# embeddings_queue

created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-199690-ms.pdf", "page": 13, "chroma:document": "closure 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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89e374-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89e3c4-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-199690-ms.pdf", "page": 14, "chroma:document": "propagation of the fracture but rather assume a fracture and bedding plane geometry and open the fracture\nand 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89e414-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-199690-ms.pdf", "page": 14, "chroma:document": "fracture 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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89e50e-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89e55e-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-199690-ms.pdf", "page": 15, "chroma:document": "complete closure of the bedding plane, which is further interrupted by a reincrease which infers the closing\nof 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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89e5ae-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89e5fe-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-199690-ms.pdf", "page": 16, "chroma:document": "affected by the rate of fracture closure.\nFigure 21\u2014G-function plots with permeability layer heterogeneity. (a) Layer perm=0.2\u03bcD,\n(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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89e658-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-199690-ms.pdf", "page": 16, "chroma:document": "regression 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\nlayer 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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89e6a8-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89e6f8-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89e748-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-199690-ms.pdf", "page": 18, "chroma:document": "Young's modulus of the rock matrix does not play a significant role in controlling the pressure fall-\noff 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89e798-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-199690-ms.pdf", "page": 18, "chroma:document": "simultaneously.\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\nresponse.\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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89e7e8-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-199690-ms.pdf", "page": 18, "chroma:document": "Barree, 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\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 ."}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89e838-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-199690-ms.pdf", "page": 18, "chroma:document": "Propagation 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\nPressure 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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89e892-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89e8e2-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-199690-ms.pdf", "page": 19, "chroma:document": "Wang, H.  and Sharma, M.M. , 2019a. A Novel Approach for Estimating Formation Permeability and Revisiting After-\nClosure 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."}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89e93c-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-199690-ms.pdf", "page": 19, "chroma:document": "implicit 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\nIterative 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89e98c-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-199690-ms.pdf", "page": 19, "chroma:document": "doi.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\nZheng, 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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89e9fa-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89ea54-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-199690-ms.pdf", "page": 20, "chroma:document": "fracture closure at the initial deflection point from the linear portion on the pressure derivative curve. Wang\nand 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89eaa4-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-199690-ms.pdf", "page": 20, "chroma:document": "Wang 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\npost-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: 2023-11-16 17:06:54
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{"source": "drive/MyDrive/Fracture closure Reviews/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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89eb44-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89eb9e-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89ebee-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-189826-ms.pdf", "page": 0, "chroma:document": "DFIT data in the Duvernay shale are analyzed using pressure transient analysis methods. Two scenarios\nare 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89ec3e-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-189826-ms.pdf", "page": 0, "chroma:document": "the 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\nor 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89ec8e-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-189826-ms.pdf", "page": 0, "chroma:document": "falloff 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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89ecde-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89ed38-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-189826-ms.pdf", "page": 1, "chroma:document": "Results and Discussion section, field data are interpreted in the context of simulation results.\nGeological 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 )."}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89ed88-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-189826-ms.pdf", "page": 1, "chroma:document": "over 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\nstress. 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89edd8-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-189826-ms.pdf", "page": 1, "chroma:document": "it 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,\nDavis 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89ee28-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-189826-ms.pdf", "page": 1, "chroma:document": "suggests 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\nspatial-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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89ee82-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-189826-ms.pdf", "page": 1, "chroma:document": "Evidence 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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89eed2-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89ef2c-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-189826-ms.pdf", "page": 2, "chroma:document": "parts of the reservoir throughout the treatment. The first hydraulic growth cluster produces a large half\nlength 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89ef7c-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-189826-ms.pdf", "page": 2, "chroma:document": "Formation. 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\nnew 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89efd6-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-189826-ms.pdf", "page": 2, "chroma:document": "rupture 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\nwall 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89f04e-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-189826-ms.pdf", "page": 2, "chroma:document": "movement 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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89f09e-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89f0ee-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-189826-ms.pdf", "page": 3, "chroma:document": "a pressure gradient of 20 KPa/m located at 3 km depth. We choose the minimum horizontal stress to be 0.8\ntimes 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89f148-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-189826-ms.pdf", "page": 3, "chroma:document": "how 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.\nAs 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89f198-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-189826-ms.pdf", "page": 3, "chroma:document": "stress, 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\nof 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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89f1e8-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89f242-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-189826-ms.pdf", "page": 4, "chroma:document": "and the Carter leakoff model (Howard and Fast 1957) for before closure analysis. Gu et al. (1993) and Nolte\net 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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89f292-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-189826-ms.pdf", "page": 4, "chroma:document": "Figure 3\u2014(a) Normal leakoff; (b) PDL; (c) tip extension; (d) storage/height\nrecession 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"}


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{"source": "drive/MyDrive/Fracture closure Reviews/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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89f33c-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-189826-ms.pdf", "page": 5, "chroma:document": "Bourdet-derivative corresponds to a straight line trend on G-function derivatives, representing Carter leakoff\n(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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89f38c-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89f3e6-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-189826-ms.pdf", "page": 6, "chroma:document": "Some DFIT responses in shale reservoirs, such as the Duvernay shale, are not consistent with those\ninterpreted 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."}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89f440-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-189826-ms.pdf", "page": 6, "chroma:document": "Figure 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\nunit 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89f490-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-189826-ms.pdf", "page": 6, "chroma:document": "Several 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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89f4e0-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89f530-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-189826-ms.pdf", "page": 7, "chroma:document": "herein to generate synthetic DFIT responses. The customized model is capable of simulating all the physical\nprocesses 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89f58a-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-189826-ms.pdf", "page": 7, "chroma:document": "separation 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\nnetwork 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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89f5e4-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89f634-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-189826-ms.pdf", "page": 8, "chroma:document": "as the optimum value.\nResults 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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89f6ac-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89f6fc-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-189826-ms.pdf", "page": 9, "chroma:document": "fluctuations are controlled by the size of fracture elements which is uniform throughout the length of\nfracture. 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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89f756-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89f7a6-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-189826-ms.pdf", "page": 10, "chroma:document": "minimum horizontal stress ( Fig. 10b ).\nFigure 10\u2014(a) Pressure profile during injection and early shut-in time for Model 2; (b) Propagation as the\nprimary 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,"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89f7f6-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-189826-ms.pdf", "page": 10, "chroma:document": "The 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\npressure 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89f846-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-189826-ms.pdf", "page": 10, "chroma:document": "hours. 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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89f896-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89f8e6-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-189826-ms.pdf", "page": 11, "chroma:document": "system 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\nCarter 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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89f940-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89f990-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-189826-ms.pdf", "page": 12, "chroma:document": "resulting in pressure gradient within the fractures. This explains the unclear breakdown point and\npressure 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89f9ea-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-189826-ms.pdf", "page": 12, "chroma:document": "ShminMinimum 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\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-"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89fa3a-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-189826-ms.pdf", "page": 12, "chroma:document": "Presented 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"}


created_at: 2023-11-16 17:06:54
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{"source": "drive/MyDrive/Fracture closure Reviews/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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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-189826-ms.pdf", "page": 13, "chroma:document": "Injection Tests Using Multiple Analysis Methods. SPE Production & Operations 24(3): 396 -406. SPE-107877-PA.\nhttp://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."}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-189826-ms.pdf", "page": 13, "chroma:document": "Creaney, S  and Allan, J.  1990 . Hydrocarbon Generation and Migration in the Western Canada Sedimentary Basin.\nGeological 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"}


created_at: 2023-11-16 17:06:54
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-189826-ms.pdf", "page": 13, "chroma:document": "(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\nDerived 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."}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-189826-ms.pdf", "page": 13, "chroma:document": "Practice  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\nKrauklis, 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-189826-ms.pdf", "page": 13, "chroma:document": "June. 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\nNolte, 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://"}


created_at: 2023-11-16 17:06:54
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-189826-ms.pdf", "page": 13, "chroma:document": "at 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"}


created_at: 2023-11-16 17:06:54
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{"source": "drive/MyDrive/Fracture closure Reviews/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: 2023-11-16 17:06:54
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-189826-ms.pdf", "page": 14, "chroma:document": "Tary, J. , Baan, M.  and Eaton, D.  2014 . Interpretation of Resonance Frequencies Recorded During Hydraulic Fracturing\nTreatments. 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"}


created_at: 2023-11-16 17:06:54
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{"source": "drive/MyDrive/Fracture closure Reviews/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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b89fe9a-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-167074-ms.pdf", "page": 0, "chroma:document": "Arrow Energy is currently conducting a wide -scale exploration and well testing programme in the Bowen Basin region of \nQueensland, 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-167074-ms.pdf", "page": 0, "chroma:document": "management 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.  \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."}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-167074-ms.pdf", "page": 0, "chroma:document": "completed 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 \nwell 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-167074-ms.pdf", "page": 0, "chroma:document": "formation 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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
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{"source": "drive/MyDrive/Fracture closure Reviews/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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a00ac-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-167074-ms.pdf", "page": 1, "chroma:document": "integrated and comprehensive assessment  of the subsurface environment; such a n analysis should be focused on identify ing \nwhich 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,"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a0106-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-167074-ms.pdf", "page": 1, "chroma:document": "Bowen 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 \nand 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a0160-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-167074-ms.pdf", "page": 1, "chroma:document": "Geology  \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 \nbasis 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 ."}


created_at: 2023-11-16 17:06:54
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-167074-ms.pdf", "page": 1, "chroma:document": "and \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. \n \nDepending 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"}


created_at: 2023-11-16 17:06:54
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-167074-ms.pdf", "page": 1, "chroma:document": "impact 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"}


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{"source": "drive/MyDrive/Fracture closure Reviews/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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a06ce-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-167074-ms.pdf", "page": 2, "chroma:document": "The brevity of well tests is likely to preclude the observation of such phenomena, but the parameters required to estimate th e \nlong-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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a0728-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-167074-ms.pdf", "page": 2, "chroma:document": "greater 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.   \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."}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a0782-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-167074-ms.pdf", "page": 2, "chroma:document": "(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 \ndifferent 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a07d2-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-167074-ms.pdf", "page": 2, "chroma:document": "\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 \nsuch 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a0836-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-167074-ms.pdf", "page": 2, "chroma:document": "The 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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a08ae-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-167074-ms.pdf", "page": 2, "chroma:document": "breakdown , rendering a destructive injection test unviable. Furthermore, at higher poroperm values, stimulated completions or \nhorizontal 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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a0912-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/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,"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a096c-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-167074-ms.pdf", "page": 3, "chroma:document": "\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).  \n \n \nDiagnostic 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."}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a09c6-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-167074-ms.pdf", "page": 3, "chroma:document": "typecurves 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 \nproviding 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a0a20-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-167074-ms.pdf", "page": 3, "chroma:document": "cased 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 \npresent 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a0a70-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-167074-ms.pdf", "page": 3, "chroma:document": "and 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 \nextensive 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a0aca-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-167074-ms.pdf", "page": 3, "chroma:document": "The 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 \ninjection 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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a0b24-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/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."}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a0b7e-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-167074-ms.pdf", "page": 4, "chroma:document": "plungers resulted in difficulties with delivering low -rate. \n \nAn outline of the open -hole testing procedure is as follows:  \n \n\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 ."}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a0bd8-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-167074-ms.pdf", "page": 4, "chroma:document": "\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 . \n 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a0c28-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-167074-ms.pdf", "page": 4, "chroma:document": "using 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 \nborehole 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%"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a0c82-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-167074-ms.pdf", "page": 4, "chroma:document": "of 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 \nfacilitated 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,"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a0cdc-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-167074-ms.pdf", "page": 4, "chroma:document": "timeframes;  \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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a0d36-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a0d86-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-167074-ms.pdf", "page": 5, "chroma:document": "schedule.  \n\u2022 Fracture Tip E xtension (FT E): Observed in a number of very low -permeability formations , the occurrence of this \neffect 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a0de0-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-167074-ms.pdf", "page": 5, "chroma:document": "database.   \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 \ntends 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 ."}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a0e3a-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-167074-ms.pdf", "page": 5, "chroma:document": "practices, 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 \nnoted 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a0f02-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-167074-ms.pdf", "page": 5, "chroma:document": "treatment. 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 \ninjection 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a0f5c-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-167074-ms.pdf", "page": 5, "chroma:document": "As 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 \nminimal; 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a0fac-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-167074-ms.pdf", "page": 5, "chroma:document": "Performing 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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a0ffc-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a104c-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-167074-ms.pdf", "page": 6, "chroma:document": "the typical breakdown profile  (Figure 3); the lack of a definitive breakdown pressure value greater than the propagation \npressure 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a109c-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-167074-ms.pdf", "page": 6, "chroma:document": "heterogeneity 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 \nobser 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a10f6-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-167074-ms.pdf", "page": 6, "chroma:document": "of 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 \npackage 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."}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a1146-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-167074-ms.pdf", "page": 6, "chroma:document": "Goonyella 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:  \n \n\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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a1196-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-167074-ms.pdf", "page": 6, "chroma:document": "\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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a11e6-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a1236-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-167074-ms.pdf", "page": 7, "chroma:document": "\u2022 Static geological model:  A full-field geological model, based on previously acquired well logs , seismic  and drilling \ndata 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 )"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a1290-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-167074-ms.pdf", "page": 7, "chroma:document": "equations ( 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  \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."}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a12e0-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-167074-ms.pdf", "page": 7, "chroma:document": "approximately 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 . \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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a1330-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-167074-ms.pdf", "page": 7, "chroma:document": "\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.  \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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a1380-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a13d0-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-167074-ms.pdf", "page": 8, "chroma:document": "proven a valuable element in the justification of open -hole DFITs as a method for acquiring in -situ subsurface data.   \n \nWhen 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  (-)"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a142a-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-167074-ms.pdf", "page": 8, "chroma:document": "\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  \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."}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a1484-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-167074-ms.pdf", "page": 8, "chroma:document": "European 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.  \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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a14d4-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-167074-ms.pdf", "page": 8, "chroma:document": "Ito, 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"}


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{"source": "drive/MyDrive/Fracture closure Reviews/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: 2023-11-16 17:06:54
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{"source": "drive/MyDrive/Fracture closure Reviews/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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
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{"source": "drive/MyDrive/Fracture closure Reviews/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: 2023-11-16 17:06:54
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{"source": "drive/MyDrive/Fracture closure Reviews/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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
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{"source": "drive/MyDrive/Fracture closure Reviews/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"}


created_at: 2023-11-16 17:06:54
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{"source": "drive/MyDrive/Fracture closure Reviews/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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
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{"source": "drive/MyDrive/Fracture closure Reviews/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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-167074-ms.pdf", "page": 13, "chroma:document": "Geo-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\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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a17b8-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a1808-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a1858-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/arma-2012-169.pdf", "page": 0, "chroma:document": "[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 \nonly 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a18a8-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/arma-2012-169.pdf", "page": 0, "chroma:document": "The 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 \nexceeds 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a18f8-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/arma-2012-169.pdf", "page": 0, "chroma:document": "Study 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 \naccount 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a1952-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/arma-2012-169.pdf", "page": 0, "chroma:document": "dVc/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. \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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a19a2-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a19f2-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/arma-2012-169.pdf", "page": 1, "chroma:document": "opening. \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 \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."}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a1a42-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/arma-2012-169.pdf", "page": 1, "chroma:document": "their 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 \npore 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a1a92-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/arma-2012-169.pdf", "page": 1, "chroma:document": "storage 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 \nthe 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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a1ae2-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a1b3c-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/arma-2012-169.pdf", "page": 2, "chroma:document": "pressure as P\nr0, 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a1b8c-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/arma-2012-169.pdf", "page": 2, "chroma:document": "following 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 \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"}


