Method for improving and reconstructing volume of super-deep and thick reservoir

Abstract

The application discloses a method for improving and reconstructing volume of an ultra-deep and super-thick reservoir, selects a perforated section to be reconstructed, determines a setting position of a packer according to a longitudinal section span, divides the perforated section into multiple large sections through the packer, and divides each large section into multiple small layers according to longitudinal stress differences; obtains an injection time of a temporary plugging agent for each small layer according to fracture development conditions of near, middle and far well regions; reconstructs each large section from bottom to top, specifically, sequentially performs artificial fracturing on all the small layers in the same large section, performs in-fracture temporary plugging on the small layer according to the injection time of the temporary plugging agent, performs interlayer temporary plugging after the in-fracture temporary plugging is completed, and repeats the small layer reconstruction process until interlayer temporary plugging of all the small layers in the large section is completed, seals the large section through the packer, and repeats the large section reconstruction process, so that the volume reconstruction of the ultra-deep and super-thick reservoir is realized when reconstruction of all the large sections in the perforated section to be reconstructed is completed; and the method improves reconstruction effect and development benefit of the ultra-deep and super-thick reservoir well.

Description

Technical Field

[0001] This invention belongs to the field of oil and gas exploration and development technology, specifically to a method for increasing the volume of ultra-deep and thick reservoirs. Background Technology

[0002] In recent years, deep oil and gas has become an important area of ​​oil and gas exploration and development in my country. The reservoirs in this region are characterized by deep burial (6000-8500m), thick target layers (100-300m), high temperature, high pressure and high stress, low porosity and low permeability of the matrix, well-developed natural fractures, and strong heterogeneity. Fractures are the main reservoir space and flow channels. Maximizing the connection of natural fractures and increasing the vertical and horizontal stimulation volume of the reservoir is the key to increasing production.

[0003] For ultra-deep and thick reservoirs, current imaging logging can only interpret natural fractures within a 3-meter radius of the wellbore in the lateral direction. The development of natural fractures in the far well area is unclear, which increases the difficulty of selecting the best stimulation technology and optimizing the construction parameters. As a result, the stimulation of fracture development zones in the far well area has not been achieved in the lateral direction, and the degree of lateral stimulation of the reservoir is insufficient.

[0004] Early vertical stimulation primarily involved general stimulation of the entire wellbore. However, due to the heterogeneity of reservoir properties along the vertical direction, general stimulation failed to achieve uniform stimulation of all sub-layers within the entire reservoir, impacting the utilization rate of the vertical profile. Production profile testing results also confirmed that general stimulation of such thick reservoirs could only open 10%–20% of the perforated section. The extent of vertical stimulation was limited, failing to fully utilize the production capacity of each oil and gas layer, resulting in poor post-fracturing effects, short effective periods, and an inability to maximize production capacity.

[0005] Currently, most large-thick reservoirs employ stratified stimulation, which can be broadly categorized into two types: mechanical stratified stimulation and non-mechanical stratified stimulation. Mechanical stratified stimulation techniques include using various mechanical tools (bridge plugs, sliding sleeve packers, coiled tubing hydraulic jetting, etc.) to achieve stratified stimulation. Non-mechanical stratified stimulation techniques include temporary plugging stratified stimulation, extreme flow restriction stratified stimulation, and various chemical plug stratified stimulation methods. However, due to the high temperature and pressure conditions of ultra-deep wells, the reliability of non-mechanical stratified stimulation techniques in achieving precise stratification is low. Compared with general stimulation of adjacent wells, there is no significant improvement in stimulation effect. Therefore, it is concluded that the effectiveness of non-mechanical stratified stimulation in ultra-deep wells is relatively low. Compared to non-mechanical stratified stimulation, mechanical stratified stimulation has higher stratification efficiency in ultra-deep wells, but bridge plug pumping is difficult in ultra-deep, high-temperature, and high-pressure wells, resulting in higher well control risks and poor applicability. Coiled tubing hydraulic jetting stratified stimulation technology is not capable of operating at depths exceeding 7000 meters, and the friction of coiled tubing in ultra-deep wells is also high, limiting the pumping capacity and scale of the operation. Therefore, ultra-deep, high-temperature, and high-pressure wells generally use sliding sleeve packers for stratified stimulation. However, ultra-deep wells have high tubing friction, high wellhead construction pressure, and significant construction risks. After running too many sliding sleeve packers down the well, on the one hand, the tubing friction is even higher due to the reduced diameter of the ball seat, which greatly increases the construction risk. On the other hand, the packer setting position is generally deep, and packers often experience failures such as loss of sealing and sticking during unsealing, which leads to extended operation cycles and increased construction risks. Therefore, the number of sliding sleeve packers generally does not exceed 3 in ultra-deep wells, and they are stimulated in a maximum of 3 layers. This still cannot meet the needs of finely stratified vertical stimulation of ultra-deep and thick reservoirs. Summary of the Invention

[0006] To address the problems existing in the prior art, this invention provides a method for increasing the volume of ultra-deep and thick reservoirs. It requires wellhead operations to meet the well control requirements for high-temperature and high-pressure well construction, while simultaneously enabling full vertical and horizontal utilization of ultra-deep, high-temperature, and high-pressure reservoirs. This allows for precise stratified stimulation of the thick reservoirs vertically and maximizes the connection of natural fractures horizontally, thereby improving the stimulation effect and development benefits of ultra-deep wells in a safer and more efficient manner.

