A process method for improving and transforming volume of ultra-high temperature carbonate reservoirs

Abstract

This invention belongs to the field of fracturing and stimulation technology for ultra-high temperature carbonate reservoirs in oil and gas field development. Specifically, it relates to a process method for increasing the stimulation volume of ultra-high temperature carbonate reservoirs. The invention mainly includes the following steps: pumping high-density weighted fracturing fluid to open the reservoir and activate some natural fractures to open artificial main fractures; pumping a composite liquid of liquid CO2 and low-viscosity slickwater into the tubing and low-viscosity high-density composite weighted fracturing fluid into the casing to increase the complexity of artificial fractures; pumping autogenous acid stimulation fluid into the tubing and low-viscosity fracturing fluid into the casing to increase the distance of acid-etched fractures and the effectiveness of complex artificial fractures; pumping fracturing fluid carrying proppant into the tubing and autogenous acid stimulation fluid into the casing to improve the conductivity of near-wellbore artificial fractures while autogenous acid enters the complex near-wellbore artificial fractures. By using high-density composite weighted fluid to open the reservoir and subsequently employing a multi-combination fluid composite stimulation technology, the reservoir stimulation volume is significantly increased, and the single-well stimulation effect is improved.

Description

Technical Field

[0001] This invention belongs to the field of fracturing and stimulation technology for ultra-high temperature carbonate reservoirs in oil and gas field development, specifically involving a process method for increasing the stimulation volume of ultra-high temperature carbonate reservoirs. Background Technology

[0002] my country possesses abundant carbonate oil and gas resources with significant exploration and development potential, making it a crucial area for future oil and gas reserve and production increases. These resources are mainly distributed in Sichuan and the Tarim Basin. Carbonate gas reservoirs are the primary development target for the Southwest Oil and Gas Field. The development of large carbonate gas field clusters, primarily the Longwangmiao Formation in Anyue County, central Sichuan, and the Dengying Formation of the Sinian System, has laid the foundation for establishing a 30 billion cubic meter gas production area. The Tarim carbonate reservoirs have essentially achieved contiguous oil-bearing areas across northern and central Tarim, with cumulative proven oil and gas equivalent exceeding 1 billion tons.

[0003] Carbonate reservoirs exhibit distinct characteristics, including porous, cavitary, fracture-cavitary, and fractured zone types. The challenges and technologies employed in reservoir stimulation differ significantly across these types. For porous reservoirs, the challenge lies in increasing the contact area of ​​artificial fractures, primarily through volumetric fracturing (including proppant fracturing). This involves using multiple fractures to increase the contact area with the reservoir, shorten the seepage distance, and improve stimulation effectiveness. For other reservoir types, the challenge is increasing the quantity and quality of artificial fractures controlling cavities and fracture zones, with acid fracturing being the primary method. Due to the complexity and diversity of reservoir types and the acid-rock reaction accompanying the expansion of artificial fractures, the actual design and optimization of acid fracturing is far more complex and difficult than proppant fracturing. Because acid fracturing technology is more mature, easier to operate in the field, and more difficult to improve, its progress lags behind proppant fracturing. Ultra-high temperature carbonate reservoirs place even higher demands on the acid solution—a key component of acid fracturing technology. Limited by ultra-high geostress and frictional resistance, lower flow rates are required. Achieving volumetric or ultra-deep stimulation places even higher demands on the stimulation fluid and process technology.

[0004] For carbonate rock stimulation, the development of pores, fractures, and cavities is more complex, and more factors influence the stimulation volume. The expansion of artificial fractures is accompanied by acid-rock reactions. On the one hand, the artificial fractures are filled with acid, making it easier to open multi-scale natural fractures in the oil and gas reservoir, especially fine natural fractures. High-viscosity fracturing fluids are difficult to open these fractures, but acid has a natural advantage, opening them after etching the surface of fine natural fractures or continuously penetrating their interior to form a network of fine fractures. On the other hand, the acid-rock reaction is rapid at high temperatures. Once the artificial fractures expand to a certain extent, the fresh acid becomes residual acid, and the artificial fractures lack support. Under high stress conditions, the conductivity is insufficient, making it difficult to form an effective stimulation volume.

