Carbonate reservoir transformation method based on temperature field change

Abstract

The invention relates to a temperature field change-based carbonate reservoir transformation method, which comprises the following steps of: carrying out temperature field change simulation on a carbonate reservoir in an artificial seam between a shaft bottom and a near shaft under different pump injection displacements by oil jacket mixed injection ground transformation liquid; obtaining a simulation result that the temperature field in the shaft bottom and near shaft artificial seam changes along with the pump injection displacement; then, according to the simulation result in the step (1), the acid fracturing transformation construction pump injection program is optimized, and acid fracturing transformation construction is conducted; compared with a conventional acid fracturing transformation method, the method has the advantages that for the ultra-deep ultra-high-temperature carbonate reservoir, the length of an acid etching crack reaches up to 200 m or above and is increased by 2-3 times, the transformation volume is enlarged by 5 times or above, meanwhile, the acid etching degree of transformation liquid to an oil pipe is reduced, and the yield of the oil pipe is increased. And the method has important reference significance for improving the transformation effect of the ultra-deep and ultra-deep ultra-high-temperature carbonate reservoir transformation well.

Description

Technical Field

[0001] This invention relates to the field of oil and gas field development technology, and in particular to a method for the stimulation of carbonate reservoirs based on temperature field changes. Background Technology

[0002] Currently, deep carbonate reservoirs have relatively dense matrices and exhibit significant low porosity and permeability characteristics, primarily relying on natural fractures or fracture-cavity systems as oil and gas storage spaces. The main purpose of reservoir stimulation is to utilize artificial fractures to connect natural fractures and fracture-cavity systems. However, due to the increasingly deeper distribution of target layers in ultra-deep carbonate reservoirs (the deepest wells exceeding 8800m), poor development and increasing heterogeneity of natural fractures, and poor fracture-cavity development, the difficulty of connecting natural fractures and fracture-cavities through stimulation has increased. High stress in ultra-deep reservoirs makes initiation difficult, often resulting in wellhead overpressure and forced termination of operations. Therefore, safely and successfully initiating reservoir initiation is also a challenge. High stress in ultra-deep carbonate reservoirs also significantly impacts the conductivity of artificial fractures. Under high closure stress conditions, the conductivity of acid-etched fractures decreases rapidly, making it difficult to maintain high permeability of oil and gas channels. Therefore, improving process measures is crucial. Improving the conductivity of artificial fractures under high closure stress is also a significant technical challenge. In the stimulation of ultra-deep carbonate rocks, commonly used acid systems have a substantial impact on tubing safety. In ultra-high temperature reservoir environments, acid corrosion is severe, and commonly used corrosion inhibitor systems do not meet the safety requirements for ultra-high temperature (200℃) corrosion. Innovation in process technology is needed to ensure construction safety. Maintaining stable production after the stimulated well is also a major challenge. Insufficient stimulation volume leads to a rapid decline in production, and the small range of fracture-controlled and well-controlled oil and gas reservoirs is insufficient to support long-term stable production, making it difficult to improve production efficiency. Therefore, increasing the effective acid-etched fracture distance also presents a challenge.

[0003] There is a considerable amount of existing research on deep acid fracturing technology for carbonate rocks. Based on different acid systems and their combined application with fracturing fluids, a series of technologies for deep acid fracturing, deep modification, and volume modification of carbonate rocks have been developed. For example, for ultra-deep and ultra-high temperature fractured carbonate reservoirs, Li Xinyong et al. proposed a composite acid fracturing technology of "concentrated stimulation of backfilled sections + acid damage to reduce fracture + shallow tubing + combination of weighted fracturing fluid to increase discharge rate + pre-fracturing fluid to create fractures + alternating injection to create high-conductivity fractures + self-generated acid to clear the distal fractured solution", and implemented large-scale composite acid fracturing volume stimulation (see Li Xinyong, Li Xiao, Zhao Bing, et al. Key technologies for large-scale acid fracturing of ultra-deep and ultra-high temperature carbonate fractured solution reservoirs in Well S of Shunbei Oilfield [J]. Petroleum Drilling Technology, 2022, 50(2):92-98.). However, this method has limited effect on reducing reservoir temperature, and the cooling range is limited to the area near the wellbore. In the deep reservoir, the temperature inside the fracture rises rapidly to the reservoir temperature, the distance of the acid-etched fracture is limited, and a large amount of ineffective pre-fracturing fluid is wasted.

[0004] CN104975840B discloses a self-generated acid composite acid fracturing process for high-temperature deep carbonate reservoirs, which involves alternating injection of self-generated acid and other acid systems. Specifically, it includes: 1) injecting slickwater into the formation through a tubing; 2) injecting non-crosslinked fracturing fluid into the formation through a tubing; 3) injecting a self-generated acid system into the formation through a tubing; 4) injecting a gelling acid system into the formation at a low flow rate through a tubing; and 5) injecting slickwater into the formation through a tubing. However, in this method, the gelling acid, crosslinked acid, and self-generated acid are resistant to temperature differences, and the concentration of self-generated acid is low, making it difficult to significantly increase the distance of acid-etched fractures.

[0005] CN113969775A discloses a method and application for increasing the effective acid fracturing length in ultra-deep carbonate reservoirs. 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 fracturing length under high-temperature conditions. However, its encapsulation process is complex and costly. Moreover, in ultra-high temperature and ultra-high stress reservoirs, the outer shell of the encapsulation is easily damaged, leading to premature release of acid, making it difficult to penetrate deep into the reservoir. The effect of improving acid fracturing is generally poor and the cost-effectiveness is low.

