertical mechanical heterogeneity favors the creation of bed-contained, sub-vertical fracture\nsystems (Cooke and Underwood 2010). Natural fractures within the Duvernay are observed and inferred\nover a variety of scales from microfractures (Ghanizadeh et al. 2015) to larger fractures (Fox 2015) and\neven fault systems ( Chopra et al. 2017 ).\nThe in-situ stress conditions are interpreted in terms of the orientation and magnitude of the effective"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae52abc-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 1, "chroma:document": "stress. Through basin scale modelling work, the stress regime is thought to be in a strike slip regime in\nmuch of the basin with thrust fault regimes encountered proximal to the Rocky Mountain deformation zone\n(Reiter and Heidbach 2014). The regional stress in much of the sedimentary basin trends with an azimuth\nof 047 as indicated through borehole breakout directions and other geologic indicators ( Reiter et al. 2014).\nThe Duvernay Formation has a characteristically high organic content with TOC values ranging from 0.1\nup to 11 percent ( Rivard et al. 2014 ) which suggests significant potential for hydrocarbon generation. In fact,\nit is the source rock for most of the hydrocarbons trapped within the upper Devonian section of the WCSB\n(Creaney and Allan 1990). Hydrocarbon generation can raise fluid pressures and may be the underlying\ncause of significant overpressure conditions observed within the Duvernay (Fox and Soltanzadeh 2015,"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae52b3e-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 1, "chroma:document": "Davis and Karlen 2014 ). The highly overpressured conditions create a geomechanical sensitivity that brings\ndiscontinuities to a state of incipient failure. This phenomenon is directly observed through reported cases\nof induced seismicity arising from treatment operations within the Duvernay Formation (Bao and Eaton\n2016 ; Schultz et al. 2017 ).\nThe Duvernay Formation is primarily composed of mudstones and thus is associated with low matrix\npermeability in the range of 3.7 \u00d7 10\u22127 to 1.2 mD ( Ghanizadeh et al. 2015). This low permeability\nsuggests that significant leak-off into the matrix is unlikely over the timescale of a DFIT. Instead, fracture\nfluid volume may be accommodated through crack tip extension of the hydraulic fractures as well as\naccommodation through secondary natural fractures. This process of rupture of the rock and subsequent\nflow of fluid into the fracture is theorised to occur in temporally intermittent periods. Evidence of sporadic"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae52bc0-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 1, "chroma:document": "spatial-temporal evolution of fluid flow is supported through various case studies of microseismicity in\nshales. For example, Goertz-Allman et al. (2017)  provide a case study where microseismicity occurs due to\npunctual activation of faults which controlled fluid movement in the subsurface.\nEvidence for Episodic Fracture Growth in the Duvernay\nEvidence of temporally-intermittent fracture behaviour is gleaned from microseismic observations during\nthe main hydraulic treatment of a nearby well within the Duvernay Formation. The microseismic temporalDownloaded from http://onepetro.org/SPEURCC/proceedings-pdf/18URC/1-18URC/D011S002R001/1236476/spe-189826-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae52c42-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 2, "chroma:document": "SPE-189826-MS 3\nevolution shows that the hydraulic fracture does not grow in a simple, steady and continuous way, but rather\nthe fracture expands to new areas of the reservoir over time. This occurs episodically through growth phases\nfollowed by relative calm. In Fig. 1b, four major microseismic clusters are identified during a hydraulic\nfracturing treatment stage, each following a growth front envelope. While there is a trend to follow these\npressure diffusion fronts (Shapiro and Dinske 2009), microseismicity may jump ahead of the theoretical\ncurve or fall behind, indicating that fracture growth is not continuous and steady. Furthermore, multiple\nmicroseismic clusters form within a single treatment stage, suggesting that rock deformation processes\nfollow an episodic behavior as well. Fig. 1b also illustrates how the hydraulic fracture accesses different\nparts of the reservoir throughout the treatment. The first hydraulic growth cluster produces a large half"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae52cc4-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 2, "chroma:document": "length towards the northwest. Subsequently, active deformation occurs closer to the wellbore before finally\nmoving towards the southeast. Even though continual pumping occurred, the fracture did not continually\ngrow in length, but rather accessed different areas of the reservoir at different times.\nFigure 1\u2014Microseismic clusters showing episodic fracture propagation. (a) Treatment parameters showing\nconsistent injection (top), yet nonconsistent growth phases (bottom); (b) microseismic events plotted\nin plan view and colored by time illustrating episodic spatial temporal growth throughout the reservoir.\nThis intermittent behavior may be a response to the mechanical layering found within the Duvernay\nFormation. Brenner and Gudmundsson (2004) described how hydrofractures become arrested at mechanical\ncontrasts between layers especially when propagating from a stiff layer into a soft layer. This arresting\nbehavior would mean that as a fracture grows, it may encounter a difficult layer to propagate into; thus, a"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae52d46-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 2, "chroma:document": "new area of the reservoir will be accessed instead. Additionally, the aperture of the hydraulic fracture varies\ndepending on the Young's modulus of the surrounding rock matrix and the fluid pressure within the fracture.\nTherefore, the hydraulic fracture likely has a non-uniform aperture distribution resulting from the complex\nmechanical heterogeneity. The heterogeneous mechanical contrast suggests that a hydraulic fracture will\nundergo a period of dilation and extension as it extends in length. This transition between dilation and\nrupture likely contributes to episodic fracture growth. Furthermore, soft elastic rock will be able to store\nelastic potential from dilation of the fracture during injection. This mechanical potential energy can be a\ndriving mechanism for growth after the injection has ceased if the pressure was not able to leak off due to low\nmatrix permeability. This effect has been observed through the generation of Krauklis waves, where fracture"}


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topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae52dc8-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 2, "chroma:document": "wall deformation coupled to fluid flow creates resonances within the hydraulically connected fluid network\n(Krauklis 1962 ). In this case, the dilation and subsequent collapse of fracture aperture is coupled to fluid\nmovement within the fracture (Liang 2017 ). The time scale that this process occurs on is partially dependent\non the elasticity of the surrounding rock mass, where low shear modulus values of the rock mass producesDownloaded from http://onepetro.org/SPEURCC/proceedings-pdf/18URC/1-18URC/D011S002R001/1236476/spe-189826-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae52e40-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 3, "chroma:document": "4 SPE-189826-MS\nlarger time period fluid movement events (Tary et al. 2014). This is because the rock can accommodate\nmore elastic deformation and thus larger apertures may be reached before the fracture constricts.\nAbundant vertical natural fractures are observed in image logs taken from a horizontal leg within the\nDuvernay Formation (Fig. 2a ). These natural fractures occur in specific orientations called sets. The first set\nis an extension fracture and follows the orientation of maximum horizontal stress. The second set is a shear\nfracture and occurs at an angle to the main set. The third set is a cross joint perpendicular to the maximum\nhorizontal stress. To calculate the resolved normal and shear stress on the natural fractures, an understanding\nof the in-situ effective stress field is required. In this case, we use a vertical stress based on 24 KPa/m and\na pressure gradient of 20 KPa/m located at 3 km depth. We choose the minimum horizontal stress to be 0.8"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae52eb8-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 3, "chroma:document": "times the vertical while the maximum horizontal stress is 1.5 times the vertical stress. Using tensor rotations,\nthe normal and shear stresses are resolved for each fracture set and shown on a Mohr's circle (Fig. 2b).\nFigure 2\u2014(a) Stereonet representation of natural fracture orientations observed from image logs in the horizontal leg\nwithin the Duvernay Formation. Fracture planes are shown as great circles while the poles to the fractures are plotted\nas points. (b) Mohr's circle representation of normal and shear stresses resolved onto fractures under the estimated\nin-situ stress conditions. A Mohr-Coulomb envelope with no cohesion and 20 degree friction angle is plotted to show\nhow close to failure the fracture system is. (c) Natural fracture system within the Duvernay Formation as exposed in\noutcrop. Fluid alteration (steel blue) follows the fracture network with some leakoff occurring into the rock matrix."}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae52f44-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 3, "chroma:document": "As fluid pressure is increased during injection, the normal effective stress in the fracture system decreases\nwithin the fluid front. The extension fracture will accept fluid most easily as it has the least resolved normal\nstress; however, when the linking cross joint or shear joint are encountered, they will transmit fluid from one\nfracture to another. Before they can transmit the fluid, there must be a buildup of fluid pressure because they\nrequire a higher normal stress to open. Once the fluid builds up to sufficient level to overcome the normal\nstress, fluid may be transmitted to another extension fracture which in turn will release the pressure to a\nlower state. Thus, flow through the fracture system itself leads to episodic buildup and release of pressure\nas different fracture systems are accessed. Fig. 2c  illustrates this effect in a Duvernay Formation equivalent\noutcrop exposure at Roche Miette in Jasper National Park, Alberta. The natural fracture system is comprised"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae52fbc-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 3, "chroma:document": "of multiple connecting fracture sets in which fluid flow pathways are established. The low permeability ofDownloaded from http://onepetro.org/SPEURCC/proceedings-pdf/18URC/1-18URC/D011S002R001/1236476/spe-189826-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae5303e-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 4, "chroma:document": "SPE-189826-MS 5\nthe matrix concentrates fluid into the fracture system as observed from the mineralogical alteration front\nfollowing the natural fracture system.\nFrom the above summary, it is concluded that the Duvernay possesses several properties that may\ncomplicate DFIT analysis: low matrix permeability, limiting leakoff from fractures; an extensive natural\nfracture system; and fine-scale mechanical layering, the latter two properties increasing the propensity\nfor intermittent fracture growth that could affect the DFIT signature. Direct observations of this behavior\nare illustrated through episodic spatial-temporal clustering behavior of microseismicity during a hydraulic\nfracture treatment.\nTheory and Methods\nDFIT Interpretation Methods\nDFIT analysis was pioneered by Nolte (1979), who introduced the Gfunction, based on material balance\nand the Carter leakoff model (Howard and Fast 1957) for before closure analysis. Gu et al. (1993) and Nolte"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae530c0-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 4, "chroma:document": "et al. (1997) demonstrated the possibility of observing afterclosure reservoir linear and pseudo-radial flow\nand their application in estimation of fracture geometry and reservoir properties.\nBarree and Mukherjee (1996)  and Barree (1998) recommended using the G-function and its diagnostic\nderivatives \n  to identify fracture closure. Barree (1998) and Barree et al. (2009) also presented\nsignatures for non-ideal leakoff behaviors such as tip extension, pressure-dependent leakoff (PDL) and\nheight recession/transverse storage based on G-function, square-root of shut-in time, and log-log plot of\npressure change with shut-in time plots. Fig. 3 summarizes normal leakoff and nonideal leakoff signatures\non G-function combination plots based on the Barree at al. (2009) interpretation methodology.\nFigure 3\u2014(a) Normal leakoff; (b) PDL; (c) tip extension; (d) storage/height"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae53142-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 4, "chroma:document": "recession signatures on G-function combination plots ( Barree et al. 2009 ).Downloaded from http://onepetro.org/SPEURCC/proceedings-pdf/18URC/1-18URC/D011S002R001/1236476/spe-189826-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae531c4-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 5, "chroma:document": "6 SPE-189826-MS\nMohamed et al. (2011) and Marongiu-Porcu et al. (2011) presented a model to predict the falloff pressure\ntrend of an idealized DFIT (normal leakoff) using standard pressure transient (PTA) log-log diagnostic plots.\nA log-log diagnostic plot of the basic falloff response shape predicted by their model is shown in Fig. 4 .\nThey identified normal leakoff as a 3/2 slope on the Bourdet-derivative (with respect to superposition time),\nand picked fracture closure as the deviation from the 3/2 slope.\nFigure 4\u2014Log-log diagnostic plot for an idealized fracture-injection/falloff test (Marongiu-Porcu et al. 2011).\nBachman et al. (2012) presented a combination of conventional diagnostic PTA plots to identify various\nflow regimes before and after fracture closure, summarized in Table 1. They demonstrated that a 3/2 on\nBourdet-derivative corresponds to a straight line trend on G-function derivatives, representing Carter leakoff\n(Nolte flow)."}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae5323c-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 5, "chroma:document": "(Nolte flow).\nTable 1\u2014Identification of flow regimes using derivative slope on log-log plot\nof pressure difference versus equivalent time functions (Bachman et al. 2012)\nLog-Log Flow Regime!\nCarter Linear Bilinear\nEquivalent Time\nDerivative\nFunctionEarly\nTime\nSlope\n-------\nEnds\ntD=0.08Late\nTime\nSlope\n-------\nStarts\ntD=5.0Early\nTime\nSlope\n-------\nEnds\ntD=0.04Late\nTime\nSlope\n-------\nStarts\ntD=4.0Early\nTime\nSlope\n-------\nEnds\ntD=0.13Late\nTime\nSlope\n-------\nStarts\n/n=8.0\nterd\u0394P/dter\n(Radial)1/1 3/2 1/2 1/2 1/4 1/4\n\u0394td\u0394P/dtec\n(Carter)1/1 1/1 1/2 0 1/4 -1/4\n\u0394t0.5d\u0394P/dtel\n(Linear)1/1 3/2 1/2 1/2 1/4 1/4\n\u0394t0.25d\u0394P/dteb\n(Bilinear)1/1 3/2 1/2 1/2 1/4 1/4Downloaded from http://onepetro.org/SPEURCC/proceedings-pdf/18URC/1-18URC/D011S002R001/1236476/spe-189826-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae532b4-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 6, "chroma:document": "SPE-189826-MS 7\nRecently, Zanganeh et al. (2018)  explained the spectrum of flow patterns and signatures observed before\nand after closure during DFITs. Their interpretation was based on rigorous numerical simulation which\nincluded the dynamic nature of fracture geometry (i.e. fracture expansion, tip extension, hinge closure,\nprogressive closure), variable leakoff rate (as a function of fracture surface area, fracture pressure, and\nfalloff time) and relative magnitude of afterflow with respect to total leakoff rate. They showed that with\nDFITs, unlike conventional buildup/falloff tests, afterflow caused by wellbore storage can last for a much\nlonger period of time, affecting pressure transient in various time periods during the pressure falloff.\nProblems with Application of Conventional DFIT Analysis Methods to the Duvernay\nSome DFIT responses in shale reservoirs, such as the Duvernay shale, are not consistent with those"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae5332c-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 6, "chroma:document": "interpreted through traditional analysis methods. Fig. 5  provides pressure profiles during injection for two\nDFITs conducted in the Duvernay Formation. There is no clear breakdown, or a sharp pressure drop after\nthe breakdown, as expected in more conventional reservoirs. In fact, in some cases there is an increasing\npressure trend after the breakdown even though the injection rate is constant or decreasing (see Field\nExample 2, Fig. 5b ). Another common signature observed in Duvernay DFITs is a large pressure drop at the\ntime of shut-in, e.g. 20 MPa and 25 MPa for Field Example 1 and 2, respectively. This significant pressure\ndrop is likely caused by another mechanism other than friction in the wellbore or tortuosity.\nFigure 5\u2014Pressure profile during injection for (a) Field Example 1; (b) Field Example 2.\nPTA and G-function diagnostic plots for Field Example 1 are provided in Fig. 6 . The trend of \ncurve is not similar to any of the signatures proposed by Barree et al. (2009). Except for the early time"}


