Method of increasing hydrocarbon recovery from wellbore penetrating dense hydrocarbon formation by hydraulic injection tool that injects thermally controlled fluid

Abstract

A method of increasing hydrocarbon recovery from a wellbore (402) penetrating a dense hydrocarbon formation (410) is disclosed. The method involves inserting a hydraulic jet tool (405) into a wellbore (402); injecting a thermal control fluid toward a wall of the wellbore (402) using the hydraulic injection tool (405) to form a cavity (420) in the wall; a further amount of the thermal control fluid is injected into the wellbore (402) using the hydraulic jet tool (405) such that the pressure in the wellbore (402) is increased, where the increased pressure forms a fracture (411) from the cavity (420), where the fracture (411) is formed by the hydraulic jet tool (405). Injecting the additional amount of the thermal control fluid to cool the dense hydrocarbon formation (410) around the cavity (420) by circulating the thermal control fluid within the cavity (420); withdrawing the hydraulic jet tool (405) from the wellbore (402); and recovering the thermal control fluid and hydrocarbons escaping from fractures (411) of the formation (410).

Description

Background Art

[0001] Hydrocarbon reservoirs having reserves trapped within formations having relatively low permeability (eg, certain tight sandstone, carbonate, and / or shale formations) exhibit little or no production and are therefore not economically desirable to develop at low oil and gas prices.

[0002] Well stimulation is a method often used to increase the net permeability of a formation or reservoir, resulting in increased production from wells that have produced little or no oil. Oil and gas wells in tight reservoirs are stimulated by hydraulic fracturing (also known as fracking), which is the process of injecting a fracking fluid into the wellbore under pressure until the fluid fractures or cracks the rock in the fractures.

[0003] Fracturing is a field practice used to increase production from uneconomic wells and allow for increased hydrocarbon recovery from hydrocarbon formations. The fracturing process may be performed using a completion that isolates a portion of a vertical or horizontal well section, perforates the casing if the well is cased, and then pumps a fracturing fluid to initiate and propagate fractures in one or more lateral extensions that create new or additional flow pathways through which hydrocarbons can more easily move from the formation into the production wellbore.

[0004] Hydraulic fracturing is a method used to stimulate the production of oil and gas wells in low permeability reservoirs. Specially designed fracturing fluids are pumped into the reservoir at high pressure and flow rates, causing vertical fractures to open. The wings of the fractures extend away from the wellbore in opposite directions based on the natural stresses within the formation.

[0005] The fracture pressure is the pressure at which the rock matrix (the finer particles between the larger particles) of the exposed formation fractures and allows injection of the fracturing fluid. The fracture pressure is established before determining reservoir treatment parameters. Hydraulic fracturing is performed above the fracture pressure, while bedrock stimulation treatments are performed at safe treatment pressures below the fracture pressure.

[0006] Deep overpressured tight oil and gas reservoirs have high fracture pressures and very hard rocks, making hydraulic fracturing operations extremely challenging. High fracture pressure is one of the major challenges in reservoirs with high stress states, low permeability, deep and high pressure and high temperature (HPHT) environments. These conditions may leave a small window to break the formation and initiate fractures due to exceeding the pumping limit or completion tubing pressure rating. Failure to break the formation may result in skipping the hydraulic fracturing stage. This will lead to increased operating costs, reduced operating efficiency and hydrocarbon recovery. The industry has proposed several solutions and technologies to reduce the high fracture pressure in tight gas reservoirs. These technologies include cyclic fracturing, low viscosity fracturing fluids, perforating and high pressurization rates. However, high fracture pressure in tight gas reservoirs remains a persistent challenge.

[0007] One approach to addressing this challenge is to cool the formation to reduce the in situ stresses created by the weight of the overlying rock and subsequently reduce the fracture pressure and increase hydraulic fracturing efficiency. However, injecting cooling fluids to cool the temperature of the formation prior to fracturing is not always possible due to limited well injection capacity.

[0008] Therefore, there is a need for a method of increasing hydrocarbon recovery from a wellbore penetrating a tight hydrocarbon formation by injecting a hydraulic jetting tool with a thermal control fluid. Summary of the invention

[0009] This Summary is provided to introduce a selection of concepts that are further described below in the Detailed Description. This Summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.

[0010] In one aspect, embodiments disclosed herein relate to a method for increasing hydrocarbon recovery from a wellbore penetrating a tight hydrocarbon formation, comprising: inserting a hydraulic jetting tool into the wellbore; using the hydraulic jetting tool to jet a thermal control fluid into a wall of the wellbore to form a cavity in the wall; using the hydraulic jetting tool to inject an additional amount of the thermal control fluid into the wellbore so that pressure in the wellbore increases, wherein the increased pressure forms fractures from the cavity, wherein injecting the additional amount of the thermal control fluid cools the tight hydrocarbon formation surrounding the cavity by circulating the thermal control fluid within the cavity; withdrawing the hydraulic jetting tool from the wellbore; and recovering the thermal control fluid and hydrocarbons escaping from the fractures in the formation.

[0011] Other aspects and advantages of the claimed subject matter will become apparent from the following description and appended claims. BRIEF DESCRIPTION OF THE DRAWINGS

[0012] Figure 1 A field example of a phase in which three attempts to fracture the formation failed is shown according to one or more embodiments.

[0013] Figure 2 Another field example is shown of a phase where multiple hours of pressure cycling failed to successfully fracture the formation, according to one or more embodiments.