[0006] Comprehensive analysis shows that existing technologies are insufficient to meet the requirements for volumetric stimulation of ultra-deep, ultra-high temperature, and ultra-high stress carbonate reservoirs. There is an urgent need to develop a stimulation method that is easy to operate, configure on-site, and pump, in order to significantly increase the distance of acid-etched fractures in ultra-high temperature carbonate reservoirs and to connect ultra-deep reservoirs. Summary of the Invention

[0007] To address the aforementioned technical challenges, this invention first simulates the temperature field changes within the fractures at the bottom of the well and near the wellbore under different pumping rates through oil-casing co-injection. Then, based on the simulation results, it optimizes the pumping procedure for acid fracturing stimulation, thereby increasing the acid etching distance of the acid-etched fractures and the reservoir control range of the artificial fractures. This achieves high conductivity even under high closure pressure, maintains the effectiveness of the artificial fractures, and promotes high and stable production. This provides a new technological approach for the efficient stimulation of ultra-deep carbonate reservoirs and a new technological means for the exploration and development of ultra-deep carbonate oil and gas resources.

[0008] To achieve this objective, the present invention adopts the following technical solution:

[0009] This invention provides a method for the stimulation of carbonate rock reservoirs based on temperature field changes, the method comprising the following steps:

[0010] (1) The temperature field changes in the bottom hole and near-wellbore artificial fractures of the carbonate reservoir were simulated under different pumping rates of the surface modification fluid injected with oil casing. The simulation results of the temperature field changes with the pumping rate in the bottom hole and near-wellbore artificial fractures were obtained.

[0011] (2) Optimize the pumping procedure for acid fracturing construction based on the simulation results described in step (1) and carry out acid fracturing construction.

[0012] The carbonate reservoir stimulation method described in this invention first simulates the temperature changes at the bottom of the well and near the wellbore under different pumping rates through oil-casing co-injection. Then, based on the simulation results, the pumping procedure for acid fracturing stimulation is optimized, including the selection of acid system and pumping rate, etc., to reduce acid corrosion on tubing to ensure the safety of ultra-deep well construction. At the same time, it effectively increases the distance of acid-etched fractures and increases the conductivity of artificial fractures, increases the stimulation volume, and promotes high and stable production of stimulated wells.

[0013] Preferably, the depth of the carbonate reservoir in step (1) is ≥7000m, for example, it can be 7000m, 7500m, 8000m, 8500m, 9000m or 9500m, etc.

[0014] Preferably, the temperature of the carbonate reservoir in step (1) is >160°C, for example, it can be 170°C, 180°C, 190°C, 200°C, 205°C, 210°C, 215°C, 218°C or 220°C.

[0015] Preferably, the ground modification fluid in step (1) includes: a combination of at least two of the following: weighted slickwater, weighted gel fracturing fluid, autogenous acid, or weighted crosslinking acid. Typical but non-limiting combinations include a combination of weighted slickwater and weighted gel fracturing fluid, a combination of weighted gel fracturing fluid and autogenous acid, or a combination of weighted crosslinking acid and weighted slickwater.

[0016] Preferably, the pumping displacement is 2.5–6.5 m³. 3 / min, for example, could be 2.5m 3 / min, 3.5m 3 / min, 4.5m 3 / min, 5.5m 3 / min or 6.5m 3 / min etc.

[0017] Preferably, the simulation results include: when the pump injection rate > 2.5 m³ / s. 3 / min (for example, it could be 2.6m) 3 / min, 2.8m 3 / min or 3.5m 3 When the pumping rate is ≥3.5 m³ / min, the temperature at the bottom of the well decreases by 28-32%, for example, 28%, 29%, 30%, 31%, or 32%; 3 / min (for example, it could be 3.5m) 3 / min, 3.6m 3 / min or 3.9m 3 When the temperature at the bottom of the well (e.g., / min) decreases by 38-42%, for example, it can be 38%, 39%, 40%, 41% or 42%, etc.; the temperature within the artificial fracture within 80m of the wellbore decreases by 28-32%, for example, it can be 28%, 29%, 30%, 31% or 32%, etc.; and the temperature of the tubing at the bottom of the well decreases by 18-22%, for example, it can be 18%, 19%, 20%, 21% or 22%, etc.

[0018] Preferably, the acid fracturing modification construction pumping procedure includes:

[0019] S1: Pump the first weighted slickwater from the annulus of the oil casing, and simultaneously pump the weighted gelling acid from the tubing;

[0020] S2: Pump heavy-duty fracturing fluid from the annulus of the casing and tubing, and simultaneously pump self-generating acid from the tubing.

[0021] S3: Pump the second weighted slickwater from the annulus of the oil casing, and simultaneously pump the weighted crosslinking acid from the tubing;

[0022] S4: Pump the third weighted slickwater from the annulus of the casing and tubing, while simultaneously pumping the weighted gel-carrying fracturing fluid from the tubing; then pump the displacement fluid from the tubing and shut in the well.

