Stimulation procedures often require the use of solid particulates having high compressive strength. In hydraulic fracturing, such particulates must further be capable of enhancing the production of fluids and natural gas from low permeability formations.
In a typical hydraulic fracturing treatment, a treatment fluid containing a solid particulate or proppant is injected into the wellbore at high pressures. Once natural reservoir pressures are exceeded, the fluid induces fractures in the formation and proppant is deposited in the fracture where it remains after the treatment is completed. The proppant serves to hold the fracture open, thereby enhancing the ability of fluids to migrate from the formation to the wellbore. Because fractured well productivity depends on the ability of a fracture to conduct fluids from a formation to a wellbore, fracture conductivity is an important parameter in determining the degree of success of a hydraulic fracturing treatment.
Since the degree of stimulation afforded by the fracture treatment is dependent upon the propped width, it is important that the proppant exhibit resistance to crushing from the high stresses in the well. When the proppant is unable to withstand closure stresses imposed by the formation, the solid particulates are compressed together in such a way that they crush and fines and/or dust are generated. Generated fines and/or dust from the proppant plug pore throats in the reservoir matrix, thereby reducing reservoir permeability.
Improvements have been continuously sought to control and prevent the crushing of proppants at in-situ reservoir conditions. For instance, resin-coated proppant materials have been designed to help form a consolidated and permeable fracture pack when placed in the formation wherein the resin coating enhances the crush resistance of the proppant.
It is further necessary, when producing oil and/or gas from an unconsolidated subterranean formation, to prevent sand grains and/or other formation fines from migrating into the wellbore and being produced from the well. The creation and/or mobilization of reservoir fines during fracturing and production has also been instrumental in reducing fracture conductivity and reducing reservoir permeability due to plugging of pore throats by the fines.
A common method to control sand migration is gravel packing which is designed to prevent the production of formation sand and reduce migration of unconsolidated formation particulates into the wellbore. Typically, gravel pack operations involve placing a gravel pack screen in the wellbore. A carrier fluid carrying the solid particulates or “gravel” leaks off into the subterranean zone and/or is returned to the surface while the particulates are left in the zone and are packed in the surrounding annulus between the screen and the wellbore. The particulates operate to trap, and thus prevent the further migration of, formation sand and fines which would otherwise be produced along with the formation fluid. Like proppants, sand control particulates must exhibit high strength and be capable of functioning in low permeability formations.
In some situations the processes of hydraulic fracturing and gravel packing are combined into a single treatment to provide stimulated production and reduce formation sand production. Such treatments are often referred to as “frac pack” operations. In some cases, the treatments are completed with a gravel pack screen assembly in place and the hydraulic fracturing fluid is pumped through the annular space between the casing and screen. In such a situation, the hydraulic fracturing treatment usually ends in a screen out condition creating an annular gravel pack between the screen and casing. This allows both the hydraulic fracturing treatment and gravel pack to be placed in a single operation.
Coated and/or uncoated particulates have further been used in gravel packing to minimize the migration of generated fines and/or dust. While the use of resin coated proppants has been successful in minimizing the generation of fines during hydraulic fracturing and fine migration during gravel packing, such materials are known to often erode oil and gas production equipment. There is an ongoing need to develop particulates exhibiting crush resistance that can be used as proppants and gravel for minimizing fines generation and fines migration, reduce proppant pack and gravel pack damage, and which are less eroding to oil and gas production equipment while exhibiting tolerance to in-situ stress conditions.
In addition to concerns arising from the creation of fines and dust downhole, the release of dust during transport of proppant and sand control particulates has come recently under close scrutiny as health concerns of field workers and those within residential areas within the vicinity of on-shore fracturing has risen. There has not been an acceptable method developed to date specifically designed to reduce the release of dust from proppants and sand control particulates. While resin coating of frac sand has been noted to decrease dust production, the addition of a resin coating doubles the cost of frac sand. In addition, the chemicals used to make the resins are not environmentally friendly. Lastly, the application of resin coating to frac sand requires the sand to be heated either by electricity or the burning of natural gas, both of which are costly. Alternative methods for reducing the generation of dust from particulates as well as controlling the migration of particulates in producing formations have thus been sought.