[0007] To achieve the above objectives, the present invention provides the following technical solution: a method for increasing the stimulation volume of ultra-deep and extremely thick reservoirs, the specific steps of which are as follows:

[0008] S1 selects the perforation section to be modified based on the reservoir properties, geostress, natural fracture development and leakage of the ultra-deep and thick reservoir. The setting position of the packer is determined according to the longitudinal stratigraphic span. The perforation section is divided into multiple large sections by the packer. Each large section is further divided into multiple small layers according to the longitudinal stress difference.

[0009] S2 determines the timing of plugging agent injection for each sub-layer when performing intra-fracture plugging based on the fracture development in the near, middle, and far well areas;

[0010] S3 modifies each large segment from bottom to top. Specifically, all small layers in the same large segment are artificially fracturing in sequence. According to the timing of the temporary plugging agent, the small layer is temporarily plugged within the fracture. After the temporary plugging within the fracture is completed, the interlayer temporary plugging is carried out. The above small layer modification process is repeated until all small layers in the large segment have completed interlayer temporary plugging. The large segment is then sealed with a packer. The above large segment modification process is repeated. When the modification of all large segments in the perforated segment to be modified is completed, the volume modification of the ultra-deep and thick reservoir is achieved.

[0011] Furthermore, in S1, the perforation section to be modified is determined based on the following conditions:

[0012] First, the reservoir and the interlayer are distinguished based on the minimum principal stress of the ultra-deep and thick reservoir.

[0013] Secondly, if the reservoir has well-developed natural fractures and the leakage rate is >100m 3 If the natural fractures are not developed and there is no leakage, then the reservoir with high matrix porosity and permeability and low geostress is selected as the perforation section to be modified, based on the reservoir properties and the magnitude of the minimum horizontal principal stress between layers.

[0014] Furthermore, in S1, the longitudinal span of the large section is 30-60m, and the sliding packer is seated between two large sections and maintains a distance of more than 10m between the upper and lower large sections; the span between each small layer within the large section is more than 10m, and the longitudinal stress difference between each small layer is 3-6MPa.

[0015] Furthermore, in S2, a natural fracture prediction technology combining imaging logging, remote sounding logging, and seismic geomechanics is used to predict the fracture development in near, middle, and far well areas.

[0016] Furthermore, the timing of applying temporary plugging agent within the fractures is determined based on the fracture development in the near, middle, and far well areas:

[0017] If the near-wellbore area is a natural fracture zone with large scale, inject a temporary plugging agent into the fracture during the middle and late stages of the pre-fluidization phase to temporarily plug the fracture.

[0018] If the natural fracture zone is well-developed in the intermediate and distant well areas, the time it takes for the artificial fracture to extend to the natural fracture zone at the current discharge rate is taken as the timing for injecting the temporary plugging agent into the fracture, based on the spatial distance between the wellbore and the predicted natural fracture.

[0019] The temporary sealant for the joint is either a powder or granules with a diameter of 1 mm, and the dosage range is 50-100 kg.

[0020] Furthermore, in S3, the smaller layers within the larger segment are fracturing sequentially according to the increasing ground stress.

[0021] Furthermore, in S3, the interlayer temporary plugging of the small layer is carried out using a combination of temporary plugging balls, which includes temporary plugging balls with a diameter of 1-5 mm and temporary plugging balls with a diameter of 5-10 mm, with a usage ratio of 2:1.

[0022] Furthermore, in S3, the dosage of the combined temporary plugging agent is calculated based on the dynamic joint height H, dynamic joint width W, and sealing depth L of the corresponding sub-layer, using the following formula:

[0023] The sealing volume V = 2H WL

[0024] The combined temporary blocking ball usage is M = 1000V.

[0025] Where 1000 is the bulk density of the temporary plugging ball, kg / m³ 3 The dynamic joint height H and dynamic joint width W were obtained by software simulation, and the sealing depth L was 0.6m.

[0026] Furthermore, in S3, the time it takes for the combined temporary plugging ball to reach the perforation zone is obtained based on the construction displacement. If the wellhead pressure shows new fracture pressure characteristics during this time, the small layer modification step is repeated to modify the next small layer within the large section until all small layers within the large section are modified.