[0023] The present invention further optimizes step S1 by co-injecting the first weighted slickwater and weighted gelled acid into the casing, which can reduce the fracturing pressure to successfully open the carbonate reservoir, reduce the temperature in the near-wellbore fracture, and open artificial fractures. Step S2 by co-injecting the weighted gelled fracturing fluid into the casing can significantly reduce the wellhead construction pressure and form the artificial main fracture. Then, the self-generated acid stock solution pumped into the tubing is mixed with the weighted gelled fracturing fluid pumped into the casing and enters the carbonate reservoir at the bottom of the well to generate acid, which not only avoids corrosion of the tubing, but also increases the acid etching distance. Step S3 by co-injecting the second weighted slickwater and weighted cross-linked acid into the casing, the weighted cross-linked acid is used to etch the artificial fracture and improve its conductivity. Step S4 by co-injecting the third weighted slickwater and weighted gelled proppant fracturing fluid into the casing, proppant is added, and the proppant enters the artificial fracture formed in the above steps to improve the support of the artificial fracture, thereby improving the conductivity of the near-wellbore artificial fracture.

[0024] Preferably, the first weighting agent used in step S1 for the first weighted slickwater includes potassium formate solution and calcium bromide solution.

[0025] Preferably, the mass concentration of potassium formate solution in the first weighting agent is 35-45%, for example, it can be 35%, 37%, 40%, 42% or 45%, etc.

[0026] Preferably, the mass concentration of calcium bromide solution in the first weighting agent is 15-25%, for example, it can be 15%, 17%, 20%, 22% or 25%, etc.

[0027] Preferably, the density of the first weighted slickwater in step S1 is 1.2–1.6 g / cm³. 3 For example, it could be 1.2 g / cm³. 3 1.3g / cm 3 1.4g / cm 3 1.5g / cm 3 Or 1.6g / cm 3 wait.

[0028] In a further preferred embodiment of the present invention, the density of the first weighted slickwater in step S1 is 1.2–1.6 g / cm³. 3 This significantly increases the net pressure of the liquid column, and at the same time, the liquid is more likely to penetrate into the carbonate reservoir, thereby breaking up the carbonate reservoir.

[0029] Preferably, the viscosity of the first weighted slickwater in step S1 is 8 to 10 mPa·s, for example, it can be 8 mPa·s, 8.5 mPa·s, 9 mPa·s, 9.5 mPa·s or 10 mPa·s, etc.

[0030] Preferably, the weighting agent used in step S1 for the weighting gelling acid includes potassium formate solution.

[0031] Preferably, the mass concentration of potassium formate solution in the weighting agent used in the weighting gelling acid is 40-46%, for example, it can be 40%, 42%, 44% or 46%, etc.

[0032] Preferably, the density of the weighting gelling acid in step S1 is 1.32–1.38 g / cm³. 3 For example, it could be 1.32 g / cm³ 3 1.33g / cm 3 1.34 g / cm 3 1.36 g / cm 3 Or 1.38g / cm 3 wait.

[0033] Preferably, the acid concentration of the weighting gelling acid in step S1 is 15-25%, for example, it can be 15%, 18%, 20%, 22% or 25%, etc.

[0034] In a further preferred embodiment of the present invention, the acid concentration of the weighting gelling acid in step S1 is 15-25%, which corrodes the area near the wellbore, reduces the fracturing pressure and the temperature inside the artificial fracture near the wellbore, and at the same time acid-etches the artificial fracture near the wellbore, thereby improving the conductivity of the artificial fracture near the wellbore.

[0035] Preferably, the oil casing construction displacement ratio in step S1 is (1.8 to 2.2):1, for example, it can be 1.8:1, 1.9:1, 2.0:1, 2.1:1 or 2.2:1, etc.

[0036] Preferably, the weighting agent of the weighting gel fracturing fluid in step S2 includes a combination of potassium formate solution and calcium bromide solution.

[0037] Preferably, the concentration of potassium formate solution in the weighting agent of the weighting gel fracturing fluid is 35% to 40%, for example, it can be 35%, 36%, 37%, 38%, 39% or 40%, etc.

[0038] Preferably, the concentration of calcium bromide solution in the weighting agent of the weighting gel fracturing fluid is 16% to 22%, for example, it can be 16%, 17%, 18%, 19%, 20%, 21% or 22%, etc.

[0039] Preferably, the density of the weighted gel fracturing fluid in step S2 is 1.3–1.7 g / cm³. 3 For example, it could be 1.3 g / cm³ 3 1.4g / cm 3 1.5g / cm 3 1.6g / cm 3 Or 1.7g / cm 3 wait.

[0040] Preferably, the viscosity of the weighted gel fracturing fluid in step S2 is 200-220 mPa·s, for example, it can be 200 mPa·s, 205 mPa·s, 210 mPa·s, 215 mPa·s or 220 mPa·s, etc.

[0041] In a further preferred embodiment of the present invention, the density of the weighted gel fracturing fluid in step S2 is 1.3–1.7 g / cm³. 3 With a viscosity of 200–220 mPa·s, it can significantly reduce wellhead construction pressure and form artificial main fractures.

[0042] Preferably, the temperature resistance of the self-generating acid in step S2 is 100-200℃, for example, it can be 100℃, 120℃, 150℃, 180℃ or 200℃.

[0043] In a further preferred embodiment of the present invention, the self-generated acid pumped into the tubing in step S2 has a temperature resistance value of 100-200℃. The self-generated acid and the weighted gel fracturing fluid pumped into the casing are mixed at the bottom of the well before entering the carbonate reservoir, at which point the acid solution begins to be generated. This avoids corrosion of the tubing, improves the safety of ultra-deep well construction, and is also more conducive to increasing the acid etching distance and improving the acid fracturing effect of the self-generated acid.

