Patent application title: TECHNIQUE OF FRACTURING WITH SELECTIVE STREAM INJECTION
Schlumberger Technology Corporation (Sugar Land, TX, US)
SCHLUMBERGER TECHNOLOGY CORPORATION
IPC8 Class: AE21B4326FI
Class name: Processes placing fluid into the formation fracturing (epo)
Publication date: 2013-07-18
Patent application number: 20130180722
A technique facilitates enhanced hydrocarbon recovery through selective
stream injection. The technique employs a system and methodology for
combining a fracturing technique and application of selective injection
streams. The selective injection streams are delivered to select,
individual subterranean layers until a plurality of unique subterranean
layers are fractured to enhance hydrocarbon recovery.
1. A method for fracturing, comprising: isolating a formation layer of a
plurality of formation layers from one or more others of the plurality of
formation layers; delivering a fluid a first time to the formation layer
at least until a pressure of the fluid is equal to an opening pressure of
the formation layer; allowing the formation layer to close after
delivering the fluid the first time; delivering the fluid a second time
to the formation layer at least until the pressure of the fluid is equal
to a reopening pressure of the formation layer, wherein the reopening
pressure is less than the opening pressure; and determining that the
reopening pressure is less than a maximum injection pressure.
2. The method of claim 1, further comprising: determining, after delivering fluid the second time, that the reopening pressure of the formation layer is greater than the maximum injection pressure; and delivering fluid one or more third times to the formation layer, at least until the reopening pressure of the formation layer is reached each of the one or more third times, wherein the reopening pressure decreases for each sequential one of the one or more third times, and wherein determining that the reopening pressure is less than the maximum injection pressure occurs after delivering the fluid the one or more third times.
3. The method of claim 2, further comprising allowing the formation layer to close after delivering the fluid each of the one or more third times.
4. The method of claim 1, wherein allowing the formation to close comprises flowing back the fluid from the formation layer.
5. The method of claim 1, further comprising: determining, after delivering the fluid the second time, that the reopening pressure of the formation layer is greater than the maximum injection pressure; and delivering a complementary chemical to improve the fracturing, duration of the fracture, or both.
6. The method of claim 1, further comprising substantially matching a flow rate of the fluid versus time while delivering the fluid the second time to a flow rate of the fluid versus time when the fluid was delivered the first time.
7. The method of claim 6, wherein the flow rate of the fluid increases over time during at least a portion of delivering the fluid the first time.
8. The method of claim 1, further comprising selecting the formation layer from among the plurality of formation layers independently of whether any others of the plurality of formation layers have been fractured.
9. The method of claim 1, further comprising determining the maximum injection pressure based on one or more capabilities of well equipment.
10. A computer system, comprising: one or more processors; a memory system comprising one or more computer-readable media storing instructions that, when executed by at least one of the one or more processors, are configured to cause the computer system to perform operations, the operations comprising: causing a pump to pump a fluid a first time to a formation layer; determining that the pressure in the fluid proximal to the formation layer is at least equal to a fracture pressure of the formation layer; causing the pump to pump fluid to the formation layer a second time, after the first time; determining that the pressure in the fluid proximal to the formation layer at least equals a reopening pressure of the formation layer, wherein the reopening pressure is less than the fracture pressure; and determining that the reopening pressure is less than a maximum injection pressure.
11. The system of claim 10, wherein causing the pump to pump the fluid the first time comprises causing the pump to pump the fluid at successively higher fluid flow rates.
12. The system of claim 11, wherein causing the pump to pump fluid the second time comprises substantially matching a flow rate of the fluid versus time while pumping the first time to a flow rate of the fluid versus time while pumping the first time.
13. The system of claim 10, wherein the operations further comprise: determining that the reopening pressure after the second time is higher than a threshold; causing a complementary chemical to be delivered to the formation layer after the second time; causing the pump to pump the fluid to the formation layer one or more third times; and for each of the one or more third times, determining that the pressure of the fluid proximal to the formation layer is at least equal to the reopening pressure, wherein the reopening pressure is reduced after each of the one or more third times.
