Shale gas is a critical unconventional energy source in China (31.6 trillion m3 recoverable reserves), with commercial extraction relying heavily on hydraulic fracturing. Low-viscosity fluids (e.g., slickwater) have limited proppant-carrying capacity, easily causing premature settlement—addressed by bubble-suspended proppants (40/70 mesh quartz sands sprayed with a surfactant for bubble adsorption). However, insufficient understanding of bubble-suspended proppants’ migration (especially in complex fractures) limits their deployment and fracturing optimization. This study focused on bubble-suspended proppants’ migration via an integrated method: large-scale visualized experiments compared them with conventional proppants (digimizer extracted sand dune parameters); an Eulerian three-phase flow model simulated bubble-suspended proppants’ migration (validated by experiments); a complex fracture network model (main/crossed/secondary fractures) further explored their transport. Results showed bubble-suspended proppants’ superior transport: longer stable migration in main fractures (overcoming gravity), less junction accumulation in crossed fractures (preventing blockage), and uniform filling in secondary fractures (via bubble suspension). A higher gas-solid ratio, appropriate pumping rate, and lower density enhanced their performance. This study clarifies the migration mechanism of bubble-suspended proppants in a gas-liquid-solid three-phase system within complex fractures and establishes targeted simulation and prediction methods. It provides accurate theoretical support and engineering guidance for the parameter optimization of bubble-suspended proppant fracturing and sand placement processes. This achievement effectively promotes the implementation of the high-efficiency sand placement technology featuring “low fluid volume and high proppant concentration,” significantly enhances fracture conductivity, helps improve shale gas recovery, and provides important support for the economy and sustainability of shale gas development.

The compaction and grain crushing (GC) of deep-buried sandstone reservoirs play a crucial role in the evolution of reservoir quality. Significant differences exist in the compaction behavior and pore preservation of reservoirs with varying sedimentary grain size characteristics. However, there is a lack of quantitative assessments and mechanistic studies of these processes. This study utilizes the Discrete Element Method (DEM) to simulate two groups of samples with different grain size distributions (GSD) to explore the processes of compaction and pore preservation. Group A samples exhibit a unimodal Gaussian GSD, with the median grain size (Md) gradually increasing, while Group B samples share the same Md but differ in GSD type. The results indicate that with increasing stress, the samples undergo three compaction stages: grain rearrangement (S1), intense GC and rearrangement (S2), and weak GC and rearrangement (S3). In S1, grains rearrange with minimal sliding and no GC, resulting in a low porosity loss rate (Delta phi/Delta sigma). In S2, GC intensifies, with fragments sliding and filling the pores between grains, leading to a significant increase in Delta phi/Delta sigma. In S3, a high coordination number reduces GC, and small pores restrict the movement of fragments, resulting in a decrease in Delta phi/Delta sigma. Md has no effect on Delta phi/Delta sigma in S1. However, samples with smaller Md experience weaker GC and have smaller pore size, making it more difficult for fragments to fill the pores during S2. In S3, samples with larger Md have higher coordination numbers, providing stronger buffering against GC and resulting in lower Delta phi/Delta sigma. Additionally, GSD does not affect Delta phi/Delta sigma during S1. In S2, sample with a coarse-skewed bimodal Gaussian GSD exhibited the weaker GC, smaller difference between pore size and fragment size, resulting in a relatively low Delta phi/Delta sigma. Therefore, under deep burial conditions, sandstone with small grain size and coarse-skewed bimodal GSD demonstrates strong resistance to compaction and effective pore preservation.