[0044] Preferably, the oil casing construction displacement ratio in step S2 is (1.6 to 2.4):1, for example, it can be 1.6:1, 1.8:1, 2.0:1, 2.2:1 or 2.4:1, etc.

[0045] Preferably, the second weighting agent used in step S3 for the second weighting slickwater includes potassium formate solution.

[0046] Preferably, the mass concentration of potassium formate solution in the second weighting agent is 43-48%, for example, it can be 43%, 44%, 45%, 46%, 47% or 48%, etc.

[0047] Preferably, the density of the second weighted slickwater in step S3 is 1.30–1.40 g / cm³. 3 For example, it could be 1.30 g / cm³ 3 1.32g / cm 3 1.35g / cm 3 1.38g / cm 3 Or 1.40g / cm 3 wait.

[0048] Preferably, the viscosity of the second weighted slickwater in step S3 is 5 to 10 mPa·s, for example, it can be 5 mPa·s, 7 mPa·s, 9 mPa·s or 10 mPa·s, etc.

[0049] Preferably, the weighting agent used in step S3 for the weighting crosslinking acid includes potassium formate solution.

[0050] Preferably, the mass concentration of potassium formate solution in the weighting agent used in the weighting crosslinking acid is 43-47%, for example, it can be 43%, 44%, 45%, 46% or 47%, etc.

[0051] Preferably, the density of the weighted crosslinking acid in step S3 is 1.32–1.37 g / cm³. 3 For example, it could be 1.32 g / cm³ 3 1.33g / cm 3 1.34 g / cm 3 1.35g / cm 3 1.36 g / cm 3 Or 1.37g / cm 3 wait.

[0052] Preferably, the acid concentration of the crosslinking acid in step S3 is 20-30%, for example, it can be 20%, 23%, 25%, 27% or 30%, etc.

[0053] Preferably, the displacement ratio of the casing and oil pipe in step S3 is (0.8-1):(0.8-1), for example, it can be 0.8:0.9, 0.8:1, 0.9:1 or 1:1, etc.

[0054] In step S3 of this invention, a second weighted slickwater is pumped into the annulus of the casing, while a weighted cross-linked acid is pumped into the tubing. The weighted cross-linked acid is used to etch artificial fractures. The self-generated acid stock solution mentioned in step S2 can only generate acid to etch the formation after entering the deep part (>80m) of the carbonate reservoir fracture and reaching a certain temperature. Therefore, the injection of weighted cross-linked acid into the tubing in step S3 can improve the acid etching degree of the artificial fractures near the wellbore and improve its conductivity. The injection of the second weighted slickwater into the casing has the effect of reducing the wellhead construction pressure and the temperature inside the tubing, thereby reducing the corrosion of the tubing by the weighted cross-linked acid and improving construction safety.

[0055] Preferably, the third weighting agent used in the third weighting slickwater in step S4 includes a combination of potassium formate solution and calcium bromide solution.

[0056] Preferably, the mass concentration of potassium formate solution in the third weighting agent is 35-45%, for example, it can be 35%, 38%, 40%, 43% or 45%, etc.

[0057] Preferably, the mass concentration of calcium bromide solution in the third weighting agent is 18-24%, for example, it can be 18%, 20%, 22% or 24%, etc.

[0058] Preferably, the density of the third weighted slickwater in step S4 is 1.2–1.8 g / cm³. 3 For example, it could be 1.2 g / cm³. 3 1.3g / cm 3 1.4g / cm 3 1.5g / cm 3 1.6g / cm 3 1.7g / cm 3 Or 1.8g / cm 3 wait.

[0059] Preferably, the weighting agent used in the weighted gel fracturing fluid carrying sand in step S4 includes calcium chloride solution.

[0060] Preferably, the mass concentration of the weighting agent calcium chloride solution used in the weighting gel fracturing fluid is 52-58%, for example, it can be 52%, 53%, 54%, 55%, 56%, 57% or 58%, etc.

[0061] Preferably, the density of the weighted gel-carrying fracturing fluid in step S4 is 1.3–1.7 g / cm³. 3 For example, it could be 1.3 g / cm³ 31.4g / cm 3 1.5g / cm 3 1.6g / cm 3 Or 1.7g / cm 3 wait.

[0062] Preferably, the viscosity of the weighted gel fracturing fluid carrying sand in step S4 is 150-170 mPa·s, for example, it can be 150 mPa·s, 155 mPa·s, 160 mPa·s, 165 mPa·s or 170 mPa·s, etc.

[0063] In a further preferred embodiment of the present invention, step S4 involves pumping a third weighted slickwater into the annulus while simultaneously pumping a weighted gel-carrying fracturing fluid into the tubing. The third weighted slickwater reduces the wellhead working pressure and the temperature inside the tubing, thereby helping the gel-carrying fracturing fluid in the tubing maintain its sand-carrying capacity and preventing sand shedding from the wellbore. The weighted gel-carrying fracturing fluid acts as a proppant, entering the artificial fracture formed in the above steps to improve the support of the artificial fracture and thus enhance the conductivity of the near-wellbore artificial fracture.

[0064] Preferably, the oil casing construction displacement ratio in step S4 is (1.5 to 2):1, for example, it can be 1.5:1, 1.6:1, 1.7:1, 1.8:1, 1.9:1 or 2:1, etc.

[0065] Preferably, the displacement fluid in step S4 includes weighted slickwater and / or weighted fracturing fluid.