14. The system of claim 10, further comprising causing the fluid to flowback, to allow the formation layer to close between the first and second times.
15. The system of claim 10, wherein the operations further comprise: selecting the formation layer from a plurality of formation layers along a wellbore; and isolating the formation layer from each other of the plurality of formation layers, independently of whether any other of the plurality of formation layers has been fractured.
16. The system of claim 10, wherein the operations further comprise determining the maximum injection pressure using data related to one or more capabilities of well equipment.
17. A computer-readable medium storing instructions that, when executed by one or more processors of a computing system, are configured to cause the computing system to perform operations, the operations comprising: causing a selected formation layer of a plurality of formation layers to be isolated from each of a remainder of the plurality of formation layers, wherein the selected formation layer is selected independently of whether any other of the plurality of formation layers have been fractured; causing fluid to be pumped to the formation layer at successively higher fluid flow rates; determining that the pressure in the fluid meets or exceeds a fracture pressure of the formation layer while the fluid is being pumped the first time; causing the fluid to be pumped to the formation layer a second time at successively higher flow rates; determining that the pressure in the fluid meets or exceeds a reopening pressure of the formation layer while the fluid is being pumped the second time, wherein the reopening pressure is less than the fracture pressure; and determining that the formation reopening pressure is less than a maximum injection pressure.
18. The medium of claim 17, wherein a maximum value of the pressure of the fluid during the first time is greater than a maximum value of the pressure of the fluid during the second time.
19. The medium of claim 17, wherein the operations further comprise: determining that the reopening pressure at the second time is higher than a threshold; causing a complementary chemical to be delivered to the formation layer after the second time; causing the pump to pump fluid to the formation layer one or more third times; and for each of the one or more third times, determining that the pressure in the fluid meets or exceeds the formation reopening pressure, wherein the formation reopening pressure is reduced after each of the one or more third times.
20. The medium of claim 17, further comprising causing the fluid to flowback, to allow the formation to close between the first and second times.
CROSS-REFERENCE TO RELATED APPLICATIONS
 This application is a continuation-in-part of U.S. patent application Ser. No. 12/848,690, filed on Aug. 2, 2010, which claims priority to U.S. Provisional Application Ser. No. 61/266,659, filed Dec. 4, 2009. The entirety of both of these priority applications is incorporated herein by reference.
 In certain well applications, recovery of hydrocarbon based fluids can decline over time to uneconomical levels. Sometimes, the recovery of hydrocarbons may be enhanced through the injection of fluids, and such techniques are referred to as secondary recovery or enhanced recovery methods. In one technique known as waterflooding, water is injected to displace oil toward a producer well. However, hydrocarbon gases, CO2, air, steam, and other fluids may be injected to enhance recovery of the desired hydrocarbons. Various fracturing techniques, including proppantless fracturing techniques, also have been employed to facilitate recovery of hydrocarbons from certain subterranean formations. Because the composition of subterranean formations often is layered, adequate control over fracturing and/or injection of the fluids is difficult due to the many unique layers holding the hydrocarbon based fluids.
 In general, embodiments of the present disclosure provide a system and methodology which combine a well stimulation technique, e.g. a proppantless fracturing technique, and application of selective injection streams at multiple unique subterranean layers to enhance hydrocarbon recovery.
BRIEF DESCRIPTION OF THE DRAWINGS
 Certain embodiments will hereafter be described with reference to the accompanying drawings, wherein, where convenient, like reference numerals are generally employed to denote like elements. In the figures:
 FIG. 1 is an illustration of a system for enhancing a fluid injection profile to multiple levels along a wellbore, according to an embodiment.
 FIG. 2 is a graph illustrating one technique for screening/fracturing a formation layer to improve fluid injection rate which enhances hydrocarbon production, according to an embodiment.
