A method for in-situ modification and plugging of coal fly ash oil reservoirs

Abstract

This invention belongs to the technical field of large-channel or dominant channel treatment and plugging in water-driven oil reservoirs, specifically involving an in-situ modification and plugging method within fly ash reservoirs. The method includes: mixing a modified working fluid and fly ash; pumping the resulting mixture into a sand-filled pipe at a constant rate; and then allowing it to stand at reservoir temperature, resulting in modified fly ash and simultaneous plugging. This invention transfers the fly ash modification treatment from the surface to the reservoir pores, achieving the same modification effect as surface modification while simplifying the process, avoiding investment in surface treatment equipment, and saving on waste liquid treatment costs. Furthermore, the waste liquid contains alkali and polymer solutions, forming an "alkali / polymer" binary system, which helps improve oil displacement efficiency. Therefore, the in-situ modification treatment and combined plugging effect within fly ash reservoirs can effectively expand the swept volume and improve oil displacement efficiency, significantly increasing oil recovery.

Description

Technical Field

[0001] This invention belongs to the field of treatment and sealing technology for large pores or dominant channels in water-driven oil reservoirs, specifically involving an in-situ modification and sealing method in fly ash oil reservoirs. Background Technology

[0002] Currently, most water-drive oil reservoirs in China have entered the "high water cut, high production" development stage, primarily due to inefficient water injection and ineffective circulation, resulting in poor water drive sweep efficiency. Analysis suggests that most domestic oil reservoirs are continental sedimentary reservoirs with significant heterogeneity. During water drive development, high-permeability areas of the reservoir experience high fluid uptake and high sweep efficiency, leading to increased aqueous phase permeability and reduced seepage resistance, further increasing fluid uptake and aqueous phase permeability. Furthermore, the high-intensity water scouring during water drive causes rock structure damage, increasing the absolute value of permeability in high-permeability areas. Therefore, the enhanced fluid uptake capacity of high-permeability areas, forming dominant channels (increased aqueous phase permeability and absolute permeability), is the main cause of inefficient water drive development and ineffective circulation. Taking the Bohai Oilfield, China's largest crude oil producer, as an example, its reservoirs are characterized by strong heterogeneity, high average permeability, high crude oil viscosity, high produced water salinity, and low rock cementation strength.

[0003] Faced with the current development status of "high-permeability" to "extremely high-permeability" reservoirs, petroleum scientists mainly adopt profile control (injecting plugging agents from water wells into high-permeability parts of the reservoir) and water shut-off (injecting plugging agents from oil wells into high-permeability parts of the reservoir) measures to reduce the permeability of high-permeability parts of the reservoir, thereby inhibiting crossflow and reducing inefficient and ineffective circulation. Currently, commonly used profile control and water shut-off fluids in oilfields both domestically and internationally mainly include polymer solutions, polymer gels, inorganic gels, and particulates (polymer microspheres, inorganic micro / nano and nanoparticles, etc.). Among these, the plugging performance of polymer solutions and polymer gels is closely related to factors such as the salinity of injected water, shear force, and reservoir temperature, greatly affecting their application range and plugging effect. Furthermore, during the development stage of "high-permeability" to "extremely high-permeability" reservoirs, operating costs surge, economic benefits deteriorate, and the prolonged low international oil prices place enormous pressure on enterprises to "reduce costs and increase efficiency." Therefore, adopting efficient and inexpensive profile control and water shut-off fluids has become a continuous research goal for petroleum scientists.

[0004] Fly ash is a waste product from coal-fired power plants (with particle sizes in the micro-nano range). It has the advantages of wide availability, low price, excellent sealing performance, and simple construction process. In China, oilfields such as Jianghan (Journal of Jianghan Petroleum Institute, 2004, 26(01): 108-109+146), Zhongyuan (Oil and Gas Recovery Technology, 1995, 2(02): 33-41), and Bohai (Offshore Oil, 2010, 3(03): 47-52) have used fly ash for profile control operations. Among them, wells J01, J17H, and J20H in the Bohai SZ36-1 oilfield increased oil production by 19,597 m³ after profile control. 3Rainfall exceeding 2×10 4 m 3 The "output / input" ratio is greater than 8, indicating significant economic benefits. Further research revealed that fly ash particles are spherical in shape, resulting in poor retention within large reservoir pores (spherical particles have better flowability), which weakens the sealing effect of fly ash to some extent. Therefore, petroleum scientists have modified fly ash under surface container conditions, significantly improving its retention within reservoir pores and thus its "resistance enhancement and permeability reduction" effect (Patent: ZL200410062271.6). However, the surface modification process for fly ash is relatively complex, with high equipment investment and processing costs. Summary of the Invention

[0005] In view of this, the present invention provides an in-situ modification and plugging method for fly ash in oil reservoirs. The method provided by the present invention can realize the in-situ modification of fly ash in oil reservoirs, realize the resource utilization of fly ash, and at the same time, the modified fly ash has a good plugging effect.