[0066] Preferably, the well shut-in time is 3.5 to 4.5 hours, for example, 3.5 hours, 3.7 hours, 4.0 hours, 4.2 hours, or 4.5 hours.

[0067] As a further preferred embodiment of the present invention, the method for stimulating carbonate reservoirs includes the following steps:

[0068] (1) For carbonate reservoirs with a depth ≥9000m and a temperature ≥200℃, simulations were conducted on the temperature field changes within the artificial fractures at the bottom of the well and near the wellbore under different pump injection rates when surface stimulation fluid was injected into the oil-casing mixture. The simulation results of the temperature field changes within the artificial fractures at the bottom of the well and near the wellbore with the pump injection rate were obtained; the pump injection rate was 2.5~6.5m. 3 / min;

[0069] The simulation results include: when the pump flow rate is >2.5m 3 When the pumping rate is ≥3.5 m³ / min, the temperature at the bottom of the well decreases by 28-32%; 3 At a rate of / min, the bottom hole temperature decreases by 38-42%, the temperature within the artificial fracture within 60m of the wellbore decreases by 28-32%, and the tubing temperature at the bottom of the well decreases by 18-22%.

[0070] (2) Optimize the pumping procedure for acid fracturing construction based on the simulation results described in step (1) and carry out acid fracturing construction.

[0071] The acid fracturing retrofit construction pumping procedure includes:

[0072] S1: Injected from the annulus of the oil jacket with a viscosity of 8–10 mPa·s and a density of 1.2–1.6 g / cm³. 3 The first step is to add weight to the slickwater, while simultaneously pumping acid into the oil pipe at a concentration of 15-25% and a density of 1.32-1.38 g / cm³. 3 The aggravating gelling acid, the discharge ratio of the oil casing is (1.8~2.2):1;

[0073] S2: The density injected from the annulus of the oil jacket is 1.3–1.7 g / cm³. 3 The heavy-duty gel fracturing fluid with a viscosity of 200-220 mPa·s was used, while the self-generating acid with a temperature resistance of 100-200℃ was pumped into the tubing. The pumping ratio of the tubing to the casing was (1.6-2.4):1.

[0074] S3: Pumped from the annulus of the oil jacket at a density of 1.30–1.40 g / cm³. 3 The second-weighted slickwater has a viscosity of 5–10 mPa·s, while the oil injection density via the tubing pump is 1.32–1.37 g / cm³. 3 For cross-linked acid with an acid concentration of 20-30%, the discharge ratio for oil casing construction is (0.8-1):(0.8-1).

[0075] S4: The density injected from the annulus of the oil jacket is 1.2–1.8 g / cm³. 3 The third type of slickwater was added, while the oil injection density via the tubing pump was 1.3–1.7 g / cm³. 3 A heavy-duty gel-based fracturing fluid with a viscosity of 150–170 mPa·s was used, and the flow rate ratio of the casing to the tubing was (1.5–2):1. Subsequently, the tubing was pumped with displacement fluid and the well was shut in for 3.5–4.5 hours.

[0076] It is worth noting that, based on the temperature field changes at the bottom of the well and within the artificial fractures during the modification process, this invention further optimizes the modification fluid system to adapt to the temperature gradient. Near the wellbore, the main component is high-temperature resistant heavy gel-carrying fracturing fluid to form a high-conductivity artificial support fracture. In the range of 50–120 m, the main component is a medium-high temperature autogenous acid system to generate acid and form etched fractures. In the range of 120–200 m in the far well zone, the main component is an ultra-high temperature autogenous acid system to generate high-concentration acid and form etched fractures.

[0077] Compared with the prior art, the present invention has at least the following beneficial effects:

[0078] The present invention provides a method for the stimulation of ultra-deep carbonate reservoirs based on temperature field changes. By simulating the temperature field changes in the artificial fractures at the bottom of the well and near the wellbore under different pumping rates, the method optimizes the selection of pumping fluid for acid fracturing stimulation. This significantly improves the distance of acid-etched fractures and the conductivity of artificial fractures in ultra-deep and ultra-high temperature carbonate reservoirs, achieving the goal of connecting ultra-deep reservoirs at great distances. It also reduces the corrosion of the tubing by the acid. Compared with conventional acid fracturing stimulation technology, the length of acid-etched fractures is increased by 2 to 3 times, and the stimulation volume is increased by more than 5 times, significantly expanding the effective stimulation volume and improving the stimulation effect. This method meets the goal of volume stimulation of ultra-deep, ultra-high temperature, and ultra-high stress carbonate reservoirs at great distances. Attached Figure Description

[0079] Figure 1 This is the construction curve of the carbonate reservoir stimulation method based on temperature field changes provided in Embodiment 1 of the present invention;

[0080] Figure 2 This refers to the effective artificial fracture morphology formed by the carbonate reservoir stimulation method based on temperature field changes provided in Embodiment 1 of the present invention. Detailed Implementation

[0081] The technical solution of the present invention will be further described below with reference to the accompanying drawings and specific embodiments. However, the following examples are merely simplified examples of the present invention and do not represent or limit the scope of protection of the present invention. The scope of protection of the present invention is determined by the claims.