[0014] Figure 3 A flow chart illustrating method steps for increasing hydrocarbon recovery from a wellbore penetrating a tight hydrocarbon formation by a hydraulic jetting tool that injects a thermal control fluid, according to one or more embodiments.

[0015] Figure 4 A cross-section of a tight hydrocarbon formation with a wellbore drilled into the formation is shown in accordance with one or more embodiments.

[0016] Figure 5 It is shown that the total minimum horizontal stress decreases as the temperature difference increases according to one or more embodiments.

[0017] Figure 6 It is shown that bottom hole pressure decreases significantly as the temperature difference increases according to one or more embodiments.

[0018] Figure 7 A cross-section of a wellbore penetrating a formation is shown, wherein a hydraulic jetting tool penetrates the wellbore, according to one or more embodiments. DETAILED DESCRIPTION

[0019] In the following detailed description of embodiments of the present invention, many specific details are set forth in order to provide a more thorough understanding of the present invention. However, it is apparent to one of ordinary skill in the art that the present disclosure may be practiced without these specific details. In other cases, well-known features are not described in detail to avoid unnecessarily complicating the description.

[0020] Throughout this application, ordinal numbers (e.g., first, second, third, etc.) may be used as adjectives of elements (i.e., any nouns in this application). The use of ordinal numbers does not imply or create any particular order of elements, nor does it limit any element to only a single element, unless explicitly disclosed, such as using the terms "before," "after," "single," and other such terms. Rather, the use of ordinal numbers is to distinguish between elements. As an example, a first element is different from a second element, and a first element may contain more than one element and be after (or before) a second element in the ordering of elements.

[0021] In one aspect, embodiments disclosed herein relate to a method for increasing hydrocarbon recovery from a wellbore penetrating a tight hydrocarbon formation, the method comprising: inserting a hydraulic jetting tool into the wellbore; using the hydraulic jetting tool to jet a thermal control fluid into a wall of the wellbore to form a cavity in the wall; using the hydraulic jetting tool to inject an additional amount of the thermal control fluid into the wellbore so that the pressure in the wellbore increases, and the increased pressure forms fractures in the cavity, wherein injecting the additional amount cools the tight hydrocarbon formation around the cavity by circulating the thermal control fluid in the cavity; withdrawing the hydraulic jetting tool from the wellbore; and recovering the thermal control fluid and hydrocarbons escaping from the fractures in the formation.

[0022] Embodiments of the present disclosure may provide at least one of the following advantages. A hydrojet tool injects a thermal control fluid to punch a cavity in a tight hydrocarbon formation. Immediately after the cavity is punched, a stimulation treatment is performed with the same thermal control fluid to propagate fractures from the punched cavity. Fractures are propagated by simultaneously injecting a proppant-containing mud into the coiled tubing and a clean fluid into the annulus. Formation disruption and stimulation can achieve injection rates that are not possible with conventional fracturing treatments due to poor well injectivity.

[0023] This approach is cost-effective and does not require mechanical isolation, subsequent intervention or lower completions.

[0024] Figure 1 A graph of pressure in psi as a function of treatment time in minutes (min) is shown.When the thermal control fluid is injected into the wellbore, pressure is built up by the hydraulic jetting tool.

[0025] In staged fracturing, many reservoir sections are hydraulically stimulated in succession. In shale gas reservoirs, staged hydraulic fracturing is performed in horizontal wellbores. Geomechanical data is used to optimize the placement of the perforated cavities and fracturing stages to maximize gas production. Pressures are determined for single-stage fracturing in tight gas sandstone reservoirs with high fracture pressures.

[0026] Plot 102 shows treatment pressure as a function of treatment time. Treatment pressure is the pressure used to inject the thermal control fluid into the wellbore to expand the cavity in the fracture.

[0027] Plot 104 shows annular pressure (annular pressure) as a function of treatment time. Annular pressure refers to the annular pressure between the production tubing used to produce reservoir fluids from the wellbore and the production casing set passing through the reservoir section.

[0028] Alternatively, annulus pressure is the pressure in the annulus between two casing strings through which reservoir fluids are produced to the surface.

[0029] Plot 106 shows the calculated bottom hole pressure (BHP) as a function of processing time.

[0030] When the bottom hole pressure (BHP) exceeds the fracture pressure, the fracture propagates. Therefore, the bottom hole pressure is a measure of the fracture pressure of the formation. As the formation cools, the BHP required to fracture the formation decreases. This shows that the cooling of the formation has an effect on the fracture pressure of the formation. The bottom hole pressure is calculated in a static, fluid-filled wellbore as follows:

[0031] BHP = MW * depth * 0.052,

[0032] Where BHP is bottomhole pressure in pounds per square inch (psi), MW is mud weight in pounds per gallon, and depth is true vertical depth in feet. If these units of measurement are used, 0.052 is the conversion factor.

[0033] Plot 108 shows the slurry flow rate in barrels per minute (bbl / min) as a function of treatment time.Slurry is a mixture of suspended solids and liquid.

[0034] The mud flow rate shows that at normal flow rates, the injection capacity is limited. When the wellbore tubing limit is reached, an injection capacity of less than 795 l / min (5 bbl / min) can be achieved for a very limited time. This means that it is not possible to inject at a higher mud flow rate, and therefore it is not possible to break the formation and create fractures.