[0006] To address the above problems, the present invention provides the following technical solution: This invention provides an in-situ modification and plugging method for fly ash reservoirs, comprising the following steps: The modified working fluid and fly ash are mixed, and the resulting mixture is pumped into the sand-filling pipe at a constant rate. Then, it is allowed to stand under reservoir temperature conditions to obtain modified fly ash and achieve sealing at the same time. The sand-filling pipe is used to simulate the reservoir layer. The modified working fluid is a mixture of alkali, polymer and water.

[0007] Preferably, the polymer is partially hydrolyzed polyacrylamide; the alkali is NaOH; and the water in the modified working fluid is oilfield production injection water.

[0008] Preferably, the mass concentration of alkali in the modified working solution is 1.2% to 12.0%; and the mass concentration of polymer is 100 mg / L to 5000 mg / L.

[0009] Preferably, the reservoir temperature is 60~75℃; the settling time is 30~50 min.

[0010] Preferably, the amount of the mixture is 1 to 1.3 times the pore volume of the sand-filled pipe.

[0011] The present invention also provides modified fly ash obtained by the in-situ modification and plugging method for fly ash reservoirs described in the above technical solution.

[0012] The present invention also provides a combined plugging method, comprising using modified working fluid and fly ash as the main agents for large-segment plugging, and using epoxy resin-polymer as the sealing agent for small-segment plugging; The epoxy resin-polymer is obtained by mixing an epoxy resin mixture and a polymer solution; The epoxy resin mixture includes epoxy resin, softener, and curing agent.

[0013] Preferably, the softener is dibutyl phthalate; the curing agent is one or more of ethylenediamine, diethylenetriamine, phthalic anhydride and maleic anhydride; and the ratio of epoxy resin, softener and curing agent in the epoxy resin mixture is 100g:20mL:20mL.

[0014] Preferably, the concentration of the polymer solution is 1000~5000 mg / L.

[0015] Preferably, the volume ratio of the polymer solution and the epoxy resin mixture in the epoxy resin-polymer is 10:0.8~1.5.

[0016] Compared with the prior art, the present invention has the following advantages: (1) The fly ash particles, waste from coal-fired power plants, are spherical in appearance. Their retention in the reservoir pores has a poor effect on "increasing resistance and reducing permeability," which weakens the sealing effect of fly ash to a certain extent. The existing modification treatment methods for fly ash are completed in a surface container. Not only is the modification process relatively complex and the treatment cost high, but the waste liquid generated by the modification treatment also has a complex composition and cannot be directly discharged into the surface environment, resulting in high costs for harmless treatment. This invention transfers the fly ash modification treatment from the surface to the reservoir pores, which not only achieves the same modification effect as surface modification treatment, but also simplifies the treatment process, avoids the investment in surface treatment equipment, and saves on waste liquid treatment costs. In addition, the waste liquid contains alkali and polymer solutions, forming an "alkali / polymer" binary system, which helps to improve oil displacement efficiency. Therefore, the in-situ modification treatment of fly ash in the reservoir and the combined sealing effect can play a dual role in expanding the swept volume and improving the oil displacement efficiency, which can significantly improve the recovery rate.

[0017] (2) Considering the small flow cross-section, high fluid velocity, and large fluid pressure gradient in the near-wellbore zone of the reservoir, the retention strength of a single "fly ash + modified working fluid" mixture (main agent) in the pores is insufficient to resist the subsequent development fluid scouring and ensure the long-term effectiveness of the plugging effect. Therefore, this invention, considering both technical and economic aspects, creates a multi-segment plugging mode of "main agent (large septum plug) + sealing agent (small septum plug)". Attached Figure Description

[0018] To more clearly illustrate the technical solutions in the embodiments of the present invention or the prior art, the accompanying drawings used in the embodiments will be briefly described below.