[0082] Taking the FD1X well, an ultra-deep well in a western oilfield, as an example, the specific implementation of this invention will be described. This well is a highly deviated well with a depth of 9310m in the stimulated section. Pre-stimulation assessment indicates that the reservoir is dolomitic carbonate rock with a relatively dense matrix, porosity below 5%, and an average permeability of 0.5×10⁻⁶. -3 μm 2 Natural fractures are not well-developed and their effectiveness is poor. The reservoir temperature in the modified section reaches 201℃, and the minimum horizontal principal stress is nearly 180MPa according to well logging interpretation analysis.

[0083] The temperature field simulation described in the following embodiments uses fracturing design simulation software (FracproPT fracturing software from Cabot Corporation, USA). Specifically, by inputting the surface fluid temperature, reservoir temperature, wellbore structure, and drilling displacement, the software calculates the temperature drop at the bottom of the well after the fluid reaches the bottom of the well based on thermodynamic exchange theory, thus obtaining the temperature changes at the bottom of the well and in the artificial fractures near the wellbore during the drilling process.

[0084] Example 1

[0085] This embodiment provides a method for the stimulation of carbonate rock reservoirs based on temperature field changes, the method comprising the following steps:

[0086] (1) The temperature field changes in the artificial fracture at the bottom of the well and near the wellbore were simulated for a carbonate reservoir with a depth of 9310m and a temperature of 201℃ under different pumping rates of oil-casing mixed injection of 20℃ surface modification fluid (weighted slickwater, weighted gel fracturing fluid and weighted crosslinking acid). The simulation results of the temperature field changes with the pumping rate in the artificial fracture at the bottom of the well and near the wellbore were obtained.

[0087] The simulation results include: when the casing pump discharge rate is ≥3.5m 3 When the flow rate is ≥1.2m / min, the temperature at the bottom of the well drops to approximately 140℃; when the casing pump injection rate is ≥1.2m... 3 When the pump flow rate is ≥3.5m / min, the temperature inside the oil pipe drops to approximately 100℃; 3 At a rate of / min, the temperature inside the artificial fracture within 80m of the wellbore decreases to approximately 150℃;

[0088] (2) Optimize the pumping procedure for acid fracturing construction based on the simulation results described in step (1) and carry out acid fracturing construction.

[0089] The acid fracturing retrofit construction pumping procedure includes:

[0090] S1: Pumped from the annulus of the oil jacket with a viscosity of 8 mPa·s and a density of 1.5 g / cm³. 3 The first step is to add weight to the slickwater, while simultaneously pumping acid into the oil pipe at a concentration of 20% and a density of 1.35 g / cm³. 3 The aggravating gelling acid, the oil casing construction discharge ratio is 2:1;

[0091] The first weighting agent used in the first weighting slickwater is a combination of a 40% potassium formate solution and a 20% calcium bromide solution; the weighting agent used in the weighting gelling acid is a 45% potassium formate solution; and the pipeline's discharge rate is 4m. 3 / min, total liquid volume is 280m 3 The casing construction displacement is 2m. 3 / min, total liquid volume is 140m 3 ;

[0092] S2: The density injected from the annulus of the oil jacket is 1.5 g / cm³. 3 The heavy-duty gel fracturing fluid with a viscosity of 210 mPa·s was used, and the self-generating acid with a temperature resistance of 150℃ was pumped into the tubing. The construction displacement ratio of the tubing and casing was 1:2.

[0093] The weighting gel fracturing fluid uses a combination of 40% potassium formate solution and 20% calcium bromide solution as weighting agents. The self-generating acid stock solution is mixed with the weighting gel fracturing fluid and diluted to a 30% solution, achieving a hydrochloric acid concentration of 15% in a carbonate reservoir at 150°C. The tubing discharge rate is 1.3m. 3 / min, total liquid volume is 198m 3 The casing installation displacement is 2.6m. 3 / min, total liquid volume is 396m 3 ;

[0094] S3: The density injected from the annulus of the oil jacket is 1.35 g / cm³. 3 The second-weighted slickwater has a viscosity of 8 mPa·s, and the oil injection density via the tubing pump is 1.35 g / cm³. 3 For heavy cross-linking acid with an acid concentration of 25%, the construction discharge ratio of the oil casing is 1:1.

[0095] The second weighting agent used in the second weighting slickwater and the weighting agent used in the weighting crosslinking acid are both potassium formate solutions with a mass concentration of 45%. The construction discharge capacity of the oil casing is 2.1m. 3 / min, each with a liquid volume of 305m³ 3 ;

[0096] S4: The density injected from the annulus of the oil jacket is 1.5 g / cm³. 3 The third weighting of the slickwater, while the oil injection density via the tubing pump is 1.4 g / cm³. 3 The oil casing was pumped with a weighted gel-carrying fracturing fluid with a viscosity of 160 mPa·s, and the displacement ratio of the oil casing was 1.7:1. Subsequently, the oil casing was pumped with displacement fluid (weighted slickwater) and the well was shut in for 4 hours.

[0097] The construction displacement of the oil pipe is 2.5m. 3 / min, total liquid volume is 340m 3 The casing installation displacement is 1.5m. 3 / min, total liquid volume 200m 3 .

[0098] The construction curve in this embodiment is as follows: Figure 1 As shown, 80m of sand was added. 3 The sand concentration gradient is 90 kg / m³. 3 150kg / m 3 240kg / m 3 300kg / m 3 and 400kg / m 3 The discharge rate for oil-casing mixed injection tends to be 4m³. 3The oil pressure fluctuates only slightly during construction, with a pressure of approximately 0.5 liters per minute.