[0035] from Figure 1 As can be seen from the various plots, for the particular field case described, three attempts to fracture or fracture the formation all failed.

[0036] Figure 2 A second field case is shown of a phase where multiple hours of pressure cycling failed to successfully fracture the formation.

[0037] Lowering the formation temperature and cooling the formation has a significant effect on reducing in situ stress and fracture pressure. This is because the thermoelasticity of the formation material becomes more elastic at lower temperatures.

[0038] This effect in a waterflooded formation (a formation in which water is injected into the reservoir to displace residual oil) is caused by the temperature difference between the injected thermal control fluid and the formation.

[0039] The reduction of in situ stress and fracture pressure utilizes thermal control fluids.

[0040] Tight gas reservoirs can be modeled using box modeling. Box modeling is a type of 3D modeling in which a box is used to create the shape of the tight gas reservoir as the final model. Therefore, box modeling uses many repeated steps. A simulated box model study of a tight gas reservoir showed that the permeability of the tight gas reservoir was 0.0592·10 -15 m 2 (0.06md(millidarcy)), porosity is 6%. The formation temperature is 150℃(300℉), and the minimum horizontal stress gradient is 0.0158MPa / m(0.7psi / ft). In different box model simulations, the formation temperature in the near-wellbore area is reduced to -7℃(20℉), 5℃(40℉) and 15℃(60℉).

[0041] from Figure 2As can be seen from the graph, for the particular field case described, several hours of pressure cycling were not able to fracture or fracture the formation.

[0042] Figure 3 A flow chart illustrating method steps for increasing hydrocarbon recovery from a wellbore penetrating a tight hydrocarbon formation by a hydraulic jetting tool that injects a thermal control fluid, according to one or more embodiments.

[0043] First, in step 302, the hydraulic jet tool is inserted into the wellbore. In some embodiments, a lubricating fluid is injected into the wellbore before the hydraulic jet tool is inserted into the wellbore. In some embodiments, the lubricating fluid has a viscosity in the range of about 0.001Pa·s to 10Pa·s (1 centipoise to 10,000 centipoise). In some embodiments, the lubricating fluid comprises a drilling fluid (mud). In some embodiments, the lubricating fluid also includes an amide-based additive for reducing torque and resistance in a water-based drilling fluid without affecting the stability of the drilling fluid. The lubricating fluid can maintain stability and performance at temperatures up to 400°F (204°C). In addition, the lubricating fluid reduces the friction between the metal body of the hydraulic jet tool and the rock forming the inner wall of the wellbore. The lubricating fluid further reduces friction torque and resistance and improves the lubrication of the water-based drilling fluid.

[0044] In step 304, a thermal control fluid is injected into the wall of the wellbore using a hydraulic jetting tool to form a cavity in the wall. The cavity may be a hole, a new perforation, or a channel created by the thermal control fluid pumped through the jetting tool. This thermal control fluid impacts the formation, forming a cavity. As the cavity is formed, the pressure at the bottom of the cavity increases, eventually inducing fractures.

[0045] Figure 4 A cross section of a tight hydrocarbon formation 410 with a wellbore 402 drilled into the formation 410 is shown. Tight hydrocarbon formation 410 may be located in southern Saudi Arabia, Oman, Algeria, Australia, the south of the United Arab Emirates, or any other part of the world that may present overpressure, deep, very hard rock. An overpressure reservoir refers to a reservoir that is higher than the hydrostatic pore pressure gradient. A deep reservoir typically refers to a reservoir that is more than 3658 meters (12,000 feet) deep. Hard rock is typically a rock that has a Young's modulus greater than about 41368MPa (6.0Mpsi). Tight hydrocarbon formation 410 may present a Young's modulus in the range of about 41368MPa to 68948MPa (6Mpsi to 10Mpsi) and a minimum stress gradient in the range of about 0.0181MPa / m to 0.0317MPa / m (0.8psi / ft to 1.4psi / ft). Tight hydrocarbon formation 410 may be any formation with a high fracture pressure. Tight hydrocarbon formation 410 has a formation maximum horizontal stress 409, which may be in any direction on the xz plane. Figure 4 In FIG. 4 , the maximum horizontal formation stress 409 is directed along the z-axis.

[0046] The wellbore 402 generally enters the tight hydrocarbon formation 410 from the ground 401. The wellbore 402 can be an open hole production well, a cased production well, or any other well generally known in the art. The wellbore 402 includes a vertical portion 403 and a horizontal portion 404, and has a wellbore diameter D. The vertical portion 403 includes a substantially vertical portion, wherein the vertical portion is within 15° of being perpendicular to the ground 401. The horizontal portion 404 includes a substantially horizontal portion, wherein the horizontal portion is within 15° of being perpendicular to the vertical portion 403 of the wellbore 402. The wellbore 402, the vertical portion 403, and the horizontal portion 404 can be formed by any method known in the art. The wellbore diameter D can be the same or different between the vertical portion 403 and the horizontal portion 404.