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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/arma-2012-169.pdf", "page": 2, "chroma:document": "compliance 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\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."}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a1c2c-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/arma-2012-169.pdf", "page": 2, "chroma:document": "in 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 \nshould 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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a1c7c-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a1ccc-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/arma-2012-169.pdf", "page": 3, "chroma:document": "r(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, \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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a1d1c-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/arma-2012-169.pdf", "page": 3, "chroma:document": "to 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 \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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a1d76-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/arma-2012-169.pdf", "page": 3, "chroma:document": "the 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, \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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a1dc6-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a1e16-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/arma-2012-169.pdf", "page": 4, "chroma:document": "80\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 \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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a1e66-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/arma-2012-169.pdf", "page": 4, "chroma:document": "critical 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. \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."}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a1eb6-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/arma-2012-169.pdf", "page": 4, "chroma:document": "measurement 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 \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:"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a1f10-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/arma-2012-169.pdf", "page": 4, "chroma:document": "in 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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a1f60-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a1fb0-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a2000-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-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\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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a205a-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 0, "chroma:document": "tests 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\nthe 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a20aa-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 0, "chroma:document": "Its 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\ninnovative 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,"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a20fa-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 0, "chroma:document": "Nolte'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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a214a-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a219a-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 1, "chroma:document": "In 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/\ndG; 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a21ea-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 1, "chroma:document": "off 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\none 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a223a-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 1, "chroma:document": "closure 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\ndifference 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 )."}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a2294-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 1, "chroma:document": "leak 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\nmethod, 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a22e4-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 1, "chroma:document": "2018 ). 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: 2023-11-16 17:06:54
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{"source": "drive/MyDrive/Fracture closure Reviews/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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a2384-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a23d4-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 2, "chroma:document": "Darcy proved that the obtained water rates could not be the explained by just pressure differentials and pipe\nfriction. 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a2424-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 2, "chroma:document": "injections.\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\nplanar 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a2474-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 2, "chroma:document": "closure 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\nclosure 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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a24ce-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a251e-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 3, "chroma:document": "contacted rock. This work also included the development of an empirical correlation to establish reservoir\npermeability 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a256e-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 3, "chroma:document": "closure 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 ).\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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a25be-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 3, "chroma:document": "pre-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.\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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a260e-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 3, "chroma:document": "solution 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,\nmaking 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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a265e-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a26b8-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 4, "chroma:document": "The 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\nis 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a2708-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 4, "chroma:document": "the 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\nthe 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a2758-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 4, "chroma:document": "pack 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.\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)."}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a27a8-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 4, "chroma:document": "gal) 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-\ntime 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"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a27f8-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 5, "chroma:document": "6 SPE-206239-MS\nFigure 1.A\u2014 Diagnostic injection G-plot for well A, stage 1.  Blue curve is bottom hole pressure, green is\nfirst derivative curve (Dp/DG), red curve is (G*Dp*/DG). G*Dp*/DG: The semilog or superposition derivative curve\nFigure 1.B\u2014 Linear Flow Time and Talley-Nolte Plots interpretation for well A, stage 1. Linear time flow function:\nBlue curve is bottom hole pressure. Talley-Nolte Plots: Blue curve is delta pressure; green is the log derivative curve.\nThe pressure fall off analysis provides an interpreted minimum stress of 9,123 psi, a pore pressure of\n8,550 psi and a late time fracture closure related to the low permeability of the contacted rock. In that respect,\nfracture closure is achieved at a Gtime of ~45, taking approximately 10 hours for the fracture to reach such\ncondition. An additional confirmation of the validity of the pore pressure estimate is given by the Talley-"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a2884-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 5, "chroma:document": "condition. An additional confirmation of the validity of the pore pressure estimate is given by the Talley-\nNolte plot that confirms the presence of a linear flow period by the identified half slope of the pressure\nderivative. When the estimated pore pressure is correct, the pressure difference curve will also fall on a half\nslope and be 2x higher in magnitude than the derivative as shown in Fig 1.B (Talley, et al., 1999).\nFrom these graphs it is difficult to understand how the fracture geometry develops and how to further\ncalibrate the leak-off profiles that are utilized in the fracture model. For such purpose, the interpreted\nminimum stress and pseudo-linear pore pressure were utilized to calibrate a litho-based 1DMEM that was\nable to predict multiple closure points measured on this well under a single tectonic boundary condition\nas shown in Fig. 2.A (calibration point is marked with a black arrow, predicted stresses are indicated by"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a28de-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 5, "chroma:document": "as shown in Fig. 2.A (calibration point is marked with a black arrow, predicted stresses are indicated by\nblue arrows).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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a292e-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 6, "chroma:document": "SPE-206239-MS 7\nFigure 2.A\u2014Traditional closure litho-based 1DMEM for well A, stage 1.\nThe pressure-match model was then run with reduced time steps to better understand how the geometry\ndeveloped through time (Fig. 2.B). It proved that, due to the low permeability of this interval, there was\nenough remaining energy within the fracture body to keep on propagating the fracture after the pumps\nhave stopped as presented on Fig. 2.C  (shifting the linear trends of a normal leak-off profile and inducing\na pressure dependent signature related to the additional area created). Under this condition, the Gperm\nequation cannot be used directly to estimate the reservoir flowing capacity since the fracture continues\nto propagate after the pumps are stopped at surface. In that respect, a DFIT numerical inversion was\nimplemented to assess the contacted reservoir permeability (Buijs and Ponce, 2018 ; Buijs, et al., 2019).\nFigure 2.B\u2014Diagnostic injection pressure-match for well A, stage 1. Green Curve:"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a297e-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 6, "chroma:document": "Figure 2.B\u2014Diagnostic injection pressure-match for well A, stage 1. Green Curve:\nMeasured well head pressure Blue Curve: Modeled well head pressure Red curve: Frac rate.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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a29d8-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 7, "chroma:document": "8 SPE-206239-MS\nFigure 2.C\u2014Net pressure plot vs Time for well A, stage 1 (Three-time instants are here illustrated).\nThe DFIT pressure-match was achieved by implementing an iterative pressure match process until the\nmodelled pressure converge to provide the same fracture closure mechanism, minimum stress, time to reach\nclosure and after-closure pressure transient dissipation that allowed to estimate a host rock permeability (as\nshown in Fig. 3.A  and Fig. 3.B).\nFigure 3.A\u2014DFIT vs simulated DFIT Gplot for well A, stage 1. Blue curve is\nbottom hole pressure, green is first derivative curve (Dp/DG), red curve is (G*Dp*/DG).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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a2a28-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 8, "chroma:document": "SPE-206239-MS 9\nFigure 3.B\u2014 DFIT vs simulated DFIT after-closure analysis for well A, stage 1 . Linear time flow function:\nBlue curve is bottom hole pressure. Talley-Nolte Plots: Blue curve is delta pressure; green is the log derivative curve.\nThis interpretation technique was utilized in all the diagnostic injection tests pumped during the\ntechnology phase development across multiple vertical wells. It proved to be an extremely powerful\ntechnique to build a thorough understanding of the pore pressure, permeability and state-of-stress conditions\nacross different units of the Vaca Muerta shale in this field.\nWhen utilizing the compliance methodology to interpret the minimum stress, fracture closure happens at\na Gtime of ~10 in less than 1 hour, with an interpreted minimum stress of 9,352 psi which is ~200 psi larger\nthan the one estimated by traditional closure techniques as presented on Fig. 4.A .\nFigure 4.A\u2014 Compliance DFIT closure analysis for well A, stage 1. Blue curve is"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a2a78-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 8, "chroma:document": "Figure 4.A\u2014 Compliance DFIT closure analysis for well A, stage 1. Blue curve is\nbottom hole pressure, green is first derivative curve (Dp/DG), red curve is (G*Dp*/DG).\nWhen implementing this magnitude to calibrate the litho-based 1DMEM (marked as red cross on track 2\nin Fig. 4.B ), the stress model not only cannot predict multiple closure points on this well but rather matched\nthe fracture pressure (ISIPs) measured consistently during multiple injections (marked as blue points onDownloaded 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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a2ac8-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 9, "chroma:document": "10 SPE-206239-MS\ntrack 2 in Fig. 4.A ). This, in turn, makes the calibrated stress model through the fracture compliance method\ninvalid, inconsistent and lacking predictive capabilities since it does not allow to properly understand the\nstate-of-stress in the host rock. Consequently, this will not allow to match any of the near wellbore and\nmicro seismic measurements of fracture height in this well (unless the concept of stress is decoupled from\nthe fracture modelling process), stopping the fracturing learning cycle and any meaningful optimization\nopportunity that will allow for improving the well economics.\nFigure 4.B\u2014Compliance 1DMEM for well A, stage 1.\nTen diagnostic injections pumped across three vertical wells in strategic positions, allow understanding\nthe permeability and the state-of-stress of this reservoir in a more profound way. When integrating\ninformation from multiple diagnostic injections, it was noticed that DFIT's pumped in zones with low"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a2b22-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 9, "chroma:document": "information from multiple diagnostic injections, it was noticed that DFIT's pumped in zones with low\nresistivity have very limited permeability when compared to high resistivity intervals where fracture\nclosured happened much faster and, at the same time, have two distinct G-function plot responses as seen\nin Fig. 5.A  (i.e. closure mechanisms).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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a2b72-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 10, "chroma:document": "SPE-206239-MS 11\nFigure 5.A\u2014 Resistivity vs DFIT \"G\" and log-log plots for well A, stage 1. Log-log plot: Blue curve is\nDelta Pressure, green is first derivative curve (dDP/dDT), red curve is (DT* dDP/dDT). DP: fall off pressure\nminus the Instantaneous Shut-In Pressure (ISIP), DT* dDP/dDT: The semilog or superposition derivative curve\nTaking these observations into account, a permeability function was built by using effective porosity\n(PHIE), resistivity, differences between deep-shallow resistivity measurements and the rock mechanics\nsynthetic travel time curves, which were further constrained by DFIT closure time permeability estimates\n(Gperm) called \"GRES_Perm\" in track 2 of Fig. 5.B  (Buijs and Ponce, 2018; Buijs, et al., 2019 ).\nFigure 5.B\u2014GRES-Perm vs TOC and slowness for well A, stage 1 .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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a2bc2-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 11, "chroma:document": "12 SPE-206239-MS\nAs shown in track 3 of Fig. 5.B, there is a strong correlation with the suggested permeability model and\nthe travel time slowness used to model the Total Organic Carbon or TOC (Passey et al 1990a and 1990b ;\nCaniggia and Ferguson, 2014), as it is when plotting the mentioned function against core measured TOC\nas presented in track 5.\nThis phenomenon would indicate that the fissures present in the analyzed wells are related to the\nmaturation and sourcing of hydrocarbons rather than to macro fissures related to structural deformations.\nIt is worth mentioning that core permeabilities in multi-fractured tight reservoirs cannot be utilized to\ncalibrate their flowing capacity models since hydraulic fracturing will induce shear failure in the contacted\nrock and alter the overall system permeability (Cluff, et al., 2007; Barree and Miskimins, 2016). In this\ncase, assuming pulse decay permeabilities can describe the shale matrix permeability, production behaviour"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a2c12-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 11, "chroma:document": "case, assuming pulse decay permeabilities can describe the shale matrix permeability, production behaviour\nand DFIT numerical inversion supports that the flowing capacity should be at least one order of magnitude\nhigher than core-based permeabilities. Simply put, core permeability is a point measurement that cannot\ndescribe the flowing capacity of a naturally fractured or fracture enhance permeability rock since it carries\nno information from these high flowing capacity channels. This is further supported by over 30 years of\nresearch on proppant pack fracturing fluid clean up studies that clearly shows that the limited effective\nflowing fracture lengths established in a nano-Darcy matrix rock cannot explain the production performance\nof these wells, reinforcing the presence of a larger contacted flowing capacity ( Duenckel, et al., 2019).\nAdditionally, matrix permeabilities cannot explain why the cumulative production from unconventional"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a2c6c-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 11, "chroma:document": "Additionally, matrix permeabilities cannot explain why the cumulative production from unconventional\nwells can be improved by implementing drawdown managment strategies. This latter allows to delay\nthe onset of matrix dominated permeabilities and take advantage of the mentioned early time enhanced\npermeability to maximize hydrocarbon recovery in such pressure dependent flowing capacity systems.\nWhen the fracture compliance closure is utilized, not only is the 1DMEM incorrect making it impossible\nto make a precise assessment of the fracture geometry created by the different treatments pumped on this\nwell but, additionally, the relationship between the time it takes for the fracture to close and the contacted\nreservoir permeability is decoupled. If we assume the fracture closure from the compliance method is\ncorrect, the fracture closure time becomes similar to the ones achieved by the PDL closure mechanism"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a2cbc-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 11, "chroma:document": "correct, the fracture closure time becomes similar to the ones achieved by the PDL closure mechanism\nassociated with natural fractures (Gtime of ~10 as presented in Fig 4.B vs Gtime of ~6 as shown in Fig.\n5.A). This suggests that the contacted reservoir flowing capacity by both diagnostic injections is comparable\nsince fracture closure is achieved on both tests in less than 1 hr. Regretfully, this becomes questionable\nsince the flowing capacity of a naturally fractured formation is not comparable with one that is dominated\nby nano-Darcy matrix permeabilities.\nWhen fractures are initiated within the slowness-brittleness anomaly shown on the second track in Fig.\n6.A, fractures can grow excessively in height and production changed drastically. Fiber production data from\nthe stage placed in the upper Vaca Muerta produced almost 60% of the production of this well. Rare enough,\nproduction came from the upper two perforation clusters instead of the seven clusters utilized to pump the"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a2d0c-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 11, "chroma:document": "production came from the upper two perforation clusters instead of the seven clusters utilized to pump the\nfracture treatment, suggesting a large flowing capacity unit has been contacted above them ( Fig. 6.B).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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a2d5c-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 12, "chroma:document": "SPE-206239-MS 13\nFigure 6.A\u2014Sonic anisotropy measured frac height vs slowing-brittleness anomaly\nFigure 6.B\u2014Fiber optic production back allocation.\nNevertheless, a discrepancy can be seen between the near wellbore sonic anisotropy fracture height\nshowing that the fracture stays contained within the upper Vaca Muerta (Fig. 6.A ) and the measured microDownloaded 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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a2dac-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 13, "chroma:document": "14 SPE-206239-MS\nseismic cloud suggesting that the fracture was able to reach the overlaying Quintuco formation ( Fig. 6.C).\nThe main question to answer at that time was if the hydraulic fracture grew into Quintuco or if the micro\nseismic events were caused by rock shear stress energy release because of the hydraulic fracture (dry events).\nFigure 6.C\u2014Micro seismic frac geometry assessment\nAs seen in Fig 6.D  blue curve, when combining the near wellbore measurement of fracture height with\nthe GRES-Perm flowing capacity model, the early time well production performance cannot be matched.\nTo match the early time performance and the produced volumes based on RTA, it is required to have a\nlarger kh (at least, 2 times higher) which further supports fracture height growth into the Quintuco formation\nas shown by the micro seismic fracture geometry assessment. At this stage, it is difficult to judge if the"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a2e06-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 13, "chroma:document": "as shown by the micro seismic fracture geometry assessment. At this stage, it is difficult to judge if the\nconnection with this higher permeability interval is a partial or a lasting one but is something that cannot\nbe avoided in the upper Vaca Muerta and rather capitalized on by landing wells in the right position.\nFigure 6.D\u2014 RTA \u2013 Sonic anisotropy vs micro seismic frac height Red curve: Microseismic kh. Blue curve: Sonic anisotrophy kh.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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a2e56-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 14, "chroma:document": "SPE-206239-MS 15\nFocal mechanism analysis performed on the micro seismic events provided a clue to understanding\nfracture geometry, showing that most of the events detected in the Quintuco are fluid connected (wet events),\nbut most likely not propped. In addition, dip-slip has the same radiation pattern as that of horizontal slip on\na horizontal surface slipping orthogonally to the strike of the dip-slip solution suggesting the development\nof horizontal fractures.\nIn this regard, the litho-based stress model calibrated based on traditional interpretation techniques was\nutilized to understand the complexity seen on the micro seismic data in the Quintuco formation and why all\nevents stop drastically at a predefined depth. As can be seen in Fig. 7.A  and 7.B, the high complexity zone\nseen in the micro seismic recorded during fracture placement coincides with a zone where the minimum\nstress (red curve) and the overburden (black curve) tend to overlap. Under this condition, the fracture"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a2ea6-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 14, "chroma:document": "stress (red curve) and the overburden (black curve) tend to overlap. Under this condition, the fracture\nwill not have a clear path to develop growth and the fracture orientation will change from vertical to\nhorizontal, explaining the development of horizontal fractures interpreted based on micro seismic events.\nAdditionally, all micro seismic events stop at the same depth where the minimum stress becomes higher than\nthe overburden stress. At this position, the fractures will stop propagating upwards since the maximum stress\nplane will be parallel to the bedding of the rock (fractures will grow in the direction of the bedding planes).\nIn turn, this proves that the litho-based 1DMEM is not only consistent with a large number of diagnostic\ninjections but also with the independent assessment of fracture geometry provided by micro seismic events.\nFigure 7\u2014Traditional vs Compliance based 1DMEM, micro seismic and proppant convection frac geometry."}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a2f00-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 14, "chroma:document": "Figure 7\u2014Traditional vs Compliance based 1DMEM, micro seismic and proppant convection frac geometry.\nWhen modelling the fracture geometry under the mentioned conditions, the simulation illustrates that\nmostly fluid can grow into the Quintuco ( Fig 7.C ), travelling further than proppant that is held back in\nVaca Muerta due to gravitational/frac wall effects. The modelled fracture geometry is consistent with the\nindependent interpretation of fracture geometry provided by the micro seismic events and, at the same time,\nthe near wellbore fracture height measurements when modelling proppant convection as presented in Fig.\n7.A (Buijs and Ponce, 2018 ).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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a2f50-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 15, "chroma:document": "16 SPE-206239-MS\nInformation from several diagnostic injections, rock physics, litho-based 1DMEM, fracture geometry\nassessment technologies, fiber optics, RTA and fracture geometry models were used to understand the\nproduction performance of this well. Among many learnings, integrated modelling clearly shows that the\nproduction from this well can only be explained by having a fracture treatment growing into the Quintuco\nformation.\nIf the compliance closure pressure is utilized to calibrate the 1DMEM, the model becomes inconsistent\nwith the previous integrated evaluation since the fracture will not be able to grow in height towards the\nQuintuco due to having the minimum stress becoming larger than the overburden at a shallower position\nas marked with a red arrow on track 2 in Fig. 7.A . This stress model then becomes inconsistent with\nthe independent assessment of fracture geometry provided by micro seismic supporting events related to"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a2fc8-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 15, "chroma:document": "the independent assessment of fracture geometry provided by micro seismic supporting events related to\nhorizontal fracture development and fracturing fluid rather than proppant. This, in turn, does not allow for\nexplaining the fiber optic production allocation showing that almost 60% of the production came from the\nupper 2 clusters of the fracture stage placed in the upper Vaca Muerta suggesting fracture growth into a\nhigher deliverability interval.\nAs proven by the integration of multiple diagnostic technologies, without a clear understanding of\nthe state-of-stress, how the rock will deform to create fracture width and, among others, the host rock\npermeability it is impossible to understand anything useful about fracture geometry. If one fails to properly\ninterpret a fracture injection test, the created fracture geometry will be incorrect, i.e. 1) the leak-off will be\noff, 2) the way the rock fails in shear will not be right, 3) the stress profile will be unsuitable and 4) the flow"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a3022-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 15, "chroma:document": "off, 2) the way the rock fails in shear will not be right, 3) the stress profile will be unsuitable and 4) the flow\ncapacities of the host rock drastically reduced (affecting production and reserves).\nThe main problem is that, depending on the workflow and software applied to describe the system,\nfracture geometries and production can be matched by following various alternative assumptions due to not\nhaving enough information to properly constrain the solution. To put things in perspective, in this case it took\nten DFITs, tracers, PLT, fiber optics, micro seismic and near wellbore assessments of fracture geometries\nto prove the lack of physical meaning of the fracture compliance closure estimates. It also demonstrates\nthat the host rock might easily be described in completely different ways, leading the engineer to follow an\ninappropriate completion optimization strategy.\nCase 2: Tight Gas Sandstone"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a3072-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 15, "chroma:document": "inappropriate completion optimization strategy.\nCase 2: Tight Gas Sandstone\nIn this case history, traditional minimum stress interpretations are supported by a DFIT numerical\ninversion constrained by triaxial elastic measurements and rock physics modelling, proving there is a direct\nrelationship between the estimated permeability based on the time it takes to reach fracture closure and core\npermeability measurements.\nThis is a tight gas reservoir that was fracture stimulated by pumping the treatment through a large\nperforation interval in a cased and cemented vertical well. After each perforation run, treated completion\nfluid was pumped at low rates to evaluate injection at perf level and to promote better diversion across the\nperforated interval.\nDuring the DFIT, treated completion fluid was pumped at 19 bpm for 5 minutes. The pressure fall off\nanalysis shows a transverse storage closure mechanism supporting the presence of secondary porosity leak"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a30c2-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 15, "chroma:document": "analysis shows a transverse storage closure mechanism supporting the presence of secondary porosity leak\noff (either by contacting a natural fracture system or created by the fracturing process). The interpreted\nminimum stress is 9,313 psi with a net pressure of 199 psi (PZS) and a Gperm of 0.046 mD (shown in Fig. 8).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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a311c-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 16, "chroma:document": "SPE-206239-MS 17\nFigure 8\u2014DFIT Gplot interpretation and Gperm calculation Blue curve is\nbottom hole pressure, green is first derivative curve (Dp/DG), red curve is (G*Dp*/DG).\nThe after-closure pressure transient goes into pseudo-radial flow giving an estimate of pore pressure of\n~9,100 psi that is consistent with the Talley-Nolte plot since the pressure difference and its derivative fall\non the same unit slope as shown in Fig. 9  (Talley, et al., 1999). An additional confirmation of the validity\nof the pore pressure estimate is given by the MDT pore pressure independent measurements (marked with\na blue arrow on track 4 in Fig. 10).\nFigure 9\u2014 DFIT After closure pseudo-radial flow function and Talley-Nolte plot. Linear time flow function:"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a316c-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 16, "chroma:document": "a blue arrow on track 4 in Fig. 10).\nFigure 9\u2014 DFIT After closure pseudo-radial flow function and Talley-Nolte plot. Linear time flow function:\nBlue curve is bottom hole pressure. Talley-Nolte Plots: Blue curve is delta pressure (b), green is the log derivative curve.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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a31bc-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 17, "chroma:document": "18 SPE-206239-MS\nFigure 10\u2014Core vs Logging-based models: Perm, PHIE, Static Young Modulus, Poisson's Ratio, Pore Pressure and 1DMEM\nThe pressure-match model shown in Fig. 11  suggests a fracture height of 16 meters that is incorporated\nin the calculated after-closure transmissibility giving a permeability estimate of 0.16 mD.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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a320c-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 18, "chroma:document": "SPE-206239-MS 19\nFigure 11\u2014DFIT Pressure-match model \u2013 Net pressure plot Purple Curve: Measured\nwell head pressure Black Curve: Modeled well head pressure Red curve: Frac rate.\nThe calibrated litho-based 1DMEM (marked with a black arrow on track 4 in Fig. 10). was able to predict\nthe minimum stress in the upper stimulated interval supporting the predictive capabilities of the workflow\nimplemented to describe elastic properties and the distribution of stress across the reservoir (marked with\na red arrow on the same track).\nThe DFIT was pressure-match with a fracture model that was calibrated with a large amount of triaxial\nmechanical tests (as shown by green arrows on track 3 in Fig. 10) and the interpreted DFIT information\nin the area indicated by a black arrow on track 1-4 in Fig 10  (interpreted pore pressure, minimum stress\nand Gperm estimates).\nThe difference in magnitude between the Gperm (0.046mD) and pseudo radial (0.16 mD) permeability"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a3266-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 18, "chroma:document": "and Gperm estimates).\nThe difference in magnitude between the Gperm (0.046mD) and pseudo radial (0.16 mD) permeability\nestimates is probably related to the pressure transient dissipation of a complex, non-planar fracture system\ndeveloped during injection. The early onset of pseudo radial flow is established due to the fracturing fluid\nleaking off through multiple fracture faces and not through a linear PKN fracture as utilized to resolve\nthe diffusivity equation. If we follow the assumptions of a PKN fracture geometry, and assume that linear\ntransient flow governs fracture leak off up until closure, then the time required for the induced pressure\ntransient to establish a pseudo-radial flow regime can be computed from the definition of Tdxf. A minimum\ndimensional time (Tdxf) value of one is required to reach pseudo-radial flow during the fall off period\n(Barree, et al., 2014 ). The time required to reach pseudo-radial transient flow (Eq. 2 ) for a single planar"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a32b6-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 18, "chroma:document": "(Barree, et al., 2014 ). The time required to reach pseudo-radial transient flow (Eq. 2 ) for a single planar\nbi-wing fracture is in the order of ~70 hours assuming permeability of 0.047 mD, an average fracture\nhalf-length of 70 meters, a far field fluid viscosity of 0.0315 cp, a 15% effective porosity and reservoir\ncompressibility of 3.87x10-5 1/psi.\n(Eq. 2)\nTpr= time to reach pseudo-radial flow (hours); \u03c6= porosity (fraction); \u03bc=fluid viscosity (cp); Ct=total\nreservoir compressibility (1/psi); xf=fracture half-length (ft); k= permeability (md)\nWhen utilizing the pseudo-radial flow function under this condition, the pore pressure estimates will not\nbe affected, but there will be a significant effect in the calculated permeability due to the complex leak off\nconditions in place, making the calculated permeability invalid since it lacks of physical meaning (Barree,\net al., 2014 ; Barree, 2020 )."}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a3310-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 18, "chroma:document": "conditions in place, making the calculated permeability invalid since it lacks of physical meaning (Barree,\net al., 2014 ; Barree, 2020 ).\nThe DFIT numerical inversion gives out the same closure mechanism, time to reach closure and minimum\nstress as the actual measured data when utilizing the Gperm and modelling the leak off into the secondary\nporosity system, further supporting the test interpretation (Fig. 8). This permeability estimate is further\nreinforced by a large number of core permeability tests performed across this interval as seen in Fig. 12,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"}