[0019] Figure 1 This is a schematic diagram of the experimental equipment and process of the present invention; Figure 2 SEM images of the appearance of fly ash before and after modification; Figure 3 This is a graph showing the relationship between permeability and time in a sand-filled pipe. Figure 4 The results show the particle size distribution and median particle size of fly ash and modified fly ash. Figure 5 Schematic diagram of experimental equipment and process in Example 2; Figure 6 The relationship between injection pressure and PV number for the first to third types of plugging agents; Figure 7 The relationship between plugging agent injection pressure and PV number under different fly ash concentrations; Figure 8 This is a schematic diagram of the multi-point interconnected dual parallel quartz sand filling pipe model in Example 3. Detailed Implementation

[0020] This invention provides an in-situ modification and plugging method for fly ash reservoirs, comprising the following steps: The modified working fluid and fly ash are mixed, and the resulting mixture is pumped into the sand-filling pipe at a constant rate. Then, it is allowed to stand under reservoir temperature conditions to obtain modified fly ash and achieve sealing at the same time. The sand-filling pipe is used to simulate the reservoir layer. The modified working fluid is a mixture of alkali, polymer and water.

[0021] In this invention, the polymer can be partially hydrolyzed polyacrylamide (HPAM); the molecular weight of the HPAM can be 500 × 10⁻⁶. 4 g / mol ~2500×10 4 g / mol; the alkali can be NaOH; the mass concentration of the alkali in the modified working solution can be 1.2%~12.0%; the concentration of the polymer can be 100mg / L~5000mg / L, specifically 3000mg / L; the water in the modified working solution can be oilfield production injection water.

[0022] In this invention, the sand-filled pipe is used to simulate an oil reservoir. The pipe material can be stainless steel, with an inner diameter of 2.0~5.0 cm and a length of 20.0~50.0 cm. In this invention, due to the high smoothness of the inner wall of the stainless steel pipe, the interlocking effect between the pipe wall and the fly ash packing material is not strong. To prevent the formation of cross-flow channels between the pipe wall and the packing material during the subsequent injection of the modified working fluid into the sand-filled pipe, and to ensure sufficient contact between the modified working fluid and the fly ash packing material, anti-cross-flow treatment needs to be implemented beforehand.

[0023] In this invention, the anti-channeling treatment step can be as follows: cleaning the inner wall of the stainless steel pipe with hydrochloric acid, surfactant, and water respectively; drying the pipe; applying epoxy resin solution to the inner wall; filling the pipe with quartz sand; and removing excess quartz sand after the epoxy resin has cured. In this invention, the mass concentration of the hydrochloric acid can be 1.0% to 8.0%; the mass concentration of the surfactant can be 0.1% to 0.3%; and the surfactant includes one or more of cationic, anionic, amphoteric, and nonionic surfactants.

[0024] In this invention, the reservoir temperature can be 60~75℃, specifically 65℃, and the settling time can be 30~50min, specifically 30min, 40min, or 50min. In this invention, when the polymer solution carries fly ash into the reservoir, at the reservoir temperature, the fly ash and NaOH react, thereby altering the fly ash's retention capacity in the porous medium and improving the plugging rate. Furthermore, inside the reservoir, under reservoir temperature conditions, NaOH can further increase the degree of polymer hydrolysis, which in turn increases the viscosity of the polymer solution, further increasing the plugging rate. Moreover, inside the reservoir, under reservoir temperature conditions, the modified fly ash structure changes, generating zeolite with a porous structure. Zeolite has strong adsorption properties, enabling it to adsorb polymer solutions and other substances near the particles, thus producing a stronger plugging effect.

[0025] Specifically, when the modified working fluid comes into contact with fly ash, the chemical reaction mainly occurs between SiO2 and Al2O3 and NaOH. The chemical reaction equations are shown in equations (1) to (3).

[0026] SiO2+2NaOH→Na2SiO3+H2O (1) Al2O3+2NaOH→2NaAlO2+H2O (2) 3Al2O3·2SiO2+10NaOH+7H2O→2Na2SiO3+6NaAl(OH)4 (3) The products Na2SiO3 and NaAlO2 are the main components of zeolite minerals. Zeolite is a porous mineral material with a molecular-level sieve structure and has extremely strong adsorption properties. It can adsorb polymer solutions and other substances near the particles, thereby producing a stronger blocking effect.