[0005] Domestic scholars have conducted extensive research on the efficient stimulation of ultra-high temperature carbonate reservoirs, employing different stimulation liquid systems and process technologies in combination to form a process system for improving the effective stimulation volume of ultra-high temperature carbonate reservoirs.

[0006] The publication number is CN114656944A. An emulsion-to-acid system for high-temperature carbonate reservoirs achieves non-uniform etching of acid through the dispersion of the emulsion. The system generates bubbles through the reaction with the acid, thereby enhancing the emulsification state of the system and improving the blocking and diversion effect of the system.

[0007] The publication number is CN113969775A, which discloses a method and application for increasing the effective acid etching fracture length in ultra-deep carbonate reservoirs. The method is characterized by the following steps: the gelling acid and crosslinking agent of the crosslinked acid system are respectively encapsulated by the oil phase and the water phase, so that they are gradually released and reacted after entering the formation, reducing the amount of acid reaction in the near-wellbore zone, and etching the formation only after entering the high-temperature formation for a period of time, thereby increasing the acid etching fracture length under high-temperature conditions.

[0008] The publication number is CN114737898A, which discloses a method for enhancing the production of ultra-high temperature carbonate reservoirs. This method develops an acid treatment process for high-temperature and ultra-high temperature carbonate reservoirs that is low in corrosion, high in conductivity, and capable of deep stimulation. By continuously and alternately pumping a film-forming agent and an acid system into the formation, the length of the acid-etched fractures and the stimulation range can be increased.

[0009] The publication number is CN110159243B. A fractured-net acid fracturing method for carbonate reservoirs includes the following steps: a) selecting the fractured-net acid fracturing well section; b) sequentially injecting low-viscosity acid and slickwater into the well at low flow rates; c) sequentially injecting low-viscosity slickwater and acid into the well at high flow rates; d) injecting slickwater carrying proppant or temporary plugging agent into the well; e) repeating steps c and d once or multiple times; f) injecting displacement fluid into the well at low flow rates. This invention provides guidance for acid fracturing design and construction, reduces construction difficulty and risk, improves construction efficiency, and ensures the effectiveness of acid fracturing construction and the fractured-net acid fracturing effect.

[0010] Based on the analysis of the aforementioned existing technologies, the current technique used for ultra-high temperature carbonate reservoirs is composite acid fracturing, aimed at increasing the length of acid-etched fractures. Different processes and stimulation fluids are employed, primarily involving the high-volume pumping of low-viscosity slickwater-type pre-flush fluid to lower the temperature within the artificial fractures near the wellbore, followed by the pumping of different acid systems. By lowering the reservoir temperature, the acid-rock reaction rate is slowed, allowing the acid to reach the distal ends of the fractures, increasing the acid-etched fracture distance and thus the stimulation volume. Some researchers have also studied autogenous acid generation, allowing the acid to enter the deep reservoir and be released at a higher temperature, which can also increase the acid-etched fracture distance and expand the stimulation range. Analysis of existing techniques for increasing the distance of acid-etched fractures in ultra-high temperature carbonate reservoirs reveals that large-scale pumping of pre-flush fluid offers limited temperature reduction, confining the cooling range to the wellbore area. Furthermore, in ultra-deep, ultra-high stress reservoirs, increasing the discharge rate is difficult, failing to achieve the designed implementation objectives. Self-generated acid fluids exhibit poor temperature resistance and low concentrations; under ultra-high stress, most acid-etched fractures cannot withstand the stress, resulting in ineffective fractures and hindering a significant increase in effective stimulation volume. In conclusion, existing technologies are insufficient for efficient stimulation of ultra-high temperature carbonate reservoirs. Therefore, a convenient and low-cost technique needs to be developed to significantly increase the distance of acid-etched fractures and the effective stimulation volume in ultra-high temperature carbonate reservoirs. Summary of the Invention

[0011] This invention proposes a process for increasing the stimulation volume of ultra-high temperature carbonate reservoirs, in order to solve the technical problem in the prior art that artificial fractures are difficult to form high-conductivity fractures due to ultra-high stress limitations, thus making it difficult to increase the effective stimulation volume.