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id: 6b8a3360-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 19, "chroma:document": "20 SPE-206239-MS\nwhere the effective flowing phase permeability calculations are close to absolute values measured at the\nlaboratory (flowing phase permeability should be ~75-80% of the core absolute permeability at a irreducible\nwater saturation of 25%). Regretfully, in this diagnostic injection, the measured DFIT and the numerical\nafter closure pressure transient cannot be compared directly due to the presence of a false pseudo-radial\nregime.\nFigure 12\u2014Actual DFIT vs simulated DFIT gplot \u2013 Gperm model vs core permeability (mD)\nGplot: Blue curve is bottom hole pressure, green is first derivative curve (Dp/DG), red curve is (G*Dp*/DG) .\nThis proves the validity of the interpretation, supporting the relationship between traditional estimates\nof minimum stress and closure time estimates of permeability that is consistent with core data ( Fig. 12).\nAt the same time, when combining core permeability data and the early onset of pseudo radial flow, one"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a33b0-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 19, "chroma:document": "At the same time, when combining core permeability data and the early onset of pseudo radial flow, one\ncan affirm that the transverse storage closure mechanism is related to induced natural fractures that provide\npressure support to the main fracture body during closure. The fissure dominated leak off will delay the\ntime it takes for the fracture faces to close on each other and, at the same time, reduce the time needed to\nreach a false after closure pseudo-radial flow regime.\nIt is worth noting that there is a matrix permeability threshold hold on top of which the enhanced\npermeability provided by the shear failure of the rock obtained during fracturing won't be enough to change\nthe overall system permeability. As supported by this case history, for matrix permeabilities greater than\nabout 0.05 mD the enhancement generated by induced shear cracks is usually negligible. Nevertheless,"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a340a-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 19, "chroma:document": "about 0.05 mD the enhancement generated by induced shear cracks is usually negligible. Nevertheless,\ninduced or in-situ natural fractures will drastically increase leak off during fracturing operations and should\nbe accounted for since this may induce premature screen outs.\nWhen the fracture compliance method is utilized to interpret the DFIT, a minimum stress of 9,455 psi,\na net pressure of 64 psi and a Gperm of 0.087 mD are estimated as shown in Fig. 13.A. For the Gperm\ncalculation, a Rp of 1 was assumed since the compliance closure considers leak off conditions related to\nmatrix permeability without the presence of natural fractures. The permeability model constrained with the\ncompliance Gperm becomes larger than the core permeability tests, making this fracture closure assessment"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a345a-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 19, "chroma:document": "compliance Gperm becomes larger than the core permeability tests, making this fracture closure assessment\ninconsistent with independent assessments of reservoir flowing capacity.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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a34aa-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 20, "chroma:document": "SPE-206239-MS 21\nFigure 13.A\u2014 DFIT compliance closure and Gperm calculation \u2013 Core vs compliance perm\nmodel  Blue curve is bottom hole pressure, green is first derivative curve (Dp/DG), red curve is (G*Dp*/DG).\nAt the same time, the interpreted low net pressures will have an effect in the modelled fracture height\nand, specially, in the fracture width since only 64 psi can be applied to deform the rock and develop fracture\naperture. Considering one is dealing with an almost 4 MM psi static young modulus rock and that the low\npermeability will not allow the fracture to develop a proper tip-screen out behavior to develop additional\nwidth, a treatment screen out is to be expected under these conditions.\nIn order to illustrate the effect of a low net pressure on fracture width, we may consider as an example\nthe maximum width in a linear elastic media for a planar fracture given by the Sneddon and Elliot equation\n(1946)  as shown in Eq. 3 :\n(Eq. 3)"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a34fa-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 20, "chroma:document": "the maximum width in a linear elastic media for a planar fracture given by the Sneddon and Elliot equation\n(1946)  as shown in Eq. 3 :\n(Eq. 3)\nW= max frac width (inch); H= fracture height (ft); \u03bc=poisson's ratio; Pnet= PZS (psi); E= Young modulus\n(psi)\nTaking into consideration a typical 54 meters fracture height coverage for this interval (as presented in\nFig. 13.B ), a 0.068\" fracture width is calculated for the fracture compliance closure considering a PR of 0.35\n(Fig. 10 ), a PZS of 64 psi ( Fig. 13.A ) and a YMES of 3.5 MM psi (Fig. 10). In that respect, with a 0.068\"\nfrac width, all treatments pumped in this field would have screen out. Nevertheless, over fifty 300-tons 12\nppag (pound per added gallon) fracture treatments were placed without a single screen out, proving that\nthe developed fracture width should have been much larger. This is only possible when having a higher net"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a354a-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 20, "chroma:document": "the developed fracture width should have been much larger. This is only possible when having a higher net\npressure to deform the rock and create fracture aperture that will allow to pump large proppant concentration\nslurries without screen outs, proving the lack of validity of the fracture compliance minimum stress estimate.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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a359a-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 21, "chroma:document": "22 SPE-206239-MS\nFigure 13.B\u2014Typical fracture height growth in this interval\nThe analysis described in the previous paragraphs supports a consistent relationship between the\npermeability estimates from traditional DFIT fracture closure time, DFIT numerical inversions and core.\nThis in turn proves that the interpreted time to reach fracture closure during the DFIT test occurs after its\nlinear leak off period as stated by traditional interpretation techniques. The fracture compliance closure-\nbased permeabilities are larger than the ones described by core and the interpreted low net pressures will not\nallow to place the treatments pumped on this reservoir without inducing a screenout, which further supports\nthe lack of physical meaning of this methodology.\nCase 3: Tight Gas Sandstone\nIn this case history, traditional minimum stress interpretations are supported by a DFIT numerical inversion"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a35f4-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 21, "chroma:document": "Case 3: Tight Gas Sandstone\nIn this case history, traditional minimum stress interpretations are supported by a DFIT numerical inversion\nbuilt on permeability estimates based on fracture closure time that will be reinforced by anchoring the\npseudo-linear estimated pore pressure in a pseudo-radial flow function analysis. This proves that there is a\ndirect relationship between the estimated permeability and the time it takes to reach fracture closure after\nthe linear leak off period of the DFIT.\nThis is a cased and cemented vertical technology well where a DFIT was pumped through a 4.5\"\nmonobore completion at 6.5 bpm through a 3-meter perforation interval. The test took place several months\nafter well construction was finished, allowing the completion fluid to heat up to reservoir temperatures of\n160\u00baC. A change in temperature of this magnitude will result in a change of viscosity from 1 to 0.19 cp"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a3644-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 21, "chroma:document": "160\u00baC. A change in temperature of this magnitude will result in a change of viscosity from 1 to 0.19 cp\nfor a 2% KCl completion fluid (Marc Laliberte, 2007 ). The pressure fall off analysis shows a PDL closure\nmechanism with an estimated minimum stress of 9,844 psi, a PZS of 763 psi and a Gperm of 0.012 mD\nand a as presented in Fig. 14.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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a3694-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 22, "chroma:document": "SPE-206239-MS 23\nFigure 14\u2014 DFIT Gplot interpretation and Gperm calculation Blue curve is\nbottom hole pressure, green is first derivative curve (Dp/DG), red curve is (G*Dp*/DG).\nThe after-closure pressure transient goes into pseudo-linear flow giving an estimate of pore pressure of\n7,130 psi. The Talley-Nolte plot confirms the correct estimation of pore pressure by the identified half slope\nof the pressure derivative and the pressure difference curves that are separated by a difference of 2x in\nmagnitude as shown in Fig 15 .\nFigure 15\u2014 Pseudo-linear flow function and Talley-Nolte plots. Linear time flow function: Blue curve\nis bottom hole pressure. Talley-Nolte Plots: Blue curve is delta pressure, green is the log derivative curve .\nAfter the DFIT was finished, the well was closed for more than twelve months to evaluate the evolution\nof bottom and well head pressures. As shown in Fig. 16 , thermal effects can be seen clearly on both gauges,"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a36ee-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 22, "chroma:document": "of bottom and well head pressures. As shown in Fig. 16 , thermal effects can be seen clearly on both gauges,\nstill an average reservoir pore pressure of 7,030 psi (485 Bar) can be realized (~ 1% difference with the\nACA estimation that is within the measuring error).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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a373e-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 23, "chroma:document": "24 SPE-206239-MS\nFigure 16\u2014Bottom hole and surface pressure measurements (Bar).\nScratch tests were utilized to optimize the number of plugs and the regions to be analyzed to get a\nrepresentative elastic behavior of the reservoir. The fracture model was calibrated with a mineralogical\nmodel constrained with XRD measurements (Track 1 and 2 in Fig. 17.A ), triaxial mechanical tests (Track\n3 in Fig. 17.A ) and the interpreted DFIT information in the area indicated by a black arrow on track 4\nin Fig 17.A . The pressure-match model suggests a fracture height development between 2 to 3 meters as\npresented in Fig. 17.B .\nFigure 17.A\u2014Mineralogy, Rock Physics, Pore Pressure and 1DMEMDownloaded 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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a378e-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 24, "chroma:document": "SPE-206239-MS 25\nFigure 17.B\u2014 Pressure match geometry and net pressure plot. Blue Curve: Measured\nwell bottom hole pressure Black Curve: Modeled well bottom hole pressure Red curve: Frac rate .\nIf one utilizes the estimated fracture height from the pressure match model and anchor the estimated pore\npressure in a pseudo-radial flow function, an upper bound on the contacted permeability between 0.025 to\n0.037 mD can be estimated (Fig. 18 ). This upper bound on the contacted permeability is consistent with the\nGperm estimated 0.012 mD that was implemented in the pressure-match model related to the time required\nto reach fracture closure.\nFigure 18\u2014Pseudo-radial flow function permeability sensitivity (anchored pore pressure).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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a37de-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 25, "chroma:document": "26 SPE-206239-MS\nThe pressure match shown in Fig. 17.B  was achieved by implementing an iterative process until the\nmodelled pressure converged to provide the same fracture closure mechanism, minimum stress, time to\nreach closure and after-closure pressure transient dissipation in the host rock as shown in the original DFIT\n(as shown in Fig. 19.A  and Fig 19.B).\nFigure 19.A\u2014DFIT vs simulated DFIT Gplot . Blue curve is bottom hole\npressure, green is first derivative curve (Dp/DG), red curve is (G*Dp*/DG) .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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a3838-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 26, "chroma:document": "SPE-206239-MS 27\nFigure 19.B\u2014 DFIT vs simulated DFIT after closure analysis . Linear time flow function: Blue curve\nis bottom hole pressure. Talley-Nolte Plots: Blue curve is delta pressure, green is the log derivative curve .\nThe analysis described in the previous paragraphs supports a consistent relationship between the\npermeability estimates from traditional DFIT fracture closure time, numerical inversions and after-closure\nanalysis. This in turn proves that the interpreted time to reach fracture closure during the DFIT test occurs\nafter its linear leak off period as stated by traditional interpretation techniques.\nCase 4: Moderate Permeability, Gas and Condensate Sandstone\nIn this case history, traditional minimum stress interpretations are supported by a DFIT numerical inversion\nbuilt on permeability estimates based on fracture closure time that is consistent with after closure analysis,"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a3888-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 26, "chroma:document": "built on permeability estimates based on fracture closure time that is consistent with after closure analysis,\nPBU and RTA assesments. The fracture closure pressure will be validated through multiple injections fall\noff analysis, proving that there is a direct relationship between the estimated permeability and the time it\ntakes to reach fracture closure after the linear leak off period of the DFIT.\nThis well was treated down a 2 7/8\" tubing and a large perforated interval, through which a DFIT, mini-\nfrac and 230 tons treatment was pumped at an average rate of 23 bpm. The DFIT pumped on this well shows\na PDL closure mechanism with an estimated minimum stress of 9,196 psi, a PZS of 333 psi and a Gperm\nof 1.42 mD as presented in Fig. 20.A. The change in slope in the log-log plot was utilized to support the"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a38e2-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 26, "chroma:document": "of 1.42 mD as presented in Fig. 20.A. The change in slope in the log-log plot was utilized to support the\ninterpreted Gplot minimum stress values (marked with a black arrow in Fig. 20.B).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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a3932-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 27, "chroma:document": "28 SPE-206239-MS\nFigure 20.A\u2014DFIT Gplot interpretation and Gperm calculation Blue curve is\nbottom hole pressure, green is first derivative curve (Dp/DG), red curve is (G*Dp*/DG).\nFigure 20.B\u2014 DFIT log-log plot  Blue curve is Delta Pressure, green is first derivative curve (dDP/dDT), red curve is (DT* dDP/dDT).\nThe DFIT estimated minimum stress was additionally confirmed by a mini-frac injection that changed the\nclosure mechanism from PDL to transverse storage due to the additional energy transferred to the rock by\nthe crosslinked fracturing fluid (presented in Fig. 21.A). The analysis shows one is dealing with a stiffening\nsystem where the net pressure (PZS) changes with continuous injection, having a PZS difference of almost\n600 psi between the DFIT and mini-frac injections. It is worth mentioning that when utilizing traditional\nfracture pressure interpretation techniques, the interpreted stress can be identified in a consistent manner"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a3982-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 27, "chroma:document": "fracture pressure interpretation techniques, the interpreted stress can be identified in a consistent manner\nacross multiple injections. If the fracture compliance method is utilized to select the minimum stress, no\nconsistent interpretation can be made by having almost 700 psi difference between the DFIT (9,196 psi) andDownloaded 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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a39d2-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 28, "chroma:document": "SPE-206239-MS 29\nmini-frac estimates (9,884 psi) (shown in Fig. 21.B). In this case the compliance closure becomes higher\nthan the fracture pressure (ISIP) of the DFIT, making this minimum stress estimation unrealistic.\nFigure 21.A\u2014 Mini-frac Gplot interpretation \u2013 Traditional fracture closure estimate . Blue\ncurve is bottom hole pressure, green is first derivative curve (Dp/DG), red curve is (G*Dp*/DG) .\nFigure 21.B\u2014Mini-frac Gplot interpretation\u2013Compliance closure estimate. Blue\ncurve is bottom hole pressure, green is first derivative curve (Dp/DG), red curve is (G*Dp*/DG).\nThe after-closure pressure transient goes into pseudo radial flow giving an estimated pore pressure of ~\n8,400 psi ( Fig. 22 ). The Talley-Nolte plot shows that the pressure difference between the fall off pressure\nand the estimated pore pressure from the analysis has a negative unit slope that coincides with its logarithmic"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a3a2c-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 28, "chroma:document": "and the estimated pore pressure from the analysis has a negative unit slope that coincides with its logarithmic\nderivative during the identified pseudo-radial flow period, supporting the validity of the analysis. The\npressure match model suggests a fracture height of 16 meters (Fig. 23) that is incorporated in the calculated\nafter-closure transmissibility giving a permeability estimate of 2 mD.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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a3a7c-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 29, "chroma:document": "30 SPE-206239-MS\nFigure 22\u2014 DFIT After closure pseudo-radial flow function and Talley-Nolte plots. Linear time flow function:\nBlue curve is bottom hole pressure. Talley-Nolte Plot: Blue curve is delta pressure, green is the log derivative curve.\nFigure 23\u2014 DFIT pressure-match model \u2013 Net pressure plot Blue Curve: Measured well\nbottom hole pressure. Black Curve: Modeled well bottom hole pressure. Red Curve: Frac rate.\nThe fracture model was calibrated with DFIT data and, while accounting for the natural fractures leak\noff, a reasonable pressure-match obtained by slightly increasing the permeability to 1.65 mD ( Fig. 23 ). The\ndifference between the Gperm (1.4 mD), pressure match (1.65 mD) and after closure permeability estimates\n(2 mD) are within acceptable measurement accuracy.\nThe DFIT numerical inversion yields the same closure mechanism, time to reach closure, minimum stress"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a3acc-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 29, "chroma:document": "The DFIT numerical inversion yields the same closure mechanism, time to reach closure, minimum stress\nand after-closure pressure transients as the actual measured data (as shown in Fig. 24 ).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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a3b1c-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 30, "chroma:document": "SPE-206239-MS 31\nFigure 24.A\u2014DFIT vs simulated DFIT Gplot . Blue curve is bottom hole\npressure, green is first derivative curve (Dp/DG), red curve is (G*Dp*/DG) .\nFigure 24.B\u2014 DFIT vs simulated DFIT Gplot and after closure analysis . Linear time flow function: Blue\ncurve is bottom hole pressure. Talley-Nolte Plot: Blue curve is delta pressure, green is the log derivative curve.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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a3b76-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 31, "chroma:document": "32 SPE-206239-MS\nA 230-ton 35# xlinked fracture treatment pumped at an average of 23 bpm was pressure-match, obtaining\na propped fracture length of 230 meters and height of 43 meters as shown in Fig 25.\nFigure 25\u2014 Main fracture treatment pressure-match fracture geometry \u2013 Proppant concentration plot Blue curve: Measured well\nbottom hole pressure Black curve: Modeled well bottom hole pressure Red curve: Frac Rate Brown-green curves: Slurry proppant concentration\nAfter the cleanup phase of the main fracture treatment, a PBU test was performed providing a contacted\npermeability of 1.27 mD, a pore pressure of 8,340 psi and an estimated fracture flowing length of 55 meters.\nFor this analysis, the fracture height was assumed to be 50 meters in comparison to the pressure match\nfracture contacted net pay of 43 meters. If this latter is utilized to calculate the contacted permeability\nthrough the estimated 63.5 mD*meters kh, an estimated flowing capacity of 1.47 mD is obtained (as shown"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a3bc6-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 31, "chroma:document": "through the estimated 63.5 mD*meters kh, an estimated flowing capacity of 1.47 mD is obtained (as shown\nin Fig. 26 ).\nFigure 26\u2014Main fracture treatment - Pressure build up interpretation\nA RTA analysis was performed based on a 12-month production history gathered after the main fracture\ntreatment took place (presented in Fig 27). The main treatment pressure-match fracture height of 43 meters\nwas utilized in the analysis, providing a contacted average permeability of 1.33 mD (57.8 mD*meters) and\nan infinite flowing fracture half length dimension of 0.04 meters (0.13 feet).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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a3c16-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 32, "chroma:document": "SPE-206239-MS 33\nFigure 27\u2014Main fracture treatment-Rate transient analysis interpretation\nInformation about the reservoir architecture obtained from the RTA was incorporated into the production\nmodel of the fracture geometry simulator software that accounts for the modelled fracture geometry,\nproppant packs physical behaviours and the reservoir properties described in the DFIT calibrated fracture\ngrid. The early clean up phase is not matched by both models since the water injected during the treatment\nis not accounted for in the analysis. The modelled fracture geometry contacted an average of 1.4 mD and\nwas able to match the production history of the well, suggesting flowing fracture lengths between 49 and\n56 meters that can be translated into an infinite fracture length of ~0.3 meters (as presented in Fig. 28).\nThe estimated infinite flowing dimension from the frac production model of 0.2-0.3 meters is consistent"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a3c66-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 32, "chroma:document": "The estimated infinite flowing dimension from the frac production model of 0.2-0.3 meters is consistent\nwith the RTA estimated infinite fracture flowing dimension of 0.04 meters (0.13 ft), sustaining the large\npressure drop in the proppant pack is related to non-Darcy flow. During the early production period, the frac\nproduction model estimates a frac length of 49 meters while the PBU suggests a flowing length in the order\nof 55 meters. The PBU and production based flowing dimensions are consistent with each other, since the\nPBU estimated length should be larger than the ones estimated during production due to not accounting for\nturbulent pressure drops ( Barree, et al., 2005 ).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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a3cc0-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 33, "chroma:document": "34 SPE-206239-MS\nFigure 28\u2014Frac geometry production model\nThe analysis described in the previous paragraphs provided a converging solution that is consistent\nwith multiple tests utilized to calibrate and understand the production performance of this well. The\nanalysis supports a consistent relationship between the permeability estimates from traditional DFIT fracture\nclosure time, DFIT numerical inversions, after-closure analysis, PBU and RTA. This in turn proves that the\ninterpreted time to reach fracture closure during the DFIT test occurs after its linear leak off period as stated\nby traditional interpretation techniques.\nComparison of DFIT and mini-frac pressure transients shows how traditional closure interpretation\ntechniques can be utilized to properly assess the minimum stress when having different closure mechanisms.\nInstead, if the fracture compliance methodology is employed, differences of up to 700 psi can be assessed\nbetween different tests minimum stress estimations."}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a3d10-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 33, "chroma:document": "between different tests minimum stress estimations.\nCase 5: Low Permeability, Gas Sandstone \u2013 Drained Reservoir\nIn this case history, traditional minimum stress interpretations are supported by a DFIT numerical inversion\nbuilt on permeability estimates based on fracture closure time that is consistent with PBU and RTA\nassesments. The fracture closure pressure will be validated through multiple injections fall off analysis,\nproving that there is a direct relationship between the estimated permeability and the time it takes to reach\nfracture closure after the linear leak off period of the DFIT.\nThis is a vertical gas well with a 30\u00ba inclination produced for several months through a single perforated\ninterval before fracture stimulating it. PBU data was used to assess the original pore pressure and flowing\ncapacity of this interval. As it is often the case with complicated test behaviors, various interpretation"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a3d60-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 33, "chroma:document": "capacity of this interval. As it is often the case with complicated test behaviors, various interpretation\nmodels could match the pressure and rate data. From the possible heterogeneity arrangements investigated,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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a3db0-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 34, "chroma:document": "SPE-206239-MS 35\na constant permeability model of 0.55 mD was interpreted (shown in Fig 29). The analysis also supported\nthe possibility of having improved reservoir properties far away from the well.\nFigure 29\u2014Pressure build analysis\nHistorical production and downhole gauge pressures were utilized to build an RTA model. As shown\nin Fig. 30 , the analysis supports a developing asymmetric drainage area with an average permeability of\n0.52 mD which is further supported by the latest geological and dynamic modelling performed by the field\nReservoir Engineering Team ( Veccia, 2016).\nFigure 30\u2014Pre-frac rate transient analysisDownloaded 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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a3e0a-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 35, "chroma:document": "36 SPE-206239-MS\nThe dynamic model forecasted production was compared to the predictions of the RTA model, showing\na high degree of correspondence. Slight differences in the late time forecasted production are related to the\ndrainage defined within geological model used within the dynamic simulation and an extended drainage\nthat was not able to be predicted by RTA since no boundary influenced flow was reached at the time\nthe analysis was performed (as presented in Fig. 31.D). Due to not having an understanding of the stress\nconditions on this interval, the forecasted pore pressure at the time the fracture treatment should take\nplace was combined with litho-based rock mechanical properties to create multiple 1DMEMs within an\nexpected range of tectonic boundaries. Multiple fracture geometries were evaluated under a wide range of\npossible state-of-stress conditions, several fracture designs were optimized, and their associated production"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a3e5a-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 35, "chroma:document": "possible state-of-stress conditions, several fracture designs were optimized, and their associated production\nperformance modelled to assess possible economic outcomes of the operation ( Fig. 31.A., Fig. 31.B , Fig.\n31.C  and Fig. 31.D ).\nFigure 31.A\u2014Litho-based rock mechanical properties Fig 31.B: Fracture optimization analysis Fig 31.C: Litho-\nbased 1DMEM sensitivity analysis Fig 31.D: Production forecasts \u2013 with and without fracture treatment.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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a3eaa-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 36, "chroma:document": "SPE-206239-MS 37\nThe estimated pore pressure at the time of fracturing provided by dynamic and RTA solutions is ~ 4,100\npsi. The validity of the prediction was assessed through an updated RTA analysis performed based on newly\nacquired production data. The analysis supports an average reservoir pressure of 4,080 psi and the presence\nof an increased permeability in the late time data supported by the presence of improved reservoir properties\nfar away from the well as suggested by PBU tests (marked with a black circle in Fig. 32). This latter\nrepresents an upper bound estimate on the average reservoir pressure considering the last production period\ncannot be properly matched (the actual average reservoir pressure should be lower than this estimate).\nFigure 32\u2014Updated rate transient analysis and Linear flow analysis plot\nThe DFIT pseudo-linear flow plot indicates a pore pressure of 4,019 psi which is consistent with the"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a3f04-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 36, "chroma:document": "The DFIT pseudo-linear flow plot indicates a pore pressure of 4,019 psi which is consistent with the\nupdated RTA model shown in Fig. 32 and within the expected range of the original predictions of the\nproduction models.\nThe DFIT analysis provided a minimum stress range between 5,312 and 5,412 psi. As shown in Fig. 33,\nthe fast fracture closure makes the calculation of the area above the linear leak off conditions and fissure\nleak off coefficient difficult to estimate since the data is affected by the water hammer effect.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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a3f54-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 37, "chroma:document": "38 SPE-206239-MS\nFigure 33\u2014 DFIT ISIP and G plots \u2013 Fracture pressure and minimum stress estimation ISIP Plot: Blue curve is well head\npressure; green is fracturing rate. Gplot: Blue curve is bottom hole pressure; green is first derivative curve (Dp/DG), red curve is (G*Dp*/DG).\nA Gperm sensitivity analysis was performed and the Rp value changed within a range of 1 to 1.3 that\nrepresents the transition from a linear to pressure depend leak off closure mechanism conditions. The\nanalysis gives an estimated average Gperm of 0.281 mD for the range of minimum stresses evaluated as\nshown in Fig. 34 :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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a3fa4-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 38, "chroma:document": "SPE-206239-MS 39\nFigure 34\u2014Gperm flowing capacity evaluation\nThe DFIT minimum stress range was verified by a mini-frac injection that changed the closure mechanism\nfrom pressure dependent leak off (PDL) to transverse storage. The analysis also supports a change in the\nfracture pressure with injection that might be related to a stiffening system with continued injection with\na thicker fracturing fluid. In this case, a range is presented since both closure pressures may be estimated\ndepending on how the gauge pressure is smoothed out.\nFigure 35\u2014 Minifrac Gplot \u2013 Minimum stress evaluation Blue curve is bottom\nhole pressure, green is first derivative curve (Dp/DG), red curve is (G*Dp*/DG).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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a3ff4-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 39, "chroma:document": "40 SPE-206239-MS\nThe average Gperm value is within acceptable measurement accuracy and considered consistent when\ncompared to PBU and RTA estimations. What is important to notice is that by utilizing traditional\ninterpretation techniques, independent of the fracture closure mechanism present, the interpreted minimum\nstress is exactly the same. As shown in Fig. 36 , if the fracture compliance method is utilized to select the\nminimum stress, no consistent interpretation can be made by having almost 900 psi difference between the\nDFIT (5,312 psi) and mini-frac estimates (6,191 psi). In this case the compliance closure becomes higher\nthan the fracture closure pressure of the DFIT, making this minimum stress estimation unrealistic.\nFigure 36\u2014 Minifrac ISIP and G plots \u2013 Fracture compliance closure ISIP Plot: Blue curve is well head pressure; green\nis fracturing rate. Gplot: Blue curve is bottom hole pressure, green is first derivative curve (Dp/DG), red curve is (G*Dp*/DG)."}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a4044-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 39, "chroma:document": "is fracturing rate. Gplot: Blue curve is bottom hole pressure, green is first derivative curve (Dp/DG), red curve is (G*Dp*/DG).\nThe DFIT log-log plot shows a consistent pseudo-linear and an invalid pseudo radial flow pattern that has\nbeen affected by the well annulus pressure (marked with a black circle in Fig. 37 annulus pressure trends).\nThe annulus pressure affects the surface pressure and bottom hole gauge in different manners. The log-log\nplot made from surface data shows a negative slope larger than -1 (physically impossible) while the log-\nlog plot from bottom hole pressure measurements is flattened out (marked with a black circle on Fig. 37\nlog-log plots).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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a409e-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 40, "chroma:document": "SPE-206239-MS 41\nFigure 37\u2014 Annulus pressure affecting pressure transient  Treating pressure in orange: Annulus pressure (psi).\nLog-log plots: Blue curve is Delta Pressure, green is first derivative curve (dDP/dDT), red curve is (DT* dDP/dDT).\nThe pseudo-linear flow function gives an estimated pore pressure of 4,019 psi, supported by a consistent\nTalley-Nolte Plot. This latter confirms the presence of a linear flow period by the identified half slope of\nthe pressure derivative. When estimated pore pressure is correct, the pressure difference curve will also fall\non a half slope and be 2x higher in magnitude than the derivative as shown in Fig. 38.\nFigure 38\u2014 After-closure analysis  Linear time flow function: Blue curve is bottom hole\npressure. Talley-Nolte Plot: Blue curve is delta pressure; green is the log derivative curve .\nThe simulation grid is updated based on the DFIT interpretation and the test is pressure-match assuming"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a40ee-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 40, "chroma:document": "The simulation grid is updated based on the DFIT interpretation and the test is pressure-match assuming\na minimum stress of 5,313 psi. Fig. 39 shows the measured vs the modelled pressure, where the minimum\nstress and the late time pressure transient is relative consistent with the measured data but the early time\nafter closure transient is difficult to match.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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a413e-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 41, "chroma:document": "42 SPE-206239-MS\nFigure 39\u2014 Pressure match vs fracture geometry net pressure plot Blue curve: Measured\nwell bottom hole pressure Black curve: Modeled well bottom hole pressure Red curve: Frac rate .\nIn order to properly calibrate the fracture model and assess its validity, a numerical inversion was\nperformed through the pressure-match model. The numerical model provides the same fracture pressure,\nminimum stress and pore pressure estimates as the measured fall off data. The only difference is a slight miss\nmatch in the time required to reach closure within the model, having the fracture closed within 3 minutes\ninstead of almost 2 minutes (Fig. 40.A and Fig. 40.B). This indicates that the permeability might be slightly\nhigher than 0.281 mD as suggested by PBU and RTA.\nFigure 40.A\u2014DFIT vs simulated DFIT Gplot . Blue curve is bottom hole"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a418e-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 41, "chroma:document": "higher than 0.281 mD as suggested by PBU and RTA.\nFigure 40.A\u2014DFIT vs simulated DFIT Gplot . Blue curve is bottom hole\npressure, green is first derivative curve (Dp/DG), red curve is (G*Dp*/DG) .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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a41de-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 42, "chroma:document": "SPE-206239-MS 43\nFigure 40.B\u2014 DFIT vs simulated after closure analysis . Linear time flow function: Blue curve is\nbottom hole pressure. Talley-Nolte Plot: Blue curve is delta pressure; green is the log derivative curve .\nFurthermore, even with an increased permeability, the early time fall of pressure is difficult to match.\nThis seems to be due of the relative position of the well and the grid that is cut at 30\u00ba, affecting the near-\nwellbore leak off calculations or due to actual crossflow between different perforated layers. Independent\nof this, when combining different measurements of permeability, pore pressure and stress one realizes that\nthe differences are negligible.\nThe pressure-match DFIT shows that the created fracture has a fracture length in the order of 100 meters\n(investigated reservoir volume), giving permeability estimates within the range of the early time PBU and\nRTA estimates. The late time RTA suggest production contributions from an improved permeability region"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a4238-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 42, "chroma:document": "RTA estimates. The late time RTA suggest production contributions from an improved permeability region\nas discussed in previous paragraphs. Production history after fracture stimulating this interval was gathered\nfor eight months and analyzed, showing an RTA average permeability of 0.75 mD as shown in Fig. 41 .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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a4288-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 43, "chroma:document": "44 SPE-206239-MS\nFigure 41\u2014Post-frac rate transient analysis\nThe analysis described in the previous paragraphs supports a consistent relationship between the\npermeability estimates from DFIT fracture closure time, DFIT numerical inversions, PBU and RTA. This in\nturn proves that the interpreted time to reach fracture closure during the DFIT test occurs after its linear leak\noff period as stated by traditional interpretation techniques. Comparison of DFIT and mini-frac pressure\ntransients shows how traditional closure interpretation techniques can be utilized to properly assess the\nminimum stress when having different closure mechanisms. Instead, if the fracture compliance methodology\nis employed, differences of up to 900 psi can be realized between minimum stress estimations which makes\nthis methodology unrealistic.\nCase 6: Low Permeability, Gas Sandstone\nIn this case history, traditional minimum stress interpretations are supported by a DFIT numerical inversion"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a42d8-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 43, "chroma:document": "Case 6: Low Permeability, Gas Sandstone\nIn this case history, traditional minimum stress interpretations are supported by a DFIT numerical inversion\nbuilt on permeability estimates based on fracture closure time that is consistent with after closure analysis,\ncore, production modelling estimates and PLT data.\nThis well was treated down a 4.5\" monobore completion, through which a set of DFIT, mini-frac and two\n~200-tons treatments were pumped at an average rate of 35 bpm. The Gplot of the first diagnostic injection\npumped on this well accounts for a possible early time PDL, followed by a transverse storage signature\n(sometimes called \"height recession\") and a linear leak-off profile across the created surface before fracture\nclosure is attained. The test interpretation provided an estimated minimum stress of 9,312, PZS of 1,002 psi"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a4328-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 43, "chroma:document": "closure is attained. The test interpretation provided an estimated minimum stress of 9,312, PZS of 1,002 psi\nand a Gperm of 0.69 mD as presented in Fig. 42 .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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a4378-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 44, "chroma:document": "SPE-206239-MS 45\nFigure 42\u2014 DFIT Gplot interpretation and Gperm calculation Blue curve is\nbottom hole pressure, green is first derivative curve (Dp/DG), red curve is (G*Dp*/DG).\nThe early time period does not seem to be related to a PDL signature related to a certain type of natural\nfractures, instead this shape of the derivative is affected by fluid decompression due to the high tortuosity\nthe system has in place at the time this test was pumped. It is important to mention that one may or may\nnot have a PDL mechanism in place but is not possible to assess it due to fluid decompression affecting the\nearly time pressure transient. The transverse storage portion of the fall off pressure is most likely due to the\npresence of secondary fractures (joints) that can provide pressure support to the main fracture body during\nthe fracture closure process and not to height recession.\nFig. 43 presents a log-log plot of the fall off pressure minus the Instantaneous Shut-In Pressure (ISIP)"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a43d2-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 44, "chroma:document": "Fig. 43 presents a log-log plot of the fall off pressure minus the Instantaneous Shut-In Pressure (ISIP)\nand its derivatives. There is a clear break of the delta pressure superposition curve that is consistent with\nthe identified closure and a pseudo radial flow period in the late portion of the pressure transient identified\nby a negative slope of 1.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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a4422-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 45, "chroma:document": "46 SPE-206239-MS\nFigure 43\u2014Diagnostic injection log-log plot . Blue curve is Delta Pressure,\ngreen is first derivative curve (dDP/dDT), red curve is (DT* dDP/dDT).\nFig. shows the pseudo-radial plot utilized to estimate the pore pressure and the permeability of the\ncontacted reservoir by employing traditional after closure techniques (Talley et al., 1999). The analysis\nproduced an estimated pore pressure of 6,269 psi that was consistent with MDT pressure measurements\nand a contacted permeability between 0.66 to 0.55 mD depending if the assumed fracture height is 4 or 5\nmeters as suggested by the pressure-match model.\nFigure 44\u2014 Diagnostic injection after closure analysis pseudo-\nradial plot. Radial flow time function: Blue curve is bottom hole pressure.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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a4472-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 46, "chroma:document": "SPE-206239-MS 47\nThe permeability calculated based on the time required for the fracture to close on its faces provides the\nsame estimate as the one obtained when utilizing traditional after closure techniques. The Talley-Nolte plot\nwas constructed to verify the validity of the pseudo-radial flow period and the calculated pore pressure. Fig.\n45 shows that the pressure difference between the fall off pressure and the estimated pore pressure from the\nanalysis has a negative unit slope that coincides with its logarithmic derivative during the identified pseudo-\nradial flow period, supporting the validity of the analysis.\nFigure 45\u2014 Diagnostic injection Talley-Nolte plot Talley-Nolte Plot: Blue curve is delta pressure, green is the log derivative curve.\nThe fracture model was calibrated with triaxial mechanical tests and the interpreted DFIT information\nthat allowed to consistently pressure-match the test as shown in Fig. 46."}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a44c2-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 46, "chroma:document": "that allowed to consistently pressure-match the test as shown in Fig. 46.\nFigure 46\u2014 Diagnostic injection pressure fall off match . Blue curve: Measured\nwell head pressure. Black curve: Modeled well head pressure. Red curve: Frac rate.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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a451c-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 47, "chroma:document": "48 SPE-206239-MS\nThe DFIT was modelled in an iterative manner until the pressure-match model could reproduce a pressure\nresponse that has the same G-function signature/shape, closure pressure, closing time and after-closure\npressure transient through the implementation of a properly calibrated grid (Buijs, et al., 2020). Fig. 47\nshows consistent DFIT and numerical DFIT Gplots.\nFigure 47\u2014 DFIT vs simulated DFIT Gplot. Blue curve is bottom hole\npressure, green is first derivative curve (Dp/DG), red curve is (G*Dp*/DG) .\nThe permeability function utilized to simulate the created fracture geometries was built based on estimates\nfrom fracture closure time and after closure analysis of pre-frac tests. The permeability model was then\nsuperposed over the core based flowing phase permeability model showing that the function is consistent\nwith an independent estimate of the flowing capacity of this reservoir based on laboratory data (track 2,"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a456c-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 47, "chroma:document": "with an independent estimate of the flowing capacity of this reservoir based on laboratory data (track 2,\nFig. 48.A )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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a45bc-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 48, "chroma:document": "SPE-206239-MS 49\nFigure 48.A\u2014PHIE vs DFIT-flowing phase core perm.\nWhen calibrating the permeability model on stage 1 (marked with a green \"x\" on track 2 in Fig. 48.A), the\nsame function was able to predict the contacted permeability by the pre-frac tests of stage 2. The predictive\npower of the function developed supports that both intervals went through the same diagenetic processes\naffecting the evolution of permeability through geological times.\nFig. 48.B  shows a comparison of the rock mechanical properties and 1D litho-based stress model with the\n3D property cube output generated at this well position. The after-closure pressure estimations from both\npre-frac tests (marked as red points on track 2 in Fig. 48.B) were consistent with the multiple open-hole MDT\nmeasurements (marked as black circles). The lithology constrained 1DMEM of the Well (Stress_Total_G4)\nwas calibrated with the interpreted data from the pre-frac tests of stage 1 and could predict the interpreted"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a460c-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 48, "chroma:document": "was calibrated with the interpreted data from the pre-frac tests of stage 1 and could predict the interpreted\nclosure points measured at stage 2 (marked with black squares on track 2 in Fig. 48.B).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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a465c-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 49, "chroma:document": "50 SPE-206239-MS\nFigure 48.B\u20141D-3D litho-based 1DMEM and pore pressure model -\nAn iterative process within the modelled fracture geometries, RTA and a production model that accounts\nfor the physical behaviours of proppant packs allowed to estimate the end of well life and EUR within 5%\nof the P50 case provided by dynamic simulations performed by the reservoir engineering team ( Fig. 49.A).\nThe model was also instrumental in predicting the PLT back allocated production that was not provided\nfor the analysis and was utilized by the operating unit to test the predictive capabilities of the implemented\nworkflow. Fig. 49.B  shows the production percentage modelled for each stage next to the PLT results,\nshowing a perfect match (80% of the overall production comes from stage 2 and 20% from stage 1)."}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a46b6-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 49, "chroma:document": "showing a perfect match (80% of the overall production comes from stage 2 and 20% from stage 1).\nFigure 49.A\u2014RTA vs Frac geometry production models.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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a4706-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 50, "chroma:document": "SPE-206239-MS 51\nFigure 49.B\u2014Frac geometry back allocated production vs PLT.\nWhen utilizing the fracture compliance method, a fast closure is achieved, providing an estimated\nminimum stress of 10,094 psi, a PZS of 222 psi and a Gperm of ~4 mD as shown in Fig. 50.\nFigure 50\u2014 DFIT Gplot interpretation and Gperm calculation Blue curve is\nbottom hole pressure, green is first derivative curve (Dp/DG), red curve is (G*Dp*/DG).\nA low net pressure or PZS, in the range of 20% of the traditional techniques\u2019 estimates ( Fig. 42), is\ntranslated into being able to apply just ~200 psi to deform the rock and create fracture width. At the same\ntime, when modelling the associated fracture geometry, the simulated fracture height will tend to be much\nlarger than the estimates presented in this analysis since the rock becomes easier to break (presented in Fig.\n46). If we utilize this large fracture height in the pseudo-radial after-closure analysis, the estimated contacted"}