Most gas reservoirs will experience water invasion after development, which reduces gas recovery. This study proposed a novel large-scale experimental method based on artificial core fabrication and rock electricity theory. Four physical models were prepared (L x W x H = 32 cm x 32 cm x 15 cm): one matrix-vugs model was dominated by matrix pores and vugses, and three vugs-fracture models were characterized by the coexistence of matrix pores, vugses, and fractures. The experimental results indicated that (1) The matrix-vugs model exhibited typical characteristics of bottom water drive. Water invaded slowly, and the ultimate gas recovery reached 85.79%, with residual gas mainly at reservoir edges. (2) The vugs-fracture models showed rapid water channeling along fractures, causing early water breakthrough and a much lower recovery of 49.57%, with residual gas concentrated in fractured zones. (3) Reducing the early production by 50% and 75% can increase the ultimate recovery by 8.15% and 10.39%, respectively, with water invasion significantly controlled. (4) The matrix zone was developed first, followed by the fractured zone, which will balance reserve utilization and enhanced recovery. This method offered a new approach for simulating water invasion in complex gas reservoirs.

The lithology of the transitional facies of the Longtan Formation in the southern Sichuan Basin is complex, with soft/hard thin interlayers of mud shale, sandstone, and limestone. Drilling this layer often results in wellbore instability, including frequent blockages, tripping resistance, and sticking. This study focuses on a shale gas block in the Longtan Formation in Zigong, where a geomechanical profile was established by integrating ground stress, rock parameter tests, and logging data. The critical collapse pressure was calculated, and wellbore instability was simulated using the Mohr–Coulomb failure criterion and the discrete element method. Results indicate significant variability in the mechanical strength of the rocks, with notable longitudinal heterogeneity and a high risk of wellbore instability. The critical collapse pressure equivalent density ranges from 1.05–1.69 g/cm3. Under low-density conditions, wellbore expansion and reduction coexist due to local shear and dropping. Even when the drilling fluid density exceeds the collapse pressure equivalent, stress imbalance can still cause localized dropping at lithologic interfaces. These findings offer valuable insights into the mechanical mechanisms behind wellbore instability in formations with soft/hard thin interlayers and provide guidance for the prevention and control of wellbore instability and associated risks.

The exploration potential of the Permian igneous rocks in the Sichuan Basin is enormous, but the lithology and physical properties of the reservoirs in this formation are very complex. Local stratification and fracture development lead to wellbore instability incidents such as stuck pipes and wellbore collapse during drilling and completion. To investigate the impact of fracture development on wellbore stability, considering the cementation of igneous rocks, we used the discrete element method to construct wellbore models for two classic igneous rock formations, tuff and breccia. We simulated the failure characteristics of different fracture densities, fracture dip angles, and groups of fractures, studying the wellbore instability patterns and their micromechanisms. The results show that: ① Discrete element numerical experiments can effectively simulate the strength and deformation characteristics of igneous rock formations; ② With increasing fracture density, the formation failure mode shows a gradual deterioration trend. When the number of fractures reaches 200, the number of microcracks in breccia and tuff are 476 and 243, respectively, with more significant changes in the failure pattern of breccia; ③ Fractures developed at 45° to 60° have the most significant weakening effect on formation cementation, with the overall formation failure pattern developing perpendicularly to the fracture dip angle and expanding outward; ④ Groups of intersecting fractures have a dual role in the initiation and development of microcracks. Microcracks first appear at fracture intersections, where the formation matrix cementation restricts the expansion of some cracks, while the cementation failure of fractures promotes the formation of shear bands. The study results provide valuable insights into the micromechanical mechanisms of fracture development affecting wellbore instability during drilling and completion in igneous rock formations.

Direct injection of low- solid curable materials with drilling fluid has the potential to streamline the construction process and reduce costs associated with lost circulation. In this paper, the basic properties, curing behavior, plugging performance, and acid- dissolution characteristics of the mixed slurry using self- made Magnesium oxide (MgO)- based curing material (MCM) combined with polysulfonate drilling fluid were investigated. The basic properties of the mixed slurry exhibited excellent pollution resistance of MCM. The mixed slurry containing 30-50% MCM showed the volume shrinkage ranging from -1.55% to 3.02% and the curing time spanning from 1.67 hours to 2.17 hours, showing exceptional curing behavior. The drilling fluid had no effect on the final strength, but the different components had either negative [sulfonated phenolic resin (SMP- 1)] or positive [sodium hydroxide (NaOH)] effects on the hydration process through scanning electron microscope (SEM), X- ray diffraction (XRD), and energy- dispersive spectrometer (EDS). Besides, retarder effectively extended the curing time to 270-470 minutes without compromising the strength of the final cured product or affecting formation processes, which can be used to control the curing time of MCM. Pressure- resistance testing revealed that sealing zones and induced cracks with rough surfaces exhibited higher interfacial bonding capacity, while induced cracks as small as 2 mm showed minimal leakage at pressures up to 16 MPa and eventually stabilized at 14 MPa. Furthermore, acid dissolution tests demonstrated complete release of cured products in a short time, offering potential benefits for reservoir protection. Field application examples further confirmed the compatibility of MCM with drilling fluid and its effectiveness in sealing cracks.