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topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae533a4-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 6, "chroma:document": "unit slope, no other straight line trend with a specific slope is observed on any of the derivative plots.\nAccording to Zanganeh et al. (2018), the long transition after unit slope, with no sharp characteristic hump,\nindicates that leakoff from fracture to surrounding formation is not dominant. This is probably due to very\nlow matrix permeability of the formation coupled with small fracture surface area of the created fracture.\nSeveral fluctuations are observed on all of the derivative plots, each lasting for a considerable period of\ntime. In this case, there is no signature of fracture closure based on any of the identification methods.Downloaded from http://onepetro.org/SPEURCC/proceedings-pdf/18URC/1-18URC/D011S002R001/1236476/spe-189826-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae53426-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 7, "chroma:document": "8 SPE-189826-MS\nFigure 6\u2014G-function and PTA diagnostic plots for Field Example 1.\nBased on the geological information, geomechanical settings and evidence for episodic hydraulic fracture\ngrowth in the Duvernay Formation provided in the previous section, combined with the anomalous DFIT\nobservations just illustrated, two hypotheses are presented to explain the DFIT behavior in the Duvernay\nformation; moving-hinge closure with tip extension, and propagation through activation of secondary\nfractures. As will be discussed below, model-generated synthetic results are compared with field data, and\nnecessary modifications are made to calibrate the model. The observations from the calibrated model are\nthen used to explain field behaviors.\nModel Description and Setup\nA customized fully-coupled stress-pore pressure simulator (Abaqus Analysis User's Guide 2016) is used\nherein to generate synthetic DFIT responses. The customized model is capable of simulating all the physical"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae534a8-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 7, "chroma:document": "processes involved in a typical DFIT including: porous media deformation; fluid flow inside the reservoir;\nhydraulic fracture initiation, propagation and closure (based on the cohesive zone method); compliance\nchange before and after closure; residual fracture aperture and conductivity; and fluid flow inside the fracture\nand fluid interaction between the fracture and reservoir (leakoff).\nThe modeling procedure is described in detail in Zanganeh et al. (2017) and Zanganeh et al. (2018).\nThe cohesive zone method (CZM) is used to model hydraulic fracture initiation, propagation and closure.\nWith the CZM, the fracture is modeled as a gradual separation between two material (rock) surfaces. This\nseparation is modeled as a progressive degradation of cohesive strength along the cohesive layer, which\nis a pre-defined surface embedded in the rock and follows a traction-separation law. Model 1 assumes\npropagation of a single planar primary fracture (HF; Fig. 7a). However, in Model 2, there is a pre-existing"}


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topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae53520-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 7, "chroma:document": "network of natural fractures (NF; Fig. 7b ), similar to the system observed in the Duvernay outcrop (Fig.\n2c). The cohesive elements are embedded in the formation rock - they are assumed to be non-existent in the\nmodel until fracture initiation and propagation criteria are reached, at which time these elements act as the\npotential pathway for fracture growth. In both simulation models, a matrix permeability of 25 nd was used.Downloaded from http://onepetro.org/SPEURCC/proceedings-pdf/18URC/1-18URC/D011S002R001/1236476/spe-189826-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae535a2-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 8, "chroma:document": "SPE-189826-MS 9\nFigure 7\u2014Simplified schematics of (a) Model 1; (b) Model 2.\nIn the previous simulation models of Zanganeh et al. (2017 and 2018 ), tangential fluid flow inside the\nfracture is calculated using Poiseuille's law:\n(1)\nwhere w is the fracture opening, \u03bc is the fluid viscosity and Pf is the fluid pressure along the fracture length\n(x direction). For an injection fluid with low viscosity (i.e. water), even a small fracture aperture of 0.1\nmm, results in a fracture with large tangential permeability (conductivity) without any significant pressure\ngradient inside the fracture. To achieve synthetic pressure responses similar to the presented field examples\nin the Duvernay Formation, especially during pumping and early shut-in time, the \u03b2 coefficient is introduced\ninto Poiseuille's formula ( Eq. 1 ). After several sensitivity simulation runs, a \u03b2 value of 1000 was selected\nas the optimum value.\nResults and Discussion\nModel 1: Tip Extension"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae53610-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 8, "chroma:document": "Results and Discussion\nModel 1: Tip Extension\nFig. 8a  provides the simulated pressure profile, G-function semi-log derivative and PTA plots during\npressure falloff for Model 1. The overall trends of the curves are similar to the Field Example 1 ( Fig. 6).\nAt the time of breakdown, the created fracture has finite conductivity with a considerable pressure gradient\ninside the fracture. This results in the sudden pressure drop at the time of shut-in.Downloaded from http://onepetro.org/SPEURCC/proceedings-pdf/18URC/1-18URC/D011S002R001/1236476/spe-189826-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae53688-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 9, "chroma:document": "10 SPE-189826-MS\nFigure 8\u2014(a) PTA diagnostic plots; (b) pressure profile and G dP/\ndG curves. Tip extension phases are shown with the dotted squares.\nAs shown by Zanganeh et al. (2018), moving hinge closure occurs during the transition from afterflow\ndominance (caused by wellbore storage) to leakoff dominance. Due to low matrix permeability and the\npressure gradient inside the fracture in the Model 1, coupled with the presence of afterflow, the pressure\nfront moves to the tip of fracture and causes tip extension of the primary fracture. Pressurization and\ndepressurization during tip extension can be repeated several times (Fig. 9) during the transition period\nbefore leakoff dominates the falloff process. Tip extension phases are shown as fluctuations on pressure\nderivative plots. It must be noted that in the simulation models, the magnitude and duration of these\nfluctuations are controlled by the size of fracture elements which is uniform throughout the length of"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae5370a-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 9, "chroma:document": "fracture. However, in reality, the magnitude and duration of each tip extension phase can be different.\nFigure 9\u2014Plan view of a single wing of the fracture showing pressure gradient inside the\nfracture and tip extension phases during falloff. The fracture aperture is magnified 1000 times.\nIn Model 1, leakoff dominance starts after 4.5 log-cycles and fracture closure does not occur.Downloaded from http://onepetro.org/SPEURCC/proceedings-pdf/18URC/1-18URC/D011S002R001/1236476/spe-189826-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae53778-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 10, "chroma:document": "SPE-189826-MS 11\nModel 2: Pre-existing Fractures and Tip Extension\nAs mentioned in the model description and setup section, Model 2 uses a pre-existing network of natural\nfractures (NF), similar to the system observed in the Duvernay outcrop. Pre-existing natural fractures can\nbe activated during injection and falloff and affect propagation direction and pressure response. Fig. 10a\nillustrates the pressure profile during injection and early shut-in period. There is no significant pressure\ndrop at the time of breakdown due to the low conductivity of the primary fracture. As the primary fracture\nhits the pre-existing fracture, propagation temporarily stops (upward trend on pressure profile) until the pre-\nexisting fracture is activated. Then, the propagation continues in the original direction perpendicular to the\nminimum horizontal stress ( Fig. 10b ).\nFigure 10\u2014(a) Pressure profile during injection and early shut-in time for Model 2; (b) Propagation as the"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae537f0-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 10, "chroma:document": "primary fracture hits and activates a preexisting fracture (fracture apertures are magnified 1000 times).\nThe falloff behavior is similar to Model 1. Given the low matrix permeability and leakoff, reactivation\nof secondary fractures can happen during the falloff period, too. The response on pressure derivative plots\nwill be similar to tip extension phases as illustrated in Model 1.\nField Example 1\nThe observed trends of Field Example 1 in Fig. 6  can be explained based on the simulation Model 1. The\nabsence of a clear breakdown and the significant pressure drop at the time of shut-in ( Fig. 5a) is caused by\nlow conductivity and the large pressure gradient inside the created fracture.\nThe PTA plots for this dataset are revisited in Fig. 11. The long transition after the early time unit slope,\nwith no sharp characteristic hump, indicates that leakoff from the fracture to surrounding formation is\nnot dominant. This is due to low matrix permeability of the formation coupled with low conductivity and"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae53868-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 10, "chroma:document": "pressure gradient inside the fracture. Three major extension cycles are observed during the falloff period\ndemonstrated by the fluctuations and inflection points. The pressure changes at the end of fall period are\nvery small as the leakoff is low and no additional extension occurs. As a result, the end of falloff period\nis highly affected by ambient temperature changes. No signature of fracture closure is observed after 200\nhours. Therefore, no reliable estimate of closure pressure and formation permeability can be made in this\nexample.Downloaded from http://onepetro.org/SPEURCC/proceedings-pdf/18URC/1-18URC/D011S002R001/1236476/spe-189826-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae538e0-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 11, "chroma:document": "12 SPE-189826-MS\nFigure 11\u2014PTA plots for Field Example 1 showing the interpretation based on tip extension cycles.\nField Example 2\nIn this DFIT, a total volume of 6.8 m3 of fresh water was injected during 3 minutes of pumping. The pressure\nvalues were recorded using surface gauges. The increasing trend after breakdown while the injection rate\nis kept constant ( Fig. 5b ) indicates the activation of secondary fractures in addition to the primary fracture\nduring the injection. Again, there is a long transition of about 2 log-cycles after the early unit slope. There are\ntwo major opening cycles during this transition, caused by activation of secondary fractures or extension of\nprimary fracture during falloff, which creates additional fracture surface area for fluid leakoff from fracture\nsystem to the formation. As a result, leakoff dominance starts after about 2.2 hours. The slope of \n  and\n plots during leakoff dominance is smaller than 3/2 and 1/2, respectively; and there is no evidence of"}


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topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae53958-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 11, "chroma:document": "Carter leakoff. The closure is picked at the inflection point on \n  curve that corresponds to change of\nslope on PPD and \n  curves, with closure pressure of 32.1 MPa and closure time of 51.4 hours. Formation\nlinear or radial flow are not observed after 300 hours of shut-in time, and no reliable estimate of formation\npermeability or initial pressure can be made.\nFigure 12\u2014PTA plots for Field Example 2.Downloaded from http://onepetro.org/SPEURCC/proceedings-pdf/18URC/1-18URC/D011S002R001/1236476/spe-189826-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 12, "chroma:document": "SPE-189826-MS 13\nConclusions\nDFIT responses in the Duvernay Formation for the cases studied are controlled by the following\nmechanisms:\n\u2022Episodic fracture growth during injection and falloff. The hydraulic fracture does not grow in a\nsimple, steady and continuous way. Growth occurs episodically through growth phases followed\nby relative calm.\n\u2022Low permeability of the matrix. This property delays the transition to leakoff dominance in the\nfalloff period, and results in long fracture closure times. Also, low leakoff favors the episodic\nfracture growth (moving hinge-closure and tip extension) as it provides a mechanism to release\npressure and create additional fracture surface area.\n\u2022Long lasting afterflow (caused by wellbore storage) and transition period due to limited leakoff.\n\u2022Low conductivity fractures. The fractures, both primary and pre-existing, have a low conductivity\nresulting in pressure gradient within the fractures. This explains the unclear breakdown point and"}


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topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 12, "chroma:document": "pressure responses after the breakdown.\nThe above mechanisms result in complex leakoff and pressure behavior. Therefore, the assumption of\nCarter leakoff, and the traditional fracture closure picks based on a straight-line tangent to the semi-log\nderivative on a G-function semi-log derivative plot or 3/2 slope on Bourdet-derivative plot are not reliable.\nFinally, it is very unlikely for the formation radial flow to occur during short falloff periods of days or weeks.\nNomenclature\nField Variables\nGG-function time, dimensionless\nmSlope of straight line, dimensionless\nPPressure, Pa\nPfFracture pressure (fluid pressure in the cohesive element), Pa\nqfracGap flow rate within the cohesive element, m3/sec\nShmaxMaximum horizontal stress, Pa\nShminMinimum horizontal stress, Pa\ntaAgarwal's time, dimensionless\ntpPumping time, sec\nwFracture opening (aperture), m\nGreek Variables\n\u03b2Coefficient in the Poiseuille's formula, dimensionless\n\u0394tShut-in time, sec\n\u03bcFracturing fluid viscosity, cp\nReferences"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 12, "chroma:document": "\u0394tShut-in time, sec\n\u03bcFracturing fluid viscosity, cp\nReferences\nAbaqus Analysis User's Guide  2016 . Dassault Systemes Simulia Corp., Providence, RI.\nAgarwal, R. G. 1980 . A New Method to Account for Producing Time Effects when Drawdown Type Curves are Used to\nAnalyze Pressure Buildup and Other Test Data. Presented at the SPE Annual Technical Conference and Exhibition,\nDallas, Texas, 21-24 September. SPE-9289-MS. http://dx.doi.org/10.2118/9289MS\nBachman, R. C. , Walters, D. A. , Hawkes, R. A. et al  2012 . Reappraisal of the G Time Concept in Mini-Frac Analysis.\nPresented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 8-10 October. SPE-160169-\nMS. http://dx.doi.org/10.2118/160169MSDownloaded from http://onepetro.org/SPEURCC/proceedings-pdf/18URC/1-18URC/D011S002R001/1236476/spe-189826-ms.pdf/1 by University of Houston user on 27 October 2023"}


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topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae53b2e-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 13, "chroma:document": "14 SPE-189826-MS\nBao, X.  and Eaton, D. W. 2016. Fault Activation by Hydraulic Fracturing in Western Canada. Science 354:1406-1409.\nhttps://doi.org/10.1126/science.aag2583\nBarree, R. D. and Mukherjee, H. 1996 . Determination of Pressure Dependent Leakoff and Its Effect on Fracture Geometry.\nPresented at the SPE Annual Technical Conference and Exhibition, Denver, Colorado, 6-9 October. SPE-36424-MS.\nhttp://dx.doi.org/10.2118/36424MS.\nBarree, R. D. 1998 . Applications of Pre-Frac Injection/Falloff Tests in Fissured Reservoirs-Field Examples. Presented\nat the SPE Rocky Mountain Regional/Low Permeability Reservoirs Symposium, Denver, Colorado, 5-8 April.\nSPE-39932-MS. http://dx.doi.org/10.2118/39932MS .\nBarree, R. D. , Baree, V . L. , and Craig, D. P. 2009 . Holistic Fracture Diagnostics: Consistent Interpretation of Prefrac\nInjection Tests Using Multiple Analysis Methods. SPE Production & Operations 24(3): 396 -406. SPE-107877-PA.\nhttp://dx.doi.org/10.2118/107877PA"}


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topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae53ba6-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 13, "chroma:document": "http://dx.doi.org/10.2118/107877PA\nBrenner, S. L. and Gudmundsson, A. 2004. Arrest and Aperture Variation of Hydrofractures in Layered Reservoirs.\nGeological Society, London, Special Publications  231(1): 117- 128. https://doi.org/10.1144/GSL.SP.2004.231.01.08\nChopra, S. , Sharma, R. K., Ray, A. K. et al  2017 . Seismic Reservoir Characterization of Duvernay Shale With\nQuantitative Interpretation and Induced Seismicity Considerations\u2014A case study. Interpretation 5(2): T185 -T197.\nhttps://doi.org/10.1190/INT20160130.1\nCooke, M. L. and Underwood, C. A. 2001. Fracture Termination and Step-Over at Bedding Interfaces Due to Frictional Slip\nand Interface Opening . Journal of Structural Geology 23: 223\u2013238. https://doi.org/10.1016/S01918141(00)000924\nCreaney, S  and Allan, J.  1990 . Hydrocarbon Generation and Migration in the Western Canada Sedimentary Basin.\nGeological Society, London, Special Publications 50: 189\u2013203."}


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topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae53cbe-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 13, "chroma:document": "Geological Society, London, Special Publications 50: 189\u2013203.\nDavis, M. and Karlen, G. 2014 . A Regional Assessment of the Duvernay Formation: A World-Class Liquids-Rich Shale\nPlay: Geoconvention, Calgary, Alberta, Canada.\nFox, A. , Soltanzadeh, M. , Watson, N.  et al  2015 . The Link Between Lithology and Rock Fractures in the Duvernay. 2015\nGussow Conference: Fine-Grained Rocks: Resources to Reserves, Banff, Alberta, Canada, October 13-15.\nFox, A. D. and Soltanzadeh, M.  2015, A Regional Geomechanical Study of the Duvernay Formation . Geoconvention,\nCalgary, Alberta, Canada.\nGhanizadeh, A. , Bhowmik, S. , Haeri-Ardakani, O.  et al 2015. A Comparison of Shale Permeability Coefficients\nDerived Using Multiple Non-Steady-State Measurement Techniques: Examples from the Duvernay Formation, Alberta\n(Canada). Fuel  140: 371\u2013387. https://doi.org/10.1016/j.fuel.2014.09.073\nGoertz-Allmann, B. P., Gibbons, S. J., Oye, V .  et al  2017 . Characterization of Induced Seismicity Patterns"}