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topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a4756-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 50, "chroma:document": "46). If we utilize this large fracture height in the pseudo-radial after-closure analysis, the estimated contacted\npermeability will be much lower than 0.55 mD (as shown in Fig. 44) becoming smaller than the flowingDownloaded 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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a47a6-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 51, "chroma:document": "52 SPE-206239-MS\nphase estimated permeabilities based on core and inconsistent with the compliance Gperm estimates of ~4\nmD ( Fig. 50 ).\nThe analysis described in the previous paragraphs provided a converging solution that is consistent with\nmultiple tests utilized to calibrate and understand the production performance of this well. The analysis\nsupports a consistent relationship between the permeability estimates from DFIT fracture closure time, after-\nclosure analysis, DFIT numerical inversions, core and RTA (Buijs, et al., 2020). This in turn proves that\nthe interpreted time to reach fracture closure during the DFIT test occurs after its linear leak off period as\nstated by traditional interpretation techniques.\nOn the other hand, the compliance-based fracture closure technique has proven to be inconsistent with\nmultiple assessments of permeability, will have a clear effect in the contacted net pay and the conductivity of"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a4800-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 51, "chroma:document": "multiple assessments of permeability, will have a clear effect in the contacted net pay and the conductivity of\nthe simulated fracture geometry upsetting the predictive capabilities of any modelling workflow. Without a\nclear understanding on the permeability, fracture pressure and minimum stress, it is not possible to properly\nmodel the associated fracture geometry of the treatments pumped on this well and, regretfully, implement\nany meaningful completion optimization.\nCase 7: Low Permeability, Gas and Condensate Sandstone\nIn this case history, traditional minimum stress interpretations are supported by fracture models built on\npermeability estimates based on DFIT fracture closure time that is consistent with PBU and production\nmodelling estimates. This well was treated down a 2 7/8\" tubing and a large perforated interval, through\nwhich a DFIT, mini-frac and 335 tons treatment was pumped at an average rate of 24 bpm."}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a485a-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 51, "chroma:document": "which a DFIT, mini-frac and 335 tons treatment was pumped at an average rate of 24 bpm.\nThe DFIT pumped in this well shows a transverse storage closure mechanism with an estimated minimum\nstress of 9,487, a PZS of 354 psi and a Gperm of 0.364 mD as shown in Fig. 51 .\nFigure 51\u2014 DFIT Gplot Interpretation and Gperm Calculation Blue curve is\nbottom hole pressure, green is first derivative curve (Dp/DG), red curve is (G*Dp*/DG).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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a48aa-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 52, "chroma:document": "SPE-206239-MS 53\nThe pseudo-linear flow function provides an estimated pore pressure of 8,568 psi which is consistent\nwith the Talley-Nolte plot presented in Fig. 52 . The onset of a pseudo-radial flow regime was affected by the\nannulus pressure fluctuations and could not be utilized to assess the reservoir flowing capacity (indicated\nwith a black arrow in Fig 52).\nFigure 52\u2014 DFIT after closure pseudo-linear flow function and Talley-Nolte plots . Radial flow time function:\nBlue curve is bottom hole pressure. Talley-Nolte Plot: Blue curve is delta pressure, green is the log derivative curve.\nThe DFIT pressure match was achieved with an average permeability of 0.55 mD that accounts for the\nnatural fractures pressure dependent leak off (as presented in Fig. 53).\nFigure 53\u2014DFIT pressure-match model \u2013 Net pressure plot . Blue curve:"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a48fa-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 52, "chroma:document": "natural fractures pressure dependent leak off (as presented in Fig. 53).\nFigure 53\u2014DFIT pressure-match model \u2013 Net pressure plot . Blue curve:\nMeasured well bottom hole pressure Black curve: Modeled well bottom hole pressureDownloaded 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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a494a-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 53, "chroma:document": "54 SPE-206239-MS\nA 335-tons treatment pumped with a 35# crosslinked fluid is pressure-match, obtaining a propped fracture\nlength of 250 meters and height of 45 meters as indicated in Fig. 54 . The model suggests that almost 40% of\nthe perforations did not accepted proppant which was consistent with the PLT spinner data that supported\nflow from this exact same interval.\nFigure 54\u2014 Main fracture treatment pressure-match \u2013 Proppant concentration plot. Blue curve: Measured well bottom hole\npressure Black curve: Modeled well bottom hole pressure Red Curve: Frac rate Brown-green curves: Slurry proppant concentration.\nAfter 3 months of production, a PBU test was performed providing a contacted permeability of 0.492\nmD, a pore pressure of 8,120 psi and an estimated fracture flowing length of 48 meters. For this analysis,\nthe fracture height was assumed to be 50 meters in comparison to the pressure match fracture contacted net"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a499a-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 53, "chroma:document": "the fracture height was assumed to be 50 meters in comparison to the pressure match fracture contacted net\npay of 45 meters. If this latter is utilized to calculate the contacted permeability through the estimated 24.6\nmD*meters kh, an estimated flowing capacity of 0.54 mD is obtained (Fig. 55).\nFigure 55\u2014Main fracture treatment - Pressure build up interpretationDownloaded 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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a49f4-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 54, "chroma:document": "SPE-206239-MS 55\nA RTA analysis is performed based on an 8-month production history gathered after the main fracture\ntreatment took place (Fig. 56 ). The main treatment pressure-match fracture height of 45 meters was\nutilized in the analysis, providing a contacted average permeability of 0.62 mD (28.36 mD*m) and an\ninfinite flowing fracture half length dimension of 0.004 meters (0.016 feet). This well is produced through\na production manifold connected to 4 additional wells, slight variations between actual and estimated\nproduction are to be expected.\nFigure 56\u2014Main fracture treatment - Rate transient analysis interpretation\nInformation about the reservoir architecture obtained from the RTA is incorporated into a production\nmodel that accounts for the modelled fracture geometry, physical behaviours of proppant packs and\nthe reservoir properties described in the DFIT calibrated fracture grid. The simulated fracture geometry"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a4a44-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 54, "chroma:document": "the reservoir properties described in the DFIT calibrated fracture grid. The simulated fracture geometry\ncontacted an average of 0.5 mD based on a DFIT-calibrated model and is able to match the production\nhistory of the well, suggesting a flowing fracture in the order of 36 meters that can be translated into an\ninfinite fracture length of 1 meter (Fig. 57).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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a4a94-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 55, "chroma:document": "56 SPE-206239-MS\nFigure 57\u2014Frac geometry production model.\nThe estimated infinite flowing dimension from the frac production model of 1 meter is consistent with\nthe RTA estimated infinite fracture flowing dimension of 0.004 meters, sustaining the large pressure drop\nin the proppant pack is related to non-Darcy flow. During the early production period, the production model\nestimates a frac length of 36 meters that is consistent with a PBU estimated flowing length in the order\nof 48 meters.\nWhen utilizing the fracture compliance method, a minimum stress of 9,775 psi, a PZS of 66.8 psi and a\nGperm of ~0.8 mD can be interpreted as presented in Fig. 58 .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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a4ae4-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 56, "chroma:document": "SPE-206239-MS 57\nFigure 58\u2014 DFIT Gplot fracture compliance interpretation and Gperm calculation  Blue\ncurve is bottom hole pressure, green is first derivative curve (Dp/DG), red curve is (G*Dp*/DG).\nAmong other inconsistencies, as mentioned in previous case histories, the compliance based low PZS (net\npressure) will tend promote a larger fracture height growth on this well. To illustrate this, the 1DMEM and\nPZS grids from the fracture model are presented, defining the fracture pressure (ISIP) as the minimum stress\nplus the PZS or net pressure of the DFIT test interpreted with traditional techniques (shown in Fig. 59).\nFigure 59\u2014Traditional closure: Litho-based 1DMEM and PZS models.\nUnder the modeled state-of-stress conditions, fracture height growth is dominated by the PZS model."}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a4b3e-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 56, "chroma:document": "Under the modeled state-of-stress conditions, fracture height growth is dominated by the PZS model.\nAs indicated by the red arrows in Fig. 59, fracture is contained within layers accounting for a PZS of 800Downloaded 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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a4b8e-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 57, "chroma:document": "58 SPE-206239-MS\nto 1,000 psi (marked with red boxes in Fig. 59 ). When the mentioned PZS magnitudes are added to the\nminimum stress at the same depth, this is translated into a fracture pressure of 10,900 psi that the fracture\ntreatment cannot break through (marked with yellow boxes in Fig. 59). The lower perforated area cannot\nbe fractured due to the large PZS between 1,000 to 1,300 psi that are translated into fracture pressures in\nthe order of 11,000 to 11,300 psi (marked with white arrows in Fig 59 ).\nWhen utilizing the compliance based PZS to constrain this model, the mentioned PZS values will decrease\nto 150 and 180 psi respectably (~18% of traditional PZS value). In turn, to match the interpreted fracture\npressure, the increased minimum stress model will tend to have a similar stress distribution to the traditional\nclosure 1DMEM. When reducing the PZS to such low values (~66 psi), the fracture treatment will be allowed"}