[0099] The final artificial crack morphology formed in this embodiment is as follows: Figure 2 As shown, the horizontal axis represents the length of the effective artificial fractures formed from the near-wellbore to the far-wellbore zone. The near-wellbore zone is a mixed zone of support fractures and acid-etched fractures, with support fractures being the dominant type. The far-wellbore zone is an acid-etched fracture zone, with acid-etched fractures being the dominant type. The effective artificial fracture length can reach more than 200m.

[0100] After modification using the method described in this embodiment, the daily oil production of the deep well FD1X is 85m³. 3 The daily gas production is 570,000 cubic meters, and the unobstructed flow rate has increased by 6.5 times compared to before the renovation.

[0101] In summary, this invention first simulates the temperature field changes within the artificial fractures at the bottom of the well and near the wellbore under different pumping rates during oil-casing co-injection. Then, based on the temperature field changes, it selects an acid fracturing stimulation pumping procedure that matches the temperature gradient, resulting in acid-etched fracture lengths exceeding 200m. Compared to conventional acid fracturing stimulation methods, this increases the fracture length by 2-3 times and the stimulation volume by more than 5 times, significantly expanding the effective stimulation volume. Furthermore, the method described in this invention has been widely applied in the stimulation of ultra-deep and ultra-high temperature (≥7000m, >160℃) carbonate reservoirs, with nearly 10 wells tested. The success rate reached 100%, and the average unobstructed flow rate of the stimulated wells increased by 5.1 times, with the average unobstructed flow rate per well reaching 3.2 million cubic meters of natural gas per day. This invention has significant reference value for improving the stimulation effect of ultra-deep and ultra-high temperature carbonate reservoirs.

[0102] The applicant declares that the above description is only a specific embodiment of the present invention, but the protection scope of the present invention is not limited thereto. Those skilled in the art should understand that any changes or substitutions that can be easily conceived by those skilled in the art within the technical scope disclosed in the present invention fall within the protection and disclosure scope of the present invention.

Claims

1. A method for stimulating carbonate reservoirs based on temperature field changes, characterized in that, The method for stimulating carbonate reservoirs includes the following steps: (1) The temperature field changes in the bottom hole and near-wellbore artificial fractures of the carbonate reservoir were simulated under different pumping rates of the surface modification fluid injected with oil casing. The simulation results of the temperature field changes with the pumping rate in the bottom hole and near-wellbore artificial fractures were obtained. (2) Optimize the pumping procedure for acid fracturing construction based on the simulation results described in step (1) and carry out acid fracturing construction.

2. The method for stimulating carbonate reservoirs according to claim 1, characterized in that, The depth of the carbonate reservoir in step (1) is ≥7000m; Preferably, the temperature of the carbonate reservoir in step (1) is >160°C.

3. The method for stimulating carbonate reservoirs according to claim 1 or 2, characterized in that, The pumping displacement in step (1) is 2.5–6.5 m³. 3 / min; Preferably, the simulation results include: when the pump injection rate > 2.5 m³ / s. 3 When the pumping rate is ≥3.5 m³ / min, the temperature at the bottom of the well decreases by 28-32%; 3 At a rate of / min, the bottom hole temperature decreases by 38-42%, the temperature within the artificial fracture within 80m of the wellbore decreases by 28-32%, and the tubing temperature at the bottom of the well decreases by 18-22%.

4. The method for stimulating carbonate reservoirs according to any one of claims 1 to 3, characterized in that, The acid fracturing retrofit construction pumping procedure includes: S1: Pump the first weighted slickwater from the annulus of the oil casing, and simultaneously pump the weighted gelling acid from the tubing; S2: Pump heavy-duty fracturing fluid from the annulus of the casing and tubing, and simultaneously pump self-generating acid from the tubing. S3: Pump the second weighted slickwater from the annulus of the oil casing, and simultaneously pump the weighted crosslinking acid from the tubing; S4: Pump the third weighted slickwater from the annulus of the casing and tubing, while simultaneously pumping the weighted gel-carrying fracturing fluid from the tubing; then pump the displacement fluid from the tubing and shut in the well.

5. The method for stimulating carbonate reservoirs according to claim 4, characterized in that, Step S1 The first weighting agent used in the first weighted slickwater includes potassium formate solution and calcium bromide solution; Preferably, the mass concentration of potassium formate solution in the first weighting agent is 35-45%; Preferably, the mass concentration of calcium bromide solution in the first weighting agent is 15-25%; Preferably, the density of the first weighted slickwater in step S1 is 1.2–1.6 g / cm³. 3 ; Preferably, the viscosity of the first weighted slickwater in step S1 is 8-10 mPa·s; Preferably, the weighting agent used in step S1 for the weighting gelling acid includes potassium formate solution; Preferably, the mass concentration of potassium formate solution in the weighting agent used in the weighting gelling acid is 40-46%; Preferably, the density of the weighting gelling acid in step S1 is 1.32–1.38 g / cm³. 3 ; Preferably, the acid concentration of the weighting gelling acid in step S1 is 15-25%; Preferably, the displacement ratio of the oil casing in step S1 is (1.8 to 2.2):

1.