[0027] In this invention, to verify the sealing effect, the sealing effect of modified fly ash is evaluated, and the method includes the following steps: (1) Obtain the particle size distribution, appearance, and mineral composition of fly ash; (2) The modified working fluid is mixed with fly ash. The resulting mixture is pumped into the sand-filled pipe at a constant rate until the pore volume of the sand-filled pipe is 1 to 1.3 times. Then, the modified working fluid is pumped into the sand-filled pipe. After stabilization, the injection end pressure P1 is recorded. The pump is then stopped, and the water permeability is calculated. K w1; (3) After standing for a period of time, restart the horizontal flow pump and inject the modified working fluid into the sand-filled pipe at a constant speed. After the pressure stabilizes, record the injection end pressure P2, stop the pump, and calculate the water permeability. K w2.

[0028] (4) Open the end cap of the sand filling pipe, take out the fly ash that has reacted with the modified working liquid after contact with the sand filling pipe, i.e. modified fly ash, dry it, and measure its particle size, particle size distribution, particle appearance and mineral composition. (5) Determine whether sealing has been achieved based on the changes in modified fly ash and its permeability; In this invention, the initial particle size distribution and median particle size of the fly ash or modified fly ash can be obtained using vibrating screen sieving technology; the appearance morphology and mineral composition of the fly ash or modified fly ash can be determined using scanning electron microscopy and X-ray diffraction detection technology, respectively.

[0029] In this invention, fly ash can also be mixed with a modified working fluid to form a plugging agent, which is then injected into a core sample (size: diameter × length = 2.5 × 10 cm, permeability) at a constant rate. K w = (5000~150000) × 10 -3 μm 2 After the injection volume reaches the designed slug size, it is left to stand for a period of time, and then water is injected until the pressure stabilizes. During this period, the injection pressure is recorded. The effect of the water-blocking working fluid in the core is evaluated by the pressure rise, resistance coefficient, residual resistance coefficient and plugging rate. The results are compared with the experimental results of fly ash to finally determine the effectiveness of the fly ash modification treatment method.

[0030] The present invention also provides modified fly ash obtained by the above-described in-situ modification and plugging method in fly ash reservoirs.

[0031] The present invention also provides a combined plugging method, comprising using a modified working fluid and fly ash as the main agents for large-segment plugging, and using epoxy resin-polymer as the sealing agent for small-segment plugging; wherein the epoxy resin-polymer is obtained by mixing an epoxy resin mixture and a polymer solution.

[0032] In this invention, the epoxy resin mixture includes epoxy resin, a softener, and a curing agent.

[0033] In this invention, the softener can be dibutyl phthalate; the curing agent can be one or more of ethylenediamine, diethylenetriamine, phthalic anhydride, and maleic anhydride; the polymer in the polymer solution can be one or more of partially hydrolyzed polyacrylamide, hydrophobic associating polymers, and polymeric surfactants. In this invention, the ratio of epoxy resin, softener, and curing agent in the epoxy resin mixture can be 100g:20mL:20mL; the mass concentration of the polymer solution can be 1000~5000mg / L.

[0034] In this invention, the volume ratio of the polymer solution and the epoxy resin mixture in the epoxy resin-polymer can be 10:0.8~1.5, specifically 10:1.

[0035] In this invention, the main agent has lower strength and weaker erosion resistance, but is cheaper and easier to use in large quantities. The sealing agent has higher strength but is more expensive and not suitable for large-scale use, but can be used for plugging in near-wellbore areas. The "main agent + sealing agent" combined plugging mode can effectively solve the contradiction between plugging agent cost and plugging strength. In the initial stage of the "main agent + sealing agent" combined plugging mode, epoxy resin is dispersed in the polymer solution in the form of tiny droplets. Over time, the curing agent causes the epoxy resin droplets to gradually transform into elastic microspheres, until they become solid microspheres. In this invention, multi-tube sand-filling pipes (filled with quartz sand, with a permeability of...) can be used. K w = (5000~150000) × 10 -3 μm 2 The effectiveness of the plugging mode can be evaluated using parallel models or physical models with "separate injection and separate production" functions, in order to simulate the plugging and fluid flow diversion effects in deep reservoirs and near wells.