[0012] To achieve the above objectives, the present invention adopts the following technical solution: A process for increasing the volume of ultra-high temperature carbonate reservoir stimulation includes the following steps: Step 1: Pump high-density composite weighting fracturing fluid into the reservoir to open the artificial main fracture; Step 2: Using the method of simultaneous injection of oil and casing, the oil tubing is pumped with a composite liquid of liquid CO2 and low-viscosity slickwater, while the casing is pumped with low-viscosity fracturing fluid. Step 3: Using the method of simultaneous injection of oil and casing, high-temperature resistant autogenous acid is pumped into the tubing, and low-viscosity fracturing fluid is pumped into the casing. Step 4: Using the method of simultaneous injection of oil and casing, the tubing pump injects sand-carrying fracturing fluid, and the casing pump injects high-temperature resistant autogenous acid.

[0013] The high-density composite weighted fracturing fluid mentioned in step one is a composite weighted fracturing fluid composed of 45% soluble salt by mass and 40% quartz sand solid particles with a particle size of 500 mesh by volume.

[0014] The density of the high-density composite weighted fracturing fluid reaches 1.8 g / cm³.3 Temperature resistance up to 220℃.

[0015] High-density composite weighted fracturing fluid is slowly pumped up in the initial stage of injection until significant signs of formation fracturing appear, at which point the reservoir is considered to have been fractured.

[0016] After the reservoir is opened, the pumping rate is based on the wellhead pressure limit. The pumping rate is limited by the pressure limit but not the pumping rate. The pumping rate of high-density composite weighted fracturing fluid needs to be combined with the actual reservoir rock properties, with the standard design amount to form artificial fractures of about 80-100m.

[0017] The composite liquid of liquid CO2 and low-viscosity slickwater mentioned in step two is a composite fracturing fluid composed of 70% liquid CO2 by volume and 30% slickwater with a viscosity of 15 mPa·s by volume.

[0018] In step two, a small-volume pump is initially injected into the tubing and casing to replace the high-density composite weighted fracturing fluid in the wellbore. Then, the pumping volume is slowly increased to the maximum within the pressure limit range. The pumping volume of the composite fracturing fluid of liquid CO2 and low-viscosity slickwater is twice that of the low-viscosity fracturing fluid.

[0019] In step three, the tubing and casing are injected with the maximum displacement pump according to the actual construction safety requirements. The injection volume of high-temperature self-generating acid is 1.5 times that of low-viscosity fracturing fluid.

[0020] In step four, the tubing pump injects fracturing fluid carrying sand, which carries high-strength ceramic particles with a combined particle size.

[0021] In step four, the tubing and casing are injected with the maximum displacement pump according to construction safety requirements. The injection volume of the high-temperature self-generating acid is twice that of the sand-carrying fracturing fluid.