Coal-bed methane (CBM), as a key component of unconventional natural gas production, often encounters wellbore stability challenges during development. The inherent fragmentation and weak cementation of coal contribute to wellbore instability, while horizontal drilling challenges mainly arise from thin interlayers and fractured zones. However, many existing studies rely on simplifying assumptions, making it increasingly important to accurately model the stress state around wellbores with complex trajectories. In this paper, a hybrid-grid geological model incorporating stress-fluid coupling is developed using the finite difference method (FDM) to more realistically represent subsurface conditions, especially at lithologic interfaces. This study investigated stress distributions around a horizontal section under varying drilling fluid densities using the established model that accounts for lithological variations, and analyzed mechanical behavior under various dogleg severity, drilling fluid soaking times, and trajectory extension conditions. The results indicate that a wellbore located near a fault or interface exhibit more uneven stress distributions and face a higher risk of instability. Increasing the density of the drilling fluid enhances wellbore support, significantly reducing damage. Once a critical density (1.70 g/cm3) is reached, the effect stabilizes, ensuring wellbore stability. Moreover, larger dogleg severity expands the damage zone. As soaking time increases, the influence of shear stress on wellbore instability grows progressively stronger. Overall, the geological model provides a new approach for designing well trajectories during the pre-drilling phase and for making real-time adjustments during drilling.

The coal formation exhibits poor cementation, leading to the risk of wellbore instability during drilling. Ensuring the stability of the wellbore in coal formation is of great significance for the safe and efficient exploitation of coalbed methane. This paper established a geological model considering fault (weak plane of coal) and two types of formations based on the actual trajectory extension of horizontal wells using Rhinoceros. The model accurately reflects the penetration of horizontal well trajectories through undulating formations. The fluid–solid interaction simulation of the stress field and plastic zone distribution around the wellbore was conducted using FLAC3D software. The critical collapse pressure was calculated based on classic rock mechanics theories using MATLAB to verify the accuracy of the numerical simulation results. The results show that the difference between the maximum and minimum horizontal principal stresses around wellbore is 35–55 MPa at 0° and 180°, and 5–40 MPa at 90° and 270°. Therefore, the risk of wellbore instability is higher near 0° and 180°. As the drilling fluid density increases (from 1.00 g/cm3 to 1.75 g/cm3), the diameter of the plastic zone in the coal formation decreases from 9.2 times to 0.3 times, and in the fault, it decreases from 17 times to 0.7 times. According to the Mohr–Coulomb criterion, the lower limit of the safe density window for drilling fluid is calculated to be 1.67 g/cm3. At a drilling fluid density of 1.70 g/cm3, the diameters of the plastic zones in the fault and coal formation are 1.43 times and 1.14 times, respectively, that of the sandstone formation. At a drilling fluid density of 1.70 g/cm3, as the wellbore curvature increases, the diameter of the plastic zone around the wellbore increases from 0.52 times to 1.02 times. This paper provides a novel method for analyzing wellbore stability that reflects the real formation and wellbore trajectory, which is beneficial for the safe and efficient drilling of coal formation.