[0036] To further illustrate the present invention, the technical solutions provided by the present invention will be described in detail below with reference to the accompanying drawings and embodiments, but these should not be construed as limiting the scope of protection of the present invention.

[0037] Example 1 1. Composition of fly ash and solvent water (1) Mineral composition of fly ash The fly ash was taken from the self-owned coal-fired power plant of DQ oilfield, and its mineral composition analysis is shown in Table 1.

[0038] Table 1 Mineral composition of fly ash

[0039] Table 1 shows that SiO2 and Al2O3 account for a relatively large proportion of the fly ash, at 55.3% and 19.7%, respectively. The SEM image of the fly ash particles before modification is shown below. Figure 2 Column (a) in the middle.

[0040] (2) The solvent water is the injected water from the BH oilfield (the target research oilfield), and its ionic composition analysis is shown in Table 2.

[0041] Table 2 Ion Composition of Injected Water

[0042] like Figure 1 As shown, a mixture of NaOH, HPAM, and injection water was used as the modifying working fluid. The modified working fluid was mixed evenly with fly ash, and the resulting mixture was placed in a piston-type intermediate container with a stirring function for later use. The mass concentration of NaOH in the modified working fluid was 10%; the mass concentration of HPAM was 3000 mg / L; and the mass concentration of fly ash in the mixture was 0.6%. A horizontal flow pump was used to pump the mixture from the intermediate container into the sand-filled tube (simulating in-situ modification treatment within the reservoir). After the injection volume reached the designed dosage of 1.2 PV, the mixture was allowed to stand at 65℃ for 30 minutes to obtain modified fly ash. Then, the modified working fluid was used to displace the sand-filled tube until the pressure stabilized. The injection pressure was continuously monitored during the experiment, and the permeability of the sand-filled tube was calculated using Darcy's formula. The relationship between the permeability of the sand-filled tube and time during the experiment is shown in [Figure showing the relationship between permeability and time]. Figure 3 ,from Figure 3 It can be seen that: From Figure 3 It can be seen that the initial permeability of the modified working fluid and fly ash mixture after filling the sand-filled pipe is [data missing]. K w ≈81.2×10 -3 μm 2 After approximately 30 minutes of reaction, the permeability of the sand-filled pipe decreased to [value missing]. K w ≈0.7×10 -3 μm 2 The permeability loss rate was 99.14%. After the NaOH solution came into contact with and reacted with the fly ash particles in the sand-filled pipe, the appearance and structure of the particles changed (see...). Figure 2 The increased particle density in the sand-filled pipe reduces the porosity between particles, decreases the permeability, increases the seepage resistance, and enhances the retention effect of "increasing resistance and reducing seepage".

[0043] SEM images of the modified fly ash particles are shown below. Figure 2 (b) from Figure 2 It can be seen that the fly ash particles before modification are spherical in appearance. After the fly ash reacts with NaOH, the modified fly ash particles exhibit an irregular shape and generate a new mineral, zeolite. The mineral composition of fly ash and modified fly ash is shown in Table 3, and the particle size distribution and proportion are shown in Table 4.

[0044] Table 3. Mineral composition of fly ash and modified fly ash (mass percentage)

[0045] Table 4 Particle size distribution and proportion

[0046] As shown in Table 4, 63.7% of fly ash particles have a diameter greater than 360 mesh, while 49.5% of modified fly ash particles have a diameter greater than 360 mesh. In addition, the proportion of modified fly ash particles smaller than 160 mesh decreased from 18.4% to 1.5%.

[0047] Figure 4 The particle size distribution and median particle size of fly ash and modified fly ash were measured. Figure 4 It can be seen that, compared with fly ash, the particle size and median particle size of modified fly ash are generally reduced. The particle size distribution of fly ash is 90~250μm, and the median particle size is about 175μm; the particle size of modified fly ash is 65~200μm, and the median particle size is 125μm.

[0048] In summary, compared with fly ash, modified fly ash particles have changed in appearance, median particle size, and mineral composition, resulting in increased density and decreased permeability of the sand-filled pipe filling material.

