Field

[0001] The invention relates to processes for extraction of oil, gas and other resources from subsurface formations by hydraulic fracturing.

Background

[0002] Large quantities of extractable hydrocarbons exist in subsurface shale formations and other very low-permeability strata, such as the Monterey Formation in the United States and the Bakken Formation in the United States and Canada. However, extraction of hydrocarbons from certain low- permeability, low porosity strata at commercially useful rates has proven to be a challenge. One method has been to induce large scale massive fractures in the formation through the use of elevated hydraulic pressure acting on a fluid in contact with the rock through a wellbore. However, this is often accompanied by serious environmental consequences such as a large surface“footprint” for the necessary supplies and equipment, as well as relatively high costs. Further, such methods have poor performance in very low-permeability formation in terms of sustainable of hydrocarbon production and rapid rates of fluid flow decline. These financial and other factors have resulted in difficulties in commercial hydrocarbon extraction from shale oil beds, tight sands and other very low permeability strata.

[0003] In their natural state, some fractures may be open to permit fluid flow, but in most cases require stimulation. The majority of natural fractures are almost fully closed or are not yet fully formed fractures. In their closed state, fractures provide little in the way of a pathway for oil, gas or water to flow towards a production well. When closed, fractures do not serve a particularly useful role in the extraction of hydrocarbons or thermal energy. In prior art fracture processes, sometimes referred to as“high rate fracturing” or“multi- stage hydraulic fracturing”, a fracture fluid which usually comprises a granular proppant and a carrying fluid, often of high viscosity (with chemical additives), is injected through a wellbore into the injection well at a high rate, for example in the range of 15-20 or more barrels per minute (bpm), often 25-40 bpm. As well, injection pressures in the range of 15,000 psi may be used to generate a highly fractured network composed essentially of artificially induced fractures. This process tends to generate relatively large, extensive, fractures that propagate outwardly from the wellbore of the injection well, which are essentially all propped with a proppant in order to provide flow paths for extraction of a petroleum resource. These‘conventional fractures’ are typically very large fractures that extend into the far-field area of the formation away from the wellbore. Most conventional processes may fracture a relatively large area but are limited in the overall drainage volume from which the resource is drained following the induced fracturing step. Therefore, such conventional processes tend to extract the oil or other resource by draining the resource initially from a limited region remote from the well followed by progressively more induced fracturing for draining other parts of the formation. Hence, the industry challenges with such fracturing methods are maintaining fracture conductivity / productivity and efforts to increase reservoir stimulation volume to create durable fracture continuity with sufficient hydraulic conductivity.

[0004] In a prior art“slickwater” fracture process, one or more of a group of appropriate polymers is added to the water to reduce its frictional resistance as it moves through small aperture fractures. In typical slickwater fracturing, extremely high injection rates are employed and the goal is to develop fracture length by carrying the fracturing fluid far from the injection point to obtain enhancement in apertures from the shear dilation effect. However, the extremely high rates used, often injecting at the very top capacity of a number of pumping trucks, while it may cause impressive length growth, also results in a very large net pressure increase on the walls of the fracture (net pressure is the difference between the pressure in the fluid in the fracture and the minimum compressive stress seeking to close the fracture). Because rates are so high, this value is large, and this tends to significantly increase the locking force, which keeps the natural fractures on both sides of the induced fracture from opening easily as the result of the stress increase, which increases the frictional resistance to slip (as described above). Because the natural fractures are not opened so much, there is impairment in terms of the injection rate at which the induced pressures can interact with the natural fractures and allow them to slip.

[0005] Methods have been disclosed in the art for generating a

conductivity enhanced natural fracture network with a multi-step process involving a non-slurry solution, followed by slurry injection steps that generate widely-disbursed network of propped fractures progressively propagating away from the wellbore into the reservoir formation. See for example

PCT/CA2015/05118 (Dusseault et ah).