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topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae53d40-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 13, "chroma:document": "Derived from Internal Structure in Event Clusters. J. Geophys. Res. Solid Earth 122: 3875 \u20133894 . http://\ndx.doi.org/10.1002/2016JB013731\nGu, H. , Elbel, J. L., Nolte, K. G. et al  1993 . Formation Permeability Determination Using Impulse-Fracture Injection.\nPresented at the SPE Production Operations Symposium, Oklahoma City, Oklahoma, 21-23 March. SPE-25425-MS.\nhttps://doi.org/10.2118/25425MS\nHarris, N. B. , Miskimins, J. L.  and Mnich, C. A.  2011 . Mechanical Anisotropy in the Woodford Shale, Permian Basin:\nOrigin, Magnitude, and Scale. The Leading Edge 30(3): 284-291. https://doi.org/10.1190/1.3567259\nHoward, C. C., and Fast, C. R. 1957. Optimum Fluid Characteristics for Fracture Extension. API Drilling and Production\nPractice  24(1): 261-270. API-57-261.\nKnapp, L. J. , McMillan, J. M  and Harris, N. B. 2017. A Depositional Model for Organic-Rich Duvernay Formation\nMudstones . Sedimentary Geology  347: 160\u201382. https://doi.org/10.1016/j.sedgeo.2016.11.012"}


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topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae53db8-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 13, "chroma:document": "Krauklis, P. V .  1962 . On Some Low-Frequency Vibrations of A Liquid Layer in An Elastic Medium. J. App. Mathematics\nand Mechanics 26( 6): 1685-1692. https://doi.org/10.1016/00218928(62)902034\nLiang, C. , O'Reilly, O. , Dunham, E. M.  et al 2017. Hydraulic Fracture Diagnostics from Krauklis-Wave Resonance and\nTube-Wave Reflections. Geophysics  82(3):D171-D186 . https://doi.org/10.1190/geo20160480.1\nMarongiu-Porcu, M. , Ehlig-Economides, C. A.  and Economides, M. J. 2011 . Global Model for Fracture Falloff Analysis.\nPresented at the SPE North American Unconventional Gas Conference and Exhibition, The Woodlands, Texas, 14-16\nJune. SPE-144028-MS. http://dx.doi.org/10.2118/144028MS\nMohamed, I. M. , Nasralla, R. A. , Sayad, M. A.  et al 2011. Evaluation of After-closure Analysis Techniques for Tight\nand Shale Gas Formations . Presented at the SPE Hydraulic Fracturing Technology Conference and Exhibition, The\nWoodlands, Texas, 24-26 January. SPE-140136-MS. http://dx.doi.org/10.2118/140136MS"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae53e30-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 13, "chroma:document": "Nolte, K. G.  1979 . Determination of Fracture Parameters From Fracturing Pressure Decline. Presented at the\nSPE Annual Technical Conference and Exhibition, Las Vegas, Nevada, 23-26 September. SPE-8341-MS. http://\ndx.doi.org/10.2118/8341MS\nNolte, K. G., Maniere, J. L., and Owens, K. A. 1997. After-Closure Analysis of Fracture Calibration Tests. Presented\nat the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 5-8 October. SPE-38676-MS. https://\ndoi.org/10.2118/38676MSDownloaded from http://onepetro.org/SPEURCC/proceedings-pdf/18URC/1-18URC/D011S002R001/1236476/spe-189826-ms.pdf/1 by University of Houston user on 27 October 2023"}


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topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae53ea8-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 14, "chroma:document": "SPE-189826-MS 15\nReiter, K., O. Heidbach, D.  Schmitt, K.  et al  2014 . A Revised Crustal Stress Orientation Database for Canada.\nTectonophysics  636: 111\u2013124. https://doi.org/10.1016/j.tecto.2014.08.006\nRivard, C. , Lavoie, D. , Lefebvre, R. et al  2014 . An Overview of Canadian Shale Gas Production and Environmental\nConcerns . International Journal of Coal Geology  126: 64-76. https://doi.org/10.1016/j.coal.2013.12.004\nSchultz, R. , R. Wang , Y . J. Gu, et al  2017 . A Seismological Overview of the Induced Earthquakes in the Duvernay Play\nnear Fox Creek, Alberta . J. Geophys. Res. Solid Earth  122: 492-505. http://dx.doi.org/10.1002/2016JB013570\nShapiro, S. A.  and Dinske, C.  2009 . Fluid Induced Seismicity: Pressure Diffusion and Hydraulic Fracturing. Geophysical\nProspecting  57(2): 301-310. http://dx.doi.org/10.1111/j.13652478.2008.00770.x\nTary, J. , Baan, M.  and Eaton, D.  2014 . Interpretation of Resonance Frequencies Recorded During Hydraulic Fracturing"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae53f20-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-189826-ms.pdf", "page": 14, "chroma:document": "Treatments. J. Geophys. Res. Solid Earth  119: 1295 -1315 . http://dx.doi.org/10.1002/2013JB010904\nZanganeh, B. , Clarkson C. R., and Hawkes, R. V . 2017. Reinterpretation of Fracture Closure Dynamics During Diagnostic\nFracture Injection Tests . Presented at the SPE Western Regional Meeting, Bakersfield, California, 23-27 April.\nSPE-185649-MS. https://doi.org/10.2118/185649MS\nZanganeh, B. , Clarkson C. R., and Jones, J. R. 2018 . Reinterpretation of Flow Patterns During DFITs Based on Dynamic\nFracture Geometry, Leakoff and Afterflow. Presented at the SPE Hydraulic Fracturing Technology Conference, The\nWoodlands, Texas, 23-25 January. SPE-189840-MS. https://doi.org/10.2118/189840MSDownloaded from http://onepetro.org/SPEURCC/proceedings-pdf/18URC/1-18URC/D011S002R001/1236476/spe-189826-ms.pdf/1 by University of Houston user on 27 October 2023"}


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topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae53f8e-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 0, "chroma:document": "SPE 167074  \nApplication of Open-hole Diagnostic Fracture Injection Test Results to \nRegional Stress Interpretation in Bowen Basin Coals  \nScott, M, Mazumder, S, Gibson, M, Probst, P, Arrow Energy  \nCopyright 2013, Society of Petroleum Engineers  \n \nThis paper was prepared for presentation at the SPE  Unconventional Resources Conference and Exhibition -Asia Pacific held in Brisbane, Australia, 11\u2013 13 November 2013.  \n \nThis paper was selected for presentation by an SPE program committee following review of information contained in an abstract  submitted by t he author(s). Contents of the paper have not been \nreviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessar ily reflect any position of the Society of Petroleum Engineers, its"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae54010-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 0, "chroma:document": "officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Socie ty of Petroleum Engineers is prohibited. Permission to \nreproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.  \n \n \nAbstract  \nDiagnostic fracture injection testing (DFIT) has become an established method of well testing in low permeability \nunconventional reservoirs \u2013  particularly in shales and coal seam gas  (CSG) . As well as providing in -situ measurements of \npermeability and reservoir pressure, the test allows estimation of the closure pressure (and fluid loss characteristics) for the \nformation under investigation , which is assumed to be a measure of minimum horizontal stress ( \u03c3h).  \n \nArrow Energy is currently conducting a wide -scale exploration and well testing programme in the Bowen Basin region of"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae54088-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 0, "chroma:document": "Queensland, Australia, in support of its plan ned CSG to liquefied natural gas (LNG)  project. This programme is mainly \nfocussed on evaluation of formations within the Moranbah and Rangal Coal Measures; these are typically present as thick, low \npermeability zones.   \nTraditional Drill Stem Test (DST) and Injection Fall- Off Test (IFOT) results have proven unreliable within such low \npermeability and under -pressured reservoirs. The limited drawdown generated by DSTs in such formations has historically \nbeen an issue for th ese, and other, reservoirs. Similarly, difficulties have been encountered with regard to the appropriate \nmanagement of IFOT injection rates in the Bowen Basin coals, which can fracture at very low rates; the resultant diagnostic \ntypecurves needed for analysis of such a \u201cfailed\u201d test have tended to introduce an u nnecessary level of uncertainty in the \nresults."}