[0022] Compared with the prior art, the present invention has the following beneficial effects: This invention discloses a process for increasing the volume of ultra-high temperature carbonate reservoir stimulation. The process involves pumping high-density composite weighted fracturing fluid to open the reservoir, creating artificial main fractures and connecting some natural fractures. This provides a pathway for subsequent fluid entry into the main structural structure, reducing the risk of later proppant injection and increasing the distance between acid-etched fractures. The solid weighting material (500-mesh quartz sand) contained in the composite fluid can enter the micro-fractures along with the fluid, providing a certain supporting effect and improving the effectiveness of the stimulation fracture network. Furthermore, by employing a combined injection method involving the tubing and casing, a composite liquid of liquid CO2 and low-viscosity slickwater is pumped into the tubing, while low-viscosity fracturing fluid is pumped into the casing. This increases the density of the injected fracturing fluid, further opening the reservoir and connecting natural fractures. It also leverages the advantages of different fracturing fluids to construct complex fractures. Under the high temperature and pressure conditions of the formation, liquid CO2 exists in a supercritical state. When mixed with slickwater, it exhibits stronger fracture penetration, easily entering micro-natural fractures, opening them, and forming a complex fracture network to increase the reservoir's stimulation volume. It can also enhance the reservoir's energy to a certain extent. During the well opening and fluid drainage process, as the bottom hole pressure decreases, the supercritical and liquid CO2 vaporizes, expanding in volume by more than one hundred times, significantly aiding in drainage and improving the fracturing fluid's flowback efficiency. Furthermore, the method of simultaneous injection of oil and casing is adopted, with the tubing pumped to inject high-temperature resistant autogenous acid and the casing pumped to inject low-viscosity fracturing fluid. The low-viscosity fracturing fluid has the effect of reducing the formation temperature inside and near the wellbore, slowing down the acid generation rate of autogenous acid, reducing the acid-rock reaction rate, and allowing the autogenous acid to better penetrate into the far end of the fracture for etching. Furthermore, by employing a combined injection method, the tubing pump injects sand-carrying fracturing fluid, while the casing pumps in high-temperature resistant autogenous acid, thereby improving the conductivity of the artificial fractures near the wellbore. Simultaneously, the autogenous acid enters the complex artificial fractures near the wellbore, increasing the effectiveness of the fractures and constructing a highly efficient and complex fracture network system composed of artificial and natural fractures, thus increasing the effective stimulation volume. Attached Figure Description

[0023] Figure 1 Schematic diagram of fracture morphology formed in different steps of the process for increasing the volume of ultra-high temperature carbonate rock reservoirs; Figure 2 Schematic diagram of effective fracture morphology after the construction of the process for increasing the volume of ultra-high temperature carbonate rock reservoirs. Detailed Implementation

[0024] To further understand the content of this invention, the invention will be described in detail below with reference to the accompanying drawings and specific embodiments. It should be understood that the embodiments are merely illustrative and not limiting of the invention.

[0025] In a western oilfield, the LT2 well reaches a depth of 8200m. The main formation is divided into three smaller layers with a span of 86m. The target reservoir temperature is 195℃. This embodiment provides a process for increasing the volume of ultra-high temperature carbonate reservoir stimulation. The specific implementation method includes the following steps: Step 1: Use materials with a density of 1.8 g / cm³ 3High-density composite weighted fracturing fluid is used to open reservoirs. The high-density composite weighted fracturing fluid consists of 45% by mass of soluble salt and 40% by volume of 500-mesh quartz sand solid particles. In this example, the soluble salt is calcium chloride, and the density of the 45% by mass calcium chloride solution reaches 1.3 g / cm³. After adding 40% by volume of 500-mesh quartz sand solid particles, the density of the resulting high-density composite weighted fracturing fluid reaches 1.8 g / cm³. 3 It has a temperature resistance of up to 220℃ and a viscosity of 50-75 mPa·s. After hydraulic fracturing with high-density composite weighting, it creates artificial main fractures and connects some natural fractures, serving as the main channel for subsequent fluid formation, reducing the risk of later proppant injection and increasing the distance of acid-etched fractures. The solid weighting material (500-mesh quartz sand) in the composite weighting fracturing fluid can enter the micro-fractures along with the fluid, providing some support and improving the effectiveness of the fracture network. During the initial injection of high-density composite weighting fracturing fluid into the reservoir, the injection rate should be slowly increased to 2-4 m³ / s. 3 The rate is adjusted based on the construction pressure to determine whether the reservoir has been broken up. When significant signs of formation fracturing appear at the construction pressure, the discharge rate is rapidly increased (under safe construction conditions) to reach a maximum discharge rate of 8-9 m³ / min. 3 The pumping speed is increased to fill the wellbore with high-density composite weighted fracturing fluid at a rate of 550 m³ / min. The total volume of composite weighted fracturing fluid injected in this step is 550 m³ / min. 3 The main crack formed is like Figure 1 As shown in (a). The main fracture formed in this step provides a good channel for the entry of liquid in subsequent steps, and is also the main channel for the flow of oil and gas in the production process.