[0047] One or more directional cavities 420 are formed radially outward in the horizontal portion 404 of the wellbore 402. The directional cavities 420 can be formed substantially perpendicular to the horizontal portion 404 of the wellbore 402. The term "substantially perpendicular" means that the spatial orientation of the two objects deviates from the vertical alignment by less than about 15°. In one embodiment, the directional cavity 420 is substantially parallel to the vertical portion 403 of the wellbore 402. The term "substantially parallel" means that the spatial orientation of the two objects deviates from the parallel alignment by less than about 15°. In other embodiments, the directional cavity 420 is in any direction substantially perpendicular to the horizontal portion 404 of the wellbore 402. The penetration of the directional cavity 420 bypasses the near-wellbore skin. In one embodiment, the directional cavity 420 extends radially outward from the horizontal portion 404 of the wellbore 402 by a distance approximately equal to or greater than 1.5 times the wellbore diameter D; this distance of at least 1.5D of the directional cavity 420 is considered from the start point of the directional cavity 420 at the outer wall of the wellbore 402 and extends into the tight hydrocarbon formation 410. In other embodiments, the directional cavity 420 extends radially outward from the outer radius of the horizontal portion 404 of the wellbore 402 by a distance approximately equal to 0.30 m (1 ft), 0.46 m (1.5 ft), 0.61 m (2 ft), 0.76 m (2.5 ft), or 0.91 m (3 ft).

[0048] In an alternative embodiment, the oriented cavity 420 extends radially outward from the horizontal portion 404 of the wellbore 402 a distance large enough to overcome the near-wellbore skin and stresses. In general, the farther the oriented cavity 420 extends into the tight hydrocarbon formation 410, the more the stress effects from the horizontal portion 404 of the wellbore 402 are reduced. These effects include how the horizontal portion 404 of the wellbore 402 affects the stress state of the near-wellbore region in the formation surrounding the oriented cavity 420 during fracturing. If the oriented cavity 420 extends a distance of three times the diameter of the horizontal portion 404 of the wellbore 402 into the tight hydrocarbon formation 410, the effects from the horizontal portion 404 of the wellbore 402 (including the near-wellbore stress) become negligible. A oriented cavity 420 extending a distance less than three times the diameter of the horizontal portion 404 of the wellbore 402 into the tight hydrocarbon formation 410 can still form a lateral fracture and can still overcome the near-wellbore stress. In one embodiment, near-wellbore stress is overcome when the directional cavity 420 extends from the outer radius of the horizontal portion 404 of the wellbore 402 into the tight hydrocarbon formation 410 by a distance of at least one and a half times the wellbore diameter D. In one embodiment, the directional cavity 420 has any diameter. In another embodiment, the directional cavity 420 has a diameter of at least about 2 inches. The directional cavity 420 can be formed by any method known in the art.

[0049] The thermal control fluid may include a mixture of abrasive material and water and may be at any temperature. In one embodiment, the abrasive material is sand. In one embodiment, the thermal control fluid includes a mixture of an erosive material and water. In one embodiment, the erosive material is sand. In one embodiment, the erosive material is an acid. The acid may be hydrochloric acid, acetic acid, or any other acid with a pH less than 6.5. Typically, the thermal control fluid needs to be compatible with the formation. Any thermal control fluid may be used, including aqueous solutions of potassium chloride liquid or other brines. In some embodiments, the thermal control fluid does not include a tackifier, a viscous component, a proppant, or an adhesive. The thermal control fluid may be introduced into the wellbore 402 by any method known in the art. The thermal control fluid may be directed through a downhole tool 405.

[0050] In one embodiment, the thermal control fluid pressure is increased to about 13.8 MPa (2000 pounds per square inch (psi)) to perform injection in the horizontal portion 404 of the wellbore 402. In one embodiment, the thermal control fluid pressure is approximately in the range of 3.4 MPa (500 psi) to 34.5 MPa (5000 psi), or in the range of 3.4 MPa (500 psi) to 15.5 MPa (2250 psi), or in the range of 6.9 MPa (1000 psi) to 34.5 MPa (5000 psi), or in the range of 6.9 MPa (1000 psi) to 13.8 MPa (2000 psi), or in the range of 13.8 MPa (2000 psi) to 34.5 MPa (5000 psi), or in the range of 10.3 MPa (1500 psi) to 15.5 MPa (2250 psi).

[0051] The thermal control fluid is at a lower temperature than the tight hydrocarbon formation. The jetting does not pulverize and compact the formation and creates a clean and stress-free directional cavity 420. In one embodiment, the debris 421 generated by the jetting is carried away from the interior of the directional cavity 420 through the horizontal portion 404 and exits the vertical portion 403, for example, through the annulus (not shown) between the wellbore 402 and the downhole tool 405.

[0052] After forming one or more directional cavities 420, the hydraulic jetting tool injects the thermal control fluid into the wellbore 402 under initial pressure and introduces it into the directional cavity 420 of the horizontal portion 404 of the wellbore 402. In general, the thermal control fluid used should be compatible with the formation. Any thermal control fluid can be used, including gases (such as N2 and CO2) and liquids (such as aqueous solutions of potassium chloride and other brines or liquid CO2). In some embodiments, the thermal control fluid does not include a tackifier, a viscous component, a proppant or an adhesive. The temperature of the thermal control fluid is selected to be a temperature that will change the temperature of the formation once the thermal control fluid is injected into the tight hydrocarbon formation 410.