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topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a4bde-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 57, "chroma:document": "closure 1DMEM. When reducing the PZS to such low values (~66 psi), the fracture treatment will be allowed\nto grow more in height and contact additional net pay. When this additional fracture height growth of the\nmain treatment is combined with the high compliance based Gperm, the contacted kh by the fracture model\nwill be too large to explain the production behavior of this well and become inconsistent with the PBU\nresults. This example also explains why it is so important to properly interpret DFITs since not being able\nto pick the right fracture closure pressure will tend to have a considerable effect on the modelled fracture\ngeometries, hydraulic fracture design and completion optimization.\nThe traditional fracture closure analysis described in the previous paragraphs provided a converging\nsolution that is consistent with multiple tests utilized to calibrate and understand the production performance"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a4c2e-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 57, "chroma:document": "solution that is consistent with multiple tests utilized to calibrate and understand the production performance\nof this well. The analysis supports a consistent relationship between the permeability estimates from DFIT\nfracture closure time, PBU and RTA. This in turn proves that the interpreted time to reach fracture closure\nduring the DFIT test occurs after its linear leak off period as stated by traditional interpretation techniques.\nCase 8: High Permeability, Gas Sandstone \u2013 Drained Reservoir\nThis is a high permeability vertical gas well that had a large skin of in the order of ~10 based on its PBU\ninterpretation. A flowing capacity model was build based on an effective porosity correlation to permeability\nthat is consistent with the PBU flowing capacity, averaging ~22 mD (Fig. 60.A and Fig. 60.B). This is a\nspecial case where damage was difficult to remove through acidizing based on previous experiences, making\nfracturing the most convenient solution to increase well economics."}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a4c7e-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 57, "chroma:document": "fracturing the most convenient solution to increase well economics.\nFigure 60.A\u2014Pressure build up analysis.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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a4cd8-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 58, "chroma:document": "SPE-206239-MS 59\nFigure 60.B\u2014PBU Permeability model.\nDuring the DFIT, completion fluid was pumped for 12 minutes obtaining a minimum stress of 7,230 psi,\na PZS of 1,271 and a Gperm of 0.538 mD psi ( Fig. 61 ).\nFigure 61\u2014DFIT Gplot \u2013 Gperm calculation.\nThe prefrac test had surface and bottom hole gauges that were utilized to track the evolution of the\npressure transient, showing a stabilized late time bottom-hole pressure that is consistent with the PBU\ninterpretation.\nWhen doing the pressure match of the test, the Gperm estimate of 0.538 mD shown in Fig. 59  could not\nbe utilized to explain the way pressure was behaving. In that respect, as shown in Fig. 62, the DFIT was\npressure-match by utilizing the PBU reservoir pressure and permeability model shown in Fig. 60.B.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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a4d28-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 59, "chroma:document": "60 SPE-206239-MS\nFigure 62\u2014 DFIT Pressure match \u2013 Fracture geometry net pressure plot . Red curve: Measured well head pressure Black\ncurve: Modeled well head pressure Brown curve: Measured well bottom hole pressure Blue curve: Modeled well bottom hole pressure\nThe DFIT and the pressure-match numerical inversion provide the same closure mechanism, net pressure,\nminimum stress and after closure pressure transients (Fig. 63).\nFigure 63\u2014DFIT vs Simulated DFIT Gplot.\nNevertheless, the estimated permeability based on closure time is not consistent with the PBU estimate\nof ~22 mD utilized to model the fall off pressure. The reason for this inconsistency is related to the Gperm\nfunction becoming insensitive to infer large permeabilities since it becomes nearly vertical on a log scale at"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a4de6-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 59, "chroma:document": "function becoming insensitive to infer large permeabilities since it becomes nearly vertical on a log scale at\nfast closure times as shown by the marked orange area in Fig. 64 (Barree, 2020 ).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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a4e2c-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 60, "chroma:document": "SPE-206239-MS 61\nFigure 64\u2014Gperm vs Gtime@closure permeability estimates for a specific DFIT condition.\nFor reservoirs that require hydraulic fracturing to increase its production performance and become\neconomical, the relationship of the Gperm to Core, DFIT ACA, PBU and RTA estimates is remarkable.\nConclusions\nThis multi-basin study from the North Sea, Europe, Russia, North Africa and South America regions\ndemonstrated how a well-defined workflow can be implemented to reduce uncertainty to properly explain\nfracture geometries and their associated production performance by integrating petrophysics, geomechanics,\nDFIT, PBU, RTA and fracture geometry modelling.\nCorrect interpretation of pre-frac tests becomes critical to design effective hydraulic fracture treatments,\ntap reservoir potential and maximize revenue. If the minimum stress is not estimated properly, fracture\ngeometry modelling results in unrealistic fracture height growth, proppant lateral coverage and proppant"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a4e7c-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 60, "chroma:document": "geometry modelling results in unrealistic fracture height growth, proppant lateral coverage and proppant\npack conductivities that will negatively affect any fracture optimization approach.\nOne of the key observations made since the inception of fracture diagnostic injections is that the pressure\ndecline after injection can be correlated to reservoir flow capacity. Multidisciplinary evaluation of reservoir\nflowing capacities from DFIT after-closure analysis, core, PBU, and rate transient analysis show a consistent\nrange that correlates with permeabilities estimated based on time required to reach well established fracture\nclosure interpretations (Gperm). Consequently, this proves that the interpreted time to reach fracture closure\nduring any diagnostic injection occurs after its linear leak off period as stated by traditional interpretation\ntechniques.\nNumerical inversions of DFIT can reproduce the same minimum stress, closure mechanism, time to reach"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a4ec2-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 60, "chroma:document": "techniques.\nNumerical inversions of DFIT can reproduce the same minimum stress, closure mechanism, time to reach\nfracture closure and after-closure pressure transients further supporting the validity of the interpretation.\nTheir assoacited litho-based 1DMEM and fracture geometry assessments provide consistent results with the\ninformation delivered by multiple injections on different geomechanical benches, PLT, fiber optics, micro\nseismic data, PBU and wells production performance.\nThe early-time fracture closure identification supported by the fracture compliance method was severely\ntested against information provided by dozens of wells across multiple basins under a wide range\nof permeability, pore pressure and state-of-stress conditions. Modelling the compliance-based fracture"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a4f12-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 60, "chroma:document": "of permeability, pore pressure and state-of-stress conditions. Modelling the compliance-based fracture\ngeometries was avoided, instead its lack of validity was explained in detail by utilizing well observations,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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a4f94-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 61, "chroma:document": "62 SPE-206239-MS\nconsistent interpretations of fracture fall off tests, PBU, core data, litho-based 1DMEM predictive\ncapabilities, logging data, fiber optics, micro seismic data and simple fracture width calculations. The\nsupporting theory of the compliance closure methodology might be mathematically consistent with the way\nfracture closure is described but is a physical process that cannot be reproduced in real fractures. Simply put,\nverifying theoretical results by utilizing fracture models built on physics that assume the described theory\nis real, does not constitute validation.\nThe fracture compliance methodology decouples the closure time and permeability relationship, leading\nto utilize inconsistent estimations of the host rock flowing capacity and its state-of-stress which has a severe\nimpact in the modelled fracture geometries. The compliance-based permeability estimates related to the"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a4fee-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 61, "chroma:document": "impact in the modelled fracture geometries. The compliance-based permeability estimates related to the\ntime required for the fracture to close tends to be between 2 to 6 times larger than the one obtained when\nfollowing traditional closure estimates. The estimated low net pressures cannot develop enough fracture\nwidth to place fracture treatments without screening out and establishes limited fracture conductivities that\ncannot be utilized to explain the production performance of multiple wells presented on this paper. This\nlatter also has a negative consequence in the modelled fracture heights that, when combined with large\nfrac closure based permeabilities, results in a large contacted net pay that becomes inconsistent with core\ndata, fiber optics, PLT, PBU and wells overall production performance. An additional proof of the lack\nof physical meaning of the compliance closure can be realized when analyzing multiple injections where"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a5034-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 61, "chroma:document": "of physical meaning of the compliance closure can be realized when analyzing multiple injections where\ntraditional closure techniques can be employed to consistently interpret the minimum stress (even when\nfracture closure mechanisms change) but, if the fracture compliance closure theory is utilized instead, large\ndifferences between the estimated stresses become visible. Regretfully, this theory is not only disagreeing\nwith Nolte's innovative work, but also has also proven to be incapable of explaining the production behavior\nof multi-fractured wells in a consistent manner when integrating numerous fracture diagnostic technologies.\nThe best proof that exists about the validity of traditional closure estimates lies in our wells, having the oil\nand gas industry utilizing this knowledge for decades to consistently improve the production performance\nof multi-fractured wells. This would not have been attainable if one fails to understand the state-of-stress"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a5084-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 61, "chroma:document": "of multi-fractured wells. This would not have been attainable if one fails to understand the state-of-stress\nand flowing capacity of the host rock that has a first-order dominant control on the success or failure of\na stimulation treatment.\nAcknowledgements\nThe authors would like to thank Wintershall Dea GmbH and their respective operating units for their\nsupport and permission to publish this paper. Special thanks are given to Antonio Bencic, Matthias\nStollenwerk, Gunter Harms, Camiel van Soest, Tibor Toth, Jorge Ponce, Dr Barree and Dr Miskimins for\ntheir contribution and large support given towards the publication of this paper.\nNomenclature\n1DMEM : 1-dimensional Mechanical Earth Model\nDFIT : Diagnostic Fracture Injection Test\nDTC : Compressional travel time\nDTC_RESIST : Resistivity based synthetic travel time\nDTC_GR : Spectral Gamma Ray based synthetic travel time\nTOC : Total Organic Carbon\nG-function \u2248 2 \u00d7 ((Time - Pumping Time)/Pumping Time) ^ 0.5"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a50d4-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 61, "chroma:document": "DTC_GR : Spectral Gamma Ray based synthetic travel time\nTOC : Total Organic Carbon\nG-function \u2248 2 \u00d7 ((Time - Pumping Time)/Pumping Time) ^ 0.5\nPHIE : Total Average Neutron-Density Porosity \u2013 Vlcay\nPBU : Pressure Build Up Test\nRTA : Rate Transient Analysis\nYMES : Static Young Modulus\nPR : Poisson's RatioDownloaded 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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a5124-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 62, "chroma:document": "SPE-206239-MS 63\nISIP : Instantaneous shut in pressure\nbpm : Barrels per minute.\nppag : poung per added gallon.\nInfinite\nflowing\nfracture half\nlength: Mathematical representation of a frac half length of infinite conductivity.\nFlowing\nfracture half\nlength: Maximum physical frac half length available to flow fluids.\nReferences\nBarree, R. D. ( 1983 ). A Practical Numerical Simulator for Three-Dimensional Fracture Propagation in Heterogeneous\nMedia, SPE 12273 . Paper presented at the SPE Reservoir Simulation Symposium, San Francisco, California.\nBarree, R.D.  and Mukherjee, H.  1996 . Determination of Pressure Dependent Leak Off and Its Effects on Fracture\nGeometry. Presented at the SPE Annual Technical Conference and Exhibition. Denver, Colorado, 6-9 October.\nSPE-36424-MS. http://dx.doi.org/10.2118/36424-MS .\nBarree, R.D.  1998 . Applications of Pre-frac Tests in Fissured Reservoirs \u2013 Field Examples . Presented at the SPE Rocky"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a5174-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 62, "chroma:document": "Barree, R.D.  1998 . Applications of Pre-frac Tests in Fissured Reservoirs \u2013 Field Examples . Presented at the SPE Rocky\nMountain Regional/Low Permeability Reservoirs Symposium. Denver, Colorado, 5-8 April. SPE-39932-MS. http://\ndx.doi.org/10.2118/39932-MS.\nBarree, R.D.  and P. Ph. Winterfeld. 1998 . Effects of Shear P lanes and Interfacial Slippage on Fracture Growth and Treating\nPressures . Presented at the SPE Annual Technical Conference and Exhibition. New Orleans, Louisiana, 27-30 October.\nSPE-48926-MS. http://dx.doi.org/10.2118/48926-MS .\nBarree, R. D.; Cox, S.A. ; Barree, V . L., and Conway, M.W.. 2003 . Realistic Assessment of Proppant Pack Conductivity\nfor Material Selection. SPE-84306-PA presented at the SPE Annual Techn ical Conference and Exhibition. Denver,\nCO. http://dx.doi: 10.2118/84306-PA.\nBarree, R.D. , Cox, S.A. , Gilbert, J.V .  and Dobson, M. 2005 . Closing the Gap: Fracture Half Length from Design,"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a51ba-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 62, "chroma:document": "Barree, R.D. , Cox, S.A. , Gilbert, J.V .  and Dobson, M. 2005 . Closing the Gap: Fracture Half Length from Design,\nBuildup and Production Analysis. SPE Journal Production & Facilities, November 2005. SPE-84491-MS. http://\ndx.doi: 10.2118/84491-MS .\nBarree, R.D. ; Barree, V .L. and Craig, D.p.. 2009 . Holistic Fracture Diagnostics: Consistent Interpretation of Pre-frac\nInjection Tests Using Multiple Analysis Methods. SPE Production & Operations 24(3):396-406. SPE 107877-PA.\nhttp://dx.doi.org/10.2118/107877-PA .\nBarree, R. D., Barree, V . L., and Craig, D.  2009 . Holistic Fracture Diagnostics: Consistent Interpretation of Pre-frac\nInjection Tests Using Multiple Analysis Methods. SPE Production & Operations Journal. SPE-107877-PA. http://\ndx.doi: 10.2118/107877-PA .\nBarree, R. D., Gilbert, J. V . , and Conway, M.W. 2009 . Stress and Rock Property Profiling for Unconventional Reservoir"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a520a-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 62, "chroma:document": "dx.doi: 10.2118/107877-PA .\nBarree, R. D., Gilbert, J. V . , and Conway, M.W. 2009 . Stress and Rock Property Profiling for Unconventional Reservoir\nStimulation. Presented at the SPE Hydraulic Fracturing Technology Conference held in The Woodlands, TX, 19-21\nJan. 2009. SPE-118703-MS. http://dx.doi: 10.2118/118703-MS.\nBarree, R.D. , Conway, M.W., and Miskimins, J.L.  2014 . Use of Conventional Well Logs in Selective Completion Designs\nfor Unconventional Reservoirs . Presented at the SPE Western North American and Rocky Mountain Joint Regional\nMeeting held in Denver, CO, 16-18 Apr. 2014. SPE-169565-MS. http://dx.doi: 10.2118/169565-MS.\nBarree, R.D. , Miskimins, J.L. , and Gilbert, J.V .  2014 . Diagnostic Fracture Injection Tests: Common Mistakes, Misfires\nand Misdiagnostics . SPE Western North American and Rocky Mountain Joint Regional Meeting. Denver, Colorado.\nSPE 169539-MS. http://dx.doi: 10.2118/169539-MS."}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a525a-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 62, "chroma:document": "SPE 169539-MS. http://dx.doi: 10.2118/169539-MS.\nBarree, R.D. , Cox, S.A. , Miskimins, J.L., and Gilbert, J.V . 2014 . Economic Optimization of Horizontal Well Completions\nin Unconventional Reservoirs. SPE Hydraulic Fracturing Technology Conference. Woodlands, Texas. SPE 168612-\nMS. http://dx.doi: 10.2118/168612-MS.\nBarree, R. D. , 2009-2015 . Principles of Hydraulic Fracturing Course.\nBarree, R.D.  and. Miskimins, J.L. , 2016 , Physical Explanation of non-linear derivatives in diagnostic fracture injection test\nanalysis : SPE Hydraulic Fracturing Technology Conference held in the Woodlands, SPE 179134-MS. http://dx.doi:\n10.2118/179134-MS .\nBarree, R.D.  Practical Fundamentals of DFIT Execution and Interpretation. December 8, 2020\nBrown, G. O. Department of Biosystems and Agricultural Engineering, Oklahoma State University, Stillwater, OK 74078,"}