 FIG. 3 is a schematic illustration showing the sequential fracturing of multiple formation layers, according to an embodiment.
 FIG. 4 is a graphical illustration of the efficiency improvements following a multi-level fracturing technique, according to an embodiment.
 FIG. 5 is a flowchart illustrating an operational procedure related to stimulation pumping which is employed to facilitate sequential fracturing of a plurality of formation levels, according to an embodiment.
 FIG. 6 is a flowchart illustrating a fracturing pumping technique employed to facilitate sequential fracturing of a plurality of formation levels, according to an embodiment.
 FIG. 7 is a flowchart illustrating fluid flushing with chemicals, e.g. acids or solvents, which may be employed to facilitate sequential fracturing of a plurality of formation levels, according to an embodiment.
 FIG. 8 is a schematic view of a computer system, according to an embodiment.
 In the following description, numerous details are set forth to provide an understanding of embodiments of the present disclosure. However, it will be understood by those of ordinary skill in the art that embodiments of the present disclosure may be practiced without these details and that numerous variations or modifications from the described embodiments may be possible.
 Embodiments of the present disclosure generally relate to a system and methodology for improving a fluid injection profile in fluid injector wells to thereby induce enhanced recovery of hydrocarbons, e.g. oil, from subterranean regions. The technique is useful in increasing the percentage of hydrocarbon based fluids recovered from a plurality of formation layers formed through a given subterranean region. According to one embodiment, selective injection streams (SIS) are used to regulate the injection of fluids, e.g. liquids, gases, steam, into formation layers through flow regulators positioned between isolating devices. Use of the selective injection streams also distributes the injected fluids more efficiently through the formation layers which increases the vertical efficiency and increases the recovery of hydrocarbons.
 As described in greater detail below, the technique improves injection of fluids and enhances hydrocarbon recovery which, as a consequence, increases hydrocarbon production. Various aspects of the present technique include the injection of fluids into specific, selected subterranean layers to create individual fractures in those layers. The selective injection stream technique is employed to increase the number of unique formation layers which are fractured. In some applications, complementary chemicals, e.g. acids or solvents, are delivered to each formation layer to improve the fracturing process and/or the duration of the created fractures. Additionally, various analyses may be performed prior to, during, and/or after the fracturing operation. The selective stream injection also increases the number of formation/reservoir layers which may be fractured in a single downhole operation.
 According to one embodiment, the technique may be used to improve the effectiveness of fluid injected, e.g. waterflooding methods, to enhance hydrocarbon recovery. In this embodiment, fluid, e.g. water or another suitable fluid, is introduced into a subterranean region to create different, individual fractures using a selective fluid injection stream. The selective fluid injection stream is sequentially directed into each isolated layer or at least into some of the isolated layers of a plurality of formation layers to cause enhanced fracturing along the entire subterranean region. The fracturing is accomplished through one or more downhole flow control devices, e.g. regulator valves, associated with each individual layer or each specific group of selected layers.
 In many applications, the deepest layer is initially fractured using the deepest associated mandrel (with or without a flow control device, e.g. flow regulator valves, installed therein), while blocking the upper regulator valves with "dummy" or "blind" valves (or other no-flow valves) to guarantee injection of fluid through the selected mandrel and into the selected formation layer. For example, the technique can be applied with free mandrels (if high wellhead pressure limitations are presented) or with flow regulator valves or other suitable flow devices disposed in the mandrel. The operation can be repeated through other mandrels to selectively and sequentially fracture each of the subsequent formation layers while the other layers are isolated. In some cases, a device may be installed into the mandrel for the purpose of protecting the mandrel integrity from the effects of pressure and/or corrosion during the fracturing process.
 In some applications, complementary chemicals are injected or otherwise delivered into the individual layers prior to or after fracturing pumping. For example, acids, e.g. hydrochloric acid (HCl), mutual solvents, diesel, paraffin or asphalten solvents may be delivered to the desired formation layer followed by or preceded by the fracturing pumping. The complementary chemicals improve the fracturing process and/or the duration of the fracture. However, use of complementary chemicals may not be required in all applications.