[0053] In some embodiments, the temperature of the thermal control fluid is selected relative to the ambient ground temperature and the formation temperature. In one embodiment, the temperature of the dense hydrocarbon formation 410 is higher than the ambient temperature at the ground 401 of the wellbore 402, and the temperature of the thermal control fluid is equal to or lower than the ambient temperature at the ground 401. Therefore, in this embodiment, the thermal control fluid is maintained at a temperature equal to or lower than the ambient temperature of the ground 401 and is injected into the wellbore 402 in the horizontal portion 404 to cool the dense hydrocarbon formation 410 near the wellbore 402. In another embodiment, the temperature of the dense hydrocarbon formation 410 is lower than the ambient temperature at the ground 401 of the wellbore 402, and the temperature of the thermal control fluid is equal to or higher than the ambient temperature of the ground 401. Therefore, in this embodiment, the thermal control fluid is maintained at a temperature equal to or higher than the ambient temperature of the ground 401 and is injected into the wellbore 402 in the horizontal portion 404 to heat the dense hydrocarbon formation 410 near the wellbore 402.

[0054] In yet other embodiments, the temperature of the thermal control fluid is selected based on the temperature of the dense hydrocarbon formation 410. In one embodiment, the temperature of the thermal control fluid is substantially lower than the temperature of the dense hydrocarbon formation 410 to cool the formation. In one embodiment, the temperature of the thermal control fluid is at least about 38°C (100°F) lower than the temperature of the dense hydrocarbon formation 410, or at least about 93°C (200°F) lower, or at least about 150°C (300°F) lower. In another embodiment, the temperature of the thermal control fluid is higher than the temperature of the dense hydrocarbon formation 410 to heat the formation. In one embodiment, the temperature of the thermal control fluid is at least about 100°F higher than the temperature of the dense hydrocarbon formation 410, or at least about 200°F higher, or at least about 300°F higher. In one embodiment, the thermal control fluid includes steam having a temperature higher than the temperature of the dense hydrocarbon formation 410. In some embodiments, the thermal control fluid has a temperature range of about -50°C (-60°F) to 5°C (40°F). In some embodiments, alternating hot and cold thermal control fluids may be injected at alternating intervals to induce a temperature change shock to reduce the fracturing pressure and optionally create fractures.

[0055] One purpose of the thermal control fluid is to cause thermal reduction of in situ stress in the tight hydrocarbon formation 410. In one embodiment, the reduction of stress in the reservoir is achieved by maintaining the thermal control fluid in the horizontal portion 404 of the wellbore 402 for a sufficient period of time to cool or heat the reservoir. In some embodiments, the injection of the thermal control fluid triggers the formation of fractures 411. In some embodiments, low temperature thermal control fluids are used in such applications, resulting in instabilities in the formation about tensile failure, and increased stress intensity at the fracture tip, resulting in fracture growth. Deeper penetration of the thermal control fluid into the reservoir and reservoir exposure time are believed to be factors that cause thermal reduction of in situ stress.

[0056] Modeling and simulation can be performed to determine the requirements of the thermal control fluid injection process. Although not shown, the modeling and simulation can be performed on any suitable computing device with one or more processors, as known in the art. The exposure time required for the thermal control fluid depends on factors such as the volume of the thermal control fluid, the temperature of the thermal control fluid, and the reservoir properties, including rock type, formation composition, thermal and rock physical properties of the rock, in situ stress, and geomechanical and geophysical properties of the formation. Advanced numerical model simulators can take into account the above factors to determine the required exposure time. In one embodiment, the method includes determining by modeling or simulation the amount of time it is necessary to inject the thermal control fluid into the wellbore 402 to change the temperature of the dense hydrocarbon formation 410 closest to the horizontal portion 404 of the wellbore 402, thereby reducing the stress of the dense hydrocarbon formation 410 closest to the horizontal portion 404 of the wellbore 402, and then continuing to inject the thermal control fluid into the wellbore 402 for the amount of time, optionally allowing the thermal control fluid to stand for a period of time, or allowing continuous injection and return by using a return annulus. For example, in some embodiments, concentric coiled tubing can be used for the application of thermal control fluids and their return.

[0057] The volume of thermal control fluid and the amount of time the thermal control fluid must remain in the formation may be based on the reservoir, mechanical and thermal characteristics, etc. A reservoir cooling analysis may be performed to determine the amount of cooling required to reduce reservoir stress.

[0058] The temperature of the thermal control fluid can be changed by any method known in the art. In one embodiment, a cooling system, a heat exchanger or a heater on the ground 401 is used to change the temperature of the thermal control fluid.

[0059] In step 306, an additional amount of thermal control fluid is injected into the wellbore using a hydraulic jetting tool, so that the pressure in the wellbore increases, and the increased pressure generates fractures from the cavity, wherein the injection of the additional amount / volume of fluid cools the tight hydrocarbon formation surrounding the cavity by circulating the thermal control fluid within the cavity. In other words, the thermal control fluid in the annulus is pulled into the fracture, helping to expand the initial cavity formed.

[0060] In step 308, the hydraulic jetting tool is withdrawn from the wellbore. The hydraulic jetting tool is withdrawn in a manner similar to that in which it was inserted into the wellbore (see step 302). In some embodiments, a lubricating fluid is injected into the wellbore before the hydraulic jetting tool is withdrawn from the wellbore, wherein the lubricating fluid includes drilling fluid (mud) to maintain stability and performance at high temperatures and to reduce friction between the metal body portion of the hydraulic jetting tool and the rock forming the inner wall of the wellbore. In one or more embodiments, the lubricating fluid used to insert the hydraulic jetting tool into the wellbore is the same as the lubricating fluid used to withdraw the hydraulic jetting tool from the wellbore.