Summary

[0006] The present method is useful for geomechanic pre-conditioning of tight, low permeability formations (<200md or, in some examples, <ioomd) in the near-wellbore area, to improve injectivity of injected fluids and/or productivity of produced fluids (hydrocarbons or geothermal fluids). Optionally, the selected formation has at least some natural fractures and fissures. The method can also be used to improve productivity of fluid by reducing sand co- production in high flow rate conditions. The present method provides versatility: with suitable adaptations, the same methodology can be used in different geological rock types and can induce mechanics that provide several applications for optimization of injection or production conditions.

[0007] The present method generates a localized fracture network in the formation by means of relatively low injection rates, combined with rapid, sequential injection cycles and low proppant volumes and concentrations.

Optionally, in at least some examples, the present method uses only water as the stimulation fluid with no proppant. The method creates a near-well, complex stimulated rock volume (SRV), i.e. fracture network, which enhances the conductivity of natural fractures in the formation or creates a SRV with fractures that are complex in orientations and azimuth.

[0008] The outcomes and objectives of using the present method include: a) In tight formations, to generate a network of multiple, short fractures and creating an induced fracture network around the well (i.e. the SRV near the well). This SRV is created by inducing near-wellbore hydraulic fracture development in multiple directions (azimuth, orientations); i.e. complex fracture network development.

b) In tight formations with a natural fracture/fissure system, to generate conductivity enhanced natural fracture network around the well (i.e. the enhanced stimulated rock volume near the well). This enhanced SRV is created by the stimulation of the near-wellbore natural fracture network.

c) In unconsolidated formations, to generate a network of multiple, short fractures and creating an induced fracture network around the well (i.e. the stimulated rock volume near the well). This SRV is created by inducing near- wellbore hydraulic fracture development in multiple directions (azimuth, orientations); i.e. complex fracture network development. Furthermore this complex SRV also triggers a formation dilation zone in the near-well area with increased permeability and compressibility.

d) Create a near-well stress reduction and formation softening that encourages rock yielding and slippage based on reducing effective stress and inducing shear strains.

e) To use the stimulated rock volume in this manner as a means to enhance the formation capacity for injection and subsequent production of fluids. Hence, the present process is a formation“pre-conditioning” process to allow for improved fluid conductivity with potential impacts on optimizing thermal and non-thermal EOR operations, sand control during high rate fluid production operations, and geothermal renewable energy applications. This pre- conditioning of the formation is to facilitate subsequent improved oil/gas production or geothermal fluids production at wells.

f) During thermal EOR methods for oil production, improve steam injectivity, steam/heat sweep area/conformity, and/or uniform distribution of heat.

g) During large scale formation stimulation/hydraulic fracturing methods, to improve fluid injectivity and fracture propagation distribution. h) During geothermal applications, create a large volume of interconnected rock mass from which heat can be extracted beneficially and to enhance the connectivity of the stimulated zone between adjacent wells to allow unimpeded fluid circulation between the wells.

i) During high rate gas/fluid production in sand formations, to reduce the amount of sand co-production from the near-well area.

j) During hydrocarbon production operations, improved near well drainage area/fluid flow for production of hydrocarbons using examples of the present method.

[0009] In one aspect, the method permits improved‘Process Control’ as follows: i) containment of injected fluids in the targeted formation; ii) allow for improved steam injectivity; iii) allow for controlled fracture propagation distribution; and iv) ensure mechanical and hydraulic integrity of the well.

[00010] The present process can be applied in vertical wells, inclined wells and horizontal wells with a variety of well completions, as shown for example in Figure 1.