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topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae5410a-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 0, "chroma:document": "results.  \n At present, the preferred exploitation method for these formations is extended -reach, open -hole, horizontal in -seam wells. As \nsuch, very few instances of cased -hole completions are available. Whilst the DFI T technique has previously been widely \napplied in cased -hole completions, largely due to its prevalence as part of hydraulic fracture stimulation treatment in North \nAmerica, its application has been extended successfully to open -hole testing as part o f this programme. Arrow has to date \ncompleted over 140 open -hole DFITs in this region, with an approximately 80% success rate in interpreted parameters with \nreasonable confidence.  \n \nThe results of this programme have been incorporated into a basin -wide interpre tation of regional stresses and subsurface \nproperties. These results have been used , in combination with Mechanical Earth Models (MEM) , to evaluate optimal  lateral"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae54182-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 0, "chroma:document": "well orientation , hydraulic fracture treatment design , as well as the mapping of variable st ress gradients in an effort to better \nunderstand the distribution of permeability trends across different geo -domains . \n  \nIntroduction  \nArrow Energy\u2019s Bowen Basin operations are located in an area characterised by thick, continuous coal seams, with low \nformation permeability. Typical values of permeability are in the order of 0.1 -10mD. Production experience within the basin \nhas already pro vided sufficient information to frame the development concept around exploitation of the low -deliverability \nreservoir; identified well types include concepts such as horizontal in -seam or hydraulically stimulated wells . \n \nThe focus of any large -scale, value -driven data acquisition programme is to better understand:  \nDownloaded from http://onepetro.org/SPEURCE/proceedings-pdf/13URCE/All-13URCE/SPE-167074-MS/1593465/spe-167074-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae541fa-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 1, "chroma:document": "2  SPE 167074  \n\u2022 Regional Permeability Trends:  Well concepts and development options may be identified based on regional trends \nin permeability; areas of high er, or lo wer, than expected permeabilities may also pla y a role in development decision -\nmaking processes.  \n\u2022 Implications for Well Construction:  A number of subsurface elements , over and above permeability , are critical \ncomponents in refining well layout and detailed construction designs.  For example, cleat orien tation is also a material \nconsideration in planning the azimuth of horizontal well with respect to this system: a higher productivity is \ntheoretically achieved by intersecting as many face cleats as possible.  \n \nBoth the estimation of probability of success for drilling execution and production forecasting in a given region require an \nintegrated and comprehensive assessment  of the subsurface environment; such a n analysis should be focused on identify ing"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae54272-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 1, "chroma:document": "which variables will prove the li miting factor in any development scenario.  \n In the Bowen Basin, for example, the traditional response to encountering thick, low -permeability coal seams has been to \npropose a horizontal well development. In highly faulted areas, or regions where geological  control suggests frequent splitting \nand merging of individual seams, this concept becomes less viable; this is especially true when attempting to minimise surfac e \nfootprint through the use of extended- reach drilling techniques, as geology may prove a greater constraint than the technical \nlimitations of the available rig -fleet.  \n \nBowen Basin  \nThick, continuous formations with a high net -to-gross ratio are present across the majority of the Bowen Basin. In gener al, \nthere is a trend for permeability to decrease with depth  within these formations . This is compounded by increased complexity"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae542e0-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 1, "chroma:document": "and low net -to-gross figures in certain regions and sequences, which are likely to impede in -seam drilling via geo -steering. \nThese  features have a material impact on well type selection and spacing.  \n \nA suitable data acquisition programme comprising petrophysical (i.e. dipole sonic and geochemical) logs and core analyses, coupled with mechanical earth models (MEM), is necessary to identify the optimum well design  per region , as a function of \nlocal stress fields and property contrasts.  \n \nGeology  \nThe Late Permian Blackwater Group is the primary target formation for coal seam gas development in the northern Bowen \nBasin. This group was deposited within extensive fluvial and lacustrine environments that prograded into the basin initially \nfrom the we st (German Creek Coal Measures , GCCM ); later, the Moranbah, Rangal and Fort Cooper Coal Measures ( MCM, \nRCM, and FCCM) were deposited from the west, north and east  (Fielding et al.,  1995) . The latter three coal measures form the"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae54362-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 1, "chroma:document": "basis of Arrow Energy\u2019s development focus within its current acreage in the Bowen Basin . \n \nCoal  Permeability  \nCoal is a poro- elastic medium, in which the primary permeability is due to the naturally fractured structure of the cleat system. \nNatur al, orthogonal fractures, known as \u201ccleats\u201d, are the primary source of permeability in coal; these are categorised as  \u201cface\u201d \nand \u201cbutt\u201d cleats . \n \nFace and butt cleats create a tortuous flow path, with two transport types  during production , whereby t ransport from matrix to \nfractures (gas only) is diffusive , and f racture transport is characterised by continuum flow (water and gas) .  \n Very little consideration is given to  the impact of such a cleat system on fluid transport in coal ; it is generally assumed to be \nsimilar to o ther fractured / dual porosity reservoirs, or even clastics . In reality, horizontal anisotropy, as well as randomly \ndistributed \u201cbundles\u201d of cleats, may have a significant impact on the permeability measured by well tests."}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae543da-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 1, "chroma:document": "Depending upon the stress magnitude and orientation, depletion of the (incompressible) fracture fluids may have a dr astic \nimpact on permeability ; higher stresses perpendicular to the face cleat orientation may result in \u201cclosure\u201d, or compaction, of \nthe cleat system, reducing permeability. This thus impacts the magnitude of resistance in the horizontal plane, resulting i n \nclosure  of the cleat network perpendicular to the maximum horizontal stress.  As such, q uantification of the orientations of face \ncleats and horizontal stresses may assist in assessing the extent to which pressure -dependent permeability is likely to impac t \nlong-term production.  \n This compaction effect may be accelerated by the production process, whereby depletion of the reservoir fluids changes the \neffective  stress (\n\u03c3\u2019), defined as:  \n Downloaded from http://onepetro.org/SPEURCE/proceedings-pdf/13URCE/All-13URCE/SPE-167074-MS/1593465/spe-167074-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae54452-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 2, "chroma:document": "SPE 167074   3 \n\ud835\udf48\u2032=\ud835\udf48\u2212\ud835\udc77\ud835\udc91 ( 1 ) \n \nIn coal formations, the critical component of this total stress model is the effective horizontal stress, as  the principal horizontal \nstresses often act pe rpendicular to the cleat system, at least at the time of cleat formation (Laubach et al.,  1997) . A numbe r of \nmodels exist which predict the impact of this changing net stress on permeabilit y (Shi & Duruc an, 2004,  Cui & Bustin, 2005 ); \none such model is as follows : \n \n\ud835\udc58=\ud835\udc580\ud835\udc52\ufffd\u22123\ufffd\ud835\udc36\ud835\udc53\ufffd\ud835\udf0e\u2032\u2212\ud835\udf0e0\u2032\ufffd\ufffd\ufffd ( 2 ) \n \nNote that t he basic geo -mechanical models propose a second, competing phenomenon, \u201cmatrix shrinkage\u201d, which occurs when \ngas desorbs  from the surface of the coal micropores, reducing the matrix volume.  This has been illustrated through field \nanalysis of production wells in the Bowen Basin (Mazumder  et al. , 2012).   \n \nThe brevity of well tests is likely to preclude the observation of such phenomena, but the parameters required to estimate th e"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae544c0-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 2, "chroma:document": "long-term implications are critical; this can be achieved through the application of suitable test types.  Arrow  has undertaken a \nnumber field and core -based studies in order to quantify these key parameters (Mazumder et al., 2012, Conn ell et al., 2013), \nand their incorporation into improved reservoir forecasting practices is currently ongoing ( Feng et al ., 2012) . \n \n \nCoal Formation Stresses  \nMeasurements from a variety of Bowen Basin coal formations are included in Figure 1, illustrating the regional trends in \nmaxi mum and minimum horizont al, as well as vertic al, stresses.  Based on these data, it is common for the vertical stress to be \ngreater than the maximum horizontal stress (i.e. a n ormal stress regime) at shallow depth s. This typically transitions to a \nStrike -Slip stress system at approximately 1000- 1300ft , the actual transition point between stress sys tems varies within each \nregion."}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae54538-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 2, "chroma:document": "region.   \n \nThis transition has been confirmed in a number of Mechanical Earth Modelling studies currently underway in Arrow Energy\u2019s \nBowen Basin tenements; these models are currently being utilised  in appraisal programmes to better define the characteristics \nof each area as part of the stimulation planning and design process.   \nThe Strike -Slip (\n\u03c3H > \u03c3h > \u03c3v) system is preferred for the purposes of hydraulic fracturing, as it provides the best chance of \ndeveloping vertic al, full-height fractures orthogonal to the wellbore. Conversely, the Extensional (Normal ) or Compressional \n(Reverse) systems are not p referred from the perspective of fracture success.  \n \nThe local stress orientations may change between the interburden and coal formations at a given depth; this poses certain \nissues from a number of perspectives:  \n \n\u2022 Horizontal Drilling:  Drilling upwards throu gh such an interbedded zone exposes the lateral well to a number of"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae545a6-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 2, "chroma:document": "different principal stress orientations, which may affect the stability of open -hole wellbores.  A sub -optimal stress \nbalance may impede the drilling process, resulting in borehole management becoming problematic in a given \nazimuth. This may, in turn, limit the potential length of any horizontal wells which may be drilled.  \n\u2022 Hydraulic Fracturing:  Hydraulic fracture confinement within a coal formation is critical to the success of any \nstimulation treatment, and depends heavily on the magnitude and direction of stress (and mechanical strength) contrasts between adjacent formations. The geometry of any hydraulic fracture may change significantly upon \nescaping such confinement; this will affect the  treatment, and resultant production, performance.  The near -region \nstress regimes and contrasts may be used to estimate the likelihood of successfully stimulating coal formations (i.e. \nwith respect to fracture containment), and thus be used to discern a per -well probability of success (POS) factor for"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae5461e-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 2, "chroma:document": "such a development scenario.  \n \nData Acquisition  Strategy  & Formation Stress Mapping  \nThe well testing workflow  adopted by Arrow Energy to evaluate and effectively utilise the key subsurface parameters is \noutlined in  Figure 2. This paper outlines the testing strategy adopted by Arrow Energy in support of this process. The \nMechanical Earth Modelling (MEM) stage, as it applies to the Bowen Basin, is outlined in a separate paper (Mazumder et al.,  \n2013).  \n \nA major focus of this process is on the relative merits of each type of well test at a development planning level. For example, \nin a high permeability (high porosity) formation, high injection rates and large volumes may be required to achieve formation \nbreakdown , rendering a destructive injection test unviable. Furthermore, at higher poroperm values, stimulated completions or"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae546dc-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 2, "chroma:document": "horizontal wells may be unnecessary, negati ng the requirement for additional geo -mechanical data.  Downloaded from http://onepetro.org/SPEURCE/proceedings-pdf/13URCE/All-13URCE/SPE-167074-MS/1593465/spe-167074-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae54754-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 3, "chroma:document": "4  SPE 167074  \n \nAs a result, Diagnostic Fracture Injection Testing (DFIT) has been employed for this purpose of identify ing in-situ stress \nparameters in regions generally considered to be of low permeability . Previous data acquisition work undertaken by  Arrow \nEnergy , supplemented by data from various mining companies , has been sufficient to provide an understanding of the \npermeability trends in the region  and focus activities . \n \nVisualisation is a key element of all in terpretation and decision -making, especially at a cross -discipline level. A geologist can \nlook at a map and identify one critical subsurface element, whilst an engineer may see another \u2013  all of these are relevant to \ninformed decision making. Stress data can be used in the following:  \n \n\u2022 Estimation of permeability versus stress trends;  \n\u2022 Assessment of pressure -dependent permeability effects;  and, \n\u2022 Estimation of effectiveness of well design (i.e. hydraulic fracture containment, wellbore stability)."}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae547cc-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 3, "chroma:document": "Diagnostic Fracture Injection Testing  \nTraditional Drill Stem Test (DST) and Injection Fall- Off Test (IFOT) results have proven unreliable within such low \npermeability and under -pressured reservoirs. The limited drawdown generated by DSTs in such formations has histor ically \nbeen an issue for these, and other, reservoirs. Similarly, difficulties have been encountered with regard to the appropriate \nmanagement of IFOT injection rates in the Bowen Basin coals, which can fracture at very low rates; the resultant diagnostic \ntypecurves needed for analysis of such a \u201cfailed\u201d test have tended to introduce an unnecessary level of uncertainty in the \nresults.  \n \nWhilst DSTs and IFOTs involve a relatively lower equipment cost, a DFIT provides a wider array of valuable data, which can  \nbe used to inform project -level decisions, i.e. well layouts and, potentially, stress -related sweet -spots, as opposed to simply"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae54844-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 3, "chroma:document": "providing the basis for well productivity estimation . The chief value of the DFIT, therefore, lies in the ability to acquire \nadditional (potentially more critical) data, as part of the testing process.  \n \nArrow Energy is conducting a large -scale data acquisition programme across the Bowen Basin in support of its Upstream LNG \nProject planning. This includes the coring, logging and te sting of 43 boreholes in the main target formations. In addition, a few \ncased and perforated frac wells have been drilled as part of this programme for production testing purposes; however, the large \nmajority of these tests (97%) have been conducted open -hole. \n \nTheory  \nA small volume of  low-viscosity fluid is pumped at  a low rate to achieve formation breakdown ; the use of formation water \nwherever possible is beneficial,  both in ter ms of leak -off characteristics as well as fluid compatibilities with any clay minerals"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae548b2-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 3, "chroma:document": "present in the formation . The intentional creation of this fracture is the key difference between the DFIT and IFOT test types; \nformation breakdown during IFOTs has traditio nally resulted in additional uncertainties in the interpreted reservoir pr operties.  \n \nOnce a fracture has been developed, the pressure is allowed to \u2018fall -off\u2019, or equalise with the reservoir, to identify key events \nand flow periods . The rate of pressure fall -off is proportional to the exposed surface area of the formation \u2013  once  a step -change \nin equalisation rate is observed, it is assume d that the fracture has closed; this occurs at the point at which fluid in the fracture \nis no longer able to offset the stress acting orthogonally ( \u03c3h).  \n Post-fracture closure, the reservoir is moving towards radial flow . This period can then be assessed for traditional reservoir \nproper ties, specifically permeability and reservoir pressure, in accordance with the standard after -closure analysis methods . An"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae5492a-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 3, "chroma:document": "extensive discussion of the  theory is available in the literature ; particularly in that published by Ramurthy  et al. (2002, 2003, \nand 2009) . \n \nEquipment  & Procedure  \nThe tests have been conducted across the basin in core / chip holes using a straddle packer configuration ; an illustration of a \ntypical testing string is included in Figure 4. The equipment utilised in the testing programme includes:  \n \n\u2022 4-stage, dual -packer in jection tool : The tool includes a by-pass for avoidance of pressure spikes during the inflation \nsequence.  The tool configuration f acilitates downhole shut -in (DHSI) , which has been observed to reduce wellbore \nstorage effect s and shut-in time . \n\u2022 Injection string : A 2 3/8\u201d injection string has proven suitable  in the majority of cases , given the relatively low"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae549ac-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 3, "chroma:document": "injection rates  required as a result of the low -permeability formtion s (generally \u22642bbl/min) . Downloaded from http://onepetro.org/SPEURCE/proceedings-pdf/13URCE/All-13URCE/SPE-167074-MS/1593465/spe-167074-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae54a24-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 4, "chroma:document": "SPE 167074   5 \n\u2022 Downhole g auges:  High- fidelity gauges are r un as part of the testing assembly to ensure any final test interpretation \nis based on reliable data; this reduces the need to account for hydrostatic or frictional effects  which may  introduce \nuncertainty during analysis . \n\u2022 Surface g auges:  Gauges  are used for preliminary analysis  when operating with surface shut -in; this allows real -time \nidentification of the required  test events and flow periods . The test duration can thus be extended (or reduced), \ndepending on the desired outcomes . These gauges  are connected between the wellhead and the pump discharge.  \n\u2022 Pumping unit : The current  HP 3 3/8\u201d fluid end pump (or similar) provides wide range of injection rates , with good \ncontrol at lower volumes. Early tests were conducted using a less fit -for-purpose system, but the use of larger \nplungers resulted in difficulties with delivering low -rate. \n \nAn outline of the open -hole testing procedure is as follows:"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae54a9c-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 4, "chroma:document": "\u2022 The testing assembly is run -in-hole, and pulled back up to the required testing depth.  \n\u2022 Pressure testing  of the surface lines (between the pumping unit and injection head) is conducted . \n\u2022 The downhole test tool is adjusted to the \u201cinflate\u201d  setting and the packers are inflated.  \n\u2022 Once the packers are set, the downhole valve is closed and the injection string is pressure -tested.  \n\u2022 With a successful pressure test to 3000psi, the tool is opened to the zone and fluid is injected.  \n\u2022 A low- viscosity injection flu id is pumped at a constant rate to generate (and propagate) a fracture.  \n\u2022 The well is shut -in using a  surface or downhole valve (or combination of both). Surface gauge data can be used to \nanalyse test progress . \n\u2022 Once radial flow (or closure pressure, depending upon the test requirements) is achieved, the testing valves may be opened and the pressure bled  down into the surface tanks ."}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae54b1e-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 4, "chroma:document": "Of particular note is the difference in test performance between surface and downhole shut -in. There are a number of \ndifferences between the two testing mechanisms : \n \n\u2022 Surface:  The test interval is exposed to the tubing hydrosta tic in addition to the surface injection pressure. Real -time \nmonitoring is available via gauges installe d in the surface surface lines (and adjusted for hydrostatic pressures).  \n\u2022 Downhole:  The test zone is not influenced by the tubing hydrostatic pressure.  The progress of the test is monitored \nusing 30 -second pressure data set via real -time telemetry to the surface. This downhole gauge pressure data is \nmeasured from within test interval.  \n \nThe advantage of open -hole testing is that any complications due to the cementing or perfor ation scheme are avoided, such as \ngeomet ric skin effects d ue to limited -entry phenomena or limited perforation effectiveness. It does, however, require that"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae54b96-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 4, "chroma:document": "borehole conditions  are amenable to packer setting , as washouts, etc, may prevent successful zonal isolation, resulting in a \nfailed test.  Hitherto , the bounding formations have proven sufficiently competent for the packer isolation process to be \nsuccessful in the majority of cases.  \n \nProgramme Results \nTo-date, Arrow  energy has conducted  more than 140 DFIT s, 76% of which have targeted coal formations . The success rating \nof the tests in coal estimating formation parameters is as follows:  \n \n\u2022 Closure Pressure:   94% \n\u2022 Permeability Estimates:  64% \n\u2022 Reservoir Pressure:  59% \n \nNote that the number of permeability estimates reported here represents only those values which may be considered with a \nreasonably high degree of confidence. Any tests which have provided an upper estim ate but not a definitive value,  due to an \nincomplete profile , are not included in this summary . \n \nBy contrast, a comparison with 144 DST / IFOT results in the company\u2019s database shows that only 57% of such tests"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae54c0e-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 4, "chroma:document": "facilitated the estimation of a permeability value with a moderate to high confidence. This is largely attributable to:  \n \n\u2022 The recent i nclusion of real-time monitoring, which has facilitated impro ved decision -making around testing \ntimeframes;  \n\u2022 An improved equipment reliability in more recent testing programmes; and,  \n\u2022 A greater appreciation for the limitations  of DST / IFOT in low -permeability coal formations.  \n \nThe type and quality information acquired as part of Arrow Energy\u2019s DFIT programme is outlined in the following section.  Downloaded from http://onepetro.org/SPEURCE/proceedings-pdf/13URCE/All-13URCE/SPE-167074-MS/1593465/spe-167074-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae54c90-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 5, "chroma:document": "6  SPE 167074  \nFormation Responses  \nTypical  formation responses , approximating \u201cDFIT type-curves \u201d, have previously been identified in the literature (Ramurthy \net al., 2002) ; these are invaluable in interpretation of the general formation properties , as well as confirmation of the near -\nwellbore geological setting  such as the identification of the presence of baffling formations . The following have been observed \nas part of Arrow Energy\u2019s testing programme:  \n \n\u2022 Pressure Dependent Leak -off (PDL): The PDL  response is the most common reservoir behaviour observed as part \nof the testing programme . \n\u2022 Fracture Height Recession (FHR) : FHR has been observed when testing thin, interbedded formations such as the \nFCCM; the presence of this effect can be forecast by pressure fluctuations  observed during the constant -rate pumping \nschedule.  \n\u2022 Fracture Tip E xtension (FT E): Observed in a number of very low -permeability formations , the occurrence of this"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae54d12-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 5, "chroma:document": "effect has helped to identify suitable (and unsuitable) well testing target zones.  \n \nReliability of Permeability Measurements  \nConcerns have previously been raised over the reliability of DFIT permeability results in comparison with DST or IFOT test \ntypes ; the relative merits of each test type has been the subject  of some discussion within the literature  (Gelber et al., 2012 ; \nTan et al., 2013 ). DFIT permeability estimates for four different geo -domains within the Bowen Basin are plotted in Figure 6, \nalongsid e the average permeability trend calculated from the previously -acquired DST / IFOT results within Arrow Energy\u2019s \ndatabase.   \n \nComparison between the two data sets suggests that permeability estimates generated by the DFIT programme demonstrate a \nsimilar correlation , both between tests types, and with respect to depth.  Of particular interest is that the trend in DFIT results"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae54d94-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 5, "chroma:document": "tends to illustrate a more  favourable permeability  compared to DST / IFOT  estimates at greater depths . A number of elements \ncontribut e to this:  \n \n\u2022 DST / IFOT \u201clow\u201d side bias: The DST / IFOT permeability -depth trend in Figure 6 has been generated using results \nin which there is \u201chigh\u201d confidence only, i.e. excluding those estimates where the quality of the radial flow (or otherwise) interpretation is unreliable , potentially resulting in low -side bias in the trend . There is , in general,  greater \nconfidence in the quality of the DFIT data, and thus the resultant interpretation, as a result of improved operational \npractices, leading a reduced discrediting of high er-perme ability outcomes in deeper zones . \n\u2022 DFIT \u201chigh -side\u201d bias: Occasionally, \u201cupper estimates\u201d of permeability , based on forecasts of pressure data in the \ninterpretation software, may be introduced to the dataset, creating a \u201chigh -side\u201d bias in the DFIT results.  It should be"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae54e16-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 5, "chroma:document": "noted that this practice is not restricted to DFIT interpretation, and the same issue may arise in the DST / IFOT trends.  \n Nevertheless, the DFIT dataset sits well within the range of scatter observed in the DST / IFOT programme, and the esti mated \npermeability values are considered valid as the basis for subsurface uncertainty modelling.  \nBreakdown & Closure Pressures  \nOne of the critical features of Arrow Energy\u2019s DFIT programme is the nature of the formation breakdown response during \ntreatment. In very few instances are the classical high -energy \u201chump\u201d observed prior to fracture propagation  (Figur e 3). This is \ncurrently interpreted to be the result of the  treatment method stimulating the existing cleat system, rather than creating a new \nfracture.  \n \nThe response to this uncertainty is  the avoidance of \u201cstepping \u201d the injection rate during the pumping process. For a constant"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae54e98-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 5, "chroma:document": "injection rate, the treatment plot is visually equivalent to a pressu re versus cumulative volume curve. As with standard leak- off \ntests in permeable formation s, identification of two distinct slopes in such a scenario allows an approximation of the formation \nbreakdown pressure . This method has been used to generate an estimate of formation breakdown pressure (Figure 7); the same \nfour geo -domains as above are represented for continuity . \n \nAs discussed above, fracture closure pressure is assumed to provide an estimate of the magnitude of the minimum horizontal \nstress. Closure pressures versus formation depth, as measured in Arrow Energy\u2019s DFIT programme, are illustrated in Figure 8. \nThe majority of data has been coll ected between 750ft and 2000ft; t he convergence in closure pressures between \napproximately 700ft and 1000ft indicates that at this depth, th e stress contrasts between target and bounding zones are"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae54f06-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 5, "chroma:document": "minimal; fracture confinement at such a depth is heavily reliant on the density differences.  \nFracture Reopening Pressure  \nPerforming a fracture \u201cre -opening\u201d test at the completion of the typical DFIT  cycle has previously been proposed as a method \nfor estimating the hydraulic fracture tensile strength  (Bjarnason et al., 1989, Hickman & Zoback, 1983) . Haimson & Fairhurst Downloaded from http://onepetro.org/SPEURCE/proceedings-pdf/13URCE/All-13URCE/SPE-167074-MS/1593465/spe-167074-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae54f88-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 6, "chroma:document": "SPE 167074   7 \n(1967) derived the following equation for estimating formation tensile strength, T : \n \n\ud835\udc43\ud835\udc4f\u2212\ud835\udc47=3\ud835\udf0e\u210e\u2212\ud835\udf0e\ud835\udc3b\u2212\ud835\udc43\ud835\udc5c ( 3 ) \n \nMore recently, application of the technique has been concerned with estimating maximum horizontal stress in low \npermeability formation; if the tensile stre ngth of the rock is assumed to represent the full  difference between the break -down \nand re -opening pressures , the maximum horizontal stress, \u03c3 H, can be estimated via the method proposed by Bredehoeft et al . \n(1976) : \n \n\ud835\udf0e\ud835\udc3b=3\ud835\udf0e\u210e\u2212\ud835\udc43\ud835\udc4f\u2212\ud835\udc43\ud835\udc5f\ud835\udc52 ( 4 ) \n \nIt has  been suggested that the results  of such a procedure are somewhat uncertain (Rutqvist et al., 2000; Ito et al., 1999) , and \nan investigation into the validity of this approach is ongoing within Arrow Energy.  An area of particular note is the nature of \nthe typical breakdown profile  (Figure 3); the lack of a definitive breakdown pressure value greater than the propagation"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae55000-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 6, "chroma:document": "pressure implies that the tensile strength  is very low (according to the assumption above) , but alternative explanations may be \nfound in the nature of the reservoir itself . \nTest Parameters  \nPrescribed s hut-in times versus depth ( for surface shut -in tests) are plotted in Figure 9, along with injection volume s versus the \nratio of depth to formation thickness ; these have been calculated based on the time required to achieve a 90% success rate.  As \npermeability decreases (typically, with depth), a smaller injection volume is required to achieve a permeability estimate in a \nsuitable timef rame.  \n \nReducing the injection volume  has the obvious impact of limiting the radius of investigation , which in turn limits the scale of \nheterogeneity captured in the average permeability  estimated through interpretation . Direct application of permeability values \nwhich may represent \u201cfalse\u201d positives can result in erroneous simulation results. However, given the scale of heterogeneity"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae55078-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 6, "chroma:document": "obser ved in Bowen Basin coals, which can demonstrate changes in cleat properties over distances less than tens of metres, the \nquestion is to what extent a  large radius of investigation is  representative of the formation properties . As a result , it is possible, \nand from a cost perspective, preferable, to account for this heterogeneity via a suitable uncertainty management process  in the \nreservoir simulation workflow . \n \n \nStress Mapping Case Study: \u201cRed Hill\u201d  \nThe Red Hill area is situated in the north -west central portion of ATP 1103 on the western flank of the Bowen Basin due north \nof the MGP. Arrow\u2019s tenement in Red Hill work -pack covers an area of approximately 225sq mi . The t opography across the \narea is rel atively benign with a relief of approx imately  330ft . To the east of the work -pack area a sharp increase in height is \nexperienced attributed to the Burton Fault.  The MCM  sub-crop to west of the area, and d ip to approx 3300ft  in the east; the"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae550fa-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 6, "chroma:document": "package is greater than 800ft  thick across the region.   \n \nThe region is part of the Collinsville Shelf , which is c haracterised by s tructurally low disturbance , with gently easterly -dipping \nstrata (approximately 3 -5\u00b0); it is bounded to the east by the Burton Jellinbah Fault Zone . Key geological features of interest in \nthe region are d iscrete areas of coked coal , and s urface basalts . The main MCM target formations in Red Hill are  the \nGoonyella Upper (GU) , Goonyella Middle (GM)  and Goonyella Lower (GL)  seams.  \n The Red H ill region has been assess ed in accordance with the data acquisition workflow outlined in Figure 2, with a view to \ndeveloping a better understanding of the interactio n between formation evaluation and reservoir performance results.   \n \nInput Data  \nThe data available within Arrow Energy for the purposes of regional -scale stress mapping includes the following:"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae55172-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 6, "chroma:document": "\u2022 Acoustic Scanner Log s: Structural dip, possible faults / microfaults, natural fractures,  coal cleat orientation  \n\u2022 Coal Quality Information : Cleat o rientation , permeability  \n\u2022 Geological and Structural Models : Structure and c ontours , deformation zones, tectonic stress, joints / f aults / folds, \nintrusion s / magnetic anomalies  \n\u2022 Micro -seismic : Fracture stimulation  performance  \n\u2022 Rock Mechanics Core Test Results : Unconfined Compressive Strength , Young\u2019s Modulus , Poisson\u2019s Ratio  \n A large majority of the data are available through mining activities in the area; Arrow Energy has undertaken a more targetted \ndata acquisition programme in areas identified as requiring additional design support.  Downloaded from http://onepetro.org/SPEURCE/proceedings-pdf/13URCE/All-13URCE/SPE-167074-MS/1593465/spe-167074-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae551f4-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 7, "chroma:document": "8  SPE 167074  \n \nThe above methodology was applied to the Red Hill region of the Bown Basi n, utlising the following data:  \n \n\u2022 Stress measurements : Three  DFITs were conducted on target coal and boundary formations  to identify \ninstantaneous shut -in pressure (ISIP) , breakdown and closure pressure s. This dataset was later added to with four \nmore tests  in the nearby region  to confirm mode lled properties . \n\u2022 Rock mechanics results : Core tests were conducted on two coal and two boundary formation samples . \n\u2022 Sonic / image logs : Mono- and di -pole sonic logs were recorded across the three wells in question , along with \nmagnetic imaging lo gs. \n\u2022 Petrophysical logs : A suite of petrophysical logs, including density, resistivity, porosity, SP and gamma ray were run \non all wells in the sample set.  \n\u2022 Static geological model:  A full-field geological model, based on previously acquired well logs , seismic  and drilling"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae55262-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 7, "chroma:document": "data was available for depth correlation and identification of relevant structural features . \n \nThe process employed to combine these data into  a One-Dimensional  (1D)  MEM is outlined in a separate piece of literature \n(Mazumder et al.,  2013) . \n \nMechanical Earth Modelling  \nAll of the above data are combined to generate MEM  for a given region; these models are then used as an input to  horizontal \nand hydraulic fracture well design. A key aspect of this process is the calibration of the model with rock mechanics test results \nand \u03c3h values estimated from DFIT results. The horizontal stresses in the formations may then be calculated via the following \nequations ( Thiercelin  & Plumb, 1994):  \n \n(\ud835\udf0e\u210e\u2212\ud835\udefc\ud835\udc43)=\ud835\udc63\n1\u2212\ud835\udc63(\ud835\udf0e\ud835\udc63\u2212\ud835\udefc\ud835\udc43)+\ud835\udc38\n1\u2212\ud835\udc632\ud835\udf00\u210e+\ud835\udc63\ud835\udc38\n1\u2212\ud835\udc632\ud835\udf00\ud835\udc3b ( 5 ) \n \n(\ud835\udf0e\ud835\udc3b\u2212\ud835\udefc\ud835\udc43)=\ud835\udc63\n1\u2212\ud835\udc63(\ud835\udf0e\ud835\udc63\u2212\ud835\udefc\ud835\udc43)+\ud835\udc38\n1\u2212\ud835\udc632\ud835\udf00\ud835\udc3b+\ud835\udc63\ud835\udc38\n1\u2212\ud835\udc632\ud835\udf00\u210e ( 6 ) \n \nThe orientation of maximum horizontal stress can be estimated from the borehole breakouts observed in the magnetic \nformation imaging logs acq uired as part of the MEM work.  \n \nModelling Results"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae552da-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 7, "chroma:document": "Modelling Results  \nThe resultant 1D MEM output for Red Hill, compared with pilot wells in the region, is included i n Figure 10.  \n \n\u2022 Cleat Orientation: Intrinsic anisotropy is identified in the target c oal seams  using dipole sonic logs . The direction of \n\u201cFast Shear\u201d provides the direction of the f ace cleats in the c oal intervals.  \n\u2022 Stress Orientation : The strike direction of borehole breakout s observed in the formation magnetic imaging logs  is \napproximately WNW -ESE, suggesting that the azimuth of principal horizontal stress is approximately N30 \u00b0E. \n\u2022 Stress Magnitude: The magnitude of \u03c3h is calculated from the DFIT results, and used to calculate the magnitude of \nSH using the method outlined above.  \n \nThe outcomes of the modelling process , including their implications for the development well concepts,  are: \n \n\u2022 The s tress regime at the evaluated depths is mostly strike -slip, suggesting that any fractures generated are likely to be \nof a vertic al, full-height  nature ."}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae55366-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 7, "chroma:document": "of a vertic al, full-height  nature . \n\u2022 Coal fractures are nearly perpendicular to the orientation of \u03c3H within the analysed region.  However, th is also \nsuggests that the natural fracture system will be highly susceptible to pressure -dependent permeability effects as fluid \nis removed from the cleats during primary depletion . \n\u2022 Bounding formation fractures are predominantly parallel to \u03c3H. The o rientation of natural fractures in sand/shale may \nrepresent a preferential flowpath for hydraulic fracturing fluids . \n\u2022 Coals are of lower stress than boundary formations ; however, the stress differential across the formations is relatively \nlow (150- 400psi), suggesting the the likelihood of containment is low.  \n \nThese results have correlated well with observed  data during execution of the drilling and stimulation  programmes , including \nlater-stage micro -seismic conducted as part of the hydraulic fracturing programme."}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae553de-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 7, "chroma:document": "Downloaded from http://onepetro.org/SPEURCE/proceedings-pdf/13URCE/All-13URCE/SPE-167074-MS/1593465/spe-167074-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae55456-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 8, "chroma:document": "SPE 167074   9 \nConclusions  \nOpen -Hole  DFITs have proven a successful, high- reliability method for assessing a number of geo- mechanical properties in \nlow-permeability coal  formations . The testing procedure has allowed the estimation of formation breakdown and closure \npressure data, along with permeability and reservoir pressures.  These permeability estimates have demonstrated similar \nconformity to regional trends as more well -established test types, suggesting that the open -hole DFIT methodology employed \nis a suitable appraisal method.  \n \nCoupling these results with special logging suites to generate 1D -MEMs has allowed the quantification of stress properties and \ntrends throughout a specific area.  The ability to successfully calibrate geomechanical models with the  observed stress data has \nproven a valuable element in the justification of open -hole DFITs as a method for acquiring in -situ subsurface data."}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae554ce-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 8, "chroma:document": "When tested against a proposed development region, t he inclusion of the closure pressure dataset in the 1DMEM p rocess has \nprovided valuable insights into the nature of the subsurface environment, as well as its likely impact on future development \nand production planning exercises.  \n \n \nNomenclature  \nNote:  The subscript zero ( 0) denotes a ny of the below properties  as defined at the initial reservoir conditions.  \n \nCf Cleat volume compressibility  (psi-1) \nE Young\u2019s modulus  (psi) \nh Net pay  (ft) \nk Absolute p ermeability  (mD)  \nPb Formation breakdown pressure  (psi) \nPp Pore pressure  (psi) \nPre Fracture re -opening pressure  (psi) \nT Formation tensile strength  (psi) \n\u03b1 Biot\u2019s coefficient  (psi-1) \n\u03b5h Tectonic strain coefficient (direction  of \u03c3h) (-) \n\u03b5H Tectonic strain coefficient ( direction  of \u03c3H) (-) \nv Poisson\u2019s ratio  (-) \n\u03c3 Total stress  (psi) \n\u03c3v Vertical stress  (psi) \n\u03c3h Minimum  horizontal stress  (psi) \n\u03c3H Maximum  horizontal stress  (psi) \n References"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae55546-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 8, "chroma:document": "\u03c3H Maximum  horizontal stress  (psi) \n References  \nBjarnason, B, Ljunggren, C, Stephansson, O. \u2018New developments in hydrofracturing stress measurements at Lule\u00e5 University \nof technology\u2019. International Journal of Rock Mechanics and Mining Sciences & Geomechanics Abstracts , Volume \n26, Issue 6 , December 1989, Pages 579- 586. \n \nCui, X. and Bustin, M. 2005. \u2018 Volumetric strain associated with methane desorption and its impact on coalbed gas production \nfrom deep coal seams \u2019. AAPG Bulletin , 89(9): 1181- 1202.  \n \nFeng, Q, Shi, H, Zhang, X, Zhang, J. 2012. \u2018 New Inflow Performance Relationship for Coalbed Methane \u2019. SPE/EAGE \nEuropean Unconventional Resources Conference & Exhibition , 20 March 2012. SPE 152163.  \n \nFielding, C, Steph ens, C, Kassan, J, Holcombe, R. 1995.  \u2018Revised palaeogeographic maps for the Bowen Basin , Central \nQueensland \u2019. Bowen Basin Symposium , 1-3 October, 1995."}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae555be-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 8, "chroma:document": "Queensland \u2019. Bowen Basin Symposium , 1-3 October, 1995.  \n \nGelber, T, Kamenar,  A, Edgoose , J. 2012 . \u2018Comparison of DFIT, DST and IFT P ermeabilities in Coal Sea m Reservoirs \nSubject to Stress \u2019. Paper Presented at the S PE Asia Pacific Oil and  Gas Conference and Exhibition, Perth, Australia  \n(SPE 158297- MS). \n \nHickman , S, Zoback,  M. 1983 . \u2018The interpretation of hydraulic fracturing pressure -time data for in -situ stress determination \u2019. \nHydraulic Fracturing Measurements , National Academy Press, 44- 54. \n \nIto, T, Evans,  K, Kawai,  K, Hayashi,  K. 1999. \u2018 Hydraulic fracture reopening pressure and the estimation of maximum \nhorizontal stress \u2019. International Journal of Rock Mechanics and Mining Sciences , 36 (6), 1999, pp. 811- 826. Downloaded from http://onepetro.org/SPEURCE/proceedings-pdf/13URCE/All-13URCE/SPE-167074-MS/1593465/spe-167074-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae55640-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 9, "chroma:document": "10  SPE 167074  \n \nLaubach, S, Mar ett, R, Olson, J, Scott, A. 1998 . \u2018Characteristics and origins of coal cleat: A review \u2019. International Journal of \nCoal Geology , 35, 175\u2013207. \n Mazumd er, S, Scott, M, Jiang, J. 2012. \u2018Permeability increase in Bowen Basin coal as a result of matrix shrinkage during \nprimary depletion \u2019. International  Journal of Coal Geology , 96-97, pp. 109- 119. \n Palmer, I. 2009. \u2018 Permeability changes in coal: analytical mo delling \u2019. International Journal of Coal Geology , 77, pp. 119 -126. \n \nRamurthy, M, Marjerisson, DM, Daves, SB. 2002. \u2018Diagnostic Fracture Injection Test in Coals to Determine Pore Pressure \nand Permeability \u2019. SPE Gas Technology Symposium , April -May 2002.  \n \nRamu rthy, M, Young, GBC, Daves, SB, Witsell, F. 2003. \u2018Case History: Reservoir Analysis of the Fruitland Coals Results in \nOptimizing Coalbed Methane Completions in the Tiffany Area of the San Juan Basin \u2019. SPE Annual Technical \nConference and Exhibition, October  2003."}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae556b8-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 9, "chroma:document": "Conference and Exhibition, October  2003.  \n \nRamurthy, M, Lyons, B, Hendrickson, RB, Barree, RD, and Magill, DP . 2009.  \u2018Effects of High Pressure -Dependent Leakoff \nand High Process -Zone Stress in Coal -Stimulation Treatments \u2019. SPE Prod uction  & Oper ations ,24 (3), pp. 407- 414 \n(SPE -107971- PA). \n \nRutqvist, J , Tsang, C, Stephansson, O. 2000. \u2018Uncertainty in the maximum principal stress estimated from hydraulic \nfracturing measurements due to the p resence of the induced fracture\u2019.  International Journal of Rock Mechanics and \nMining Sciences , 37 ( 1\u20132), pp. 107-120. \n \nShi, JQ, Durucan, S. 2005.  \u2018A model for changes in coalbed permeability during primary and enhanced methane recovery \u2019. \nSPE Reservoir Evaluation & Engineering, 8 ( 4), pp. 291 -299. \n Tan, CH , Demircan , G, Satyagraha , M. 2013. \u2018CSG well testing \u2013  our experience in Queensland\u2019.  Paper presented at the  \nAPPEA Conference and Exhibition, Brisbane, Australia ."}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae55730-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 9, "chroma:document": "APPEA Conference and Exhibition, Brisbane, Australia . \n \nThiercelin, M, Plumb , R. 1994 . \u2018Core -based prediction of lithologic stress contrasts in East Texas formations \u2019. SPE Formation \nEvaluation (2510258).  \n \n  Downloaded from http://onepetro.org/SPEURCE/proceedings-pdf/13URCE/All-13URCE/SPE-167074-MS/1593465/spe-167074-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae557a8-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 10, "chroma:document": "SPE 167074   11 \nFigures & Tables  \n \n \nFigure 1: Bowen Basin Stress Data (Arrow Energy Internal)  \n \n \nFigure 2: Data Acquisition Strategy  \n \nWELLCONCEPT\nPLANNING\nAppraisal Programme\n(Field)\nDEVELOPMENT\nCONCEPT\n\u2022Permeability\n\u2022Closure Pressure\n\u2022Pore Pressure\n\u2022Breakdown \nPressure\nRESERVOIR\nSIMULATION\n\u2022Drawdown Regime\n\u2022EUR\nLOG\nACQUISITION\n\u2022Dipole Sonic\n\u2022Formation Imaging \n(Breakouts, \nWashouts) \nGEO-\nMECHANICAL\nMODELLING\n\u2022Single / Multi -Lateral\n\u2022Inclination / Azimuth\n\u2022Solids Control \nTechnologies\nDFIT RESULTSLab / Desktop Studies Field Development Planning\nRESERVOIR\nQUALITY\n\u2022Regional Trends\n(Stress, Permeability, \netc.)\n\u2022Compaction\u2022In-situ Stresses\n\u2022Sanding Models\n\u2022Poro -elastic \nProperties\n\u2022Mechanical \nStrength Properties\nCOREDATA\nRecycleDownloaded from http://onepetro.org/SPEURCE/proceedings-pdf/13URCE/All-13URCE/SPE-167074-MS/1593465/spe-167074-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae5582a-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 11, "chroma:document": "12  SPE 167074  \n \n  \n(a) Classical b reakdown profile  (b) Observed coal breakdown pattern  \nFigure 3: Observed f racture initiation in open- hole DFITs  \n \n \nFigure 4: Testing string configuration  \n TimeTreating Pressure, \nInjection RateInjection Rate\nTreating Pressure\nTimeTreating Pressure, \nInjection RateInjection Rate\nTreating Pressure\nP\nP\nPP\nP\nPDownloaded from http://onepetro.org/SPEURCE/proceedings-pdf/13URCE/All-13URCE/SPE-167074-MS/1593465/spe-167074-ms.pdf/1 by University of Houston user on 27 October 2023"}