 The technique also may include employing an analysis process to evaluate and monitor aspects of the hydrocarbon production enhancement. The analysis may be performed prior to, during, and/or after the operation, and various monitoring techniques may be continued following the operation. For example, the analysis may be performed prior to the fracturing operation by screening criteria to facilitate selection of well candidates for which the present technique is suitable. The pre-operation analysis may include evaluating well parameters, including mechanical integrity, injection and fracture pressure, geological correlations, petrophysics, reserves calculations, production profiles, operational aspects, risk evaluation, planning of the operation, and economics of the operation.
 The analysis also may include operational aspects, including definition of the fracture pressure which may be obtained through, for example, "step rate tests" as described below. Other operational aspects may include defining the pressure increment employed during the fracture operation, and implementing the operation (or contingency plan if necessary). The analysis also may include ongoing monitoring techniques which include monitoring of well parameters, e.g. flow rates, pressures, and water/fluid quality. Monitoring may be achieved with a variety of technologies, including tracers, spinners, distributed temperature sensing fiber optic systems, and/or other technologies designed to measure injection rates at each formation layer, e.g. injection rates through specific regulator valves at each formation layer. The monitoring techniques also may include the use of mathematical models to reproduce dynamic aspects of the reservoirs, formation layers, and overall well performance. The injection rates for a given layer or layers may be modified according to the results of the modeling.
 Referring generally to FIG. 1, a well system 20 is illustrated as deployed in a well 22, having at least one wellbore 24, to facilitate individual fracturing of a plurality of formation layers by improving the fluid injection profile and therefore enhancing hydrocarbon recovery. The well system 20 includes a selective injection completion 26 designed to improve the vertical sweeping by enabling the controlled injection of fluid into individual, selected formation layers 28 of a plurality of formation layers 28. The completion 26 provides control over the injection flow, e.g. water injection flow, to individual formation layers 28 via corresponding mandrels/flow control devices 30. By way of example, the mandrels/flow control devices 30 may include flow regulators, e.g. water flow regulators (WFR), such as flow regulator valves. The mandrels/flow regulators 30 provide better control over the injection profile throughout the reservoir and the individual formation layers 28 of that reservoir.
 In the specific example illustrated in FIG. 1, the selective injection completion 26 includes a tubing string 32 having isolation devices 34, e.g. packers. In the specific embodiment illustrated, the mandrels/flow control devices 30 may include flow regulator valves disposed in side pocket mandrels 36. In some applications, the flow regulators 30 include dummy valves. Additionally, the side pocket mandrels 36 are independently isolated between packers 34, thus allowing separate injection, e.g. water injection, into specific, selected formation layers 28 according to a specific pattern profile design. This ability substantially enhances the fracturing operation via the selective injection while isolating the other well zones/formation layers from the fracturing pressure. It also should be noted that in the embodiment illustrated, tubing string 32 is deployed within a surrounding casing 38 having perforations 40 associated with each formation layer 28 to enable flow of injection fluid from the tubing string 32, through the appropriate flow control device 30, through the corresponding perforations 40, and into the selected, surrounding formation layer 28.
 Depending on the injection/fracturing application and on the surrounding environment, well system 20 may include a variety of other components to facilitate injection and/or monitoring of the procedure. For example, a sensor system 42 may be deployed downhole with tubing string 32 to monitor the fracturing of each formation layer 28. The sensor system 42 may be deployed within tubing string 32, along the exterior of tubing string 32, or at a location separated from tubing string, such as along casing 38. Additionally, the sensor system 42 may include a variety of sensors 44, e.g. distributed sensors or discrete sensors, designed to measure desired parameters, such as pressure, temperature, flow rate, porosity, or other parameters related to the stimulation procedure and/or surrounding reservoir. The sensor system 42 is useful for collecting data to enable various analyses prior to, during, and/or after fracturing of individual layers 28.