[00011] We disclose a method for generating a complex fracture network within a formation in the near-wellbore area, comprising the steps of:

a) selecting a target formation having a well therein and a permeability which is less than or equal to about 200md (milliDarcy); in one example less than about 100 md; and a porosity less than or equal to about 20%;

b) determining the Closure Pressure, Fracture Extension Rate (FER) and Fracture Extension Pressure (FEP) of the target formation; and

c) performing one or more injection cycles, each of which comprises multiple sequential injection stages comprising:

i. a pre-flush water injection stage at approximately the FEP level and/or a selected injection rate (SIR) which is about 5%~40% higher than said FER; ii. a particulate injection stage, comprising injecting a slurry for a maximum of about 90 minutes, the slurry containing proppant particles; and optionally

iii. a post-flush water injection stage, comprising injection of water at about the SIR rate. [00012] In the above steps, the injection stages of step (c) are separated from each other in time by a shut-in period of maximum of approximately 90 minutes or until the pressure in the formation drops to the formation closure pressure of the formation, or up to 30% below the formation closure pressure. In one example, the shut-in period is less than about 60 minutes and in other examples, the shut-in period is less than about 30 minutes.

[00013] We further disclose that said step (c) may be followed by a step (d) comprising further larger-scale fracturing or steam injection of the formation for resource extraction or production. Step (d) may be separated from step (c) by a shut-in period which in some examples is up to approximately 24 hours.

[00014] We disclose that the method may consist of multiple

conditioning/production cycles applied to a formation, each of said

conditioning/production injection cycles, comprising multiple cycles consisting of said steps a-c. In some examples, each of the injection cycles is followed by one or more rounds of said step (d).

[00015] In the present method, the slurry use in step (c) may comprise about 1% to about 8% by volume or by weight of said proppant particles, preferably about 3% to about 6% by volume or by weight of said proppant particles. In certain examples, if the formation has a low or moderate inherent leak off rate, then the slurry may comprises about 3% of said proppant particles, whereas if the formation has a high inherent leak off rate, then the slurry may comprise about 5% of said proppant particles.

[00016] We further disclose that step (b) may comprise performing one or more of the following:

a) a baseline Step Rate Test (SRT) followed by a Pressure Fall-Off Test

(PFOT)

b) a Minifrac Test to determine the closure stress state in the target

formation

c) an Injectivity Test followed by Pressure Fall-Off Test (PFOT). [00017] In another example, a water injection step is performed between steps (b) and (c) to pre-condition the well. The water injection is performed at an injection rate at approximately the FER, and said water injection is then followed by a shut in prior to step (c) of up to about 24 hours of shut in or until initial formation pressure is achieved. Optionally, there may be multiple water injection steps prior to step (c) that use only water as the stimulation fluids with no proppant.

[00018] We further describe a method for generating a complex fracture network within a formation in a near-well area, comprising the steps of:

a) selecting a target formation having a well therein and a permeability which is less than or equal to about 200md (milliDarcy) and a porosity less than or equal to about 20%;

b) determining the Closure Pressure, Fracture Extension Rate (FER) and Fracture Extension Pressure (FEP) of the target formation; and

c) performing multiple, sequential injection stages, each of the stages comprising water injection approximately the FEP level and/or a selected injection rate (SIR) which is about 5%~40% higher than said FER. Each water injection is performed for about 5-45 minutes. The injected water is free of particulates/proppant. In one example, the water injection is performed for about 5-30 minutes or in another example, about 15 minutes.

[00019] The water injection stages are separated in time by a shut-in period of maximum of approximately 60 minutes or until the pressure in the formation drops to the formation closure pressure of the formation, or up to 30% below the formation closure pressure.

[00020] In some examples, step (c) in the above method may comprise use of water that is free of additives, or water with additives that are essentially fluids. Such water injection stages are multiple (2-6 injection stages), typically short (5-30 minutes per stage) and done in rapid succession with intervening shut-in periods of 15-60 minutes. Some variation in these parameters is anticipated depending on rock type, fracture network, permeability, and the stress/pore pressure conditions of the rock. [00021] We further disclose that said step (c) in the above method may be followed by a step (d) comprising further larger-scale fracturing of the formation for resource extraction or production. Step (d) may be separated from step (c) by a shut-in period which in some examples is up to approximately two (2) hours, and in other examples is up to about 24 hours.

