A new method for improving fracture conductivity in carbonate reservoirs

Abstract

The invention discloses a new method for improving the conductivity of fractures in carbonate reservoirs, and the specific steps include: S1: determining the mineral components of the reservoir; S2: preliminarily selecting theoretical chemicals that can strengthen the fracture surface rock; S3: screening the theoretical chemicals determined by S2 with the goal of improving the strength of the fracture surface rock; S4: screening the chemicals determined by S3 with the goal of damaging the fracture surface rock with low permeability; S5: selecting the chemicals determined by S4 with the goal of quickly strengthening the fracture surface rock after the chemical agent is injected into the fracture; S6: finally selecting the chemicals determined by S5 with the goal of achieving the highest fracture conductivity under reservoir conditions; S7: the on-site application process is to first inject fracturing fluid or acid, and then inject the chemicals determined by S6. The invention has a novel idea for improving the conductivity of fractures in carbonate reservoirs, a simple application process, and a significant improvement in fracture conductivity.

Description

Technical Field

[0001] The invention relates to an oil and gas field fracturing or acid fracturing production increasing technology, in particular to a new method for improving the conductivity of fractures in carbonate reservoir production increasing transformation, belonging to the field of oil and gas field production increasing transformation. Background Art

[0002] The plans of the state and central oil enterprises clearly point out that deep and ultra-deep carbonate oil and gas reservoirs are the focus of future oil and gas exploration and development. However, deep and ultra-deep layers bring high temperatures, ultra-high temperatures and ultra-high closure stresses. Under high and ultra-high temperatures, rocks are prone to plastic deformation, which causes the proppant in the cracks to embed into the crack wall rock or the number of contact points on the acid-etched crack surface to increase, leading to crack closure, which is manifested as reduced fracture conductivity, increased resistance to oil and gas flowing from the reservoir to the wellbore, and reduced oil and gas well production. Ultra-high closure stress will aggravate crack closure. In addition, due to differences in rock mineral components, some carbonate oil and gas reservoirs have softer rocks and are prone to creep. Softer rocks will further amplify the crack closure effect.

[0003] There are currently two main ways to deal with the problem of reduced fracture conductivity. The first is to form stronger non-uniform etching on the fracture surface, such as forming deeper etching grooves, that is, using multiple liquids (acids) for multi-stage alternating injection; the second is to first etch with acid and then support the fracture with proppants. Although these two methods can improve the fracture conductivity to a certain extent, the degree of improvement is extremely limited in high closure stress and soft rocks, and the on-site construction operation is complicated, and the success rate needs to be further improved. Therefore, abandoning the above two ideas for improving fracture conductivity, a new method for improving fracture conductivity in carbonate reservoir production enhancement is proposed. Summary of the invention

[0004] The purpose of the present invention is to address the above-mentioned shortcomings, adopt the idea of ​​chemically strengthening fracture surface rocks, and propose a new method for improving the fracture conductivity of carbonate reservoirs by increasing production and reforming the fractures. The specific technical scheme is as follows.

[0005] Step S1: Determine the mineral composition of the reservoir. Take a core from the target layer downhole, and use an X-ray diffractometer and a scanning electron microscope + energy dispersive spectrometer to determine the specific mineral composition of the carbonate core.

[0006] Step S2: Preliminary selection of theoretical chemical agents that can strengthen the fracture surface rock. There are two ways to determine the theoretical chemical agents. The first is to determine a series of theoretical chemical agents based on the idea of ​​generating new chemical bonds between rock particles and combining the main minerals determined in step S1; the second is to determine a series of theoretical chemical agents based on the idea of ​​replacing the main minerals determined in step S1 with minerals with a larger Mohs hardness value through chemical reactions.

[0007] Step S3: Screen the theoretical chemical agent determined in step S2 with the goal of improving the rock strength of the fracture surface. With the reservoir temperature and pressure as the upper limit, the rock sample is completely immersed in the theoretical chemical agent determined in step S2, and a series of experiments are carried out to improve the rock strength of the fracture surface using the theoretical chemical agent determined in step S2 under a series of temperatures, pressures and immersion times. The strength of the rock sample before and after the experiment is tested by non-destructive testing technology (such as a rock ultrasonic pulse detector, a scratch or indentation tester), and several chemical agents that improve the strength of the rock sample are selected by comparison.

[0008] Step S4: The chemical agent determined in step S3 is screened with the goal of reducing the permeability of the rock on the fracture surface. The treatment of the rock sample is exactly the same as step S3, except that the chemical agent determined in step S3 is used, and the rock sample gas permeability tester is used to test the permeability of the rock sample before and after the experiment, and several chemical agents with lower damage to the permeability of the rock sample are selected by comparison.