6. The method for stimulating carbonate reservoirs according to claim 4 or 5, characterized in that, The weighting agent of the weighted gel fracturing fluid mentioned in step S2 includes a combination of potassium formate solution and calcium bromide solution; Preferably, the concentration of potassium formate solution in the weighting agent of the weighting gel fracturing fluid is 35% to 40%; Preferably, the concentration of calcium bromide solution in the weighting agent of the weighting gel fracturing fluid is 16% to 22%; Preferably, the density of the weighted gel fracturing fluid in step S2 is 1.3–1.7 g / cm³. 3 ; Preferably, the viscosity of the weighted gel fracturing fluid in step S2 is 200–220 mPa·s; Preferably, the temperature resistance of the self-generating acid in step S2 is 100-200℃; Preferably, the displacement ratio of the oil casing in step S2 is (1.6 to 2.4):

1.

7. The method for stimulating carbonate reservoirs according to any one of claims 4 to 6, characterized in that, Step S3: The second weighting agent used in the second weighting slick water includes potassium formate solution; Preferably, the mass concentration of potassium formate solution in the second weighting agent is 43-48%; Preferably, the density of the second weighted slickwater in step S3 is 1.30–1.40 g / cm³. 3 ; Preferably, the viscosity of the second weighted slickwater in step S3 is 5-10 mPa·s; Preferably, the weighting agent used in step S3 for the weighting crosslinking acid includes potassium formate solution; Preferably, the mass concentration of potassium formate solution in the weighting agent used in the weighting crosslinking acid is 43-47%; Preferably, the density of the weighted crosslinking acid in step S3 is 1.32–1.37 g / cm³. 3 ; Preferably, the acid concentration of the crosslinking acid in step S3 is 20-30%; Preferably, the displacement ratio of the oil casing in step S3 is (0.8~1):(0.8~1).

8. The method for stimulating carbonate reservoirs according to any one of claims 4 to 7, characterized in that, The third weighting agent used in the third weighting slickwater described in step S4 includes a combination of potassium formate solution and calcium bromide solution; Preferably, the mass concentration of potassium formate solution in the third weighting agent is 35-45%; Preferably, the mass concentration of calcium bromide solution in the third weighting agent is 18-24%; Preferably, the density of the third weighted slickwater in step S4 is 1.2–1.8 g / cm³. 3 ; Preferably, the weighting agent used in the weighted gel-carrying fracturing fluid in step S4 includes calcium chloride solution; Preferably, the mass concentration of the weighting agent calcium chloride solution used in the weighted gel-carrying fracturing fluid is 52-58%; Preferably, the density of the weighted gel-carrying fracturing fluid in step S4 is 1.3–1.7 g / cm³. 3 ; Preferably, the viscosity of the weighted gel-carrying fracturing fluid in step S4 is 150–170 mPa·s; Preferably, the displacement ratio of the oil casing in step S4 is (1.5~2):

1.

9. The method for stimulating carbonate reservoirs according to any one of claims 4 to 8, characterized in that, The well shut-in time in step S4 is 3.5 to 4.5 hours.

10. The method for stimulating carbonate reservoirs according to any one of claims 1 to 9, characterized in that, The method for stimulating carbonate reservoirs includes the following steps: (1) For carbonate reservoirs with a depth ≥9000m and a temperature ≥200℃, the temperature field changes in the artificial fractures at the bottom of the well and near the wellbore were simulated under different pumping rates of the surface modification fluid injected with the oil-casing mixture. The simulation results of the temperature field changes with the pumping rate at the bottom of the well and near the wellbore were obtained. The pump discharge rate is 2.5–6.5 m³. 3 / min; The simulation results include: when the pump flow rate is >2.5m 3 When the pumping rate is ≥3.5 m³ / min, the temperature at the bottom of the well decreases by 28-32%; 3 At a rate of / min, the bottom hole temperature decreases by 38-42%, the temperature within the artificial fracture within 60m of the wellbore decreases by 28-32%, and the tubing temperature at the bottom of the well decreases by 18-22%. (2) Optimize the pumping procedure for acid fracturing construction based on the simulation results described in step (1) and carry out acid fracturing construction. The acid fracturing retrofit construction pumping procedure includes: S1: Injected from the annulus of the oil jacket with a viscosity of 8–10 mPa·s and a density of 1.2–1.6 g / cm³. 3 The first step is to add weight to the slickwater, while simultaneously pumping acid into the oil pipe at a concentration of 15-25% and a density of 1.32-1.38 g / cm³. 3 The aggravating gelling acid, the discharge ratio of the oil casing is (1.8~2.2):1; S2: The density injected from the annulus of the oil jacket is 1.3–1.7 g / cm³. 3 The heavy-duty gel fracturing fluid with a viscosity of 200-220 mPa·s was used, while the self-generating acid with a temperature resistance of 100-200℃ was pumped into the tubing. The pumping ratio of the tubing to the casing was (1.6-2.4):

1. S3: Pumped from the annulus of the oil jacket at a density of 1.30–1.40 g / cm³. 3 The second-weighted slickwater has a viscosity of 5–10 mPa·s, while the oil injection density via the tubing pump is 1.32–1.37 g / cm³. 3 For cross-linked acid with an acid concentration of 20-30%, the discharge ratio for oil casing construction is (0.8-1):(0.8-1). S4: The density injected from the annulus of the oil jacket is 1.2–1.8 g / cm³. 3 The third type of slickwater was added, while the oil injection density via the tubing pump was 1.3–1.7 g / cm³. 3 A heavy-duty gel-based fracturing fluid with a viscosity of 150–170 mPa·s was used, and the flow rate ratio of the casing to the tubing was (1.5–2):

1. Subsequently, the tubing was pumped with displacement fluid and the well was shut in for 3.5–4.5 hours.

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