[0049] Example 2 Retention and plugging properties of fly ash and modified fly ash in core samples A polymer aqueous solution and an alkali-polymer-water binary system were used as the carrier fluid and mixed with fly ash to form a plugging agent. For details of the plugging agent composition, please refer to [link to details]. Figures 6-7 , Figure 6 C P =600mg / L, refers to HPAM at a concentration of 600mg / L (M=1900×10). 4 A polymer aqueous solution was used as the first plugging agent; C P =600mg / L + 0.6 fly ash, refers to HPAM with a concentration of 600mg / L (M=1900×10). 4 A polymer aqueous solution and fly ash are mixed as a second plugging agent, wherein the fly ash content in the second plugging agent is 0.6% by mass; C P =600mg / L + 3% NaOH + 0.6% fly ash, refers to mixing the modified working solution and fly ash to obtain a third plugging agent. The fly ash content in the third plugging agent is 0.6% by mass, and the modified working solution contains HPAM (M=1900×10). 4 The concentration of ) is 600 mg / L, and the mass concentration of NaOH is 3%. Figure 7 C P=600mg / L + 3%NaOH + 0.3%fly ash, refers to mixing the modified working solution and fly ash to obtain the fourth plugging agent. The fly ash content in the fourth plugging agent is 0.3% by mass, and the modified working solution contains HPAM (M=1900×10). 4 The concentration of ) is 600 mg / L, and the mass concentration of NaOH is 3%; C P =600mg / L + 3%NaOH + 1.2%fly ash, refers to mixing the modified working solution and fly ash to obtain the fifth plugging agent. The fly ash content in the fifth plugging agent is 1.2% by mass, and the modified working solution contains HPAM (M=1900×10). 4 The concentration of ) is 600 mg / L, and the mass concentration of NaOH is 3%.

[0050] The above-mentioned plugging agent was loaded into a piston-type intermediate container with a stirring function for later use, and the columnar core ( K w ≈5000×10 -3 μm 2 Or 12000×10 -3 μm 2 Insert the core holder, connect the pipeline and pressure measuring instrument. Figure 5 The horizontal flow pump was started, and the plugging agent in the intermediate container was injected into the core at an injection rate of 2.0 mL / min. The core was allowed to stand for 30 minutes, followed by water flooding until the pressure stabilized. The injection pressure was recorded during the experiment, and the drag coefficient, residual drag coefficient, and plugging rate were calculated.

[0051] Experimental results 1) The influence of plugging agent type The relationship between the injection pressure and PV number for the first to third types of plugging agents during the experiment is shown in the figure. Figure 6 , Figure 6 Test in K w ≈5000×10 -3 μm 2 Tests were conducted under columnar core conditions, from Figure 6 It can be seen that during the injection of the three plugging agents, with the increase of injection volume, the amount of plugging agent retained in the rock pores increases, the pore flow cross-section decreases, the seepage resistance increases, and the injection pressure increases. Among them, the third plugging agent has the largest pressure increase, followed by the second plugging agent, and the first plugging agent has the smallest pressure increase. In the subsequent water drive stage, some of the retained plugging agent in the pores migrates and is extracted, the pore flow cross-section partially recovers and increases, and the injection pressure decreases. At the end of the subsequent water drive, the third plugging agent has the highest pressure retention value, the second plugging agent is in the middle, and the first plugging agent has the lowest pressure retention value.

[0052] 2) Effect of modified fly ash concentration The relationship between plugging agent injection pressure and PV number under different fly ash concentrations is shown in the figure. Figure 7 , Figure 7 Test in K w ≈12000×10 -3 μm 2 Tests were conducted under columnar core conditions, from Figure 7 It can be seen that during the plugging agent injection stage, the injection pressure increases with the increase of injection volume and fly ash concentration. The pressure rise is larger and faster when the fly ash concentration in the plugging agent is 1.2% (the pressure rises sharply and stops when the injection volume reaches about 1.5PV). The pressure rise and speed are moderate when the fly ash mass concentration in the plugging agent is 0.6%, and smaller when the mass concentration is 0.3%.

[0053] 3) Drag coefficient, residual drag coefficient, and plugging rate The results of the "resistance-increasing and permeability-reducing" effect of the plugging agent retention in the core pores, namely the resistance coefficient, residual resistance coefficient, and plugging rate test results, are shown in Tables 5-6.