[0009] Step S5: The chemical agent determined in step S4 is selected with the goal of quickly strengthening the fracture surface rock after the chemical agent is injected into the fracture. During actual fracturing or acid fracturing, when the injection into the fracture is stopped, the net pressure in the fracture will gradually drop to 0. When the net pressure in the fracture is equal to 0, it means that the two fracture surfaces begin to contact for acid fracturing, and it means that the proppant begins to support the fracture wall for fracturing. Therefore, from the time when the injection is stopped to the time when the net pressure in the fracture drops to 0, several chemical agents that can strengthen the fracture surface rock within this period of time are selected from the chemical agents determined in step S4. The length of this period of time is related to factors such as the physical properties of the reservoir matrix, the degree of development of natural fractures and fracture holes, and the volume of reservoir transformation, and ranges from tens of minutes to several hours.

[0010] Step S6: The chemical agent determined in step S5 is finally selected with the goal of the highest fracture conductivity under reservoir conditions. A fracture conductivity test experiment under reservoir conditions (temperature, closure stress) is carried out using a high-temperature and high-pressure fracture conductivity test device. Fracturing experiment group: inject the chemical agent determined in step S5 → lay proppant → test fracture conductivity; fracturing comparison group: lay proppant → test fracture conductivity; acid fracturing experiment group: inject acid to etch fractures → inject the chemical agent determined in step S5 → test fracture conductivity; acid fracturing comparison group: inject acid to etch fractures → test fracture conductivity. A chemical agent is finally selected with the goal of the highest fracture conductivity.

[0011] Step S7: The field application process for improving the fracture conductivity of carbonate reservoirs by using the chemical agent determined in step S6 is to first inject one or more fracturing fluids or acid fluids or inject them alternately in multiple stages, then inject the chemical agent determined in step S6, then inject proppant or no proppant, and finally inject displacement fluid.

[0012] The present invention discloses a new method for improving the conductivity of fractures in carbonate reservoirs.Figure 1 shown.

[0013] The inventors found that the existing patent CN110809662B for improving fracture conductivity belongs to the first method of forming stronger non-uniform etching on the fracture surface mentioned in the background technology of the present invention, while patents CN111140226B, CN111852433B, and CN115701479A belong to the second method of acid etching and proppant supporting fractures mentioned in the background technology of the present invention. Compared with the existing patents, the main differences of the present invention are: although the ultimate purpose is the same, the principles and methods of implementation are different. The present invention fundamentally solves the problem of reduced fracture conductivity caused by rock deformation, and can greatly improve the fracture conductivity under soft rock formations or high closure stress.

[0014] The benefits of the present invention are: the idea of ​​improving the conductivity of fractures is novel, the application process is simple, and the fracture conductivity is significantly improved. Other advantages, objectives and features of the present invention will be partially reflected in the following description, and partly will be understood by those skilled in the art through research and practice of the present invention. BRIEF DESCRIPTION OF THE DRAWINGS

[0015] Figure 1 The present invention is a flow chart of a new method for improving fracture conductivity in carbonate reservoirs for increasing production. DETAILED DESCRIPTION

[0016] The preferred embodiments of the present invention are described below. It should be understood that the preferred embodiments described herein are only used to illustrate and explain the present invention, and are not used to limit the present invention.

[0017] Taking a carbonate oil and gas reservoir in the Tarim Basin as an example, a new method for improving the fracture conductivity of carbonate reservoirs by increasing production and reforming the fractures is proposed. The specific technical solution is as follows.

[0018] Step S1: Determine the mineral composition of the reservoir. The core obtained from 8049 m underground was determined to have a specific mineral composition of 0.9% clay, 3.2% quartz, and 95.9% calcite using an X-ray diffractometer and a scanning electron microscope + energy dispersive spectrometer.

[0019] Step S2: Preliminary selection of theoretical chemical agents that can strengthen the fracture surface rock. Based on the idea of ​​generating new chemical bonds between rock particles, combined with the calcite determined in step S1, a series of theoretical chemical agents are determined to be tetraethyl orthosilicate, diammonium hydrogen phosphate, and nano calcium hydroxide, etc.; based on the idea of ​​replacing the calcite (Mohs hardness of 3) determined in step S1 with a mineral with a larger Mohs hardness value through chemical reaction, a series of theoretical chemical agents are determined to be zinc sulfate, sodium fluoride, and zinc chloride, etc.

[0020] Step S3: Screen the theoretical chemical agent determined in step S2 with the goal of improving the rock strength of the fracture surface. The reservoir temperature is 172°C and the pressure is 82MPa. The rock sample is completely immersed in the theoretical chemical agent determined in step S2 using a high-temperature and high-pressure reactor. Experiments are carried out to improve the rock strength of the fracture surface using the theoretical chemical agent determined in step S2 under a series of temperatures (100, 135, 172°C), pressures (10, 45, 82MPa) and immersion times (1, 6, 12, 24, 48h). The strength of the rock sample before and after the experiment is tested by a rock ultrasonic pulse detector. Tetraethyl orthosilicate, diammonium hydrogen phosphate, nano calcium hydroxide, zinc sulfate and sodium fluoride increase the rock sample strength by an average of 15.8%, 59.6%, 13.6%, 17.2% and 4.3%, respectively. Zinc chloride reduces the rock sample strength by an average of 7.1%. Therefore, tetraethyl orthosilicate, diammonium hydrogen phosphate, nano calcium hydroxide and zinc sulfate are selected with the goal of improving the rock strength of the fracture surface.