[0027] Furthermore, the packer is a sliding sleeve packer. A suitable plugging ball is selected according to the size of the ball seat of the sliding sleeve packer. The plugging ball is dropped into the wellhead. The wellhead pressure change is observed according to the time it takes for the plugging ball to reach the position of the packer ball seat. If there is a pressure "rise and fall" characteristic at the wellhead when the sliding sleeve opens, it is judged that the plugging ball has been successfully set, the upper sliding sleeve opens, and the lower section is blocked. Otherwise, the sliding sleeve does not open, so the plugging ball is dropped again until the sliding sleeve is opened.

[0028] Compared with the prior art, the present invention has at least the following beneficial effects:

[0029] This invention provides a method for increasing the stimulation volume of ultra-deep and thick reservoirs. It utilizes packers to divide the perforated section to be stimulated into multiple large segments, and further divides these large segments into multiple smaller layers, achieving multi-level composite stratification of the perforated section. This segmented stratification effectively reduces the risks of fracturing operations, improves the targeting of fracturing to specific layers, and enables full stimulation of dominant reservoirs. It allows for the fracturing of as many reservoir layers as possible in a single fracturing operation, increasing the degree of vertical reservoir stimulation. Temporary plugging agents are used to temporarily plug each smaller layer both within the fracture and between layers. Intra-fracture temporary plugging increases the spread of artificial fractures laterally, while inter-layer temporary plugging... Plugging can enhance the vertical stimulation of reservoirs, and the combination of these two methods significantly increases the stimulation volume of ultra-thick reservoirs. Simultaneously, by combining natural fracture prediction technology with precise timing of temporary plugging agent application during fracture-based temporary plugging, the constraints of natural fractures on artificial fracture propagation can be overcome, allowing artificial fractures to extend further. Through these operations, efficient stratified stimulation of ultra-deep, high-temperature, high-pressure, and ultra-thick reservoirs is ultimately achieved, solving the problems of high difficulty and high construction risk in fine stratification of ultra-deep, high-temperature, high-pressure, and ultra-thick reservoirs. The method of this invention is an efficient and economical technological approach to increasing the stimulation volume of ultra-deep, ultra-thick reservoirs.

[0030] Furthermore, when performing interlayer temporary plugging, this invention uses temporary plugging balls with different particle sizes. According to the close packing theory, the pores between large-diameter temporary plugging balls are filled by small-diameter balls, which improves the pressure resistance of the plugging, saves the amount of temporary plugging agent, and achieves the effect of improving the temporary plugging pressure and the plugging effect.

[0031] Furthermore, this invention employs a combined natural fracture prediction technology, which can accurately predict the location and extent of natural fracture development within a 300-meter range of the wellbore. It can then target and communicate with natural fractures laterally, thereby temporarily plugging the natural fractures within the fractures and increasing the lateral extension distance and impact range of artificial fractures. Attached Figure Description

[0032] Figure 1 Schematic diagram illustrating the division of mechanical packers into layers and temporary plugging layers;

[0033] Figure 2 A natural fracture prediction technology that combines imaging logging, remote acoustic logging, and seismic geomechanics;

[0034] Figure 3 Construction curve of reservoir stimulation in well X6. Detailed Implementation

[0035] The present invention will be further described below with reference to the accompanying drawings and specific embodiments.

[0036] For ultra-deep, high-temperature, and high-pressure reservoirs, mechanical stratification processes suffer from high risks, difficulties, and high costs, limiting their application. This invention provides a method for increasing the stimulation volume of ultra-deep, extremely thick reservoirs. By increasing the lateral reach of artificial fractures and employing a combination of mechanical stratification and temporary plugging stratification in the vertical direction, the method aims to maximize the number of stratifications in the extremely thick reservoir and enhance the vertical stimulation degree, ultimately achieving the goal of increasing the stimulation volume. The specific steps are as follows:

[0037] Step 1: Select the best perforation interval based on reservoir properties, geostress, natural fracture development and leakage, and set reasonable interval span and stress difference within the interval;

[0038] Step 2: After perforation, the fracture development in the near, middle and far well areas is evaluated based on the natural fracture prediction technology that combines imaging logging, remote sounding logging and seismic geomechanics. This is used to optimize the construction parameters of each layer. Based on the spatial distance between the fracture and the wellbore, differentiated measures are taken for the use of intra-fracture plugging agents and the timing of plugging to increase the lateral stimulation volume. Then, the setting position of the sliding sleeve packer combination tool is designed.

[0039] Among them, imaging logging fracture prediction technology is used to evaluate the fracture development in the near-wellbore area of ​​0-3 meters; remote sounding logging fracture prediction technology is used to evaluate the fracture development in the intermediate well area of ​​3-30 meters; and seismic geomechanical fracture prediction technology is used to evaluate the fracture development in the distant area of ​​30-300 meters.

[0040] Step 3: First, modify the perforation section below the bottom sliding packer. Then, use a combination of temporary plugging balls to temporarily plug the opening in the pressed-open section. Then, modify other small layers in this section.

[0041] Step 4: Open the upper sliding sleeve, seal the lower reservoir, modify the upper reservoir according to the optimized construction parameters, and then use a combination of temporary plugging balls to temporarily plug the gaps in the upper reservoir that have been pressed open, and then modify other small layers in the same section.