[0054] Table 5. Drag Coefficient, Residual Drag Coefficient, and Plugging Rate

[0055] Table 6. Drag coefficient, residual drag coefficient, and plugging rate (plugging agent slug size 2PV)

[0056] As shown in Tables 5 and 6, the resistance coefficient, residual resistance coefficient, and plugging rate increase with the increase of the plugging agent injection amount. Compared with polymer aqueous solution, fly ash and modified fly ash have significantly larger resistance coefficients, residual resistance coefficients, and plugging rates, indicating better plugging effects. Furthermore, modified fly ash exhibits significantly better retention, "resistance enhancement and permeability reduction," and plugging effects than fly ash.

[0057] Example 3 Experiments were conducted on the water blocking and fluid flow diversion effects of a multi-point interconnected dual-parallel quartz sand-filled pipe model. The experimental equipment and procedures are detailed below. Figure 8 The components of the plugging agents 1 through 3 involved are as follows: No. 1 plugging agent includes a large-section plugging agent and a sealing agent. The large-section plugging agent is a mixture of modified working fluid and fly ash. No. 2 plugging agent contains 1.2% fly ash by mass, and the modified working fluid contains HPAM polymer (M=1900×10⁻⁶). 4The mass concentration of the product (from China Petroleum Daqing Refining & Chemical Company) is 500 mg / L, the mass concentration of NaOH is 3%, and the sealing agent is epoxy resin-polymer. The epoxy resin-polymer is obtained by mixing epoxy resin mixture and HPAM polymer solution with a concentration of 3000 mg / L at a volume ratio of 1:10. The epoxy resin mixture is obtained by mixing epoxy resin, dibutyl phthalate and ethylenediamine at a dosage of 100 g: 20 mL: 20 mL.

[0058] The No. 2 plugging agent is a mixture of modified working fluid and fly ash. The fly ash concentration in the No. 2 plugging agent is 1.2% by mass, and the modified working fluid contains HPAM polymer (M=1900×10⁻⁶). 4 The concentration of NaOH (from China Petroleum Daqing Refining & Chemical Company) is 500 mg / L, and the concentration of NaOH is 3%.

[0059] No. 3 plugging agent is made of M=1900×10 4 It is composed of HPAM polymer (produced by China National Petroleum Corporation Daqing Refining & Chemical Company), phenolic resin (provided by CNOOC Tianjin Oilfield Services) and water, wherein the mass concentration of HPAM polymer is 2000 mg / L and the mass concentration of phenolic resin is 3000 mg / L.

[0060] Experimental steps: Option 1 involves conducting an experiment using plugging agent No. 1. The specific steps are as follows: The model ( Figure 8 Vacuum pumping and saturated water operation were performed. Then, simulated oil was used to fully saturate the core pores at 65℃ and a viscosity of 85 mPa·s to establish an original saturated oil formation model. Water flooding was then carried out from the model injection end until the produced fluid water cut reached 98%. Afterwards, 0.2 PV of plugging agent was injected into the high-permeability pipe from the produced end. This 0.2 PV plugging agent consisted of 0.18 PV of large-segment plugging agent and 0.02 PV of sealing agent. After injection, the pipe was allowed to stand at 65℃ for 1 hour. Then, the original displacement direction was restored, and water flooding was again carried out from the model injection end until the produced fluid water cut reached 98%. Injection pressure was recorded periodically during the experiment, and produced fluid was collected to calculate the recovery rate. The results are shown in Table 7.

[0061] Option 2 involves conducting experiments using plugging agent No. 2. The specific steps are as follows: The model ( Figure 8Vacuum pumping and saturated water operation were performed. Then, simulated oil was used to fully saturate the core pores at 65℃ and a viscosity of 85 mPa·s to establish an original saturated oil formation model. Water flooding was then performed from the model injection end until the produced fluid water cut reached 98%. Afterward, 0.2 PV of plugging agent No. 2 was injected into the high-permeability pipe from the produced end. The injection was completed and the pipe was allowed to stand at 65℃ for 1 hour. Then, the original displacement direction was restored, and water flooding was again performed from the model injection end until the produced fluid water cut reached 98%. Injection pressure was recorded periodically during the experiment, and produced fluid was collected to calculate the recovery rate. The results are shown in Table 7.

