Deep marine shale gas (3500–4500 m) and ultradeep marine carbonate oil and gas (≥ 6000 m) are among the most important development areas for China's future oil and gas resources. Some key problems related to the safety and efficient drilling and completion of marine oil and gas wells are addressed in this paper: (1) a prediction method for pore pressure in deep marine reservoirs; (2) a method to solve the problems of low penetration rates and high drilling costs; (3) a method to maintain wellbore sealing integrity under cyclic loading to simulate staged fracturing; (4) a wellbore stability control method; and (5) how to carry out efficient hydraulic fracturing. To focus on the efficient drilling and completion of oil and gas wells in ultradeep shale and carbonate formations, we carried out research to solve the aforementioned problems and share our results in this paper.

Continuous circulation technology can realize the continuous circulation of continuous pumping during drilling, which can be used to improve borehole cleanliness in extended-reach drilling and prevent cutting bed accumulation from adversely affecting downhole operations. This paper describes the mechanism of continuous circulation technology and the advantages and disadvantages of its supporting equipment, analyzes the theoretical model of cutting bed migration in extended-reach drilling, studies the distribution, thickness and migration law of cutting bed when continuous circulation technology is used, and optimizes and recommends the flowrate, ROP and drillstring rotation speed of well Panyu A in eastern part of the South China Sea. The results show that the cutting bed of the extended-reach drilling has wavy distribution and dynamic migration with time, and the migration velocity of the cutting bed is inversely proportional to the hole size. The migration direction is from the bottom of the well to the head of the well. The thickness of the cutting bed is the largest at the beginning of the horizontal section, and the thickness near the bottom of the well is the smallest. The research results provide a theoretical reference for borehole cleaning control in extended-reach well.

我国深层超深层油气井固井面临高温、高压、复杂介质和复杂工况等的挑战,水泥环长效密封完整性难以保证,常规固井技术与装置不能满足需求,亟需理论创新和研究井筒完整性固井新技术.近年来,中国石化通过科研攻关,完善了固井水泥环密封完整性理论体系,建立了复杂工况条件下的水泥环密封失效控制方法,研发了"防窜、防腐、防漏、防损伤"高性能水泥浆,研制了适用于深层复杂工况环境的固井尾管悬挂器、分级注水泥器及配套附件,提出了固井优化设计新方法,形成了深层复杂油气藏固井新技术.建议今后进一步完善特色水泥浆技术体系,研发绿色、智能环保材料,攻关固井技术信息化与智能化,持续推进基础理论研究,提高深层超深层复杂油气井固井质量.

Growing global energy demand and limited reserves of traditional energy resources are causing a growing energy shortage. In order to meet future energy needs, new energy resources must be continuously explored. Deepwater drilling research has emerged as one of the key ways to address this issue, and well structure slimming is an effective way to increase drilling speed and reduce costs. The hole size of the second section of deepwater wells decreases from a conventional 660.4 mm to 444.5 mm and increases from 500–800 m to 800–1200 m, creating problems where the conventional 660.4 mm cone bit cannot be used, the rate of penetration (ROP) of the cone bit is low, and the service life is short. To solve these problems, a 444.5 mm artificial polycrystalline diamond compact (PDC) was designed for the first time for use at home or abroad, and according to the characteristics and operation requirements of the 914.4 mm conductor jetting process, a unique anti-collision gauge protector was designed, an innovative bypass nozzle was configured, and a hydraulic design to prevent bit balling in shallow soft mudstone was formulated. PDC jetting bit-drilling technology based on well structure slimming was successfully applied to eight deepwater wells in the eastern South China Sea, which successfully jetted a 914 mm conductor and greatly improved the ROP of their second-section holes. When the below-mudline depth of the second-section hole increased by 37.01%, the average ROP increased by 227.84%. These technical achievements have successfully realized deep drilling with seawater, increased speed and efficiency, achieved good application results, and accumulated valuable experiences that can be used for reducing the cost and increasing the efficiency of offshore drilling operations.

受井壁表面粗糙度、钻井液残留和温压扰动等因素的影响,固井二界面是整个环空封隔的最薄弱环节,且极易发生张拉破坏导致环空密封失效,但已有的评价方法只能获得固井二界面的胶结剪切强度,不能很好地评价固井二界面抗拉破裂性能.为此,考虑岩性、界面粗糙度、钻井液残留、冲洗液清洗和水泥浆等主要因素,建立了一种固井二界面胶结抗拉强度室内评价方法,从冲洗效率、胶结细观结构、抗拉强度、破裂形貌等多个维度对固井二界面胶结抗拉性能进行了系统评价.研究结果表明,该评价方法科学合理、步骤清晰、简单适用、试验结果离散性小,不同因素下测试结果区分度好,进一步完善了固井二界面胶结强度评价方法,具有较高的推广应用价值.

针对深层、超深层和复杂地层等对钻井提速的要求,考虑深层岩体可钻性变化,提出了基于钻头破岩能量与岩石特征自适应匹配的钻井提速技术.在分析钻头破岩过程中扭矩特征的基础上,研制了自适应匹配工具,利用行星齿轮和扭簧结构进行能量存储与释放,钻进岩性均质地层过程中提前蓄能,钻遇砾石层或非均质地层时释放能量进行辅助破岩.通过静力学和动力学性能测试,验证了自适应匹配工具结构的可靠性和实现提速的可行性.自适应匹配工具在深层页岩气井进行了现场试验,结果表明:与使用常规方法的邻井相比,机械钻速提高了 83%,验证了该工具提速的有效性和稳定钻头工作状态的效果.钻头破岩能量与岩石自适应匹配提速技术,为深层、超深层和复杂地层钻井提速提供了理论支撑和新的技术途径.