[0061] Now turn again Figure 4, the penetration of the directional cavity 420 in the tight hydrocarbon formation 410 overcomes the additional near-wellbore stresses and also allows the thermal control fluid to effectively reduce the in-situ stress of the reservoir, resulting in a lower fracture pressure and allowing additional fracturing. In the case where the directional cavity 420 does not penetrate the reservoir and bypasses the area of ​​greater stress near the wellbore, the thermal control fluid will reduce the in-situ stress, but may not be sufficient to overcome the additional stress generated in the near-wellbore area, which may cause the fracture pressure to be still too large compared to the tubular completion limits. During the drilling and completion process, the formation of the near-wellbore skin leads to a new stress state, which may further increase the formation of cracks. The piercing of the near-wellbore skin by the directional cavity solves this problem. The deeper penetration of the cavity 420 is independent of the stress direction and bypasses the near-wellbore skin, which eliminates fracture tortuosity and improves the transportability of the fracture.

[0062] The directional cavity 420 can replicate a "short" vertical well with an appropriate length as disclosed herein. Typically, in the fracturing of a vertical well, longitudinal fractures are more likely to form at lower pressures due to the stress state in the underground region. Fractures typically extend perpendicular to the minimum principal stress in the underground region. Typically, the minimum principal stress is horizontally oriented; therefore, for a vertical wellbore, longitudinal fractures are more likely to form and are formed at lower fracture pressures. Therefore, the directional cavity 420 in the horizontal portion 404 of the wellbore 402 serves as a starting point for fractures 411, which can be longitudinal fractures relative to the directional cavity 420. Fractures 411 extend radially outward from the horizontal portion 404 of the wellbore 402 and the directional cavity 420 perpendicular to the minimum principal stress (x, z) of the underground region. In addition to the stress reduction obtained from the cooling of the reservoir, the deeper penetration of the directional cavity 420 into the tight hydrocarbon formation 410 also synergistically reduces the pressure required to initiate fractures 411.

[0063] The method then contemplates fracturing of the tight hydrocarbon formation 410 and creating fractures 411. During the hydraulic fracturing operation, a thermal control fluid is pumped at a pressure and flow rate sufficient to fracture the reservoir formation and create fractures. Fracturing may be performed by any method generally known in the art. The use of the disclosed directional cavity 420 and the injection of the thermal control fluid reduces the fracture pressure of the formation and results in fracturing the formation at a lower pressure. In one embodiment, the injection of the thermal control fluid initiates the formation of fractures 411, which are further extended by hydraulic fracturing. The fractures 411 may be created in a planar configuration.

[0064] In one embodiment, fracturing is performed while isolating portions of the wellbore 402. In one embodiment, fracturing is performed without isolating portions of the wellbore 402. Any suitable fracturing fluid may be used to perform fracturing, for example, an oil-based or water-based fluid with or without proppants. In one embodiment, the fracturing fluid is the same as the thermal control fluid. In one embodiment, the fracturing fluid is the same as the thermal control fluid. In one embodiment, the fracturing fluid is different from the thermal control fluid. In one embodiment, the fracturing fluid is different from the thermal control fluid.

[0065] Fractures 411 are initiated in tight hydrocarbon formation 410. Directed cavities 420 provide a cavity similar to a weakened wellbore and facilitate the creation of planar hydraulic fracture structures. Deep directional cavities 420, a minimum of 1.5 wellbore diameters, help ensure the formation of lateral fractures.

[0066] The fracture 411 may start along the weakest point in the directional cavity 420 itself. If explosive perforation techniques are used, the cavity 420 may be blocked by debris 421. The explosive perforation technique may form a cone of the directional cavity 420, wherein the directional cavity 420 narrows as it extends from the entrance hole at the horizontal portion 404 of the wellbore 402 to the tip of the directional cavity 420 in the tight hydrocarbon formation 410. The explosive perforation technique may pulverize the formation surrounding the directional cavity 420, and may compact the rock and debris within the directional cavity 420. The pulverized formation surrounding the directional cavity 420 exists in an elevated stress state, so that when hydraulic pressure is applied, fracture face reorientation may occur. In fracture face reorientation, as the hydraulic fracture grows, the fracture no longer confines itself within the fracture plane, but reorients itself along a non-planar geometry. When directional cavity 420 has a reduced stress state due to jetting, fracture face reorientation is less likely to occur because jetting flushes the formation rather than compacting it, does not stress the formation surrounding directional cavity 420 , and jetting removes debris 421 from directional cavity 420 .

[0067] In another embodiment, the fractures 411 are generally generated in the direction of the maximum horizontal formation stress 409 of the tight hydrocarbon formation 410. The tight hydrocarbon formation 410 has a maximum horizontal formation stress 409, which can be in any direction in the xz plane. In one embodiment, the plurality of planar fractures 411 are generated transverse to the horizontal portion 404 of the wellbore 402. In one embodiment, the plurality of planar fractures 411 are generated transverse to the vertical portion 403 of the wellbore 402. In one embodiment, the plurality of planar fractures 411 are generated transverse to the directional cavity 420.

[0068] Once the planar fractures 411 are created, other methods of increasing hydrocarbon recovery can occur. In one embodiment, proppants are introduced into the fractures 411. Any type of proppant may be used, such as sand, glass, or organics.