 To better recognize candidate wells (e.g. a well screening process) and/or to better respond to low injection rates detected in some formation layers, a detailed review of possible problems affecting injection water restriction may be performed. A screening process of problems and their possible associated solutions may be conducted to determine the more appropriate stimulation system to be employed with the present technique. In some applications, the screening process may be based on the principle of formation/perforations breakdown and the creation of conductor channels within the formation by proppantless fluid, such as water.
 Referring generally to FIG. 2, the fracturing process may involve pumping the injection fluid, e.g. water or another suitable fluid, in a "step rate test" procedure followed by the flow back. It should be noted a pump cycle includes both of the previously mentioned stages (pumping the injection fluid and flow back). The step rate test procedure includes a series of successively higher injection rates for which pressure values are read and recorded at each rate and time step 46, as illustrated in FIG. 2. In FIG. 2, a plot of injection rates and the corresponding stabilized pressure values are graphically represented as a constant slope straight line 48 to a point 50 at which the formation fracture, or "breakdown", pressure is exceeded (FIP) in a first pump cycle 52. The flow back stage is then performed to allow the transition between pump cycles and to increase the formation perturbations. A second pump cycle 54 is performed and a fracture re-opening pressure (FRP) 56 effectively becomes the parameter for evaluating the effectiveness of the stimulation process and also for ranking the success of the treatment. The success ranking depends on the differential pressure achieved when the fracture re-opening pressure 56 is compared with the injection pressure of fluid from the fluid injection plant, e.g. water injection plant. The re-opening fracture pressure could be affected every time the pumping cycle is done, reducing the effective re-opening pressure. The cycles may be repeated until the reduction in such pressure is considered profitable. Performing several cycles increases formation perturbations which induces fatigue and makes the formation weaker. This is demonstrated by a decrease in the reopening pressure due to reduction in the tensile strength and Young's Modulus of the formation.
 In the present technique for enhancing hydrocarbon recovery, vertical sweeping efficiency is an important factor, and that factor is addressed by the selective stream completion 26 when used for fracture stimulation. Furthermore, the fracture stimulation via selective stream completion 26 provides a technique directly focused on improving vertical efficiency at a low cost and low risk. Another attribute of the technique is maintaining selectivity in the injection because the fractures are selectively performed in accordance with the selective string arrangement. The fracturing technique is designed to avoid communication between formations while substantially enhancing conductivity of flow along a selected or determined formation. In the embodiment of FIG. 3, the sequential stimulation, e.g. fracturing, of individual formation layers 28 is illustrated. In this example, the selective injection completion 26 is used to fracture individual layers 28 or specific groups of layers through the empty mandrel (or using flow control devices) 30 having "dummy" or "blind" valves 58 to block injection of fluid into other layers of the subterranean region. In that way, injection of fluid is concentrated through a selected control device(s) 30 and into the specific layer or group of layers 28 to be fractured.
 As illustrated in the embodiment of FIG. 3, the injection sequence is repeated for each layer or group of layers of the subterranean region. Initially, the dummy valves 58 are used to block flow into the upper formation layers 28, while the lowermost formation layer 28 is fractured or otherwise stimulated. In the specific example illustrated, a well stimulation fluid 60, e.g. a water-based fracturing fluid, is first delivered down through tubing string 32. In this example, the fracturing fluid is flowed outwardly through the lowermost mandrel 30 and into the lowermost formation zone 28 to create the desired fractures 62, as illustrated in the left portion of FIG. 3.