[0042] Step 5: For reservoirs with a larger longitudinal span, add a set of sliding packers and in-section temporary plugging procedures, and repeat step (iv).

[0043] In step one, perforation sections are selected based on reservoir properties, minimum horizontal principal stress between layers, degree of development of near-wellbore natural fractures, and drilling fluid loss. Reasonable layer spans (span within a large section) and stress differences within sections (stress differences between small layers within a large section) are set, and different stimulation layers are divided using sliding sleeve packers.

[0044] First, the reservoir and the interlayer are distinguished based on the minimum principal stress of the modified layer. The stress difference between the reservoir and the interlayer is generally above 20 MPa.

[0045] Secondly, reservoirs with well-developed natural fractures (fracture density > 0.3 fractures / meter) and large leakage (leakage > 100 m3) should be prioritized as perforation sections. If natural fractures are not well-developed and there is no leakage, reservoirs with high matrix porosity and permeability and low geostress should be selected as perforation sections based on reservoir properties and the magnitude of the minimum horizontal principal stress between layers.

[0046] Secondly, the perforated section is divided into 1, 2, 3...n smaller layers. Based on the thickness and spacing of each smaller layer, it is further divided into 2 or 3 larger sections. The principle for stratification of these larger sections is that each section spans approximately 30-60 meters, ensuring reasonable spans between sections to prevent cross-layering and achieving complete stratification between sections. The span between smaller layers within a larger section is greater than 10 meters, and the stress difference between each smaller layer is between 3 and 6 MPa. According to construction data, reservoirs with large (>6 MPa) or small (<3 MPa) stress differences between smaller layers exhibit poor temporary plugging and diversion effects. This is because small stress differences lead to large fracture height extension, making separation difficult; large stress differences result in significant differences in physical properties between the upper and lower layers, requiring higher temporary plugging pressure. If the stress and physical properties of the smaller layers within a larger section are roughly equivalent, the span of the larger section should be shortened to ensure successful stimulation of the smaller layers. If the stress difference between the smaller layers within a larger section is large, the amount of temporary plugging agent used in that layer should be increased.

[0047] The number of large sections is determined by the thickness of the extremely thick reservoir. Around 150 meters is divided into 2 large sections, around 200 meters into 3 large sections, and over 200 meters into 4 large sections. Large sections are separated by sliding sleeve packers, and smaller layers within a section are temporarily plugged by temporary plugging balls, which are then pressed open sequentially.

[0048] In step two, after the modified layer division is completed, the perforation operation is finished, the construction parameters for each small layer are optimized, and the location of the sliding sleeve packer assembly tool is designed:

[0049] Based on the natural fracture prediction technology that combines imaging logging (0-3m), long-range acoustic logging (0-30m), and seismic geomechanics (0-300m), the fracture development in near, middle, and far well areas is evaluated to optimize the construction parameters of each sub-layer and determine the timing of injection of temporary plugging agent into the fracture.

[0050] Specifically, the detection range of imaging logging is within 3 meters of the wellbore. Therefore, imaging logging is used to predict natural fractures within 3 meters of the wellbore, long-range acoustic logging is used to predict fractures within 30 meters, and seismic geomechanics methods are used to predict fractures within 300 meters.

[0051] 1) If a large-scale natural fracture zone develops in the near-wellbore area, the natural fracture will constrain the propagation of hydraulic fractures, limiting the fracture propagation range to the near-wellbore area and restricting the lateral modification volume. In this case, it is necessary to increase the construction intensity and combine the use of in-fracture plugging agents and differentiated plugging timing measures to allow artificial fractures to propagate further. Specifically, in the mid-to-late stage of the pre-fluidization phase, in-fracture plugging agents are pumped in to reduce the influence of natural fractures in the near-wellbore area, thereby causing the artificial fractures to deflect excessively and achieve the modification of the far-wellbore area.

[0052] 2) If the natural fracture zone is well-developed in the intermediate and distant well areas, based on the numerical simulation results and the spatial distance between the wellbore and the natural fracture zone, the injection timing is determined by fracturing software such as Fracpro, Gohfer, and StimPlan, under the existing construction flow rate. The time it takes for the artificial fracture to extend to the predicted natural fracture is calculated, and this time is used as the injection timing for the temporary plugging agent in the fracture, thereby achieving full modification of the natural fracture in the intermediate and distant well areas and increasing the lateral modification volume.

[0053] The temporary sealant for the joint is either a powder or granules with a diameter of 1 mm, and the dosage range is 50-100 kg.

[0054] 3) Design the setting position of the sliding sleeve packer assembly tool. This position should be more than 10m away from the upper and lower sections. The setting position should ensure good cementing quality, avoid the casing coupling, and ensure that the stratification of the sections is more thorough and that no cross-layering occurs between sections.