Further, alternative materials have been sought for use in selective simulation operations. Typically, a subterranean formation penetrated by a well has a plurality of distinct zones or formations of interest. During production of fluids from the well, it usually is desirable to establish communication with only the zone or formations of interest such that stimulation treatments do not inadvertently flow into a non-productive zone or a zone of diminished interest. Selective stimulation (such as by hydraulic fracturing and acid stimulation) becomes pronounced as the life of the well declines and productivity of the well decreases.
Typically, selective stimulation entails perforating the zone and/or formation with a perforating gun placed adjacent to the zone and/or formation of interest. The procedure is repeated until all of the zones and/or formations of interest have been perforated. The perforating gun is then retrieved to the surface by means of a wireline. When fracturing is desired, the fracturing fluid is pumped into the well under pressure exceeding the pressure at which the zone and/or formations would fracture. In order to prevent the fracturing fluid from flowing into zones having greater porosity and/or lower pressure, a mechanical device, such as a straddle packer, or plug or sand fill may be set in the well between a fractured zone and the zone to be fractured to isolate the stimulated zone from further contact with the fracturing fluid. This procedure is then repeated until all of the zones of interest are perforated and fractured. Once the completion operation is finished, each plug is drilled out of or otherwise removed from the well to permit fluid to be produced to the surface.
Recently, methods and assemblies have been developed for effectuating zonal isolation between intervals of the wellbore that do not depend on the removal of perforating equipment in and out of the well. For instance, attention has been focused on the use of isolation assemblies which allow for selected treatment of productive (or previously producing intervals) in multiple interval wellbores. Zonal isolation assemblies are expensive and alternatives have been sought.
Focus has been centered recently on the use of swellable elastomeric materials as packers and isolation profilers. However, the use of swellable elastomeric polymers in wells is often limited due to evasive organic and inorganic chemicals, temperatures, pressures and other subterranean environmental factors that decrease the life and the reliability of the elastomer. Such factors also present problems to other components used in the recovery of hydrocarbons from wells. For instance, enzymes commonly used as breakers in fracturing fluids are typically inactivated at high temperatures. Their use at elevated temperatures, for instance, at temperatures greater than 150° F., causes them to denature and lose activity.
Ineffective fracturing of a formation may also result from the loss of friction between tubular and other metallic substrates within the well. Friction reduction between treatment fluids and surfaces contacted by the fluid has also presented ongoing issues. In many instances, the types of viscosifying agents which may be used in fracturing fluids is limited since friction reduction equates to a faster reduction in viscosity of the viscosifying agent upon contact with hydrocarbons. Alternatives have been sought for addressing friction reduction at in-situ downhole conditions.
Resources have also been spent on both chemical and physical techniques for effectively reducing frictional drag created during the flow of hydrocarbons within a hydrocarbon producing reservoir. Alternatives for reducing friction have focused on drag reduction agents. Typically, friction reduction agents are large polymers with long chains which tend to build non-Newtonian gel structures. Drag reducing gels are shear-sensitive and often require specialized injection equipment (such as pressurized delivery systems). Further, since friction reduction agents are typically highly viscous, usually no more than 10 weight percent of polymeric friction reduction agents are present in the carrier fluid. Some attention has been focused on the use of slurries or dispersions of polymers to form free-flowing and pumpable mixtures in liquid media. However, such polymers often agglomerate over time, thus making it very difficult for them to be placed in hydrocarbon liquids where reduced drag is needed. Further alternatives for lowering the frictional drag of fluids within a well have been sought in order to enhance the productivity of hydrocarbons from the well.
In addition, alternatives have been sought for controlling or inhibiting the formation and/or precipitation of scales, paraffins and asphaltenes during the production of hydrocarbons in subterranean formations. While well treatment agents have been successfully employed to control and/or inhibit the formation of scales, paraffins and asphaltenes, such agents are typically mixed on the fly with other components, such as proppant and sand control particulates. Alternative means of controlling the formation and/or inhibition of scales, paraffins and asphaltenes which simplify preparation of well treatment fluids on site are desired.
It should be understood that the above-described discussion is provided for illustrative purposes only and is not intended to limit the scope or subject matter of the appended claims or those of any related patent application or patent. Thus, none of the appended claims or claims of any related application or patent should be limited by the above discussion or construed to address, include or exclude each or any of the above-cited features or disadvantages merely because of the mention thereof herein.