 After fracturing the lowermost formation layer 28, it is blocked by dummy valve 58, as illustrated in the middle portion of FIG. 3. The flow control device 30 of the next sequential formation layer 28 to be stimulated, e.g. fractured, is then opened to allow the outflow of fluid 60, as illustrated. While a given formation layer 28 is fractured (or otherwise stimulated), the other formation layers 28 are isolated from the pressure of the fracturing fluid via packers 34 and the closed flow control devices 30 in those other well zones. This process of introducing an injection fluid into a selected formation layer 28 while isolating the other formation layers is repeated for each sequential formation layer, as further illustrated in the rightmost portion of FIG. 3. To obtain desired isolation or inclusion, different options may be employed, e.g. selective dummy or blind valve installation and retrieval.
 The flow control devices 30 may be actuated between open and closed positions via a variety of actuators depending on the design of the flow control device. With certain flow regulator valves, including dummy valves 58, a shifting tool may be moved downhole to manipulate the appropriate valve. For example, injection into specific layers 28 may be achieved by moving/actuating/retrieving the regulator valves 30/58 via a low-cost slickline operation. As result, it is not necessary to pull out the selective string to make individual fractures, thus avoiding substantial costs associated with the rig rate and required replacement tools.
 The selective stream injection technique substantially increases the efficiency of hydrocarbon recovery from a variety of wells. Improvements are provided with respect to not only vertical efficiency but also with respect to areal efficiency and total efficiency or recovery factor. Referring generally to FIG. 4, a graphical illustration is provided to illustrate the substantial improvements in various efficiency measurements when the present "fracturing with selective stream injection technique" is employed to recover hydrocarbons from a subterranean region.
 As illustrated in the example of FIG. 4, areal efficiency is substantially improved, as illustrated by upper portion 66 of the graphical representation in FIG. 4. In this particular example, the areal efficiency is based on a well configuration in which four injector wells are employed in the corners of a pattern of wells, and a producer well is located in the center of the pattern. Over time, the injected fluid flows into the porous media displacing oil to the producer well. The ratio between the area flooded with water and the area of the pattern (a rectangle in this case) is referred to as areal efficiency. It should be noted that a variety of patterns of the injector wells and producer wells may be employed depending on the characteristics of the application and reservoir environment. As additional formation layers are reached by the injected fluids, the areal efficiency increases in these particular formation layers, thus improving the overall areal efficiency.
 Vertical efficiency is illustrated in a lower portion 68 of the graphical representation in FIG. 4 by a schematic cross-sectional view of formation layers 28 at three different times. In this example, five different formation layers 28 are flooded with water 60. The injected water 60 is distributed in the different formation layers according to the petrophysical properties, e.g. permeability and thickness of the layers; formation damage during the well completion; and/or pore pressure. In this example, the vertical efficiency is the ratio between the volume of the layers flooded and the total volume of the layers. The vertical efficiency, in particular, can be substantially improved through the use of the technique described herein which employs fracturing with selective stream injection of individual formation layers 28. However, the total efficiency or recovery factor, ER, also is improved and is the product of three efficiencies, namely displacement efficiency, areal efficiency, and vertical efficiency.
 The fracturing with selective injection stream technique may be employed in a variety of environments with many types of wells. However, one embodiment of the methodology for carrying out this technique includes initially preparing a well for intervention. At this initial stage, each layer 28 to be individually treated is properly prepared to ensure the integrity of the selective injection completion 26 and to verify each formation layer 28 has treatment isolation/independency with respect to the other layers 28. In some applications, an optional "pickling" job is performed at this stage by delivering a complementary chemical into one or more individual formation layers. For example, HCl may be delivered downhole to clean the injection string or tubing 32 by eliminating residual components in the walls of the tubing which could otherwise block the flow control devices/valves 30 or damage the formation layers 28.
 The initial segments of one embodiment of the procedure are illustrated in the flowchart of FIG. 5. In this specific example, a slickline may be used to isolate formation layers with dummy valves 58, as illustrated by block 70. The system is then flow tested by a pressure test, as represented by decision block 72. If the flow is zero, an optional pickling operation may be performed by directing a complementary chemical, e.g. HCl, downhole, as represented by block 74, prior to inclusion of the selective group to be fractured, as represented by block 76. If, on the other hand, flow is detected as an indication of lack of isolation, a tracer log may be run and the dummy valves 58 may be readjusted and/or the equipment may be re-run downhole, as represented by block 78.