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{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 12, "chroma:document": "SPE 167074   13 \n \n(a) Before Closure  \n \n(b) After Closure  \nFigure 5: Before - and a fter-closure  analyses of typical open -hole test  \n \n \nFigure 6: Perme ability versus depth trend (MCM and  RCM formations)  \n \n0\n500\n1000\n1500\n2000\n2500\n30000.01 0.10 1.00 10.00 100.00\nFormation Midpoint [ft]Permeability [mD]\nGeo-Domain 1\nGeo-Domain 2\nGeo-Domain 3\nGeo-Domain 4\nDST / IFOT TrendDownloaded from http://onepetro.org/SPEURCE/proceedings-pdf/13URCE/All-13URCE/SPE-167074-MS/1593465/spe-167074-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae5591a-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 13, "chroma:document": "14  SPE 167074  \n  \n(a) Coal  Formations  (b) Boundary  Formations  \n \nFigure 7: Formation breakdown pressures \n \n  \n(c) Coal  Formations  (d) Boundary  Formations  \nFigure 8: Closure Pressures in Coal and Boundary formations  \n \n  \n(a) Shut -in Time  (b) Injection Volumes  \nFigure 9: Prescribed shut -in times  and injection volumes  for 90% success rates (coal formations  only) \n 0\n500\n1000\n1500\n2000\n2500\n30000 500 1000 1500 2000 2500 3000Formation Midpoint [ft]Breakdown Pressure [psi]\nGeo-Domain 1\nGeo-Domain 2\nGeo-Domain 3\nGeo-Domain 40\n500\n1000\n1500\n2000\n2500\n3000\n35000 500 1000 1500 2000 2500 3000 3500 4000Formation Midpoint [ft]Breakdown Pressure [psi]\nGeo-Domain 1\nGeo-Domain 2\nGeo-Domain 3\nGeo-Domain 4\n0\n500\n1000\n1500\n2000\n2500\n30000 500 1000 1500 2000 2500 3000Formation Midpoint [ft]Closure Pressure [psi]\nGeo-Domain 1\nGeo-Domain 2\nGeo-Domain 3\nGeo-Domain 40\n500\n1000\n1500\n2000\n2500\n30000 500 1000 1500 2000 2500 3000Formation Midpoint [ft]Closure Pressure [psi]\nGeo-Domain 1\nGeo-Domain 2\nGeo-Domain 3"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae55992-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 13, "chroma:document": "Geo-Domain 1\nGeo-Domain 2\nGeo-Domain 3\nGeo-Domain 4\n0\n500\n1000\n1500\n2000\n2500\n30000 5 10 15 20 25 30 35 40 45Formation Midpoitn [ft]Shut -in time [hrs]\nLow Confidence\nHigh Confidence\nMid Confidene\nPrescribed SIT\n0.002.004.006.008.0010.0012.0014.00\n0 50 100 150 200 250 300 350 400Formation Midpoitn [ft]\nDepth / Thicness [ft/ft]Volume\nPrescribed \nVolumeDownloaded from http://onepetro.org/SPEURCE/proceedings-pdf/13URCE/All-13URCE/SPE-167074-MS/1593465/spe-167074-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae55a0a-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-167074-ms.pdf", "page": 14, "chroma:document": "SPE 167074   15 \n \n \nFigure 10: Stress / Cleat contrast for permeability trending  \nDownloaded from http://onepetro.org/SPEURCE/proceedings-pdf/13URCE/All-13URCE/SPE-167074-MS/1593465/spe-167074-ms.pdf/1 by University of Houston user on 27 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae55a82-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/arma-2012-169.pdf", "page": 0, "chroma:document": "1. INTRODUCTION \nHydraulic fracturing is a proven technology for the in-\nsitu rock stress measurement. The magnitude and orientation of the minimum horizontal stress S\nh and the \nmaximum horizontal stress SH can be estimated by \ncontrolling the fracturing and shut-in processes of test intervals in a borehole. Hydraulic fracturing is widely \nused in rock engineering,  oil drilling, and seismic \nresearch fields, with the bene fits of great measure depth, \nsimple calculation without rock mechanics parameter, \nreliable result, and almost in any rock formation. \nAlthough hydraulic fracturing method has been well \ndeveloped in measuring technique and measurement \nequipment, further studies of its measurement principle and rock failure mechanism are necessary \n[1]. For \ncomplex conditions in the field test, the actual result is \nnot as simple as conventional theory. For example, the measured reopening pressure, which is very important to estimate the maximum horizontal stress, is affected not"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae55b0e-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/arma-2012-169.pdf", "page": 0, "chroma:document": "only by in-situ stress, but also injection rate, pore \npressure, system compliance, etc. In the conventional theory, the pore pressure is generally substituted by \nhydrostatic pressure, and the system compliance is \nignored. As a result, a non-ignorable error may exist in \nthe estimation of the maximum horizontal stress. \nIn this paper, the effect of residual aperture and system \ncompliance on reopening pressure is studied. A novel \nanalysis is presented to explain the phenomena observed in the comparing experiments which were carried out by \nhydraulic fracturing method in Beijing Wenquan Station. 2. CONVENTIONAL THEORY  \nThe information related to in-situ stress estimation can \nbe obtained from the borehole pressure P curve with \ntime t. A typical borehole pressure record is shown in \nFig.1. In the hydraulic fracturing field test, a short \ninterval in a borehole is sealed off by inflatable packers, \nand pressurized by fluid injection from a pump on the ground (stage 2 in Fig.1). When the fluid pressure"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae55b86-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/arma-2012-169.pdf", "page": 0, "chroma:document": "exceeds the tensile strength of the rock around the seal-off section, fracture occurs on the borehole wall, and \npropagates perpendicular to the least principal in-situ stress (stage 3 in Fig.1). To define the pressure of the \nfracture walls, several reopening and draining repeated \ncycles are needed (stage 6-9 in Fig.1). \n \nFig. 1. Typical curve of pressure-time by hydraulic fracturing.              \nARMA 12-169                                                                \n \nStudy on effect of residual aperture and system compliance in in-situ stress \nmeasurement by hydraulic fracturing method \n \nDong, Y.K., Li, H. and Wang, H.Z.  \nKey Laboratory of Crustal Dynamics, Institute  of Crustal Dynamics, CEA, Beijing, China \nABSTRACT:  Residual aperture causes pressure penetration into the fract ure prior to its reopening, and system compliance makes \nthe measured reopening pressure unequal to the real value. Both of the two fact ors are ignored in the conventional theory. Taki ng"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae55bfe-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/arma-2012-169.pdf", "page": 0, "chroma:document": "account of residual aperture and system compliance effects, we  analyzed the phenomenon that  measured reopening pressure Pr(a) \ndecreases with the repeated test  cycles, and considered that Pr(a) gradually approaches to the real value Pr0 due to the increased \ndVc/dP and residual aperture effect. Furthermore, we present two critical values, critical crack length Lc and critical crack capacity \nCc, to explain the phenomenon that Pr(a) is less than Ps. It is concluded that Pr(a) is between Pr0 and Ps when Cc appears earlier than \nLc. Comparing experiments by hydraulic fracturing in 3 borehole s of about 5 m away from each other were carried out. For the \nphenomenon Pr(a) is less than Ps at 2 test sections, that is different from others at  the same depth, we concluded that it\u2019s not caused \nby high stress difference, and modified the 2 abnormal data to average lever based on  residual aperture and system compliance \ntheory."}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae55c9e-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/arma-2012-169.pdf", "page": 0, "chroma:document": "theory. \n \n Downloaded from http://onepetro.org/ARMAUSRMS/proceedings-pdf/ARMA12/All-ARMA12/ARMA-2012-169/1597153/arma-2012-169.pdf/1 by University of Houston user on 30 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae55d20-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/arma-2012-169.pdf", "page": 1, "chroma:document": "Two important parameters, reopening pressure Pr and \nshut-in pressure Ps, can be obtained from the P-t curve. \nWhen the fracture propagates sufficiently away from the \nborehole, normal stress on the fracture wall is the \nminimum horizontal stress Sh, which can be estimated by \nthe shut-in pressure Ps. At the beginning of the fracture, \nthe stress concentration by the borehole is a function of \nSH and Sh. Thus the borehole pressure while the induced \nfracture begins to reopen, i.e. the reopening pressure Pr, \ncan be used to estimate SH [2]. In the conventional theory \nof hydraulic fracturing, SH and Sh are estimated from the \nfollowing two equations: \n  r0 3HhSS P P=\u2212 \u2212                          (1) \n                  hsSP=                                (2) \nwhere P0 is pore pressure inside the fracture before \nopening. \n3. EFFECTS OF RESIDUAL APERTURE AND \nSYSTEM COMPLIANCE  \nBased on the conventional theory, Pr generally is larger \nthan Ps, except that there is a big difference between SH"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae55dac-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/arma-2012-169.pdf", "page": 1, "chroma:document": "than Ps, except that there is a big difference between SH \nand Sh (e.g. SH/Sh >2). However, the statistic data of field \ntests indicate that the measured reopening pressure lies \nso close to the shut-in pressure  that it is far beyond our \nexpectations, i.e. Pr=Ps. In order to explain such a \nparadox, Ito et al. took into account of the residual aperture of the fracture and the hydraulic compliance of \nfracturing system, which are entirely ignored in the \nconventional theory \n[3]. \n3.1. Residual aperture \nAlthough the fracture is shut-in under the action of \ncrustal stress after draining pr ocess, it can\u2019t return to the \nstate prior to the fracturing. The residual aperture exists between two surfaces of the fracture since the net area of contact of the two surfaces is usually a small fraction of \ntheir nominal area, as Fig.2 shows. \n \n(a)  First fracturing cycle          (b) Reopening cycle \nFig. 2. Effect of residual aperture.  In the first fracturing cycle, it is appropriate to replace"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae55e24-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/arma-2012-169.pdf", "page": 1, "chroma:document": "pore pressure P0 by hydrostatic pressure. However, in \nthe following reopening cycles, the residual aperture \ncauses pressure penetration into the fracture prior to its \nreopening. Consequently, the last component in equation \n(1) should be borehole pressure rather than P0, and the \nmaximum horizontal stress can be expressed as follows \n[4]: \nr 32HhSS P=\u2212                          (3) \n3.2. System compliance \nWith the comparison of Eq. (1) and Eq. (3), it is found \nthat Pr from Eq. (3) does not exceed Sh regardless of SH \nvalue, and be about half of the value from Eq. (1). Ito et \nal. explained the difference by system compliance. \nSystem compliance C is generally used to indicate \nstorage characteristic of the measurement system (fluid \nvolume change per unit pressure). It consists of flow \ntube deformation, borehole deformation, and fluid \ncompressibility. Assuming negligible fluid leakage into surrounding rock, the effect of the fracture opening on"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae55ea6-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/arma-2012-169.pdf", "page": 1, "chroma:document": "the borehole pressure variation can be expressed as follows \n[5]: \ncdP Q\ndV dtCdP=\n+                           (4)  \nwhere d Vc is the change of pressurized fluid volume due \nto the fracture opening. Q is the flow rate, and P is the \nborehole pressure, as shown in Fig.3. \n \nFig. 3. Illustration of hydraulic fracturing system.  \nWe usually determine reopening pressure Pr by choosing \nthe point at which the slop of P-t curve begins to sharply \ndecrease. Since the flow rate Q and the system \ncompliance C are constant, Eq. (4) indicates that the Downloaded from http://onepetro.org/ARMAUSRMS/proceedings-pdf/ARMA12/All-ARMA12/ARMA-2012-169/1597153/arma-2012-169.pdf/1 by University of Houston user on 30 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae55f1e-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/arma-2012-169.pdf", "page": 2, "chroma:document": "deviation of the P-t curve depends on the relative value \nof dVc/dP and C. As shown in Fig.4, the reopening \nprocess can be divided into 4 stages according as the \ndeviation. The fracture begins to reopen at stage 2. The \nP-t curve will deviate from linearity to some degree. \nHowever, since the system compliance C is far larger \nthan the value of d Vc/dP at the early stage of fracture \nreopening, no detectable change occurs on the P-t curve. \nHence, it is difficult to identify the real reopening \npressure on the P-t curve. When borehole pressure P \nreaches the level of Sh, the stress acting normally on the \nfracture surfaces goes into a critical state. The deviation \nof the P-t curve from linearity gets visible, where the \nmeasured pressure is common ly considered as the real \nreopening pressure by mistake. To distinguish the two reopening pressure, Ito et al. denote the real reopening \npressure as P\nr0, and the measured reopening pressure as \nPr(a)."}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae55f96-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/arma-2012-169.pdf", "page": 2, "chroma:document": "r0, and the measured reopening pressure as \nPr(a). \n \nFig. 4. Relationship of measured reopening pressure Pr(a) and \nreal reopening pressure Pr0. \n4. EXPERIMENT RESULTS ANALYSIS \nTo study the effects of residual aperture and system \ncompliance on reopening pressure Pr, we carried out a \ncomparing experiment in Wenquan Station, Beijing. \nThree boreholes of 150 m in depth, 130 mm in diameter, \nand about 5 m away from each other were drilled. The boreholes penetrated into granite, and quaternary deposits 10-20 m. The in-situ stress tests of hydraulic fracturing were carried out in each of 3 boreholes. \n4.1. Pr(a) decreases with repeated cycles  \nFig. 5 shows the recorded hydraulic fracturing P-t curve \nof ZK2 borehole at a depth of  112 m. It indicates that the \nmeasured reopening pressure decreases with the \nfollowing repeated test cycles, even be less than Sh in the \nlast cycle, which can also be observed in most hydraulic \nfracturing measurements. This phenomenon was simply"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae5600e-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/arma-2012-169.pdf", "page": 2, "chroma:document": "fracturing measurements. This phenomenon was simply \nexplained in some literature. On the one hand, sometimes the fracturing process in the first cycle is not \nsufficient if we shut down the pump shortly after the \nbreakdown pressure is reach. Continuous fracturing will \nbe happen in the following one or two repeated cycles \n(the second cycle shown in Fig. 6), which should be \navoided in the reopening pressure obtaining. On the \nother hand, as the repeated test progresses, pressurized \nfluid will permeate into wall rock and can\u2019t back flow immediately, which results in an increase of pore pressure around the test interval \n[6]. \n012345024681012\n \nFig. 5. Recorded P-t curve at 112m depth in ZK2 borehole.  \nTaking account of residual aperture and system \ncompliance effects, we give another explanation to the phenomenon. The real reopening pressure P\nr0 has no \nchange as the reopening and draining cycle repeats, because it changes only with in-situ stress (as Eq. 3 \nshows). The measured reopening pressure P"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae56090-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/arma-2012-169.pdf", "page": 2, "chroma:document": "shows). The measured reopening pressure P\nr(a) lies on \nnot only in-situ stress but also relative value of d Vc/dP  \nand C (as Eq. 4 shows). As the Fracturing continues in \nrepeated cycles, Pr(a) will continually decrease and \napproach to Pr0, due to the increased d Vc/dP and the \neffect of residual aperture. \n4.2. Pr(a) is less than P s \nFig. 6 shows the recorded hydraulic fracturing P-t curve \nof ZK5 borehole at a depth of 67 m. It is shown that the \nreopening pressure Pr(a) is less than Ps in almost all \nrepeated cycles. In most cases, it is generally recognized \nthat there is a comparative difference between SH and Sh \nin the test area, i.e. ( SH+P0)/Sh\u22652, whereas our \ncomparing measurement indicates that this phenomenon \nis not caused by high stress difference. \n \nFig. 6. Recorded P-t curve at 67m depth in ZK5 borehole.  \nSince the 3 boreholes are so close to each others, we can \nignore the differences caused by topography, fault, and rock character, and assume that the results of 3 boreholes"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae560fe-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/arma-2012-169.pdf", "page": 2, "chroma:document": "should be similar within experimental error range. Fig. 7 Downloaded from http://onepetro.org/ARMAUSRMS/proceedings-pdf/ARMA12/All-ARMA12/ARMA-2012-169/1597153/arma-2012-169.pdf/1 by University of Houston user on 30 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae56180-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/arma-2012-169.pdf", "page": 3, "chroma:document": "shows the stress ratio SH/Sh of each test interval in 3 \nboreholes (ZK1, ZK2, and ZK5), where SH and Sh were \nestimated by eq.(1) and eq.(2). All of the SH/Sh values \ndistribute around 1.7, except for 2 abnormal points, \nwhich are marked as solid triangle symbol. The SH/Sh \nvalues of the 2 abnormal points are larger than 2, while \nthe other points at the same depth are about 1.7. So it is \nconcluded that the abnormal phenomenon is not caused by high stress difference in the test area, but maybe well \nleakage, pressure relief of packers, large fracturing \nheight, etc. \n40\n50\n60\n70\n80\n90\n100\n110\n120\n1301.0 1.5 2.0 2.5 3.0SH / ShDepth /mzk1\nzk2\nzk5\n1.72.22.1\n \nFig. 7. Distribution of SH/Sh values with depth.  \nBased on Ito\u2019s theory of residual aperture and system \ncompliance, we present two critical values to analyse the phenomenon that P\nr(a) is less than Ps. \n\u2022 Critical crack length Lc \nThe normal stress on fracture is a function of SH and Sh \ndue to the effect of stress concentration by the borehole,"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae561f8-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/arma-2012-169.pdf", "page": 3, "chroma:document": "due to the effect of stress concentration by the borehole, \nwhich weakens rapidly away from the borehole. At a sufficient distance from the borehole, the normal stress \non fracture becomes almost equal to the value of S\nh, as \nshown in Fig. 8. When the fluid pressure reaches to the \nlevel of Sh, the crack length will greatly increase with \nsmall increment  of fluid pressure. The reopening crack \nlength L at this balance stress condition is defined as \ncritical crack length Lc. The fluid pressure is considered \nas Pr0 as the fracture begin to reopen, and equals to Sh at \ncritical crack length Lc. \n \nFig. 8. Sketch of critical crack length Lc. \n\u2022 Critical crack capacity Cc \nThe parameter of d Vc/dP indicates the crack capacity due \nto the fracture opening, which is related to crack length L, \ncrack height H, and borehole radius a. The relative value \nof dVc/dP and C dominates the deviation of P-t curve. \nWhen d Vc/dP becomes considerably large compared"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae56270-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/arma-2012-169.pdf", "page": 3, "chroma:document": "When d Vc/dP becomes considerably large compared \nwith C, P-t curve begins to deviate from its initial trend. \nThe value of d Vc/dP at this moment is defined as critical \ncrack capacity Cc, and the measured reopening pressure \nPr(a) can be located on the P-t curve.  \nIn most conditions, the two critical states occur not at the \nsame time. Fig. 9 is the sketch of d Vc/dP vs open crack \nlength L. For some reason, such as larger crack height H, \nthe critical value Cc will be achieved earlier than Lc, as \nthe solid line shows in Fig. 9. Contrarily, Lc will be \nachieved earlier due to smaller H, as the dashed line \nshows. On the P-t curve, critical value Lc corresponds to \nthe point that borehole pressure is equal to Sh, and \ncritical Cc corresponds to Pr(a). The appearance order of \nthe two critical values determines the relative magnitude \nof Pr(a) and Sh (Ps), and corresponds to two typical \npatterns of the P-t curve. When Cc appears earlier than \nLc, the measured reopening pressure Pr(a) is less than Sh,"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae5666c-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/arma-2012-169.pdf", "page": 3, "chroma:document": "Lc, the measured reopening pressure Pr(a) is less than Sh, \nand close to the real reopening pressure Pr0 (solid line in \nFig. 10), as the above comparing experiment result shows.  When L\nc appears earlier, Pr(a) is larger than Sh \n(dashed line in Fig. 10). \n \nFig. 9. Sketch of d Vc/dP vs open crack length L. Downloaded from http://onepetro.org/ARMAUSRMS/proceedings-pdf/ARMA12/All-ARMA12/ARMA-2012-169/1597153/arma-2012-169.pdf/1 by University of Houston user on 30 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae56720-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/arma-2012-169.pdf", "page": 4, "chroma:document": "Fig. 10. Sketch of relationship of Pr(a) and Sh. \n4.3. Modification \nWith consideration of residual aperture and system \ncompliance, we try to modify the two abnormal data in \nFig. 7, whose SH/Sh value is larger than 2. Based on the \nabove analysis, we concluded that (1) the measured reopening pressure P\nr(a) will gradually approach to the \nreal value Pr0 in the repeated test cycles, (2) Pr(a) is close \nto Pr0 when Cc appears earlier than Lc, and (3) the tiny \ndeviation of P-t curve at stage 2 (Fig. 4) can be observed \nin a smaller time scale. So we modified the two \nabnormal data by determining Pr(a) in the last test cycle, \nin a smaller time scale, and using Eq.(3) to calculate SH. \nFig. 11 shows the modified result that the SH/Sh values of \nthe two abnormal data are reduced to the average level. \n40\n506070\n80\n90\n100110\n120\n1301.0 1.5 2.0 2.5 3.0\nSH / ShDepth /mzk1\nzk2\nzk5\nmodified\n1.7\n \nFig. 11. Modification of the 2 abnormal data based on residual \naperture and system compliance theory.  5. CONCLUSIONS"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae56798-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/arma-2012-169.pdf", "page": 4, "chroma:document": "aperture and system compliance theory.  5. CONCLUSIONS \nIn the conventional theory, residual aperture and system \ncompliance are entirely ignored. The existence of \nresidual aperture prior to the fracture reopening causes \npressure penetration into the fracture. System \ncompliance is the primary factor for the difference \nbetween Pr(a) and Pr0. \nTaking account of residual aperture and system \ncompliance effects, we analyzed the phenomenon that \nmeasured reopening pressure Pr(a) decreases with the \nrepeated test cycles, and considered that Pr(a) gradually \napproaches to the real value Pr0 due to the increased \ndVc/dP and residual aperture effect. Furthermore, we \npresent two critical values, critical crack length Lc and \ncritical crack capacity Cc, to explain the phenomenon \nthat Pr(a) is less than Ps. It is concluded that the \nappearance order of the two critical values determines the relative magnitude of P\nr(a) and Sh (Ps), and \ncorresponds to two typical patterns of the P-t curve."}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae56810-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/arma-2012-169.pdf", "page": 4, "chroma:document": "corresponds to two typical patterns of the P-t curve. \nWhen Cc appears earlier than Lc, Pr(a) will be between Sh \nand Pr0. \nComparing experiments by hydraulic fracturing were \ncarried out to study the effects of residual aperture and \nsystem compliance. For the phenomenon Pr(a) is less than \nPs at 2 test sections, that is different from others at the \nsame depth, we concluded that it\u2019s not caused by high stress difference, and modified the 2 abnormal data to \naverage lever by determining P\nr(a) in the last test cycle in \na smaller time scale, and using Ito\u2019s theory to calculate \nSH. \nREFERENCES \n1. You, M.Q. 2005. Study on the geo-stresses \nmeasurement with hydro-fracture of borehole. Chinese \nJournal of Geotechnical Engineering, 27(3): 350-353. \n2. LI F.Q., B.C. Zhang, and K.Z. Su. 1993. Reservoir \nInduced Earthquake Risk in Yangtze Gorges Dam Area. \nBeijing: Seismological Press. \n3. Ito, T., T. Satoh, and H. Kato. 2010. Deep rock stress \nmeasurement by hydraulic fracturing method taking"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae56888-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/arma-2012-169.pdf", "page": 4, "chroma:document": "measurement by hydraulic fracturing method taking \naccount of system compliance effect. In Proceedings of \nthe 5th International Symposium on In-situ Rock Stress, \nBeijing, China, 25-27 August 2010 , ed. F.R. Xie, 43-49. \nLeiden: CRC Press/Balkema.  \n4. Ito, T., K. Evans, K. Kawai, et al. 1999. Hydraulic \nfracture reopening pressure and the estimation of \nmaximum horizontal stress. Int. J. Rock Mech. Min. Sci. & Geomech. Abstr., 36: 811-826.  \n5. Ito, T., A. Igarashi, H. Ito, et al. 2006. Crucial effect of \nsystem compliance on the maximum stress estimation \nin hydro fracturing method: Theoretical consideration and field test verification. Earth Planet and Space, 58: \n963-971. Downloaded from http://onepetro.org/ARMAUSRMS/proceedings-pdf/ARMA12/All-ARMA12/ARMA-2012-169/1597153/arma-2012-169.pdf/1 by University of Houston user on 30 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae56900-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/arma-2012-169.pdf", "page": 5, "chroma:document": "6. Guo Q.L., Q.M. An, S.G. Zh ao, and H.Z. Wang. 1996. \nThe analysis and interpretation of the data of hydraulic fracturing stress measurement. In Crustal Tectonics and \nCrustal Stress(8). Beijing: Seismological Press, 103- \n113. Downloaded from http://onepetro.org/ARMAUSRMS/proceedings-pdf/ARMA12/All-ARMA12/ARMA-2012-169/1597153/arma-2012-169.pdf/1 by University of Houston user on 30 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae56978-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-206239-ms.pdf", "page": 0, "chroma:document": "SPE-206239-MS\nDFIT: An Interdisciplinary Validation of Fracture Closure Pressure\nInterpretation Across Multiple Basins\nHern\u00e1n Buijs , Wintershall Dea GmbH\nCopyright 2021, Society of Petroleum Engineers\nThis paper was prepared for presentation at the 2021 SPE Annual Technical Conference and Exhibition held in Dubai, UAE, 21 - 23 September 2021.\nThis paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents\nof the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect\nany position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written\nconsent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae569f0-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-206239-ms.pdf", "page": 0, "chroma:document": "not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.\nAbstract\nRecent papers on pre-frac tests have proposed fracture closure pressure interpretation methodologies that\nlead to an earlier, higher stress estimation than the ones estimated from well-established practices. These\nearly time estimations based on the fracture compliance method lead the practitioner to utilize unrealistic\npermeability, stress, and fracture pressure models. This, in turn, has a severe impact on the modeled fracture\ngeometries which hinders the hydraulic fracture optimization process. A multi-basin analysis of pre-frac\ntests from the North Sea, Europe, Russia, North Africa and South America is presented to support traditional\nclosure estimation techniques. The validity of traditional minimum stress interpretation techniques will be\nreinforced through multiple case histories by comparing permeability estimates from the time required for"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae56a68-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-206239-ms.pdf", "page": 0, "chroma:document": "the fracture to achieve closure during diagnostic injections, after-closure analysis, core, pressure build up\nand rate transient analysis. Results will be supported further by fiber optics and production logging tool\n(PLT) driven flow allocation, fracture geometry assessment through micro seismic and sonic anisotropy,\nand diagnostic injections numerical inversions.\nIntroduction\nInjection pressure has been measured for safety considerations since the inception of hydraulic fracturing.\nIts importance for characterizing fractures was recognized as early as 1954 by Harrison et al., who developed\na relation between pressure and the fracture volume. In 1958, the potential importance of understanding the\nfracturing pressure response to recognize the type of created fracture was noted by Godbey and Hodges\n(Nolte and Gulrajani, 2000).\nThe art of fracture pressure decline analysis is largely based on Ken Nolte's work (Nolte, 1979 ). His"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae56ae0-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-206239-ms.pdf", "page": 0, "chroma:document": "innovative postulations allowed our industry to determine the expected frac geometry, its conductivity, the\nformation flow capacity, and the optimum hydraulic fracture design as well as the means necessary to place\nthe treatment (Nolte, 2007 ). Our industry has utilized this knowledge for several decades to optimize fracture\ntreatments, bringing value to their completions and consistently improve well economics.\nNolte's idealized fracture pressure decline assumptions lead to the development of the G-function,\nthrough which a plot of pressure versus the dimensionless Gtime will yield a straight-line during the fractureDownloaded from http://onepetro.org/SPEATCE/proceedings-pdf/21ATCE/2-21ATCE/D021S036R006/2489405/spe-206239-ms.pdf/1 by University of Houston user on 30 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae56b58-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-206239-ms.pdf", "page": 1, "chroma:document": "2 SPE-206239-MS\nclosure process. This latter represents a constant leak off condition; where fracture closure pressure is\nidentified when a deviation of such a linear trend becomes evident.\nRegretfully, Nolte's postulations are seldom met in routine field practice; having early time deviations\nfrom the proposed G-function straight line until constant leak off conditions are achieved. Nolte and others\ncontinued to address such non-ideal conditions and provided techniques to diagnose the related pressure\nresponses ( Nolte, 1991 ; Nolte et al., 1993; Barree and Miskimins, 2016). Independently of the mentioned\nnon-linearities and the reasons of their occurrence, one of the mainstays of Nolte's work was that fracture\nclosure can be realized at the end of a fracture linear leak off period.\nIn order to make a better assessment of the fracture closure pressure, extensions of the original analysis\nwere made by introducing the utilization of the derivative of pressure with respect to the G-function (dp/"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae56bd0-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-206239-ms.pdf", "page": 1, "chroma:document": "dG; Castillo, 1987 ) and the superposition derivative (Gdp/dG; Barree and Mukherjee, 1996). This workflow\nchanged the equation for the whole industry by providing a consistent method for establishing fracture\nclosure pressure when utilizing in concert the G-function, the log-log plot of pressure change after shut-in\nand their respective derivatives (Barree, et al., 2009 ).\nTraditional fracture closure estimates were further supported by field and laboratory experiments of\nhydraulic fracture closure evaluation. Physical measurements of fracture dimensions during pressure fall\noff have been examined and their results proved to be consistent to traditional estimations of fracture\nclosure pressure. Evidence from downhole tiltmeters, finely instrumented laboratory experiments of fracture\npropagation and closure estimates demonstrate that a residual fracture width is retained after closure.\nConsequently, closure is a misnomer, and if a \"closed\" fracture remains open, the relationship between what"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae56c3e-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-206239-ms.pdf", "page": 1, "chroma:document": "one interprets as fracture closure and the minimum horizontal stress needs to be clearly defined based on\nthe measurement (Craig, et al., 2017). This supports the definition of fracture closure as the pressure within\nthe fracture that equals the contacted minimum horizontal stress, representing a neutral stress state (zero\n\"net pressure\" in the fracture).