[00022] We further describe examples of the present method wherein the target formation is sandstone, an unconsolidated sand formation, or a tight sand formation. In these examples, the method is performed to provide one or more of: enhanced fluid conductivity (remolding, dilation and permeability

enhancement) around the well and across a perforated well interval,

minimization of large pressure drops across perforated interval, reduction of ‘skin’ in the near wellbore area (i.e. mitigation of a high pressure drop around the wellbore, which can lead directly to wellbore stability problems & formation sand production), and achieving uniform proppant placement throughout the injection cycles and can result in re-stressing around the well. In some examples, the proppant size and other injection parameters may depart somewhat from the above examples, depending on toe formation lithology and geomechanic conditions, gas flow rate, well completion, and amount of sand co- production.

[00023] The present method provides versatility: the same methodology can be used in different geological rock types and can induce mechanics that provide several applications for optimization of injection or production conditions.

Definitions

[00024] The terms identified below have the following definitions when used in this disclosure and claims, unless otherwise stated or the context requires otherwise:

[00025] “Near Well”: a distance of typically 0.5 to 30 meters from the wellbore. [00026] Stimulated Rock Volume (SRV): the volume of formation that is affected (both mechanically and the fluid conductivity aspects) by a

stimulation process, such as the present method described herein.

[00027] “Fracture Extension Rate” (FER): minimum injection rate required to induce fracturing or mechanical yielding of a formation.

[00028] “Fracture Extension Pressure” (FEP): minimum injection pressure required to induce fracturing or mechanical yielding of a formation.

[00029] “Fracture Gradient” (FG): rate of change of fracturing pressure “ISIP”: Instantaneous Shut-In Pressure; the pressure in the formation at the instant fluid injection into the formation stops. ISIP can also be used as an estimation of minimum principal stress in the formation.

[00030] “Minimum principal stress”: the inherent stress condition of the formation that must be overcome for a fracture or mechanical yielding of the formation to occur.

[00031] “SRT”: Step Rate Test; a formation test that varies injection rate in a series of increasing‘steps’ of a certain duration over a range of injection rates. The analyses of the SRT data are used to determine the fluid-flow and stress conditions of a formation.

[00032] “Pressure Fall-Off Test (PFOT)”: a formation test that records the declining pressure during a shut-in period of a well after fluid injection operations. The analyses of the PFOT data are used to determine the leak-off properties and fluid-flow conditions of a formation.

[00033] “Skin”: refers to the pressure change (typically pressure drop) that occurs in the near-well area between the well and the formation during production of fluids from the formation.

[00034] “screen out”: the plugging of a fracture or flow path in the formation with proppant/particulates that leads to a sudden a rapid injection pressure increase (with concurrent loss of injectivity). [00035] “Closure Pressure”: determined after a fluid injection event, is the pressure in a formation when a fracture(s) fully closes (seals) during the shut-in period; due to fluid leak-off into the surrounding rock. Closure pressure can be used as an estimation of minimum principal stress in the formation.

Brief Description of the Drawings

[00036] Figure 1 is a schematic cross section of a well extending into a formation for implementing the present method.

[00037] Figure 2 is a graph showing the results of a pressure fall off test (PFOT) performed in a formation as an initial step of the present method.

[00038] Figure 3 is a graph showing injection cycles with sufficient shut-in periods for multiple PFOT’s performed in an example of the present method.

[00039] Figure 4 is a chart shown the results of the multiple SRTs before and after the treatment using the present method; showing the change in geomechanic parameters of the target zone ISIP, Closure Pressure, and FEP.

[00040] Figure 5 is a graph that schematically illustrates implementation of a further example of the present invention.

[00041] Figure 6 is a graph that schematically illustrates implementation of a still further example of the present invention.

[00042] Figure 7 is a schematic diagram of the reduction in the high pressure drop around the wellbore; i. e. the reduction in high‘skin’ around the wellbore.

[00043] Figure 8 is a schematic diagram of the stress change (reduction) that can occur in a formation with injection of water using the Mohr-Coulomb effect.