[0055] Step 3: First, modify the perforation section below the bottom sliding packer. Then, use a combination of temporary plugging balls to temporarily plug the already opened sections. Finally, modify other small layers within this section.

[0056] 1) For the modification of the section below the bottom packer, first, based on the optimized construction parameters, pump non-crosslinked fracturing fluid at a low flow rate, and then slowly increase the flow rate. 0.3~0.5m 3 / my Initially, the fluid was being replaced with the original wellbore completion fluid. After observing significant fracture pressure, the flow rate was increased to [a higher level]. 1.5~2.0m 3 / my.

[0057] 2) After the construction pressure stabilizes, pump in cross-linked gel fracturing fluid, gradually increasing the flow rate while limiting the pressure. Determine the timing of injecting temporary plugging agent into the fracture based on the location of the natural fracture development zone, and reduce the flow rate accordingly. Up to 1-1.5m 3 / min Apply temporary plugging agent into the fracture, observe changes in wellhead pressure, and gradually increase the flow rate. Following the designed stepped increase method, gradually increase the sand ratio to complete the construction of this small section. After sand displacement is completed, replace with non-crosslinked fracturing fluid and gradually decrease the flow rate. Up to 1.0m 3 / min Left and right. A low-displacement sand mixing truck mixes and injects 1-5mm + 5-10mm combination temporary plugging balls to seal the already pressed-open layer section, temporarily plugging the joint;

[0058] Preferably, the dosage of the combined temporary plugging ball is optimized based on the dynamic joint height H, dynamic joint width W, and sealing depth L of the opened section. The formula for calculating the dosage of the combined temporary plugging agent is as follows:

[0059] The sealing volume V = 2H WL (m 3 )

[0060] The combined temporary blocking ball usage is M = 1000V (kg).

[0061] The bulk density of the temporary plugging ball is 1000 kg / m³. 3 Calculations were performed. Based on indoor experiments, the optimal ratio of 1-5mm temporary plugging balls to 5-10mm temporary plugging balls (2:1) yielded the best plugging effect. Therefore, the final usage of 1-5mm temporary plugging balls was 2M / 3, and the usage of 5-10mm temporary plugging balls was M / 3. Combining simulation results from software such as Fracpro, Gohfer, and StimPlan, the dynamic joint height H and dynamic joint width W of the opened section could be determined. The sealing depth L was calculated empirically as 0.6m.

[0062] 4) After determining the amount of temporary plugging balls used in the interlayer temporary plugging combination, at a low displacement ( 1.0m 3 / my Calculate the time it takes for the combined temporary plugging ball to reach the perforated section under the specified displacement (approximately). Observe the wellhead pressure changes. If the wellhead pressure shows new fracturing pressure characteristics, switch to cross-linked gel fracturing fluid according to the single-layer construction mode described above, gradually increase the displacement, and complete the construction of this small layer in a timely manner according to the design. If this large section is divided into several small layers, then according to the combined temporary plugging ball temporary plugging method described above, complete the construction of each small layer layer by layer according to the increasing ground stress.

[0063] After the reservoir below the bottom sliding packer is constructed, the discharge rate is gradually reduced to 1.5m³. 3 At a speed of approximately [speed not specified] / min, switch the fluid to non-crosslinked fracturing fluid. Select an appropriate plugging ball based on the size of the upper packer ball seat and drop the plugging ball at the wellhead. Observe the wellhead pressure change and determine the time it takes for the plugging ball to reach the upper packer ball seat position. If there is a pressure "rise and fall" characteristic at the wellhead when the sliding sleeve opens, it is determined that the plugging ball has been successfully set, the upper sliding sleeve has opened, and the lower reservoir has been plugged. Otherwise, if the sliding sleeve does not open, continue dropping plugging balls until the sliding sleeve opens.

[0064] Step 4: Open the upper sliding sleeve, seal the lower reservoir, modify the upper reservoir according to the optimized construction parameters, and then use a combination of temporary plugging balls to temporarily plug the gaps in the upper reservoir that have been pressed open, and then modify other small layers in that section.

[0065] After the sliding sleeve is opened, the fluid is switched to cross-linked gel fracturing fluid, and the first small layer of the upper section is constructed according to the design. Then, a combination of temporary plugging balls is used to temporarily plug the joint of the first small layer that has been opened in the upper section, and the second small layer is constructed. Then, the combination of temporary plugging balls is put in to modify each small layer of the section layer by layer. The specific steps are similar to the construction procedure in step three.

[0066] Step 5: If the longitudinal span of the modified well section is larger (span > 200m), add a set of sliding sleeve packers and a temporary plugging procedure within the section, and repeat step (IV) once.