\nIn 2007, a relationship between wells initial production (IP) and the G-time value at traditional fracture\nclosure was discovered by Conway et al. Their field-tested observation proved there is an intrinsic\nrelationship between the time it takes for the fracture faces to close on each other and the host rock\npermeability (fast closure times equals more permeability). Additionally, over 3,000 analyzed DFIT's from\nthe Rocky Mountain region supported that reservoirs with Process Zone Stress (PZS) gradients greater than\n0.2 psi/ft were economically poor producers (Ramurthy et al., 2013). A larger PZS, representing a larger"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae56cc0-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-206239-ms.pdf", "page": 1, "chroma:document": "difference between fracture and minimum stress, could be related to an increase time to reach fracture\nclosure pressure that stands for lower reservoir permeabilities. Similar approaches were implemented by\nseveral companies when utilizing correlations between the time required for the fracture to close or constant\nleak off magnitudes through pressure derivatives to predict the production of multi-fractured completions\n(Ponce, 2010 ).\nTherefore, if a relationship between the G-function and flow rate exists, then it is reasonable to expect a\ncorrelation between permeability and the G-function. This led to the development of an empirical correlation\nto estimate permeability based on fracture closure time during a Diagnostic Fracture Injection Test (DFIT)\nwhen after-closure radial-flow data are not available (Barree, et al., 2009).\nRecent papers have proposed fracture closure pressure interpretations based on the fracture compliance"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae56d2e-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-206239-ms.pdf", "page": 1, "chroma:document": "method, interpreting an earlier, higher stress estimation than the ones estimated from well-established\nmethodologies ( McClure et al., 2014; 2016  and 2019 ; Jung et al.,2016; Wang and Sharma, 2017 and\n2018 ). Regretfully, this not only opposes Nolte's pioneering work but also proves to be inconsistent with\ndetailed laboratory work, reservoir characterization, fracture geometry assessment technologies, and wells\nproduction performance.\nThis paper presents a multi-basin interdisciplinary study that seeks to support traditional closure\nestimation techniques by DFIT tests numerical inversion further supported by the comparison ofDownloaded from http://onepetro.org/SPEATCE/proceedings-pdf/21ATCE/2-21ATCE/D021S036R006/2489405/spe-206239-ms.pdf/1 by University of Houston user on 30 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae56dec-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-206239-ms.pdf", "page": 2, "chroma:document": "SPE-206239-MS 3\npermeability estimates based on the time required for the fracture to achieve closure, DFIT after-closure\nanalysis, core, pressure build up (PBU) and production rate transient analysis (RTA).\nAs a secondary objective, the case histories presented in this paper prove how the same hydraulic fracture\nlearning cycle (workflow) can be applied to bring value to multi-fractured completions in any type of\nreservoir under a wide range of permeability, pore pressure and state of stress conditions.\nWell Selection Criteria\nThe wells selected for this multi-basin case study have comprehensive and diverse data sets including\ncomplete open hole logging suites, core, PBU, detailed fracture treatment information and long-term\nproduction histories. All analyzed wells are vertical, have permanent downhole gauges and represent a\nwide range of permeabilities under different pore pressure and state-of-stress conditions. Produced reservoir\nfluids include oil, gas, and gas and condensate."}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae56e6e-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-206239-ms.pdf", "page": 2, "chroma:document": "fluids include oil, gas, and gas and condensate.\nThe information utilized for the analysis presented in this paper represents actual conditions encountered\nin wells where uncertainty needs to be collapsed through integrated workflows capable of explaining well\nproduction performance consistently. This allows to properly characterize each reservoir and understand\nthe performance of the fracture treatment placed, providing key information to further optimize hydraulic\nfracture design and bring additional value to the completions.\nMethodology\nIntroduction\nSince the main parameter utilized to assess the validity of traditional fracture closure estimates presented in\nthese case histories is permeability, it is pertinent to shortly describe its meaning and how the concept was\nestablished. The development of Darcy's Law started in 1830 with the Saint-Michel well test when Henry\nDarcy proved that the obtained water rates could not be the explained by just pressure differentials and pipe"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae56edc-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-206239-ms.pdf", "page": 2, "chroma:document": "friction. At this point in time, Darcy deduced an unknown process was occurring, i.e., resistance to flow in\nthe aquifer. It took almost 30 years of knowledge exchange with practicing engineers, direct observations\nof geology and laboratory work to describe the concept of permeability as a means to describe pressure lose\ndue to fluid flow in porous media (Brown, 2002). This is, in essence, the workflow that is applied to the\npresented case histories where a single permeability estimate from multiple processes will be utilized to\ndescribe the reservoir flow capacity. This, in turn, will be utilized to support traditional estimates of fracture\nclosure pressure based on the time required for the fracture faces to close upon each other during diagnostic\ninjections.\nWorkflow\nPermeability, net pressure (PZS) and, among others, 1D mechanical earth models (1DMEM) are created\nfor history-matching the DFIT observed rate and treating pressures. For such purpose, a grid-oriented"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae56f5e-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-206239-ms.pdf", "page": 2, "chroma:document": "planar 3D fracture simulator with shear decoupling capable of managing pressure dependent leak off\n(PDL) and transverse fracture storage is employed (Barree, 1983). DFITs are analyzed utilizing traditional\nmethodologies ( Barree and Mukherjee, 1996; Barree, et al., 1998 and 2009 ; Talley, et al., 1999). Interpreted\nparameters are used to build numerical inversions of such tests based on an iterative process to fine tune the\nfracture simulation model (Gulrajani, et al., 1996; Piggott, et al., 1992; Buijs and Ponce, 2018; Buijs, et al.,\n2019  and 2020 ). A relationship between the host rock permeability and the time required to reach fracture\nclosure is validated through a pressure-match model and its numerical inversion. The fracture closure-based\npermeability estimates (Gperm) are supported by multidisciplinary estimations obtained from DFIT after"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae56fcc-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-206239-ms.pdf", "page": 2, "chroma:document": "closure analysis, core, PBU and RTA.Downloaded from http://onepetro.org/SPEATCE/proceedings-pdf/21ATCE/2-21ATCE/D021S036R006/2489405/spe-206239-ms.pdf/1 by University of Houston user on 30 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae57044-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-206239-ms.pdf", "page": 3, "chroma:document": "4 SPE-206239-MS\nThe correctness of the estimated minimum stress is further validated by evaluating the predictive\ncapabilities of lithology-based 1DMEM, fiber optic and PLT based production back allocation, near\nwellbore and far field assessment of fracture geometries.\nDiagnostic Fracture Injection Tests Numerical Inversion and Gperm Calculation\nOne of the few ways to start a conversation with a reservoir is by pumping completion fluid at fracturing\nrates and analyzing how the pressure fall off with time after the injection is stopped. The language for\nsuch a reservoir dialogue and information exchange is formed by the dimensionless time function called\n\"G-function\" introduced by Nolte (1979) . Barree et al. (1996 , 1998  and 2009 ) refined the meaning of the\ndifferent type curves to clearly identify the minimum stress and further infer additional information about the\ncontacted rock. This work also included the development of an empirical correlation to establish reservoir"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae570b2-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-206239-ms.pdf", "page": 3, "chroma:document": "permeability based on the time needed for the fracture to close during this type of test as shown by Eq 1:\n(Eq. 1)\nGperm= effective permeability (mD); \u03bc = viscosity (cp); P z= process zone stress; \u03c6 = effective porosity;\nCt= total compressibility (1/psi); G c= Gtime at closure; E = Young Modulus (MM psi); r p= leak off height\nto gross frac height ratio\nThe dimensionless time-to-closure is a function of the volumetric efficiency of the fluid and the volume\nto surface area ratio of the created frac. The viscosity used in this analysis approximates the injected fluid\nviscosity corrected for relative permeability effects in the invaded region around the fracture. Leak off until\nclosure is dominated by the mobility of the injected fluid more than the far-field reservoir properties. The\nreservoir effects are handled through the compressive storage term made up of porosity and total reservoir\ncompressibility ( Barree, 2020 )."}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae5712a-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-206239-ms.pdf", "page": 3, "chroma:document": "compressibility ( Barree, 2020 ).\nMultiple DFITs pumped with completion fluid are used to characterize the reservoir by utilizing\ntraditional type curve matching techniques to analyze the pressure transient. Depending on the DFIT\ninterpretation or how one further refines the input to build the computational grid model, several possible\nsolutions can provide an identical pressure match of the fall off data. Most of the functions used to describe\nprocesses within the models have no unique inverse solution and therefore can be replicated in various ways.\nIn order to reduce uncertainty, the analysis was further validated by computing numerical models of such\npre-frac tests in a grid-oriented planar 3D fracture simulator with shear decoupling. The applied workflow\nwas the same as the one utilized to develop the different type curves used by the industry to infer fracture\nclosure pressure ( Barree et al., 1996  and 1998):\n1.The instantaneous shut in pressure (ISIP) is identified."}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae571ac-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-206239-ms.pdf", "page": 3, "chroma:document": "1.The instantaneous shut in pressure (ISIP) is identified.\n2.The minimum stress is estimated by type curve matching.\n3.A permeability estimate based on fracture closure time is calculated.\n4.Traditional after closure analysis is utilized to estimate the reservoir pore pressure and, whenever\npossible, permeability.\n5.The fracture grid is calibrated, the model is run, and the fall-off data pressure-matched.\n6.The modelled pressure is used as it was the actual measured pressure data and analyzed in the same\nmanner.\n7.The fracture model is recalibrated and run again until the pressure match model provides a converging\nsolution capable of reproducing the same minimum stress, time required to reach closure, fracture\nclosure mechanisms and after closure pressure transient seen in the measured pressure data.\nReal data may offer interpretation challenges by having different fracture closure mechanisms in place,"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae57224-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-206239-ms.pdf", "page": 3, "chroma:document": "making it troublesome to identify the correct minimum stress and the time required to reach it (amongDownloaded from http://onepetro.org/SPEATCE/proceedings-pdf/21ATCE/2-21ATCE/D021S036R006/2489405/spe-206239-ms.pdf/1 by University of Houston user on 30 October 2023"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae57292-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-206239-ms.pdf", "page": 4, "chroma:document": "SPE-206239-MS 5\nother variables). When implementing such interpretation cycles, it is possible to numerically model the\nmeasured pressure data and further validate or update the original interpretations, bringing additional value\nto characterize the host rock and the created fracture geometry.\nDFIT based reservoir characterization (i.e: permeability and pore pressure) is further compared to\nindependent measurements such as core, PBU, modular formation tester (MDT) and RTA, showing a high\ndegree of correspondence. Mini-fracs using gels were not utilized to estimate the flowing capacity of the\nhost rock since the relationship between closure time and permeability is decoupled by the presence of\npolymer accumulating in the fracture faces during leak off.\nFracture Geometry and Production Performance Evaluation\nThe fracture treating-pressure history for pre-frac tests and main treatments analyzed are modeled using\na commercial grid-oriented planar 3D fracture simulator with shear decoupling. Digital treatment data"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae5730a-857d-11ee-bb1c-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-206239-ms.pdf", "page": 4, "chroma:document": "is utilized as the input pumping schedule for fracture geometry simulation in this study. Rock physics\nprinciples are utilized to derive lithology-based minimum stress models (1DMEMs) while pore pressure\nand permeability estimates are obtained from multiple and diverse measurements (Barree, et al., 2009; Buijs\nand Ponce, 2018 ; Buijs, et al., 2020 ).\nA combination of numerical and analytical solutions is utilized to model production from the selected\nwells. Initially, RTA is used to assess the contacted net pay (\"kh\"), the reservoir volume and the drainage\nshape that defines the reservoir architecture. The methodology consists of an iterative analysis that honors\nthe flowing material balance, variable reservoir fluid properties and reservoir energy through depletion\n(Cox, S.A. et al., 2002  and 2007 ).\nAs a second step, a fracture production model is utilized to confirm RTA results and to effectively evaluate"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae57382-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/spe-206239-ms.pdf", "page": 4, "chroma:document": "the combined dynamic interactions of reservoir transient flow, gel clean-up, multiphase and non-Darcy\nflow. This latter is a production simulator that combines reservoir transient production forecasting for an\narbitrary shape, rectangular, bounded reservoir with a damaged hydraulic fracture. Its simulations accounts\nfor effects of closure stress, embedment, spalling, filter-cake deposition and erosion, bulk gel damage, and\nnon-Darcy multiphase flow on proppant packs (Duenckel, et al., 2019; Barree, et al; 2003). An iterative\nprocess between the modelled fracture geometry, RTA and a production model that accounts for proppant\npack physical behaviours is implemented till a converging solution is found.\nCase 1: Shale Oil\nIn this case history, traditional minimum stress interpretations are supported by a DFIT numerical inversion\nthat will be reinforced by the integration of permeability modelling, core measurements, stress modelling,\nfiber optics, micro seismic and RTA."}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae573fa-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-206239-ms.pdf", "page": 4, "chroma:document": "fiber optics, micro seismic and RTA.\nThis is a vertical cased and cemented technology well in the Vaca Muerta Shale that was completed with\nfour limited entry fracture stages. In terms of hydraulic fracturing design, the length of individual clusters,\nspacing between clusters, number of holes and hole size were done using most recent understanding of\ncluster dynamics plus proprietary considerations, following a reservoir and completion quality assessment\n(Buijs and Ponce, 2018 ). A hybrid fracture design consisting of slick water and x-linked gel (25 #/1,000\ngal) was utilized to pump two different frac job sizes based on preliminary simulations (200 and 300 tons\nof proppant).\nThe attached G-Function, linear flow time function and Talley-Nolte plots (Fig. 1.A and Fig. 1.B )\ncorrespond to a DFIT pumped above the Vaca Muerta's hot section called \"The Kitchen\". The type curve\nidentified in the Gplot is described as a \"Tip Extension\" closure mechanism that accounts for an early-"}


created_at: 2023-11-17 19:17:23
topic: persistent://default/default/8e5da3e9-8391-4ad8-a826-4d5919dbf381
id: 9ae57472-857d-11ee-bb1c-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/spe-206239-ms.pdf", "page": 4, "chroma:document": "time pressure dependent leak-off (PDL) followed by a linear leak-off profile across the created surface till\nfracture closure is achieved.Downloaded from http://onepetro.org/SPEATCE/proceedings-pdf/21ATCE/2-21ATCE/D021S036R006/2489405/spe-206239-ms.pdf/1 by University of Houston user on 30 October 2023"}