[00044] Figure 9 is a schematic diagram of the stress change (reduction) that can occur in a formation with multiple injection cycles of water using the stress-softening effect. [00045] Figure 10 is a schematic view of the near-well formation response, following implementation of an example of the present method.

[00046] Figure 11 is a further schematic view of the near-well formation response, following implementation of an example of the present method.

Detailed Description

Target Formations

[00047] The present process can be applied in a variety of formations that are considered tight, i.e. low permeability. The target formation permeability may be generally less than 200 md (milliDarcy) or in some examples less than 100 md, and the porosity is generally less than 20%. Suitable target formations include:

• Tight sands

• Tight shaley sands

• Tight sandy shales

• Tight conglomerates and shaley conglomerates

• Unconsolidated sand formations (soft rock)

[00048] For petroleum recovery applications, such formations are typically (but not always) heavy oil bearing or gas bearing. These formations typically do not have an extensive well-developed natural fracture system, and have low fluid conductivity. Furthermore, in sedimentary rocks, low permeability strata such as tight carbonates, shales and low porosity sandstones are typical candidate rocks. These rocks generally have a system of joints, bedding or schistosity planes, fractures and fissures that have naturally formed, but may be in a largely closed state.

[00049] For geothermal applications, target formations include granites, schists, metasediments and other igneous or metamorphic rock types. Injection Strategy

[00050] Figure 1 schematically depicts an injection well suitable for use with the present method, as well as an example of formation resistivity levels along the well string.

[00051] According to one example, the method includes the following steps:

1. Initially, the well is prepared for stimulation. If the well is a production well, the rod strings and the submersible/downhole pump are retrieved from the well. An injection tubing string (“tubing”) is set at a given depth to allow only for stimulation of the set of perforations in the well (see Figure 1)

2. An initial Formation Testing Program (FTP) is performed at the well. A baseline formation testing program is performed to:

a) Verily if hydraulic fracture communication is established with the target zone.

b) Verily the optimum pre-flush and post-flush stage volumes.

c) Determine the baseline formation fluid-flow parameters (formation

pressure, permeability, leak-off rate) and geomechanics parameters (Closure Pressure, FEP, FER, etc.) to ensure optimum design and performance of the present operations.

d) Determine and SRT value for the well (see Figure 3).

Examples of suitable formation tests are described in more detail below.

3. Shut down the well for up to 24 hrs. Monitor pressure decline response and record the data every 3 seconds during this period.

4. Perform an initial injection cycle (cycle #1). The injection rate (SIR) used for the present cycle will be 5%-40% higher than the FER established from the SRT data. Cycle #1 consists of the following:

• Sand stage #1:

o Pre-flush stage: water injection @ SIR.

Water volume injected is 5-20 m3. ^■ Inject water at a pressure equal to FEP or until the pressure stabilizes at the assumed SIR injection rate. Sand stage: Blend and inject large-grained proppant

(“sand”); to be injected at SIR for up to 90 min @ the SIR. Proppant size can be selected from the following ranges: particle size range which is one of 16-70 mesh, 30-70 mesh, 16-30 mesh or 40-60 mesh, or, in some examples, proppant size is larger than 16 mesh.

^■ Proppant concentration is 1-5% by volume in the injected slurry.

^■ Injection time for this stage can be shortened if a formation screen-out condition occurs. Such a screen- out condition is approximately a sustained injection pressure increase of 0.8 MPa/min or higher, at a relatively constant SIR. This parameter can vary depending on the proppant concentration, and the geological and geomechanical parameters of the formation being stimulated.

^■ Achieving the onset of an in situ screen-out condition permits developing of the necessary stress alteration mechanism in the formation. One should not over- inject the sand past the onset of the screen-out, as this may increase the risk of wellbore plugging with the injected sand. Therefore, in one example, injection of sand should not continue past about 120 seconds (of injection time) once a screen-out condition is noted from the process monitoring data.

^■ If a screen-out condition is confirmed, switch to the post-flush stage as soon as possible (within 120 seconds of this development).