[0067] Example

[0068] like Figure 1 As shown, well X6, an example well, is an ultra-deep, highly deviated well located in the Kelasu structural belt of the Kuqa Depression. The completed well depth is 7060m (vertical depth 6402.7m), with a maximum inclination angle of 76.4°. The completed formation is the Cretaceous Bashkichik Formation. The section to be stimulated is 6805–7020m (215m inclined thickness / 96.6m vertical thickness). The stimulation section has a large span of 215m and contains seven small layers. The natural fractures are highly heterogeneous, making uniform stimulation difficult. Mechanical stratification would require the installation of seven sets of sliding sleeve packers, posing a very high construction risk. If temporary plugging stratification is used entirely, the interlayer stress difference would result in poor deflection. As mentioned earlier, a multi-stage composite stratification stimulation technology combining mechanical packers and temporary plugging balls was selected, combined with imaging logging, remote acoustic logging, and seismic geomechanical natural fracture prediction technology to achieve sufficient stimulation of the reservoir both vertically and horizontally.

[0069] The specific steps are as follows: Step 1, as shown in Table 1, based on the drilling and logging data of this well and geological understanding, the perforation sections of this well are determined to be in 7 stages: Stage 1 (7010–7020 m), Stage 2 (6978–6985 m), Stage 3 (6959–6966 m), Stage 4 (6927–6937 m), Stage 5 (6898–6908 m), Stage 6 (6828–6838 m), and Stage 7 (6805–6812 m). Based on the vertical reservoir properties, minimum horizontal principal stress between layers, degree of natural fracture development, and thickness and span of the perforation sections, Stages 1, 2, and 3 are determined to form one large section with a span of 61 m; Stages 4 and 5 are determined to form one large section with a span of 39 m; and Stages 6 and 7 are determined to form one large section with a span of 33 m. Large sections are separated by sliding sleeve packers, and smaller sections within large sections are temporarily blocked by combined temporary plugging balls for inter-layer temporary blocking and layering modification.

[0070] Table 1 Classification Scheme for Well X6

[0071]

[0072] Step two, after completing the perforation operation, based on the development of natural fractures using imaging logging, remote acoustic logging, and seismic geomechanical exploration, and according to different fracture development degrees and fracture distances from the wellbore, such as... Figure 2 As shown, the construction parameters for each sub-layer were optimized. Levels 1, 2, and 3 all feature large-scale natural fracture zones near the wellbore; therefore, the drainage rate was rapidly increased to 5m³ during construction of each sub-layer within this large section. 3 At approximately [speed] / min, 50 kg of temporary plugging agent powder is pumped in during the middle of the pre-flush to mitigate the influence of natural fractures in the near-wellbore area and prevent excessive deflection of artificial fractures, thereby achieving the stimulation of the far-wellbore area. In the two large sections consisting of stages 4 and 5 and stages 6 and 7, a natural fracture zone develops at 200 meters from the maximum principal stress azimuth, calculated by software to be 4m... 3 At a flow rate of [flow rate] / min, the time for the artificial fracture to extend to the natural fracture zone is approximately 25 minutes. Therefore, during the construction of each small layer within these two large sections, approximately 50 kg of temporary plugging agent powder is pumped in during the pre-flush stage, lasting about 25 minutes. Based on existing construction experience and technical capabilities in this block, the sand addition intensity during fracturing is approximately 1.6 m. 3 Based on reservoir properties and sand body thickness, the construction scale was optimized, and the total sand addition was designed to be 166m³. 3 The sand addition amounts for the left and right, upper, middle, and lower sections are 40.7m³ and 40.7m³, respectively. 3 57.5m 3 67.8m 3 Based on an average sand ratio of 15% and a pre-fluid ratio of approximately 50%, the total liquid volume is calculated to be 2600 m³. 3 Then, based on the cementing quality and the span distance between the large sections, the packer setting positions were selected based on the cementing quality and the avoidance of the casing coupling. The positions of the three sliding sleeve packers were determined to be 6948m, 6865m and 6795m respectively.

[0073] Step three: After completing the above two steps, use a ball to open the lowest sliding sleeve, establishing a flow channel. First, modify the lowest layers of the well, namely stages 1, 2, and 3. Initially, use a low discharge rate of 0.3–0.5 m³ / h. 3 Pump non-crosslinked fracturing fluid at a rate of / min, replacing the original wellbore completion fluid, and gradually increase the pumping rate to 1.5–2.0 m³ / min. 3 / min ensures packer setting (with) Figure 3 Then, pump in cross-linked gel fracturing fluid, quickly increasing the flow rate to 5m³. 3 / min, the pumped liquid enters the second-level sub-layer with lower ground stress and better physical properties in the three perforation sections.

[0074] At approximately 15 minutes into the pre-flush, 50 kg of temporary plugging agent particles were pumped in to prevent excessive deflection of the artificial fractures near the wellbore. Then, the sand ratio was gradually increased using a stepped approach, and the construction of this small section was completed according to the design. The construction pressure was approximately 110 MPa, and 30 m of sand was added. 3 (Appendix) Figure 3 (Phase A). After completing the second stage of sand addition, the discharge rate was reduced to 2.0 m³. 3 / min pumping combined with temporary plugging balls for plugging. According to the calculation formula for the amount of combined temporary plugging balls, 90kg of 1-5mm temporary plugging balls and 45kg of 5-10mm temporary plugging balls were added. After the combined temporary plugging balls reached the bottom of the well, the pressure rise was observed to be about 6.8MPa, which is greater than the inter-layer stress difference, confirming the successful plugging of the second-stage small layer. (See attached...) Figure 3 (Phase B), the bottom level 1 was opened, and following the above sequence, the construction of the first level sub-layer was completed according to the design (see attached). Figure 3 (Phase C). The third level of sub-layers within this section was modified sequentially according to the above order (see appendix). Figure 3 (E stage).