 In a subsequent stage of the technique, the injection fluid 60, e.g. water or another suitable fluid, is delivered downhole and introduced into a specific layer or group of layers 28 between packers 34 to create individual fractures 62 in the specific layer(s), as discussed above with reference to FIG. 3. The selective fluid injection stream 60 can be used sequentially on individual, isolated formation layers 28 to increase the number of formation layers 28 that may be independently fractured. Consequently, the selective stream technique enables independent treatments on specific layers and optimizes the effective channeling creation throughout the overall formation. In many applications, brine may be used as a fracture fluid when formation layers are sensitive to untreated water.
 Referring generally to FIG. 6, a flow chart is provided to illustrate one procedure for carrying out the fracturing process discussed above with reference to FIG. 2. Initially, several fracturing pump cycles may be performed, as represented by block 80. The fracturing pump cycles may be performed through two different stages, the first of which is a step rate test or the fluid injection stage when fluid 60 is injected into a desired, selected formation layer to be fractured. The second stage is a flow back stage (not a fluid injection stage) which allows the pump cycles to transition and increase the perturbation effect to the formation. In operational conditions, the fluid injection wells work under a specific injection pressure established by the pumping capacity of the surface facilities of the hydrocarbon field as provided for retaining injection operations. However, this specific injection pressure is not related to any injection pressure obtained during the fracturing process application. This specific injection pressure could be measured for any formation through dynamic pressure profiling when fluid injection is performed in a particular well at normal operating conditions.
 Accordingly, the required injection pressure must be available/obtained before performing the fracturing process described herein. The number of fracturing pump cycles may be determined according to, for example, detailed analysis related to formation characteristics and a cost-benefit analysis of the operation. Upon ending the fracturing pumping cycles, the last fracture reopening pressure obtained is compared to the injection pressure previously defined, as represented by decision block 82. If the fracture reopening pressure is above the injection pressure value, then a chemical flushing may be performed, as represented by block 84. Subsequently, several fracturing pumping cycles may again be carried out, as represented by block 86, until the fracture reopening pressure is less than the injection pressure, as represented by decision block 88. If the fracture reopening pressure is less than the injection pressure, the fracturing pumping is stopped and the fracturing is ended, as represented by blocks 90 and 92. If there is difficulty in achieving a fracturing reopening pressure which is less than the injection pressure, additional testing and/or other techniques may be employed, as represented by block 94.
 As discussed above, chemicals may be directed downhole with and/or in addition to the injection stream 60 to facilitate or enhance the fracturing process. If, for example, a limitation in injection rate occurs due to near wellbore restrictions, complementary chemicals (e.g. hydrochloric acid (HCl), mutual solvents, diesel, paraffin or asphalten solvents) may be added to improve the fracturing process and the duration of the fracture. In some applications, the complementary chemicals may be added during the step rate test.
 Referring generally to the flowchart of FIG. 7, one example of the addition of complementary chemicals pumping is illustrated. During an initial step rate test, the injection rate is compared to the injection pressure, as illustrated by block 96. The injection rate is compared to a predetermined value Y, as represented by decision block 98. If the injection rate is above the value Y, then a pre-flush is employed in which a complementary chemical, e.g. HCl, is delivered downhole to the desired well zone/formation layer, as represented by block 100.
 Subsequently, a flush procedure is delivered downhole with an additional, or stronger, complementary chemical, as represented by block 102. The flush procedure may be followed with a displacement fluid procedure, as represented by block 104.
 Referring again to the decision block 98. If the injection rate is below the value Y, then an appropriate tool on coiled tubing may be run in hole, as represented by block 106. The coiled tubing is used to conduct and supplement the pre-flush procedure, as represented by block 100. Subsequently, the flush and displacement procedures may be conducted, as represented by blocks 102, 104.