[0069] In step 310, the thermal control fluid and hydrocarbons escaping from the cracks in the formation are recovered. In some embodiments, the thermal control fluid and hydrocarbons are pumped by a submersible pump. In other embodiments, the thermal control fluid and hydrocarbons flow out of the wellbore by the natural pressure exerted by the formation on the fluid. The hydrocarbons need to be separated from the thermal control fluid. The separation can be performed in a centrifuge. In one or more embodiments, during the process of producing hydrocarbons, more thermal control fluid is injected into the wellbore to maintain the low temperature in the wellbore.

[0070] Those skilled in the art will appreciate that any suitable jetting tool, such as a HydraJet TM Abrasive jet tools can be used to form Figure 3 and Figure 4 Furthermore, the jetting tool may be used with any suitable process, such as the SurgiFrac process (described below). Figure 7 The formation may be perforated using dynamic steering (discussed further in ), such that the jetting tool may be used to inject fluid into the formation to create additional cavities / fractures.

[0071] Figure 5 A simulated graph showing minimum horizontal stress as a function of the temperature difference between the reservoir temperature before and after treatment is shown. The minimum horizontal stress is in psi and the temperature difference is in degrees Fahrenheit. From the graph, it can be seen that the minimum horizontal stress decreases as the temperature difference increases, which means that the colder the well, the lower the horizontal stress in the formation.

[0072] Figure 6 A graph showing the BHP required to initiate a fracture as a function of time is shown. The BHP is in psi and the time is in minutes. As can be seen from the graph, the BHP required to initiate a fracture decreases significantly as the temperature difference increases.

[0073] Figure 7 A cross-section of formation 702 is shown, with wellbore 704 penetrating formation 702.

[0074] To achieve optimal production, the jetting tool propagates a limited number of discrete fractures that are widely separated and well distributed. If too many fractures are propagated, the width and length of each fracture decreases as the number of fractures increases. Fractures are created only where they are needed. Multiple fractures in close proximity to each other improve the initial stimulation response. High-rate, high-volume open-hole fracturing can result in extreme multiple fractures, resulting in most of the treatment fluid being injected into a small area, while the rest of the well section is essentially untreated. This result is desirable when the lateral well has very uniform formation properties and no areas are fractured during drilling.

[0075] In one or more embodiments, the jetting tool uses a dynamic diversion technique. That is, instead of using mechanical seals or chemical blockages, the jetting tool uses the dynamic movement of the fluid itself to divert a large portion of the fluid flow to a specific point in the formation. For the dynamic diversion technique, the carbonate zone is acidified or a proppant-containing mud is used to achieve fracture diversion. A small jetting tool is placed at the end of the treatment string. Coiled tubing can be used to achieve the necessary fracturing rate. Since the process only produces one fracture system at a time, the required pumping rate is not very high. The jetting tool was originally used to form small jet cavities (tunnels) in the formation. The low sand concentration during the jetting stage also allows the jetting tool to perforate the liner or cemented casing.

[0076] A hydraulic jetting tool 706 is inserted into the wellbore 704. The hydraulic jetting tool 706 pumps pressurized thermal control fluid into the wellbore, which impacts the formation from the inside of the well, thereby forming a cavity. The pressure of the thermal control fluid depends on the nature of the formation, design requirements, and limitations of the surface facilities. As the cavity forms, the pressure at the bottom of the cavity increases, eventually initiating a fracture. The thermal control fluid in the annulus is pulled into the fracture 708, helping to extend the fracture.

[0077] The hydrojet tool 706 passes out of the cavity and then moves directly to the stimulation stage. As the cavity forms, the pressure at the bottom of the cavity increases, eventually initiating a fracture. The thermal control fluid moves down the annulus into the fracture, helping the fracture to expand. The stimulation fluid is pumped into the tubing and the annulus at the same time.

[0078] Thermal control fluids are used as stimulation fluids to reduce fracture pressure.

[0079] Cooling of the formation and reduction of the fracture pressure are achieved by the following steps. The first step includes forming a plurality of directional cavities substantially perpendicular to the horizontal portion of the wellbore by jetting. The second step involves injecting a thermal control fluid into the wellbore, wherein the temperature of the thermal control fluid is selected to change the temperature of the dense hydrocarbon formation. The third step involves fracturing the dense hydrocarbon formation by creating a plurality of planar fractures.

[0080] Then, a thermal control fluid is injected for a period of time to further cool the formation, and finally the same thermal control fluid is used to fracture the formation. The injection of thermal control fluid can be done in a wellbore with a cemented metal casing placed and cemented (cased well) or in an uncased well (open hole).

[0081] The hydrojetting tool is compatible with acidizing, chemical injection and proppant fracturing fluid applications. The hydrojetting tool is a highly configurable component that can be customized with shot count and alignment, tool diameter and even directional tooling to accommodate targeted stimulation operations.

[0082] In one or more embodiments, the thermal control fluid is carbon dioxide, CO2. Cold injection of carbon dioxide creates a cold zone around the well. This temperature difference can significantly reduce in situ stress. Thermally induced fractures caused by the injection of cold carbon dioxide may have an adverse effect on caprock and fault activation, which may lead to carbon dioxide leakage. However, due to the higher temperature difference between the injected thermal control fluid and the reservoir temperature, this phenomenon reduces the total minimum horizontal stress by increasing thermal stress.

[0083] Stress represents the internal forces that adjacent particles of a tight hydrocarbon formation exert on each other.