[0026] Step Two: Using a combined oil-casing injection method, a composite fracturing fluid of liquid CO2 and low-viscosity slickwater is pumped into the artificial main fracture opened in Step One through the tubing pump, while low-viscosity fracturing fluid is pumped through the casing pump to increase the complexity of the artificial fracture. The composite fracturing fluid of liquid CO2 and low-viscosity slickwater consists of 70% liquid CO2 and 30% slickwater with a viscosity of 15 MPa·s, exhibiting strong penetrability and making it easier to open micro-natural fractures, thus facilitating the formation of a fracture network. Considering the safety of liquid CO2, a pressure-limited but not flow-limited approach is adopted for construction, initially using a 1m... 3 Pumping at a rate of / min replaces the high-density composite weighted fracturing fluid in the wellbore. Then, the pumping rate is slowly increased, and maximum pumping is carried out according to construction safety requirements. The total pumped fluid volume in this stage is approximately 900m³. 3The injection rate of the liquid CO2 composite fracturing fluid is twice that of the low-viscosity fracturing fluid. Besides improving the penetration of the composite fluid and forming a complex fracture network to increase reservoir stimulation volume, liquid CO2 can also enhance the reservoir's energy to a certain extent. During the well opening and blowout process after the stimulation operation, as the bottomhole pressure decreases, the supercritical and liquid CO2 vaporizes, expanding in volume by more than one hundred times, significantly aiding in flowback and improving the fracturing fluid flowback efficiency.

[0027] Step 3: This step follows immediately after Step 2. Continuing with the simultaneous injection method of oil and casing, high-temperature self-generating acid is pumped through the tubing pump, while low-viscosity fracturing fluid is pumped through the casing pump; the pumping speed is increased to 8-9 m / s. 3 At a rate of / min, continue pumping at this maximum stable rate to allow the high-temperature self-generated acid to reach the distal end of the main fracture for etching. The total pumped volume in this stage is 500m³. 3 The pumping volume of high-temperature resistant autogenous acid is 1.5 times that of low-viscosity fracturing fluid.

[0028] Step Four: After completing Step Three, stop the pump for 30 minutes to allow the high-temperature autogenous acid to completely etch the fractures. Then continue with the simultaneous injection method of tubing and casing. The tubing pump injects sand-carrying fracturing fluid, and the casing pump injects high-temperature autogenous acid to improve the conductivity of the artificial fractures near the wellbore. At the same time, the autogenous acid enters the complex artificial fractures near the wellbore, forming fractures such as... Figure 1 As shown in (d), the fracturing fluid injected by the tubing pump has a density of 1.35 g / cm³. 3 Calcium chloride-weighted fracturing fluid carries high-strength ceramic aggregates with combined particle sizes (30 / 50 mesh, 40 / 70 mesh). The total pumping volume for this step is 900 m³. 3 The pumping rate of the high-temperature resistant autogenous acid is twice that of the proppant-carrying fracturing fluid, and the proppant addition rate is 30m³. 3 When injecting oil into tubing and casing, slowly increase the injection rate using a pressure-limited but not flow-limited method until the injection rate reaches the maximum flow rate of 8-9 m³. 3 At a rate of / min, while pumping the proppant-carrying fracturing fluid, high-temperature self-generating acid is also pumped, allowing the ceramic particles to enter the fracture for support. The high-temperature self-generating acid continues to etch at the distal end of the fracture, ultimately forming near-wellbore supported fractures and mid-to-distal acid-etched fractures, such as... Figure 2 As shown.

[0029] In this embodiment, well LT2, before stimulation and production testing, produced 3.5 tons of oil per day, which was insufficient to meet the demands of efficient production from ultra-deep wells. Using the innovative technology of this invention, the daily oil production reached 105 tons after stimulation, significantly improving the stimulation effect. Compared with neighboring wells in the same block, the production increase was over 80%, confirming the strong application potential of this technology. It plays a crucial role in promoting efficient stimulation of ultra-deep, ultra-high temperature carbonate rocks, and is particularly significant for the stimulation of ultra-deep, tight carbonate rocks in the Tarim Oilfield.