created_at: 2023-11-16 17:06:54
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id: 6b8a52aa-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 62, "chroma:document": "Brown, G. O. Department of Biosystems and Agricultural Engineering, Oklahoma State University, Stillwater, OK 74078,\nUSA . Article in Water Resources Research July 2002 . DOI: 10.1029/2001WR000727Downloaded 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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 63, "chroma:document": "64 SPE-206239-MS\nBuijs, H.  and Ponce, J. , 2018  An Engineered Approach to Hydraulically Fracture the Vaca Muerta Shale . Presented at the\nSPE Hydraulic Fracturing Technology Conference held at the Woodlands, TX, 23-25 Jan. SPE-189866-MS. https://\ndoi.org/10.2118/189866-MS .\nBuijs, H. ; Ponce, J.; and P. Veeken. Validation of flow capacity and state-of-stress models in unconventional reservoirs\nby implementation of numerical mo dels of diagnostic fracture injection tests Published on The Leading Edge, June\n2019 . https://doi.org/10.1190/tle38060306.1 .\nBuijs, H.  An Engineered Approach to Hydraulic Fracture the Vaca Muerta Shale , 2018 . https://webevents.spe.org/\nproducts/an-engineered-approach-to-hydraulic-fracture-the-vaca-muerta-shale\nBuijs, H. , Guerra, C. ; Sonwa, R. ; Nami, P; Vecchia, L. ; and Ishmuratov, R. , 2020  Building Multifrac Completion Strategies\nin Tight Gas Reservoirs: A North Sea Case . Presented at the Abu Dhabi International Petroleum Exhibition &"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a537c-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 63, "chroma:document": "in Tight Gas Reservoirs: A North Sea Case . Presented at the Abu Dhabi International Petroleum Exhibition &\nConference, Abu Dhabi, 9th Nov. SPE-202713-MS. https://doi.org/10.2118/202713-MS.\nCarter, R.D. : Derivation of the General Equation for Estimating the Extend of Fracture Area. Appendix 1 of \"Optimum\nFluid Characteristics for Fracture Extension\" Drilling and Production Practice, Howard, C.R. and Fast, C.R. , API,\nNew York ( 1957 ), 261-269.\nCastillo, J.L.  1987 . Modified Fracture Pressure Decline Analysis Including Pressure-Dependent Leakoff. SPE 16417.\nSPE/DOE Low Permeability Reservoirs Symposium held in Denver, Colorado, May 18-19, 1987.\nConway, M. W.; Lindeman, S. W. and Barree, R.D. Selection of Stimulation Fluids and Treatment Design for Low -\nPermeability Reservoirs: SPE Hydraulic Fracturing Technology Conference held College Station, TX. SPE 106085-\nMS. http://dx.doi: 10.2118/106085-MS ."}