Post-flush stage: water injection at SIR for one wellbore volume. 5. Shut the well in for about 30 minutes to 1.5 hours or until the pressure in the formation drops to the established formation Closure Pressure or up to 30% less than this Closure Pressure.

6. Perform a second injection cycle (cycle #2), which substantially repeats cycle #1. Some modification to the injection strategy can be implemented based on the data recorded from cycle #1. Such modifications can include injection time, volume of fluid injected, injection rate, and proppant concentration.

7. Shut the well in for up to about 1 hour (60 min) or until the pressure in the formation drops to the established formation Closure Pressure or up to 30% less than this Closure Pressure.

8. Perform a third and optionally additional injection cycles, following the same or similar injection procedure as cycle #2. Some modification to the injection strategy can be implemented based on the data recorded from previous cycles. Such modifications can include injection time, volume of fluid injected, injection rate, and proppant concentration.

9. Apply an SRT and shut the well in for about 12-24 hours (see Figure 3), or until initial formation pressure is achieved. Do not perform activities at the well during the shut-in time other than monitoring. According to one example, one may monitor formation response, for example using BHP/WHP gauges, at all times, including between active injection episodes and shut-in periods.

10. Following the shut-in period, collect data from monitoring system, unset the packer and reset it at the given depth for the stimulation of the second set of perforations, as required.

[00052] According to one aspect of the present method, the proppant size is relatively large as compared to at least some prior art processes, for example in a range which is one of 16/70, 40/60 mesh or 30/70 mesh size. In some cases, other mesh sizes may be used depending on the rock type and stimulation objectives. [00053] In other examples, step 4 consists of use of water as the injection fluid which is free of proppant particles, optionally with fluid additives. Such water injection cycles are described above.

Subsequent steps

[00054] After the above steps are performed, the well can be converted to petroleum production, thermal EOR operations, hydraulic fracturing, or geothermal operations, as required.

[00055] In one embodiment, the present process of“preconditioning” the well may be repeated on an alternating basis with an EOR process. For example, the process can be performed at the start of each steam injection cycle during Cyclic Steam Stimulation operations (a Thermal EOR process).

[00056] The present process may be repeated on an alternating basis with a geothermal process to sustain connectivity for the circulation of fluids between wells for the extraction of heat. For example, the process can be conducted when necessary to stimulate the fractures in the geothermal reservoir to allow the unimpeded flow of the heat transfer fluid (water or supercritical CO2) between wells.

Formation Testing Program (FTP)

[00057] The formation tests performed in the above step 2 may include:

• Baseline Step Rate Test (SRT) followed by Pressure Fall -Off Test (PFOT)

• Minifrac Test to determine the closure pressure/stress state in the target formation

• Injectivity Test followed by Pressure Fall-Off Test (PFOT).

o water injection to pre-condition the well for the present stage; o injection rate to be determined from baseline SRT; should be at the FER;

o followed by up to about 24 hours of shut-in (SI) time or until initial formation pressure is achieved.

• Repeat of SRT, followed by up to about 24 hours of SI time or when initial formation pressure is achieved. • Temperature; Oxygen Activation (OA) or Radioactive Tracer (RT) Log: all to determine fluid storage zones in the near-well area.

[00058] The formation testing program and specific testing parameters can be modified depending on the site specific conditions. The tests described may be conducted with water as the injection fluid. The formation test is designed to measure geomechanical parameters, permeability and leak-off properties of the target zone to be preconditioned.

[00059] Formation pressure response data are recorded during injection and shut-down (non-injection periods) with a surface pressure gauge to measure wellhead pressure (WHP) and/or bottom-hole-pressure (BHP) gauges. The pump pressures, WHP and BHP record wellbore pressure conditions during the injection and shut-in period. Raw data from BHP gauge, WHP gauge, pump pressure, rate and volume is collected at a frequency of about 1 second to about 1 minute, for example at a 3 - 5 second frequency.