China possesses substantial shale oil and gas resources, a significant portion of which is recoverable. Hydraulic fracturing technology plays an essential role in enhancing oil recovery. However, accurately predicting the propagation of hydraulic fractures in complex reservoirs remains challenging due to the inherent weakness of shale formations. Based on the discrete element method (DEM), a coupled hydraulic fracturing model that incorporates perforation erosion and flow distribution was developed. This model simulates the mechanical interactions between hydraulic fractures and natural weak planes, providing insights into fracture morphology, perforation erosion, flow distribution, and net pressure inversion. Results show that low cementation interface angles facilitate vertical fracture propagation, while higher angles restrict vertical propagation by capturing fractures. Due to shear stress concentration, bedding planes limit vertical propagation through shear failure, and natural fracture zones exacerbate non-uniform propagation by inducing stress perturbations. Furthermore, the degree of non-uniform fracture propagation is influenced by flow distribution, which is significantly affected by perforation friction. The findings reveal the mechanisms of hydraulic fracture propagation and the uneven propagation behavior of multiple fracture clusters, offering a theoretical foundation for understanding the governing principles of hydraulic fracture behavior, particularly in explaining the non-uniform propagation of multi-cluster hydraulic fractures in layered reservoirs.

In large-scale hydraulic fracturing of unconventional reservoirs, high viscosity friction reducers (HVFR) which employ high concentration polymers of high molecular weight can improve proppant suspension, but still lack long-distance and long-time proppant transport capability. Herein, for the first time, we report a fracturing fluid made of self- assembled low molecular weight polymer and a surfactant (LMPS). When using only 0.1 wt% of the polymer, LMPS has a viscosity of 29.6 mPa.s.s (170 s(-1) , 25 degree celsius) and can achieve full suspension of 40/70 mesh sand at 80 degree celsius. LMPS can form robust short molecular chain networks through numerous self-assembling association sites, rather than relying on entanglement. Notably, it achieves a minimum loss tangent as low as 0.1 in the viscoelastic response, demonstrating its strong elastic characteristics. According to the creep-recovery test, the strain recovery rate (87.9 %) of LMPS at 0.2 wt% polymer concentration far exceeds that of the HVFR with a concentration as high as 10.1 %. This indicates that LMPS has a stronger deformation-resisting ability, thereby preventing proppant settling. Taking advantage of LMPS' superior proppant suspension capability, proppant can move with the slurry to the whole fracture for placement, while the HVFR provides only 48 % height support of the fractures in the form of dunes. A field trial shows that at a polymer concentration of 0.2 wt%, LMPS can stably transport 20/40 mesh quartz sand under a slurry rate of 2.8 m(3)/min and a proppant concentration of 635 kg/m(3) during the fracturing process.

Salt dissolution induced by drill - in fluid loss is a frequent occurrence in saline- lacustrine reservoirs, which can potentially result in serious formation damage. In light of this, an experimental study was conducted to investigate the salt mineral dissolution and dynamic damage in the rock samples collected from a saline- lacustrine carbonate reservoir and the response of porefracture structures using the in - situ drill - in fluids. The study further involved analyzing the formation- damage- control (FDC) ability of the in - situ drill - in fluids. The results indicated that although salt dissolution significantly increased the pore size of the tight matrix and the width of natural fractures, improving the conductivity of seepage channels, the increase in porefracture size may have greatly aggravated the drill - in fluid loss during the process. The continuous serious filtrate loss, lower pressure- bearing capacity of the plugging zone, and lower permeability recovery rate (PRR) of rock indicated poor FDC performance of in - situ brine drilling fluids for the salt- dissolved core samples. The FDC performance of drill - in fluids for saline- lacustrine carbonate reservoirs was optimized based on the response of reservoir porefracture structure to salt dissolution and the theory of slightly underbalanced activity. The experimental results showed that the optimized drill - in fluids had better FDC ability, with an average PRR increase of 14.04%. Field application indicated that the optimized drill - in fluids reduced the drill - in fluid loss by 76.48%, shortened the drilling cycle by 45.20%, and increased the initial production capacity per well by 7.70%. This study can provide insightful guidance to optimize the FDC performance of drill - in fluids for saline- lacustrine hydrocarbon reservoirs during drilling.