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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 63, "chroma:document": "Permeability Reservoirs: SPE Hydraulic Fracturing Technology Conference held College Station, TX. SPE 106085-\nMS. http://dx.doi: 10.2118/106085-MS .\nCox, S.A. ; Gilbert, J.V .; Sutton, R.P. and Stoltz, P. 2002 . Reserve Analysis for Tight Gas . SPE 78695. Paper presented at\nthe SPE Eastern Regional Meeting. Lexington, KC. http://dx.doi.org/10.2118/78695-MS .\nCox, S.A. ; Sutton, R.P. ; Stoltz, P. ; Barree R. D. and Conway, M.W. 2007 . Evaluation of Complex Reservoir Geometries and\nCompletion Practices on Production Analysis. SPE 111285 MS Paper presented at the SPE Easter Regional Meeting.\nLexington, KC http://dx.doi.org/10.2118/111285-MS .\nCraig, D. P.; Barree, R. D. ; Warpinsiki, N. R.  and Blasingame, T. A., 2017  Fracture >Closure Stress: Reexamining\nField and Laboratory Experiments of Fracture Closure Using Modern Interpretation Methodologies. Presented at the\nSPE Annual Technical Conference & Exhibition held at San Antonio, TX, 9-11 October. SPE-187038-MS. https://"}


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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 63, "chroma:document": "SPE Annual Technical Conference & Exhibition held at San Antonio, TX, 9-11 October. SPE-187038-MS. https://\ndoi.org/10.2118/187038-MS.\nCluff, R.M. ; Shanley, K.W. and Miller, M.A. Three things we thought we understood about shale gas, but were afraid\nto ask, AAPG  (2007).\nDuenckel, R. J.; Barree, R.D., Drylie, S.; O'connell, L.G. and Abney, K.L. Proppants \u2013 What 30 Years of Study have\nTaught Us, SPE 187451 . SPE Production & Operations. May 2019. http://dx.doi.org/10.2118/187451-MS.\nEissa, A. , Kazi, A. , Relation Between Static and Dynamic Young's Moduli of Rocks . Int. J. Rock Mech. Min. Sci. Geomech.\nAbstr . V olume 25, Number 6, Pages 479-482, 1988.\nGeerstma J.  and de Klerk F.A.  Rapid Method of Predicting Width and Extent of Hydraulically Induced Fractures. SPE\nJournal of Petroleum Technology . December 1969, 1571-81.\nGodbey, J.K. and Hodges, H.D. : \"Pressure Measurements During Formation Fracturing Operations, \". Trans., AIME\n(1958) 213, 65\u201369."}


created_at: 2023-11-16 17:06:54
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 63, "chroma:document": "Godbey, J.K. and Hodges, H.D. : \"Pressure Measurements During Formation Fracturing Operations, \". Trans., AIME\n(1958) 213, 65\u201369.\nGulrajani, S.N. , Mack, M.G.  and Elbel, J.L.: \"Pressure History Inversion for Interpretation o f Fracture Treatments,\" paper\nSPE 36439, presented at the SPE Annual Technical Conference and Exhibition, Denver, Colorado, USA (October 6\u2013\n9,1996);\nHarrison, E., Kieschnick, W.F. Jr. and McGuire, W.J.: \"The Mechanics of Fracture Induction and Extension,\". Trans.,\nAIME  (1954 ) 201, 252\u2013263.\nJohnson, R.L. , You, Z. , Riberiro, A. , Mukherjee, S., Salomao de Santiago, V . and Leonardi, C.. 2020 . Integrating Reservoir\nCharacterization, Diagnostic Fracture Injection Testing, Hydraulic Fracturing and Post-Frac Well Production Data to\nDefine Pressure Dependent Permeability Behavior in Coal. Presented at the SPE Asia Pacific Oil & Gas Conference.\nPerth, Australia, 20-22 October, 2020. SPE-202281-MS. http://dx.doi.org/10.2118/202281-MS ."}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 63, "chroma:document": "Perth, Australia, 20-22 October, 2020. SPE-202281-MS. http://dx.doi.org/10.2118/202281-MS .\nJung, H. , M. M. Sharma , D. D. Cramer, S. Oakes, and M. W. McClure. 2016 . Re-examining interpretations of non-ideal\nbehavior during diagnostic fracture injection tests. Journal of Petroleum Science and Engineering 145: 114-136, doi:\n10.1016/j.petrol.2016.03.016.\nKhristianovic, A.A. and Zheltov, Y .P.. 1955 . Formation of Vertical Fractures by Means of Highly Viscous Liquid. Paper\n6132 presented at the 4 th World Petroleum Congress, Rome, 6-15 June.\nLai, C.Y . , Zheng, Z. , Dressaire, E. , Ramon, G.Z., Huppert, H.E and Stone, H.A 2006 . Elastic Relaxation of Fluid - Driven\nCracks and Resulting Backflow . Physical Review Letters, 117, 268001 , December, 2016. Phys. Rev. Lett. 117, 268001\n(2016) - Elastic Relaxation of Fluid-Driven Cracks and the Resulting Backflow (aps.org)"}