 The technique of fracturing with selective stream injection may be employed in a variety of wells formed in many types of subterranean regions. The number of formation layers independently treated in fluid injector wells to improve hydrocarbon recovery in producers, as well as the number and type of packers, regulator valves and other components of the injection completion, may be adjusted according to the specific environment and application. Similarly, the injection fluid and any complementary chemicals used to facilitate fracturing may be selected according to the parameters of the specific application and/or environment in which the technique is employed. The procedural stages of the methodology also may be adjusted to accommodate specific parameters of a given application employing the selective stream injection technique. Various candidate well screening techniques also may be employed to determine wells best suited for improved production through selective fracturing.
 Embodiments of the disclosure may also include one or more systems for implementing one or more embodiments of the processes and techniques shown in and described above with reference to FIGS. 1-7. Accordingly, FIG. 8 illustrates a schematic view of such a computer or processor system 800, according to an embodiment. The processor system 800 may include one or more processors 802 of varying core (including multiple cores) configurations and clock frequencies. The one or more processors 802 may be operable to execute instructions, apply logic, etc., for example, to flatten the seismic image 300, identify packages, determine spatially any areas of contamination, compare results, verify results, etc., according to one or more of the embodiments of the method 200 described above. It will be appreciated that these functions may be provided by multiple processors or multiple cores on a single chip operating in parallel and/or communicably linked together.
 The processor system 800 may also include a memory system, which may be or include one or more memory devices and/or computer-readable media 804 of varying physical dimensions, accessibility, storage capacities, etc. such as flash drives, hard drives, disks, random access memory, etc., for storing data, such as images, files, and program instructions for execution by the processor 802. In an embodiment, the computer-readable media 804 may store instructions that, when executed by the processor 802, are configured to cause the processor system 800 to perform operations. For example, execution of such instructions may cause the processor system 800 to implement one or more portions and/or embodiments of the method described above.
 The processor system 800 may also include one or more network interfaces 806. The network interfaces 806 may include any hardware, applications, and/or other software. Accordingly, the network interfaces 106 may include Ethernet adapters, wireless transceivers, PCI interfaces, and/or serial network components, for communicating over wired or wireless media using protocols, such as Ethernet, wireless Ethernet, etc.
 The processor system 800 may further include one or more peripheral interfaces 108, for communication with a display screen, projector, keyboards, mice, touchpads, sensors, other types of input and/or output peripherals, and/or the like. In some implementations, the components of processor system 800 may not be enclosed within a single enclosure or even located in close proximity to one another, but in other implementations, the components and/or others may be provided in a single enclosure.
 The memory device 804 may be physically or logically arranged or configured to store data on one or more storage devices 810. The storage device 810 may include one or more file systems or databases in any suitable format. The storage device 810 may also include one or more software programs 812, which may contain interpretable or executable instructions for performing one or more of the disclosed processes. When requested by the processor 802, one or more of the software programs 812, or a portion thereof, may be loaded from the storage devices 810 to the memory devices 804 for execution by the processor 802.
 Those skilled in the art will appreciate that the above-described componentry is merely one example of a hardware configuration, as the processor system 800 may include any type of hardware components, including any necessary accompanying firmware or software, for performing the disclosed implementations. The processor system 800 may also be implemented in part or in whole by electronic circuit components or processors, such as application-specific integrated circuits (ASICs) or field-programmable gate arrays (FPGAs).
 Although only a few embodiments have been described in detail above, those of ordinary skill in the art will readily appreciate that many modifications are possible without materially departing from the present disclosure. Accordingly, such modifications are intended to be included within the scope of this present disclosure, as defined in the claims.
Patent applications by SCHLUMBERGER TECHNOLOGY CORPORATION
Patent applications in class Fracturing (EPO)
Patent applications in all subclasses Fracturing (EPO)