[0030] Furthermore, it should be understood that although this specification describes embodiments, not every embodiment contains only one independent technical solution. This narrative style is merely for clarity. Those skilled in the art should consider the specification as a whole, and the technical solutions in each embodiment can be appropriately combined to form other embodiments that can be understood by those skilled in the art. The above content is only for illustrating the technical concept of the present invention and should not be construed as limiting the scope of protection of the present invention. Any modifications made based on the technical concept proposed in this invention shall fall within the scope of protection of the claims of this invention.

Claims

1. A process for increasing the volume of ultra-high temperature carbonate reservoirs, characterized in that, Includes the following steps: Step 1: Pump high-density composite weighting fracturing fluid into the reservoir to open the artificial main fracture; Step 2: Using the method of simultaneous injection of oil and casing, the oil tubing is pumped with a composite liquid of liquid CO2 and low-viscosity slickwater, while the casing is pumped with low-viscosity fracturing fluid. Step 3: Using the method of simultaneous injection of oil and casing, high-temperature resistant autogenous acid is pumped into the tubing, and low-viscosity fracturing fluid is pumped into the casing. Step 4: Using the method of simultaneous injection of oil and casing, the tubing pump injects sand-carrying fracturing fluid, and the casing pump injects high-temperature resistant autogenous acid.

2. The method for increasing the volume of ultra-high temperature carbonate reservoirs according to claim 1, characterized in that, The high-density composite weighted fracturing fluid mentioned in step one is a composite weighted fracturing fluid composed of 45% soluble salt by mass and 40% quartz sand solid particles with a particle size of 500 mesh by volume.

3. The method for increasing the volume of ultra-high temperature carbonate reservoirs according to claim 2, characterized in that, The density of the high-density composite weighted fracturing fluid is 1.8 g / cm³. 3 Temperature resistance up to 220℃.

4. The method for increasing the volume of ultra-high temperature carbonate reservoirs according to claim 3, characterized in that, The high-density composite weighted fracturing fluid is slowly pumped up in the initial stage of injection until significant signs of formation fracturing appear, at which point the reservoir is determined to have been fractured.

5. The method for increasing the volume of ultra-high temperature carbonate reservoirs according to claim 4, characterized in that, After the reservoir is opened, the pumping rate is based on the wellbore pressure limit. The pumping rate is limited by the pressure limit but not the pumping rate. The pumping rate of high-density composite weighted fracturing fluid needs to be combined with the actual reservoir rock properties, with the standard design amount to form artificial fractures of about 80-100m.

6. The method for increasing the volume of ultra-high temperature carbonate reservoirs according to claim 1, characterized in that, The composite liquid of liquid CO2 and low-viscosity slickwater mentioned in step two is a composite fracturing fluid composed of 70% liquid CO2 by volume and 30% slickwater with a viscosity of 15 mPa·s by volume.

7. The method for increasing the volume of ultra-high temperature carbonate reservoirs according to claim 6, characterized in that, In step two, a small-volume pump is initially injected into the tubing and casing to replace the high-density composite weighted fracturing fluid in the wellbore. Then, the pumping volume is slowly increased to the maximum within the pressure limit range of the wellbore. The pumping volume of the composite fracturing fluid of liquid CO2 and low-viscosity slickwater is twice that of the low-viscosity fracturing fluid.

8. The method for increasing the volume of ultra-high temperature carbonate reservoirs according to claim 1, characterized in that, In step three, the tubing and casing are injected with the maximum displacement pump according to the actual construction safety requirements. The injection volume of high-temperature self-generating acid is 1.5 times that of low-viscosity fracturing fluid.

9. The method for increasing the volume of ultra-high temperature carbonate reservoirs according to claim 1, characterized in that, In step four, the tubing pump injects fracturing fluid carrying sand, which carries high-strength ceramic particles with a combined particle size.

10. The method for increasing the volume of ultra-high temperature carbonate reservoirs according to claim 9, characterized in that, In step four, the tubing and casing are injected with the maximum displacement pump according to construction safety requirements. The injection volume of the high-temperature self-generating acid is twice that of the sand-carrying fracturing fluid.

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