[0021] Step S4: The chemical agent determined in step S3 is selected with the goal of lowering the permeability of the rock on the fracture surface. The treatment of the rock sample is exactly the same as step S3, except that the chemical agent determined in step S3 is used. The rock sample gas permeability tester is used to test the permeability of the rock sample before and after the experiment. Tetraethyl orthosilicate, diammonium hydrogen phosphate, nano calcium hydroxide, and zinc sulfate reduce the permeability of the rock sample by an average of 44.6%, 54.2%, 47.3%, and 82.1%, respectively. Therefore, tetraethyl orthosilicate, diammonium hydrogen phosphate, and nano calcium hydroxide are preferably selected with the goal of lowering the permeability of the rock on the fracture surface.

[0022] Step S5: The chemical agent determined in step S4 is selected with the goal of quickly strengthening the fracture surface rock after the chemical agent is injected into the fracture. Since the reservoir is relatively low-permeability and dense, the brittleness index is low, and natural fractures are not developed, it is difficult to form a complex fracture network by acid fracturing, the transformation volume is small, and the pressure in the fracture diffuses slowly after acid fracturing. The on-site acid fracturing results show that the time from stopping the injection to the time when the net pressure in the fracture drops to 0 is as long as 6.2 hours. Combined with the experimental results of different immersion times carried out in step S4, tetraethyl orthosilicate and diammonium hydrogen phosphate are selected.

[0023] Step S6: The chemical agent determined in step S5 is finally selected with the highest fracture conductivity under reservoir conditions as the target. The target reservoir is subjected to acid fracturing, and a high-temperature and high-pressure fracture conductivity test device is used to conduct fracture conductivity test experiments at a reservoir temperature of 172°C and a closure stress of 68MPa. The acid fracturing test group: inject acid to etch the fracture → inject the chemical agent determined in step S5 → test the fracture conductivity; the acid fracturing comparison group: inject acid to etch the fracture → test the fracture conductivity. The fracture conductivity of the acid fracturing comparison group is 10.4μm 2 ·cm, the fracture conductivity of the acid fracturing test group using tetraethyl orthosilicate and diammonium hydrogen phosphate was 34.6 and 53.7 μm respectively. 2·cm, and finally selected diammonium hydrogen phosphate with the goal of maximizing fracture conductivity.

[0024] Step S7: The field application process of improving the conductivity of carbonate reservoir fractures by using the chemical agent determined in step S6 is to first inject a fracturing fluid to create fractures, then inject an acid solution to etch the fractures, then inject diammonium hydrogen phosphate, and finally inject a displacement fluid.

[0025] The above description is only a preferred embodiment of the present invention and does not limit the present invention in any form. Although the present invention has been disclosed as a preferred embodiment as above, it is not used to limit the present invention. Any technician familiar with this profession can make some changes or modify the technical contents disclosed above into equivalent embodiments without departing from the scope of the technical solution of the present invention. However, any simple modification, equivalent change and modification made to the above embodiments according to the technical essence of the present invention without departing from the content of the technical solution of the present invention still fall within the scope of the technical solution of the present invention.

Claims

1. A new method for improving the conductivity of fractures in carbonate reservoirs, characterized in that: The following steps are involved: S1: Determine the reservoir mineral composition; S2: Preliminary selection of theoretical chemical agents that can strengthen fracture surface rocks; S3: Screening the theoretical chemical agents determined in step S2 with the goal of improving the rock strength of the fracture surface with chemical agents; S4: screening the chemical agent determined in step S3 with the goal of lowering the permeability of the rock on the fracture surface damaged by the chemical agent; S5: The chemical agent determined in step S4 is selected with the goal of rapidly strengthening the fracture surface rock after the chemical agent is injected into the fracture; S6: finally selecting the chemical agent determined in step S5 with the goal of improving fracture conductivity with the chemical agent to the maximum under reservoir conditions; S7: The field application process of improving the fracture conductivity of carbonate reservoirs by using the chemical agent determined in step S6 is to first inject one or more fracturing fluids or acid fluids or inject them alternately in multiple stages, then inject the chemical agent determined in step S6, then inject proppant or not inject proppant, and finally inject displacement fluid; Among them, the step of preliminary selection of theoretical chemicals that can strengthen the rock on the fracture surface described in S2 includes: determining a series of theoretical chemicals based on the idea of ​​generating new chemical bonds between rock particles and combining the main minerals determined in step S1; or determining a series of theoretical chemicals based on the idea of ​​replacing the main minerals determined in step S1 with minerals with a larger Mohs hardness value through chemical reactions.

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