Step Rate Test fSRT)

[00060] A conventional SRT is performed. In one example, the injection period is followed by a shut-in (i.e. pressure fall-off) which can be up to about 24 hours, for example between 4 and 24 hours. Monitor pressure response during and after the SRT test, and collect raw data every 3 seconds to be used for data analysis. Analyze the hours of shut-in time (PFOT data) using well-test software. From the SRT, the following parameters can be determined:

• Fracture Extension Rate (FER)

• Fracture Extension Pressure (FEP)

• Fracture Gradient (FG)

• Closure Pressure after fracture conditions

• Fracture-enhanced formation permeability (PFOT analyses)

[00061] Figures 2 and 3 are graphs that schematically show pressure fall-off test (PFOT) data from examples of formation tests. These figures show PFOT data for a preliminary test prior to the initial injection, and subsequent PFOT data following repeated cycles of the preliminary“conditioning” cycles as described above.

Injection Strategy Design

[00062] The above injection strategy, including injection rates, pressures and durations, may be modified based on the results of the baseline formation testing program.

[00063] In one example, an‘injection strategy’ includes the integration of:

• Injection rates and pressures;

• Cycle duration (period of time for Injection - Shut-down - Injection stages);

• Pre-flush and Post -flush strategies;

• Proppant fracture treatment/stage size (volume);

• Proppant fracture treatment design parameters (density, rheology, proppant concentration, particle size);

• Process monitoring data collection and analyses during injection operations;

• Minimum data collected should be WHP, Pump Pressure, BHP, pump injection rate, volume, slurry density and rheology.

[00064] A suitable injection strategy for the fracturing steps is relevant for improved well performance, maintaining formation injectivity, optimizing the stimulated rock volume, and maximizing post-treatment fluid productivity.

[00065] The final design of the startup injection strategy for the well can be based at least in part on the results of the formation testing program, as described above, to determine the following essential parameters:

• Maximum /minimum injection pressure and injection rate range;

• Pressure limit to prevent fracturing the overlying caprock or underlying geological seal.

• Injection slurry characteristics (density range, concentration of proppant, etc).

• Duration of injection and shut-in stages. [00066] Based on the above parameters, a suitable injection strategy procedure and injection cycle schedule can be determined. The injection procedures and schedule in Steps 4-8 of the Injection Strategy can be modified based on the above parameters in order to optimize the development of the near- well stimulated rock volume. Process monitoring data can be collected and analyzed during process to allow the injection procedures to be optimized over time. Using this monitoring data, the above injection strategy can be reviewed and updated during the course of the process.

Present Method Applications

[00067] The present method uses in situ mechanisms for complex fracture generation that include stress alterations and kinematic mechanics in the near- well area to induce: natural fracture/fissure conductivity enhancement, localized stress alterations, fracture rotations, fracture dilation, shear displacement, formation dilation, and block rotations. These mechanics may occur individually or in some combination, depending on the rock type and injection strategy used as described above. These mechanics create a complex fracture network around the well which results in limited-extent development of an SRV of multiple short fractures and/or formation yielding.

[00068] Figures 5, 6, 8, 9 and 11 provide schematic illustrations of the injection strategy described above for pre-conditioning a formation prior to a subsequent EOR application (Figure 5) or a large-scale formation fracturing (Figure 6) and resource extraction. Under such an application(s), the following factors apply to the present process:

• The slurry injected can optionally incorporate oil production enhancing chemicals to further enhance/improve the subsequent hydrocarbon production during a EOR process.

• The formation can be a tight formation with or without a natural system of fractures/fissures. In the case of unconsolidated sand formations, the above process can be modified to include an initial“preconditioning” step of injecting water or water with a very low concentration of proppant on the order of 1-3% by volume in the injected fluid [00069] In one example, a complete cycle consists of 3 water stages of 10 m3 to precondition the formation and enhance injectivity, followed by two larger hydraulic fracturing stages to enhance injectivity of the formation. The larger stages are in turn divided into two parts to provide rotation to the fracture events, in which sand and water injection stages are alternated. The above 3 + 2 cycle is in turn repeated 3 times in the well, with SRT tests performed between cycles.