[0075] Step four: After completing the major modifications to the lower section, reduce the emission volume to 1m³. 3 The pumping speed was 0.5 m³ / min to open the middle sliding sleeve, sealing the lower reservoir. A rise and fall in wellhead pressure was observed, indicating successful setting of the steel ball and opening of the middle sliding sleeve. Then, a low pumping speed of 0.5 m³ / min was applied. 3 Pump non-crosslinked fracturing fluid at a rate of / min. After the pressure stabilizes, switch to crosslinked gel fracturing fluid, gradually increasing the flow rate to 4.0 m³ / min. 3 At a rate of / min, the pumped fluid enters the fourth sub-layer, which has lower ground stress and better physical properties, within the two perforation sections of the central section. Because a natural fracture zone exists at 200 meters from the location of the maximum principal stress, approximately 50 kg of temporary plugging agent particles are pumped in during the pre-fluidization stage (around 25 minutes). Then, the sand ratio is gradually increased in a stepped manner to complete the construction of this sub-layer according to the design, adding 35 m³ of sand. 3 After the replacement of this small layer is completed, the construction displacement will be reduced to 2.0m. 3 The pumping rate was 1 / min for the combined temporary plugging ball sealing. Based on the formula for calculating the combined temporary plugging ball dosage, 150 kg of temporary plugging balls with a diameter of 1-5 mm and 75 kg of temporary plugging balls with a diameter of 5-10 mm were injected. After the combined temporary plugging balls reached the bottom of the well, the operating pressure was observed to rise to approximately 8.5 MPa, confirming successful diversion of the inter-layer temporary plugging. Then, the pumping rate was increased to 4.0 m³ / min. 3 Construction was completed at a rate of / min, according to the design. A total of 57.5m of sand was added during this renovation section. 3 Construction is progressing smoothly.

[0076] Step 5: After completing the major renovation of the central section, reduce the emission volume to 1m³. 3The pumping speed was reduced to 0.5 min. A steel ball was used to open the upper sliding sleeve, sealing the middle reservoir. A "rise and fall" change in wellhead pressure was observed, indicating successful steel ball setting. The upper sliding sleeve was then opened. First, the 7th sub-layer, with better physical properties and lower geostress, was fracturing. Then, a combination of temporary plugging balls was pumped in for inter-layer temporary plugging and redirection. The 6th sub-layer was then stimulated, following the specific steps outlined in step four. After completing these five steps, the well successfully completed the stratified fracturing operation, achieving precise stratified stimulation of seven sub-layers within a 215m span reservoir.

[0077] This invention solves the problems of high difficulty and high construction risk in fine-grained stratification of ultra-deep, high-temperature, high-pressure, and extremely thick reservoirs. It presents a technological method for increasing the stimulation volume of ultra-deep, extremely thick reservoirs. This method utilizes a multi-stage composite stratification approach combining sliding sleeve packers and temporary plugging balls, along with imaging logging, remote acoustic logging, and natural fracture prediction technology based on seismic geomechanics. This achieves efficient stratified stimulation of ultra-deep, high-temperature, high-pressure, and extremely thick reservoirs. This invention is a highly efficient and economical technological method for increasing the stimulation volume of ultra-deep, extremely thick reservoirs. The invention has achieved significant results in field application. In the X6 well of the Kuqa Depression in the Tarim Oilfield, this technology successfully achieved stratified stimulation. Post-stimulation blowout testing showed an oil pressure of 75 MPa with a 9mm nozzle, equivalent to a daily gas production of 74 × 10⁻⁶. 4 m 3 / d, the unobstructed flow rate increased from 300,000 cubic meters to 2.5 million cubic meters, an 8-fold increase, significantly improving the modification effect. Microseismic monitoring results show that the modified volume increased 3.5 times compared to previous modification technologies, achieving the optimized design goals. During the trial production period, gas production profile tests showed that the gas production of the seven modified sections ranged from 6.8 to 15.2 × 10⁻⁶ m³ / d. 4 m 3 / d, confirming that each sublayer was effectively modified. Microseismic monitoring and gas production profile testing results demonstrate the effectiveness of the technology of this invention, which will significantly improve the modification volume and effect of ultra-deep, high-temperature, high-pressure, and ultra-thick reservoirs.