For the analysis of the formation damage caused by the compound function of drilling fluid and fracturing fluid, the prediction method for dynamic invasion depth of drilling fluid is developed considering the fracture extension due to shale minerals erosion by oil-based drilling fluid. With the evaluation for the damage of natural and hydraulic fractures caused by mechanical properties weakening of shale fracture surface, fracture closure and rock powder blocking, the formation damage pattern is proposed with consideration of the compound effect of drilling fluid and fracturing fluid. The formation damage mechanism during drilling and completion process in shale reservoir is revealed, and the protection measures are raised. The drilling fluid can deeply invade into the shale formation through natural and induced fractures, erode shale minerals and weaken the mechanical properties of shale during the drilling process. In the process of hydraulic fracturing, the compound effect of drilling fluid and fracturing fluid further weakens the mechanical properties of shale, results in fracture closure and rock powder shedding, and thus induces stress-sensitive damage and solid blocking damage of natural/hydraulic fractures. The damage can yield significant conductivity decrease of fractures, and restrict the high and stable production of shale oil and gas wells. The measures of anti-collapse and anti-blocking to accelerate the drilling of reservoir section, forming chemical membrane to prevent the weakening of the mechanical properties of shale fracture surface, strengthening the plugging of shale fracture and reducing the invasion range of drilling fluid, optimizing fracturing fluid system to protect fracture conductivity are put forward for reservoir protection.

Huge numbers of induced unpropped (IU) fractures are generated near propped fractures during hydraulic fracturing in shale gas reservoirs. But it is still unclear how their fracture space and conductivity evolve under in-situ conditions. This paper prepares three types of samples, namely, manually split vertical/parallel to beddings (MSV, MSP) and parallel natural fractures (NFP), to represent the varied IU fractures as well as their surface morphology. Laser scan and reconstruction demonstrate that the initial fracture spaces of MSVs and MSPs are limited as the asperities of newly created surfaces are well-matched, and the NFPs have bigger space due to inhomogeneous geological corrosion. Surface slippage and consequent asperity mismatch increase the fracture width by several times, and the increase is proportional to surface roughness. Under stressful conditions, the slipped MSVs retain the smallest residual space and conductivity due to the newly sharp asperities. Controlled by the bedding structures and clay mineral hydrations, the conductivity of MSPs decreases most after treated with a fracturing fluid. The NFPs remain the highest conductivity, benefitting from their dispersive, gentle, and strong asperities. The results reveal the diverse evolution trends of IU fractures and can provide reliable parameters for fracturing design, post-fracturing evaluation, and productivity forecasting.

At present, reservoir simulation is widely used in making reservoir development projects or reservoir adjustment projects. It is rarely used in reservoir production and development management. The main task of reservoir production and development management is to put forward stimulation measures and injection and production adjustment project. There are three main problems currently encountered. Due to the lack of measured single layer's production data, it is difficult to optimize the injection and production adjustment project. It is difficult to quantify and predict the effect after carry out the stimulation measures. Therefore, it is difficult to optimize stimulation measures. Even if the stimulation measures is made, it is difficult to predict the effect after apply. It is hard to predict when key indicators such as pressure recovery inflection point and water cut inflection point will occur. It is impossible to quantitatively evaluate and compare reservoir development effects under different injection-production ratios. It is not possible to predict the changes of reservoir dynamics as soon as possible and optimize injection and production adjustment project according to the changes. After the application of the adjustment project for a period of time, the optimization can be continued according to the application effect. Taking an offshore reservoir as an example, to solve the problems encountered in reservoir production and development management, the application of reservoir simulation model is carried out. For the wells with test data, the virtual well is applied to ensure that the stratified water injection data of the reservoir simulation model is consistent with the measured data. According to the industry standards, the relevant parameters are adjusted reasonably, and the reservoir simulation model with high accuracy of history matching is established. By setting related keywords in the .sch file, the calculation and output of the stratified data are realized. Each time step of stratification, well group, well zone production data can be calculated. The prediction of measure adjustment project and the optimization of injection and production project are realized. After the implementation of the adjustment project, the tracking display appears application effect is good.