[00070] The combination of short and long cycles is particularly suitable for tight formations, wherein the short cycles create a near well“softening” of the formation and stress reduction effect, leading to complex fracture network development in the near-field around the well. Figures 8 and 9 schematically illustrate the mechanisms that induce formation softening response to the present method. Figures 6 and 11 schematically illustrate the above example.

[00071] Figures 5 and 10 provide schematic illustrations of the injection strategy described above for pre-conditioning of an unconsolidated sand formation. In this example, the method can be used to stabilize the formation that is undergoing an aggressive production strategy (for example, gas production) that can trigger disruption of fabric, and a weakened zone due to a high‘skin effect’ (i.e. high pressure drop around the wellbore), that causes strains and kinematics that reduce formation cohesion. Such conditions can trigger sand production with the produced hydrocarbon (typically gas), which can be problematic. Under such an application, the following factors apply to the present process:

• Lower injection rates and pressures - injection stage at approximately or about 10-20% above the FEP level and/or a selected injection rate (SIR) which is about 5%-75% higher than said FER.

• Lower water volumes, low injection rate, multiple-rapid injection cycles- each injected stage approximately 1-50 m3 of fluid, injection stage duration of 0.25- 1 hour.

• higher proppant volumes/concentrations and larger proppant size - proppant concentration of approximately 5-10% v/v or wt/wt, with sizes of approximately 40/60 to 30/70 mesh size. • Formation yielding with fluid conductivity enhancement (remolding, dilation and permeability enhancement) around the well and across the interval.

• Minimize large pressure drops across perforated interval.

• Reduce‘skin’ in the near wellbore area (i.e. mitigate high pressure drop around the wellbore which can lead directly to wellbore stability problems & formation sand production). Figure 7 schematically illustrates the mechanism of skin reduction around a wellbore.

• Low viscosity, high leak-off injected fluid (water) pumped at low rates achieves uniform proppant placement throughout the injection cycles and can result in re-stressing around the well.

[00072] Such parameters above may be varied in this method, depending on lithology and geomechanic conditions of formation, fluid/gas flow rate, well completion, and amount of sand co-production.

[00073] Based on these characteristics the present method can be used as an optimized sand control process with the following advantages over conventional wellbore sand control systems:

1. Simultaneous skin reduction in the near wellbore area (by‘shifting’ the pressure drop away from the well); and restressing of the formation in the near- well area to mitigate against adverse sand production mechanics.

2. Maintenance of a high gas flow-rate and optimum formation conductivity in the near-well area due to the formation yielding effect.

3. Simplified well (re)completion & stimulation process; screens & liners, and well packing are typically not required with the present method. The treatment process can be short-term (eg about 24 hours) and can typically be used with the existing well completion.

[00074] Figure 10 schematically shows formations 10 in which a well 20 is used to perform injection cycles according to the present method. The resulting formation includes a zone 22 of course sand emplacement, having a complex network with multiple fractures. The resulting formation 10 is also characterized by a zone 24 characterized by dilated and yielded formation and stress changes. Zones 22 and 24 are both generally centered around well 20. [00075] According to some examples, the slurry injection stages are performed with a slurry having a particulates concentration which is selected from the following ranges: 1-20%, 1-10%, 1-8%, 3-6%. In other examples, the particulate size in the slurry is selected from the following ranges: 16-70 mesh, 30-70 mesh, or 40-60 mesh.

[00076] While this invention has been particularly shown and described with reference to exemplary embodiments, it will be understood by those skilled in the art that various changes in form and detail may be made therein without departing from the spirit and scope of the invention. The inventors expect skilled artisans to employ such variations as appropriate, and the inventors intend the invention to be practiced otherwise than as specifically described herein. Moreover, any combination of the above-described elements in all possible variations thereof is encompassed by the invention unless otherwise indicated herein or otherwise clearly contradicted by context.