Claims

1. A method for increasing the stimulation volume of ultra-deep and extremely thick reservoirs, characterized in that, The specific steps are as follows: S1 selects the perforation section to be modified based on the reservoir properties, geostress, natural fracture development and leakage of the ultra-deep and thick reservoir. The setting position of the packer is determined according to the longitudinal stratigraphic span. The perforation section is divided into multiple large sections by the packer. Each large section is further divided into multiple small layers according to the longitudinal stress difference. S2 determines the timing of plugging agent injection for each sub-layer when performing intra-fracture plugging based on the fracture development in the near, middle, and far well areas; S3 modifies each large segment from bottom to top. Specifically, all small layers in the same large segment are artificially fracturing in sequence. The small layer is temporarily plugged according to the timing of the injection of the intra-fracture plugging agent. After the intra-fracture plugging is completed, the inter-layer plugging is carried out. The above small layer modification process is repeated until all small layers in the large segment have completed inter-layer plugging. The large segment is then sealed with a packer. The above large segment modification process is repeated. When all large segments in the perforated segment to be modified are modified, the volume modification of the ultra-deep and thick reservoir is achieved. In S2, a natural fracture prediction technology combining imaging logging, remote sounding logging, and seismic geomechanics is used to predict the fracture development in near, middle, and far well areas. The timing of applying temporary plugging agent within the fracture zone is determined based on the fracture development in the near, middle, and far well areas: If the near-wellbore area is a natural fracture zone with large scale, inject a temporary plugging agent into the fracture during the middle and late stages of the pre-fluidization phase to temporarily plug the fracture. If the natural fracture zone is well-developed in the intermediate and distant well areas, the time it takes for the artificial fracture to extend to the natural fracture zone at the current discharge rate is taken as the timing for injecting the temporary plugging agent into the fracture, based on the spatial distance between the wellbore and the predicted natural fracture. The temporary sealant for the joint is either a powder or granules with a diameter of 1 mm, and the dosage range is 50~100 kg.

2. The method for increasing the stimulation volume of ultra-deep and thick reservoirs according to claim 1, characterized in that, In S1, the perforation section to be modified is determined based on the following conditions: First, the reservoir and the interlayer are distinguished based on the minimum principal stress of the ultra-deep and thick reservoir. Secondly, if the reservoir has well-developed natural fractures and the leakage rate is >100m 3 If the natural fractures are not developed and there is no leakage, then the reservoir with high matrix porosity and permeability and low geostress is selected as the perforation section to be modified, based on the reservoir properties and the magnitude of the minimum horizontal principal stress between layers.

3. The method for increasing the stimulation volume of ultra-deep and thick reservoirs according to claim 1, characterized in that, In S1, the longitudinal span of the large section is 30-60m, and the sliding packer is set between two large sections and maintains a distance of more than 10m between the upper and lower large sections; the span between each small layer in the large section is more than 10m, and the longitudinal stress difference between each small layer is 3-6MPa.

4. The method for increasing the stimulation volume of ultra-deep and thick reservoirs according to claim 1, characterized in that, In S3, the smaller layers in the larger segment are fracturing sequentially according to the increasing ground stress.

5. The method for increasing the stimulation volume of ultra-deep and thick reservoirs according to claim 1, characterized in that, In S3, interlayer temporary plugging of the small layers is carried out using a combination of temporary plugging balls, which includes temporary plugging balls with a diameter of 1-5 mm and temporary plugging balls with a diameter of 5-10 mm, with a usage ratio of 2:

1.

6. The method for increasing the stimulation volume of ultra-deep and thick reservoirs according to claim 5, characterized in that, In S3, the dosage of the combined temporary plugging agent is calculated based on the dynamic joint height H, dynamic joint width W, and sealing depth L of the corresponding sub-layer, using the following formula: The sealing volume V = 2H·W·L Combined temporary blocking ball usage M=1000V Where 1000 is the bulk density of the temporary plugging ball, kg / m³ 3 The dynamic joint height H and dynamic joint width W were obtained by software simulation, and the sealing depth L was 0.6m.

7. The method for increasing the stimulation volume of ultra-deep and thick reservoirs according to claim 1, characterized in that, In S3, the time it takes for the combined temporary plugging ball to reach the perforation zone is obtained based on the construction displacement. If the wellhead pressure shows new fracture pressure characteristics at this time, the small layer modification step is repeated to modify the next small layer in the large section until all small layers in the large section are modified.

8. The method for increasing the stimulation volume of ultra-deep and thick reservoirs according to claim 1, characterized in that, The packer is a sliding sleeve packer. Select an appropriate plugging ball according to the size of the ball seat of the sliding sleeve packer, and put the plugging ball into the wellhead. Observe the change in wellhead pressure at this time according to the time it takes for the plugging ball to reach the position of the packer ball seat. If there is a pressure "rise and fall" characteristic at the wellhead when the sliding sleeve opens, it is judged that the plugging ball has been successfully set, the upper sliding sleeve opens, and the lower section is blocked. Otherwise, if the sliding sleeve does not open, continue to put in plugging balls until the sliding sleeve opens.

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