created_at: 2023-11-16 17:06:54
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 63, "chroma:document": "(2016) - Elastic Relaxation of Fluid-Driven Cracks and the Resulting Backflow (aps.org)\nMarc Laliberte , \"Model for Calculating the Viscosity of Aqueous Solutions,\"  J. Chem. Eng. Data, 52, 321- 335, 2007Downloaded 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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 64, "chroma:document": "SPE-206239-MS 65\nMarc Laliberte , \"Model for Calculating the Viscosity of Aqueous Solutions,\" J. Chem. Eng. Data, 52, 1507 -1508, 2007\n(Correction and update)\nMcClure, Mark W. , Christopher A. J. Blyton, Hojung Jung, and Mukul M. Sharma. 2014 . The Effect of Changing Fracture\nCompliance on Pressure Transi ent Behavior During Diagnostic Fracture Injection Tests . SPE 170956. Paper presented\nat the SPE Annual Technical Conference and Exhibition, Amsterdam, The Netherlands.\nMcClure, Mark W. , Hojung Jung , Dave D. Cramer, and Mukul M. Sharma . 2016 . The fracture compliance method for\npicking closure pressure from diagnostic fracture injection tests. SPE Journal 21(4): 1321 -1339, doi: 10.2118/179725-\nPA.\nMcClure, M. ; Bammidi, V .; Cipolla, C. ; Cramer, D.; Martin, L., Savitski, A. ; Sobernheim and V oller, K. 2019 . A\nCollaborative Study on DFIT Interpretation: Integrating Modeling Field Data, and Analytical Techniques . URTeC:"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 64, "chroma:document": "Collaborative Study on DFIT Interpretation: Integrating Modeling Field Data, and Analytical Techniques . URTeC:\n123. Paper presented at the Unconventional Resources Technology Conference, Denver, CO. DOI 10.15530/\nurtec-2019-123 .\nNolte, K.G.  1979 . Determination of Fracture Parameters from Fracturing Pressure Decline. Presented at the SPE\nAnnual Technical Conference and Exhibition, Las Vegas, Nevada, 23-24 September. SPE 8341-MS. http://\ndx.doi.org/10.2118/8341-MS.\nNolte, K.G. : \"Fracturing Pressure Analysis for Non-Ideal Behavior,\" paper SPE 20704, presented at the SPE Annual\nTechnical Conference and Exhibition, New Orleans, Louisiana, USA (September 23\u201326, 1990); also in Journal of\nPetroleum Technology  (February 1991 ) 43, No. 2, 210\u2013218.\nNolte, K.G. , Mack, M.G.  and Lie, W.L. : \"A Systematic Method for Applying Fracturing Pressure Decline: Part 1,\" paper\nSPE 25845, presented at the SPE Rocky Mountain Regional Meeting and Low Permeability Reservoirs Symposium,"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 64, "chroma:document": "SPE 25845, presented at the SPE Rocky Mountain Regional Meeting and Low Permeability Reservoirs Symposium,\nDenver, Colorado, USA (April 12\u201314, 1993).\nNolte, K.G. , Maniere, J.L. and Owens, K.A. : \"After-Closure Analysis of Fracture Calibration Tests,\" paper SPE 38676,\npresented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA (October 5\u20138, 1997).\nNolte, K.G.  and Gulrajani, S.N.  Fracture Evaluation Using Pressure Diagnostics Reservoir Stimulation, 3rd Edition, 2000\nNolte, K. G. , 2007 . Keynote Speech at the Hydraulic Fracturing Technology Conference. College Station, TX 2007.\nPassey, Q. , Creaney S , Kulla J, Moretti F. and Stroud J. , 1990a. Source rock analysis from well logs \u2013 \u0394LogR Technique.\nBased on information in the following reference: Passey, Q.R., S. Creaney, J.B. Kulla, F.J. Moretti, J.D Stroud (1990)\nA practical model for organic richness from porosity and resistivity logs , AAPG Bulletin, V ol. 74, No. 12 (December"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a5638-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 64, "chroma:document": "A practical model for organic richness from porosity and resistivity logs , AAPG Bulletin, V ol. 74, No. 12 (December\n1990), page 1777  \u2013 1794 .\nPassey, Q.R.  Creaney S. , Kulla J., Moretti F.  and Stroud J. , 1990b . A practical model for organic richness from porosity\nand resistivity logs , AAPG Bulletin , V ol. 74, No. 12 (December 1990), Page 1777 \u2013 1794.\nPerkins T.K.  and Kern L.R.  Widths of Hydraulic Fractures. SPE Journal of Petroleum Technology. September 1961 ,\n937-49; Trans. AIME 222, September 1961.\nPiggott, A.R. , Brady, B.H.  and Gu, H.: \"Reservoir Formation Characterization from Hydraulic Fracturing Records,\"  Proc.,\nEurock'92 Symposium, London, UK ( 1992 ), 360\u2013365.\nPonce, J. E.  Personal communications  (2010 ).\nRamurthy, M. ; Towler, B. ; Harris, G.H  and Barree, R.D. , 2013 . Effects of High Pressure-Dependent Leak-Off and\nHigh Process-Zone Stress (PZS) on Stimulation Treatment and Production. Presented at the SPE Unconventional"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a567e-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 64, "chroma:document": "High Process-Zone Stress (PZS) on Stimulation Treatment and Production. Presented at the SPE Unconventional\nResources Conference and Exhibition Asia-Pacific. Brisbane, Australia. 11-13 November, 2013. SPE-167038-MS.\nhttp://dx.doi.org/10.2118/167038-MS .\nSneddon, I.N.  and Elliot, A.A. : \"The Opening of a Griffith Crack Under Internal Pressure,\" Quarterly of Appl. Math.\n(1946 ) 4, 262\u2013267.\nTalley, G. D., Swindell, T.M., Water, G.A., and Nolte, K.G. 1999 . Field Application of After Closure Analysis of Fracture\nCalibration Test . Paper SPE 52220. Presented at the SPE Mid-Continent Operations Symposium, Oklahoma City,\nUSA, 28-31 March. http://dx.doi: 10.2118/52220-MS.\nVeccia, L. . Personal communications  (2016 )\nWang, HanYi and Mukul M. Sharma. 2017 . New variable compliance method for estimating in-situ stress and leak-off\nfrom DFIT data . SPE 187348. Paper presented at the SPE Annual Technical Conference and Exhibition, San Antonio,\nTX."}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a56ec-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/spe-206239-ms.pdf", "page": 64, "chroma:document": "from DFIT data . SPE 187348. Paper presented at the SPE Annual Technical Conference and Exhibition, San Antonio,\nTX.\nWang, HanYi and Mukul M. Sharma . 2018 . Estimating unpropped fracture conductivity and compliance from diagnostic\nfracture injection tests. SPE 189844. Paper presented at the SPE Hydraulic Fracturing Technology Conference &\nExhibition. The Woodlands, TX.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: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a573c-84a2-11ee-9ca1-0242ac1c000c
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/arma-2018-225.pdf", "page": 0, "chroma:document": "1. INTRODUCTION  \nDiagnostic fracture injection tests ( DFIT) involve \npumping a fluid (typically water), at a constant rate for a \nshort period of time, creating a relatively small hydraulic \nfracture before the well is shut in. The pressure transient \ndata after shut -in is analyzed to obtain in -situ stresses \nand reservoir properties. In addition, the net pressure \ntrends in a DFIT can be also used to infer the induced \nfracture complexity in different geological settings \n(Potocki 2012) and stress -dependent un -propped fracture \nconductivity can be estimated through forward  modeling \nor inverse calculation ( Wang and Sharma 2018 ). This \nvaluable information  obtained from DFITs provides key \ninput parameters for modeling hydraulic fracture \npropagation ( Wang 2015; Wang 2016; Wang et al. 2016 ), \nstimulation design (Ramurthy et al. 2011), development \nof reservoir models  (Mirani et al. 2017; Loughry et al. \n2015 ; Wang 2017 ) and post -fracture analysis (Fu et al. \n2017) ."}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a5782-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/arma-2018-225.pdf", "page": 0, "chroma:document": "of reservoir models  (Mirani et al. 2017; Loughry et al. \n2015 ; Wang 2017 ) and post -fracture analysis (Fu et al. \n2017) . \nThe advent of fracturing pressure decline analysis was \npioneered by the work of Nolte (1979 and1986). With \nthe assumptions of power -law fracture growth, \nnegligible spurt loss, constant fracture compliance (or \nstiffness), constant fracture surface area afte r shut -in and \nCarter\u2019s leak -off (a constant pressure boundary \ncondition), a remarkably simple and useful equation for the pressure decline can be obtained based on a G -\nfunction approach. Wang and Sharma (2017b) showed  \nthat that the traditional \u201ctangent lin e method ( Barree et al. \n2009 ) \u201d undere stimate s the closure stress while the  \n\u201ccompliance method \u201d (McClure et al. 2016 ) estimates \nthe onset of closure rather than the  closure stress. Based \non their analysis, a new \u201cvaria ble compliance method\u201d \nwas proposed to  estimate the closure stress. Wang and"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a57d2-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/arma-2018-225.pdf", "page": 0, "chroma:document": "on their analysis, a new \u201cvaria ble compliance method\u201d \nwas proposed to  estimate the closure stress. Wang and \nSharma (2018) further confirmed that fracture \ncompliance is pressure -dependent during closure , and \nthe mechanical ly closed fracture is still subject to leak -\noff. The stress -dependent un -propped fracture \nconductivity c an be estimated by analysis of DFIT data.  \nPrevious papers  have been mainly focused on planar \nfracture s in homogen eous reservoirs, and relatively little \nwork has been done to interpret DFIT data in naturally \nfractured reservoirs with fracture pressure depe ndent \nleak-off (FPDL) and variable fracture compliance. In \nthis study, we extend our previous work to investigate \npressure transient behavior in naturally fractured \nreservoir s.  \n2. THE GOVERNING EQUATI ONS  \n2.1. 1D Fracture Pressure Dependent Leak -off \nwith Variable Compliance              \nARMA 1 8\u2013225"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a5818-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/arma-2018-225.pdf", "page": 0, "chroma:document": "with Variable Compliance              \nARMA 1 8\u2013225                                                                \n \nEstimating Fracture Closure Stress in Naturally Fractured  \nReservoirs with Diagnostic Fracture Injection Test s \n \nHanYi Wang  \nThe University of Texas at Austin, Austin, Texas, USA  \nMukul M. Sharma  \nThe University of Texas at Austin, Austin, Texas, USA  \n \nCopyright 20 18 ARMA, American Rock Mechanics Association  \nThis paper was prepared for presentation at the 52nd US Rock Mechanics / Geomechanics Symposium held in Seattle , Washington , USA, 17\u201320 \nJune  2018. This paper was selected for presentation at the symposium by an ARMA Technical Program Committee based on a technical and \ncritical review of the paper by a minimum of two technical reviewers. The material, as pres ented, does not necessarily reflect any position of"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a5868-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/arma-2018-225.pdf", "page": 0, "chroma:document": "critical review of the paper by a minimum of two technical reviewers. The material, as pres ented, does not necessarily reflect any position of \nARMA, its officers, or m embers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the \nwritten consent of ARMA is prohibited. Permission to reprodu ce in print is restricted to an abstract of not more than 200 words; illus trations may \nnot be copied. The abstract must contain conspicuous acknowledgement of where and by whom the paper was presented.   \n \n \n ABSTRACT:  Diagnostic Fracture Injection Tests (DF IT), which have also been referred to as Injection -Falloff Tests, Fracture \nCalibration Tests  or Mini -Frac Tests in the literature, have evolved into a commonly used technique to obtain in -situ stress. \nSimplifying  assumption s used  in traditional G -function model often lead to an underestimation of the  closure stress, even for a"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a58b8-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/arma-2018-225.pdf", "page": 0, "chroma:document": "Simplifying  assumption s used  in traditional G -function model often lead to an underestimation of the  closure stress, even for a  \nplanar fracture geometry. When a DFIT  is conducted  in naturally fractured reservoirs, the stimulated natural fractures can either \nalter the effective reservoir permeability within the distance of investigation or interact with  the hydraulic fracture to form a \ncomplex fracture geometry. In this study, we p resent a new pressure transient model for DFIT analysis in naturally fractured \nreservoirs, and it is shown that using established methods to pick closure stress often lead to significant over or underesti mates, \nregardless of whether the reservoir is heavil y fractured or sparsely fractured. Our proposed \u201cvariable compliance method\u201d gives a \nmuch more accurate and reliable estimation of closure stress in both homogenous and naturally fractured reservoirs."}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a5912-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/arma-2018-225.pdf", "page": 0, "chroma:document": "much more accurate and reliable estimation of closure stress in both homogenous and naturally fractured reservoirs.  \n \n \n \n \n  \n \nDownloaded from http://onepetro.org/ARMAUSRMS/proceedings-pdf/ARMA18/All-ARMA18/ARMA-2018-225/1190432/arma-2018-225.pdf/1 by University of Houston user on 30 October 2023"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a598a-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/arma-2018-225.pdf", "page": 1, "chroma:document": "The transient pressure response during fracture closure is \nderived using the following assumptions:  \n1. Reservoir  is isotropic and homogeneous and contains \na single slightly compressible fluid.  \n2. The fluid viscosity, formation porosity and total \ncompressibility are independent of pressure.  \n3. Reservoir permeability is low so that poroelastic \neffects caused by fluid leak -off are negligible  \n4. Gravity effects are negligible and pressure gradients \nare small thorough out the reservoir.  \n5. Mechanical ly closed fracture has residual fracture \nwidth so it is still subject to leak -off (Wang and \nSharma 2018) and the fracture leak -off surface area \nremains unchanged.  \n6. Fracture pressure is uniformly distributed inside the \nfracture.  \n7. The pore pressure disturbance c aused by fracture \npropagation is negligible. This means that fluid leak -\noff during pumping is very small and the duration of \ninjection is very short (typically 3 -5 minutes) while"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a59da-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/arma-2018-225.pdf", "page": 1, "chroma:document": "off during pumping is very small and the duration of \ninjection is very short (typically 3 -5 minutes) while \nthe total shut -in time can be hours, days or even \nweeks.  \n8. Leak -off is linear  and perpendicular to the fracture \nsurface and pressure interference among fractures and \nlate time radial flow has not been developed yet.  \nAssuming 1D linear Darcy flow and a slightly \ncompressible, single -phase fluid in the reservoir, the \ndifferential form of the mass balance can be written as:  \n\u2202P\n\u2202t=1\n\ud835\udf07\ud835\udc53\ud835\udf19\ud835\udc50\ud835\udc61\u2202\n\u2202x(k\u2202P\n\u2202x)                                  (1) \nwhere P is the pressure, k is formation permeability, \nwhich can be a function of P. \u03bcf is fluid viscosity, \u03d5 is \nformation porosity and ct is total formation \ncompressibility. From a material balance perspective \n(fluid compressibility is negligible compared to that of \nthe fracture), the total rate of fluid leak -off into the \nformation,  qf , after shut -in equals the rate of shrinkage"}


created_at: 2023-11-16 17:06:54
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{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/arma-2018-225.pdf", "page": 1, "chroma:document": "the fracture), the total rate of fluid leak -off into the \nformation,  qf , after shut -in equals the rate of shrinkage \nof total f racture volume,  Vf, as pressure declines:  \n\ud835\udc5e\ud835\udc53=\u2212 \ud835\udc51\ud835\udc49\ud835\udc53\n\ud835\udc51\ud835\udc61                                      (2) \nFracture stiffness, which is the reciprocal of fracture \ncompliance, is defined as (Wang and Sharma 2017a; \nWang et al. 2018):  \n\ud835\udc46\ud835\udc53=\ud835\udc34\ud835\udc53\ud835\udc51\ud835\udc43\ud835\udc53\n\ud835\udc51\ud835\udc49\ud835\udc53                                              (3) \nwhere \ud835\udc43\ud835\udc53 is pressure inside fracture and \ud835\udc34\ud835\udc53 is  half of the \ntotal fracture surface area (only account for 1 wall). \nSubstituting  Eq.(3) into Eq.(2), we have  \n\ud835\udc5e\ud835\udc53=\u2212 \ud835\udc34\ud835\udc53\ud835\udc51\ud835\udc43\ud835\udc53\n\ud835\udc46\ud835\udc53\ud835\udc51\ud835\udc61                                      (4) \nAt the boundary of the fracture surface, both Darcy\u2019s \nlaw and material balance have to be honored:  \ud835\udc5e\ud835\udc53=\u2212 2\ud835\udc34\ud835\udc53\ud835\udc58\n\ud835\udf07\ud835\udc53 \ud835\udc51\ud835\udc43\n\ud835\udc51\ud835\udc65=\u2212  \ud835\udc34\ud835\udc53\ud835\udc51\ud835\udc43\ud835\udc53\n\ud835\udc46\ud835\udc53\ud835\udc51\ud835\udc61 at x=0        (5) \nRearranging Eq. (5), we get the boundary condition at \nthe fracture surface:  \n\ud835\udc58\n\ud835\udf07\ud835\udc53 \ud835\udc51\ud835\udc43\n\ud835\udc51\ud835\udc65=1\n2\ud835\udc46\ud835\udc53\ud835\udc51\ud835\udc43\ud835\udc53\n\ud835\udc51\ud835\udc61 at x=0                     (6) \nWith initial condition (disregarding the pressure"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a5a70-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/arma-2018-225.pdf", "page": 1, "chroma:document": "the fracture surface:  \n\ud835\udc58\n\ud835\udf07\ud835\udc53 \ud835\udc51\ud835\udc43\n\ud835\udc51\ud835\udc65=1\n2\ud835\udc46\ud835\udc53\ud835\udc51\ud835\udc43\ud835\udc53\n\ud835\udc51\ud835\udc61 at x=0                     (6) \nWith initial condition (disregarding the pressure \ndisturbance during the short injection period)  \n  \ud835\udc43=\ud835\udc430 at t=0,x>0                              (7) \n  \ud835\udc43=ISIP  at t=0,x=0                           (8) \nwhere \ud835\udc430 is the initial pore pressure and ISIP  is the \ninstant shut -in pressure. The governing equation  Eq.(1), \nplus the initial condition Eq. (7) -(8) and boundary \ncondition Eq.(6) uniquely describe the pressure transient \nbehavior during DFITs. To account for wellbore storage \neffects, the fracture stiffness \ud835\udc46\ud835\udc53 needs to be replaced by \nthe fracture -wellbore system stiffness, which is defined \nas: \n\ud835\udc46\ud835\udc60=    \ud835\udc46\ud835\udc53\ud835\udc34\ud835\udc53\n\ud835\udc34\ud835\udc53+\ud835\udc46\ud835\udc53\ud835\udc49\ud835\udc64 \ud835\udc50\ud835\udc64                                   (9) \nwhere \ud835\udc49\ud835\udc64 is the wellbore volume and \ud835\udc50\ud835\udc64 is the water \n(injection fluid in the wellbore) compressibility.   \n2.2. Fracture Stiffness of Complex Frac ture \nGeometry  \nBecause fracture stiffness (or compliance) represents"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a5ac0-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/arma-2018-225.pdf", "page": 1, "chroma:document": "2.2. Fracture Stiffness of Complex Frac ture \nGeometry  \nBecause fracture stiffness (or compliance) represents \nsurface normalized compressibility, for a fracture with \ncomplex fracture geometry, the total fracture stiffness is \ncontrolled by the stiffness of multiple individual fracture \nsegments, as illustrated in Figure.1.  \n \nFig. 1 Illustration of complex fracture geometry . \nThe complex fracture is formed by individual segments \nwith different orientations and fracture surface area. Let \nthe ith fracture surface area of one wall denoted as Af,i \nand its pressure -dependent stiffness denoted as Sf,i, the \ntotal fracture stiffness  can be determined from the \nstiffness of each individual fracture segment (analogous \nto capacitors in  parallel s): \n\ud835\udc46\ud835\udc53=\ud835\udc34\ud835\udc53\n\ud835\udc34\ud835\udc53,1\n\ud835\udc46\ud835\udc53,1+\ud835\udc34\ud835\udc53,2\n\ud835\udc46\ud835\udc53,2+\u22ef+\ud835\udc34\ud835\udc53,\ud835\udc5b\n\ud835\udc46\ud835\udc53,\ud835\udc5b                       (10) \nDownloaded from http://onepetro.org/ARMAUSRMS/proceedings-pdf/ARMA18/All-ARMA18/ARMA-2018-225/1190432/arma-2018-225.pdf/1 by University of Houston user on 30 October 2023"}


created_at: 2023-11-16 17:06:54
topic: persistent://default/default/c01518eb-579a-4a9d-8cdf-22ca77573fa8
id: 6b8a5b06-84a2-11ee-9ca1-0242ac1c000c
encoding: FLOAT32
metadata:
{"source": "drive/MyDrive/Fracture closure Reviews/Fracture closure Reviews/arma-2018-225.pdf", "page": 2, "chroma:document": "Where,  \n\ud835\udc34\ud835\udc53=\ud835\udc34\ud835\udc53,1+\ud835\udc34\ud835\udc53,2+\u22ef+\ud835\udc34\ud835\udc53,\ud835\udc5b                    (11) \n2.3. Pressure Dependent Permeability  \nIn previous literature (Barree et al. 2009), the \nphenomenon of pressure -dependent permeability is often \ncalled as pressure -dependent leak -off ( PDL), however, \nthis is not a n appropriate term, because leak -off is \nalways pressure -dependent, even  if the permeability is \nconstant (Wang and Sharma 2017b). There are many \nequations  that can be used to express the  formation \neffective permeability as a function of pressure, such as \na linear, power law or hyperbolic relationship. To make \na general case and use as few  free parameters as \npossible, we can use a general formula to relate \nformation permeability and pressure:  \nk(P)=(\ud835\udc58\ud835\udc52\u2212\ud835\udc580)\ud835\udc52\ud835\udc50\u2212\ud835\udc52\ud835\udc3c\ud835\udc46\ud835\udc3c\ud835\udc43 \u2212\ud835\udc43\n\ud835\udc3c\ud835\udc46\ud835\udc3c\ud835\udc43 \u2212\ud835\udc43\ud835\udc5c\ud835\udc5f\ud835\udc56\ud835\udc54\ud835\udc56\ud835\udc5b\ud835\udc4e\ud835\udc59\ud835\udc50\n\ud835\udc52\ud835\udc50\u22121+\ud835\udc580      (12) \nwhere \ud835\udc58\ud835\udc52 is the effective reservoir  permeability at the \nend of pumping and \ud835\udc580 is the original reservoir \npermeability. \ud835\udc43\ud835\udc5c\ud835\udc5f\ud835\udc56\ud835\udc54\ud835\udc56\ud835\udc5b\ud835\udc4e\ud835\udc59  is the pressure where reservoir"}