[0084] The total minimum horizontal stress in the formation σ T,min Depends on temperature and pressure and is described by the following relationship:

[0085] σ T,min = σ hmin,i + σ ΔT + σ ΔP (1)

[0086] Among them, σ hmin,i is the initial minimum horizontal stress, σ ΔT is the thermoelastic stress, σ ΔP is the poroelastic stress.

[0087] Thermoelastic stress σ ΔT is related to the effect of temperature on the reservoir stress field, while the poroelastic stress σ ΔP Related to the effect of pore pressure on the reservoir stress field. The thermoelastic stress generated by the injection of a thermal control fluid that is colder than the formation is given by:

[0088]

[0089] Where α is the thermal expansion coefficient of the reservoir rock, E is Young's modulus, ν = Poisson's ratio, β is the shape factor of the cooling zone, i.e. β>0, and ΔT is the new temperature generated by the cooling fluid minus the reservoir temperature.

[0090] The magnitude of thermal stress is proportional to the rock's stiffness, thermal expansion coefficient, and temperature change. The greater the temperature difference, the higher the thermal stress, the lower the total stress, and the lower the required breakdown pressure.

[0091] Although only a few exemplary embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications may be made in the exemplary embodiments without substantially departing from the present invention. Therefore, all such modifications are intended to be included within the scope of the present disclosure defined by the appended claims.

Claims

1. A method of increasing hydrocarbon recovery from a wellbore (402, 704) penetrating a tight hydrocarbon formation (410, 702), comprising: inserting (302) a hydraulic jetting tool (405, 706) into the wellbore (402, 704); Using the hydraulic jetting tool (405, 706), jetting (304) a thermal control fluid onto a wall of the wellbore (402, 704) to create a cavity (420) in the wall; injecting (306) an additional amount of the thermal control fluid into the wellbore (402, 704) using the hydraulic jetting tool (405, 706) such that the pressure in the wellbore (402, 704) increases, wherein the increased pressure creates fractures (411, 708) from the cavity (420), wherein injecting the additional amount of the thermal control fluid cools the tight hydrocarbon formation (410, 702) surrounding the cavity (420) by circulating the thermal control fluid within the cavity (420); withdrawing (308) the hydraulic jetting tool (405, 706) from the wellbore (402, 704); and Thermal control fluids and hydrocarbons escaping from the fractures (411, 708) in the formation (410, 702) are recovered (310).

2. The method according to claim 1, wherein: The thermal control fluid is cooler than the tight hydrocarbon formation (410, 702).

3. The method according to claim 1 or 2, wherein: The thermal control fluid includes air, hydrogen, helium, sulfur hexafluoride, steam or any inert gas.

4. The method according to any one of claims 1 to 3, wherein: The thermal control fluid includes a mixture of abrasive material and water.

5. The method according to claim 4, wherein: The abrasive material includes sand.

6. The method according to any one of claims 1 to 5, wherein: The thermal control fluid includes a mixture of an aggressive material and water.

7. The method according to claim 6, wherein: The corrosive material comprises an acid.

8. The method of claim 7, wherein the acid comprises hydrochloric acid, acetic acid, or any other acid having a pH less than 6.

5.

9. The method according to any one of claims 1 to 8, wherein: The thermal control fluid includes an aqueous solution of potassium chloride.

10. The method according to any one of claims 1 to 9, wherein: The thermal control fluid includes gases such as N2 and CO2.

11. The method according to any one of claims 1 to 10, wherein: The thermal control fluid includes a liquid, such as an aqueous solution of potassium chloride and other brines or liquid CO2.

12. The method according to any one of claims 1 to 11, wherein: The temperature of the thermal control fluid is at least 38°C (100°F) lower than the temperature of the tight hydrocarbon formation (410, 702), or at least 93°C (200°F) lower, or at least 150°C (300°F) lower.

13. The method according to any one of claims 1 to 12, wherein: The temperature of the thermal control fluid ranges from about -50°C (-60°F) to 5°C (40°F).

14. The method according to any one of claims 1 to 13, wherein: The pressure of the thermal control fluid is up to 13.8 MPa (2000 psi).

15. The method according to any one of claims 1 to 13, wherein: The pressure of the thermal control fluid is between 3.4 MPa (500 psi) and 34.5 MPa (5000 psi), or between 3.4 MPa (500 psi) and 15.5 MPa (2250 psi), or between 6.9 MPa (1000 psi) and 34.5 MPa (5000 psi), or between 6.9 MPa (1000 psi) and 13.8 MPa (2000 psi), or between 13.8 MPa (2000 psi) and 34.5 MPa (5000 psi), or between 10.3 MPa (1500 psi) and 15.5 MPa (2250 psi).

16. The method according to any one of claims 1 to 15, wherein: The cavity (420) is formed radially outward in a horizontal portion (404) of the wellbore (402, 704).

17. The method according to any one of claims 1 to 16, wherein: The cavity (420) is formed substantially perpendicular to the horizontal portion (404) of the wellbore (402, 704), wherein substantially perpendicular refers to a deviation of less than 15°.

18. The method according to any one of claims 1 to 17, wherein: The cavity (420) is substantially parallel to the vertical portion (403) of the wellbore (402, 704), wherein substantially parallel refers to a deviation from parallel alignment of less than 15°.

19. The method according to any one of claims 1 to 18, wherein: The thermal control fluid is a proppant-loaded mud injected downward along the oil pipe of the wellbore (402, 704), and a cleaning fluid is simultaneously injected downward along the annulus of the wellbore (402, 704).

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