[0062] Option 3 involves conducting experiments using plugging agent No. 3. The specific steps are as follows: The model ( Figure 8 Vacuum pumping and saturated water operation were performed. Then, simulated oil was used to fully saturate the core pores at 65℃ and a viscosity of 85 mPa·s to establish an original saturated oil formation model. Water flooding was then performed from the model injection end until the produced fluid water cut reached 98%. Afterward, 0.2 PV of plugging agent No. 3 was injected into the high-permeability pipe from the produced end. The injection was completed and the pipe was allowed to stand at 65℃ for 1 hour. Then, the original displacement direction was restored, and water flooding was again performed from the model injection end until the produced fluid water cut reached 98%. Injection pressure was recorded periodically during the experiment, and produced fluid was collected to calculate the recovery rate. The results are shown in Table 7.

[0063] Table 7. Experimental data on oil recovery rate

[0064] As shown in Table 8, the recovery rates of the high-permeability and low-permeability layers in the three schemes during the water drive stage were approximately 59% and 35%, respectively. At the end of well shut-off (production end) and subsequent water drive, in Scheme 1, the recovery rate of the high-permeability layer was 60.06%, an increase of 1.09%, and the low-permeability layer was 52.08%, an increase of 17.79%, with a model recovery rate increase of 9.44%. In Scheme 2, the recovery rate of the high-permeability layer was 61.67%, an increase of 2.55%, and the low-permeability layer was 46.23%, an increase of 11.21%, with a model recovery rate increase of 6.88%. In Scheme 3, the recovery rate of the high-permeability layer was 62.06%, an increase of 2.94%, and the low-permeability layer was 40.23%, an increase of 5.21%, with a model recovery rate increase of 4.08%.

[0065] In summary, compared with Scheme 2 and Scheme 3, Scheme 1 has a better effect on "increasing resistance and reducing permeability" and diverting fluid flow in the high-permeability layer of the model, which greatly improves the utilization of the low-permeability layer of the model and increases the recovery rate.

[0066] Although the above embodiments have provided a detailed description of the present invention, they are only some embodiments of the present invention, and not all embodiments. People can obtain other embodiments based on these embodiments without creative effort, and these embodiments all fall within the protection scope of the present invention.

Claims

1. A method for in-situ modification and plugging of oil reservoirs with fly ash, characterized in that, Includes the following steps: The modified working fluid and fly ash are mixed, and the resulting mixture is pumped into the sand-filling pipe at a constant rate. Then, it is allowed to stand under reservoir temperature conditions to obtain modified fly ash and achieve sealing at the same time. The sand-filling pipe is used to simulate the reservoir layer. The modified working fluid is a mixture of alkali, polymer and water.

2. The method of in situ modification and plugging of coal fly ash oil reservoirs according to claim 1, characterized in that, The polymer is partially hydrolyzed polyacrylamide; the alkali is NaOH; and the water in the modified working fluid is oilfield production injection water.

3. The in-situ modification and plugging method for fly ash reservoirs as described in claim 2, characterized in that, The modified working solution contains an alkali concentration of 1.2% to 12.0% and a polymer concentration of 100 mg / L to 5000 mg / L.

4. The in-situ modification and plugging method for fly ash reservoirs as described in claim 1, characterized in that, The reservoir temperature is 60~75℃; the settling time is 30~50 min.

5. The in-situ modification and plugging method for fly ash reservoirs as described in claim 1, characterized in that, The amount of the mixture used is 1 to 1.3 times the pore volume of the sand-filled pipe.

6. Modified fly ash obtained by the in-situ modification and plugging method for fly ash reservoirs according to any one of claims 1 to 5.

7. A combined plugging method, characterized in that, This includes using modified working fluid and fly ash as the main agents for large-segment plugging, and using epoxy resin-polymer as the sealing agent for small-segment plugging; The epoxy resin-polymer is obtained by mixing an epoxy resin mixture and a polymer solution; The epoxy resin mixture includes epoxy resin, a softener, and a curing agent; The modified working fluid is a mixture of alkali, polymer and water.

8. The combined plugging method as described in claim 7, characterized in that, The softener is dibutyl phthalate; the curing agent is one or more of ethylenediamine, diethylenetriamine, phthalic anhydride and maleic anhydride; the ratio of epoxy resin, softener and curing agent in the epoxy resin mixture is 100g:20mL:20mL.

9. The combined plugging method as described in claim 7, characterized in that, The concentration of the polymer solution is 1000~5000 mg / L.

10. The combined plugging method according to any one of claims 7 to 9, characterized in that, The volume ratio of the polymer solution and the epoxy resin mixture in the epoxy resin-polymer is 10:0.8~1.5.

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