A novel apparent permeability model of shale gas is derived considering the stress dependence, the thickness of adsorbed layer, slip flow, Knudsen diffusion and surface diffusion. The thickness of the adsorbed layer is derived according to the porosity occupied by the adsorbed phase in the capillary model. Consequently, the impact of the adsorbed layer and its change with the pressure on apparent permeability can be clearly revealed in the novel model in ultramicropores, or micropores, or mesopores, or macropores. With the stress dependence and the thickness of adsorbed layer considered simultaneously, the effective hole radius is substantiated to be smaller than the original hole radius to a certain degree. On account of this, the ratio of apparent permeability to the intrinsic permeability computed by the novel model is a lot distinct from the existing models. As the pressure increases, the ratio in the novel model declines from above 1 to below 1, followed by a slight upward trend. However, the ratio in other models drops all the way and yet remains above 1 as the pressure rises. Finally, the impact factors of permeability, including stress dependence coefficient, hole radius, reservoir pressure, Langmuir volume and Langmuir pressure, are analyzed. The contribution of slip flow, Knudsen diffusion and surface diffusion to apparent permeability is also illustrated.

Drilling fluid loss is an important engineering and technical problem that restricts deep and ultra-deep drilling, and the well loss in reservoir interval is the most serious reservoir damage mode in drilling and completion stage. It is the main way to control lost circulation to use the bridging plugging material to block the fracture leakage channel. However, the design of bridge plugging formula often adopts the empirical or semi-empirical method, leading to low plugging success rate and poor plugging effect. By the CFD-DEM simulation, it is clear that the bridge retention, accumulation filling and pressurized plugging are three key links in the formation process of fracture sealing layer. Considering the efficient bridging and compact filling of the plugging material, and based on the concept of “absolute bridge addition” and the theory of tight packing, a new experimental formula design method for pressurized plugging is proposed. “Absolute bridging amount” is used as a optimization parameter to determine the bridging material amount in the formula. The traditional compact packing theory is improved by the “complementation method”, which overcomes its defects of poor adaptability to the filling materials with discontinuous or overlapping particle size distribution, and determines the filling material addition in the plugging formula. The results of laboratory and field experiments show that the proposed method can realize the rapid and efficient design of the formula for deep naturally fractured reservoir, effectively ensure the sealing effect of the formula for deep naturally fractured reservoir and reduce the total amount of materials in the formula and save the material cost. The proposed method provides a new idea and theoretical basis for the design of plugging formula for deep naturally fractured reservoir.

岩体裂缝面摩擦特性是影响裂缝地层井壁稳定性的重要因素.文中选取川西雷口坡组超深层碳酸盐岩井下岩心为研究对象,对充填、未充填天然裂缝面和抛光裂缝面摩擦因数进行测试,分析微凸体、充填物和钻井液浸泡对裂缝面摩擦因数的影响,建立了未充填裂缝面粗糙度与摩擦因数关系模型.结果表明:超深层碳酸盐岩充填裂缝面摩擦因数(0.307～0.391)要低于基质裂缝面(未充填裂缝面为0.520～0.550、抛光裂缝面为0.420～0.441);钻井液浸泡后摩擦因数降低,且裂缝面越光滑,摩擦因数下降幅度越大.分析认为:相对于白云石基质,方解石充填物矿物颗粒间黏着摩擦较弱,以及裂缝面形态更为平坦,是导致充填裂缝面摩擦因数较低的主要原因,而钻井液浸泡岩心裂缝面后产生的润滑效应也会导致摩擦因数降低.研究成果能够为超深层裂缝性碳酸盐岩地层井壁稳定性评价提供重要的实验参数支撑,为封堵防塌钻井液优化提供基础指导.

为了解决鄂尔多斯盆地下古生界奥陶系马家沟组碳酸盐岩储层岩性类型复杂、变化快、难识别以及部分老井无测井解释剖面,地质研究人员无法快速有效判别岩性等问题,以富县地区马家沟组马五段为研究对象,分析了目前常用的岩性识别方法,通过取心资料确定了主要的岩石类型,结合碳酸盐岩中主要矿物的测井响应数值,得出了可采用光电吸收截面指数曲线与补偿密度曲线、补偿密度与补偿中子曲线两两包络的包络法与聚类分析—最小临近算法实现岩性解读的认识.研究结果表明:①包络法操作简便,能快速识别白云岩、石灰岩、石膏,尤其在含膏地层中优势明显,适用于生产中对岩性的预判,其操作关键点在于曲线左右刻度值的调整,其判别准确与否的关键在于曲线质量是否可靠;②聚类分析—最小临近算法结果更精确,其预测符合率高达92.31％,更适用于后期科研所需,但是该方法需要一定量的取心数据作为支撑;③目前上述两种方法在坍塌角砾岩的识别中都还存在着局限性,对于坍塌角砾岩的识别还需要借助成像测井以及地质认识来实现.

超深层海相碳酸盐岩储层中发育的天然裂缝有可能显著增加钻完井过程的井壁失稳和钻井液漏失风险,并且关于天然裂缝发育程度及裂缝微观特征对超深层碳酸盐岩力学性质的影响机制尚需系统深入研究.为了给超深层碳酸盐岩地层防塌防漏和酸压工艺技术改进提供实验依据,以四川盆地川西坳陷中三叠统雷口坡组碳酸盐岩储层为例,开展了三轴力学实验,结合CT扫描重构、裂缝充填物分析、裂缝面扫描成像和摩擦系数测试等成果,从裂缝产状、充填物和摩擦学特征等方面研究其力学特性.研究结果表明:①川西坳陷雷口坡组超深层碳酸盐岩储层天然裂缝多被高纯度方解石充填,岩石具有泊松比低、力学强度低且离散性强的特点;②雷口坡组岩样普遍发生高角度天然裂缝剪切破坏,破裂面倾角介于46°～80°,天然裂缝轮廓平整,裂缝面微凸体欠发育且坡度小,方解石充填物硬度低且胶结程度弱;③裂缝产状、充填物和摩擦学特征导致岩石抗剪切破坏能力弱、抗压强度整体偏低,裂缝面摩擦系数小是导致其抗剪切破坏能力弱的关键原因;④水基钻井液对方解石充填层的良好润湿性导致岩石强度进一步降低,且裂缝主控特征更为显著.结论认为,该研究成果可为超深层裂缝性碳酸盐岩储层井壁失稳控制和酸压设计优化提供更具针对性的基础指导.

Understanding the relationship among the individual factors (i.e., carbonate rock types, acid rock reaction kinetics, deterioration of rock mechanical properties) can provide practical guidelines that can be used for the design and optimization of acid fracturing operation. A comprehensively experimental study was conducted to investigate the acid rock reaction kinetics of carbonate rocks under acidified conditions, and how the acid rock reaction would influence the carbonate rock mechanical properties. In addition, the deterioration mechanism of the carbonate rock mechanical properties is determined by the qualitative analysis of casting thin section images. Results show that the limestone rock is more susceptible to acid dissolution than limy dolomite rock under the same acidified conditions. The limestone rock has relatively large reaction rate constant and low activation energy, however, it is reverse in limy dolomite rock. As a result, the mechanical properties of rocks with relatively low cementation strength could be highly or lowly weakened. The reduction (in percentage, %) in mechanical properties of the limestone rocks with relatively high cementation strength is greater than that of the limy dolomite rocks with relatively high cementation strength. Casting thin section images show that the cementation and fillings of limestone and limy dolomite rocks are calcite and calcite-dolomite, respectively. The non-uniform (i.e., superficial and local deep) and uniform etched pattern (i.e., superficial and symmetrical) occur on the end surface of limestone and limy dolomite, respectively. Consequently, the mechanical properties of relatively high cemented limestone rocks are more significantly reduced than that of relatively high cemented limy dolomite rocks. This work is of great practical guidelines for the design and optimization of acid fracturing operations, as well as the efficient stimulation of carbonate reservoirs.