低渗储层的区域延展性大、油气生产效率低,以及钻井和储层改造作业频繁等特点使得多年在常规油气藏生产作业中所总结出的知识体系与开发方式不能很好地应用于此.借助AI技术快速掌握储层数据信息、提升认知水平、高效制定工程措施,是实现致密储层降本增效开发的新方法.从数据挖掘的角度出发,收集了来自加拿大Cardium致密储层1 286 口井的50余种影响参数,利用敏感性测试深入探索了该低渗储层历史产量与地理/物性/工程等多维参数的相关性,通过建立和综合对比多种机器学习技术优选出最佳的产量预测模型;为了增加数据利用效用,应用了 k-Fold交叉验证方法可以显著改善模型预测精度.结果表明,在所有机器学习算法中随机森林方法表现突出,优化模型可以将产量预测的准确率提高到85％以上.这项研究为海外低渗油气田的储层快速评价、项目综合决策和开发中的降本增效提供了有力的保障.

The compressive strengths and hydration products was investigated of oil well cement mixed with fly ash at ultra-high temperatures. Cured at 150 degrees C, the strength for test samples with 30% and 50% fly ash was relatively high in the early days but declined in subsequent days. However, the samples with 70% fly ash showed a continuous trend. The compressive strengths were relatively high at 28 days, and all the samples met the cementing requirements at this temperature. At 220 degrees C, the mix with 30% fly ash had the least compressive strength, while that of 70% fly ash content was comparatively high. X-ray diffraction analysis shows that the main crystalline hydration products at 150 degrees C were tobermorite and hibschite. At 220 degrees C, tobermorite decomposes into xonotlite because it has limited high temperature stability. The pozzolanic reaction of fly ash and portlandite Ca(OH)(2) produced a comparatively stable phase known as hibschite. The scanning electron microscopy analysis shows that the surface morphology of tobermorite is fibrous while hibschite is vitreous. Both compounds have high strength characteristics due to their structural interconnectedness. Xonotlite crystal is coarse and plate-shaped with poor bonding, which negatively impacts its strength stability. Due to the presence of hibschite, cement mix with high amounts of fly ash is suitable for application at 220 degrees C.

After the drilling fluid enters the wellbore, it will affect the distribution of the stress field around the wellbore, thereby degrading the strength of the rock, and induce wellbore instability, reservoir damage, well-bore collapse, tool jamming and even wellbore scrapping. In this paper, the impact of drilling fluid on the macro and meso characteristics of deep shale after entering the formation has been systematically studied. This study found that whether water-based or oil-based drilling fluid enters the shale micropores and fissures, it will degrade the shale microscopic characteristics over time. For the interval with developed fractures, oil-based drilling fluid is more likely to cause fractures to propagate under pressure in a relatively short period of time. However, with the prolongation of the drilling fluid soaking time, the water-based drilling fluid is easier to communicate between natural fractures and artificial fractures, which in turn leads to a significant decrease in rock strength and instability of the borehole wall. Both water-based and oil-based drilling fluids have the law of weakening the strength of shale. The compressive strength, Young's modulus and Poisson's ratio of the rock show a decreasing trend with the extension of the drilling fluid immersion time, and the rock mechanics parameters of immersed water-based drilling fluid have a greater attenuation than oil-based drilling fluid. This research can provide a theoretical basis for safe and fast drilling of deep shale.

顺北56X井是部署在顺北V号条带的超深重点风险预探井,钻井过程中面临二叠系和志留系易漏失、奥陶系破碎地层井壁稳定性差、奥陶系桑塔木组易井斜、井眼轨迹控制难和储层钻遇裂缝带气侵等技术难点.为此,针对二叠系、志留系和奥陶系的地质特征,选用防漏堵漏钻井液和高温强封堵油基钻井液,并制定相应维护处理措施,有效预防了二叠系和志留系的漏失,保障了奥陶系的井壁稳定;应用"大扭矩螺杆+垂直钻井系统"防斜打快技术,实现了直井段的防斜打快;通过优化井眼轨道、采用工具面快速调控工艺、配套高温随钻测量技术和制定井眼轨迹技术方案,使该井井眼轨迹与井眼轨道符合度高,实现准确中靶;利用"微过平衡密度+简易控压"钻井技术,解决了储层钻遇裂缝带气侵的问题.顺北56X井钻井过程中未出现井控风险,准确中靶,顺利钻至井深9300.00 m(垂深8087.94 m)完钻,成为我国目前最深的水平井,同时也是目前亚洲陆上最深的水平井.该井安全成井,表明我国具备了钻特深水平井的能力,可为中国石化"深地一号"工程顺北特深层油气藏勘探开发提供技术支撑.

Unconventional oil and gas formations are abundant, have become an increasingly important part of the global energy supply, and are attracting increasing attention from the industry. Predicting key reservoir properties plays a significant role in both geological science and subsurface engineering workflows. With the advent of horizontal well drilling and multiple-stage hydraulic fracturing, the Montney Shale formation is one of the most promising and productive shale plays in Canada. However, very few academic papers discuss its in situ stress, reservoir pressure, and permeability, which are essential for the development of the Montney Shale. The objective of this study is to analyze the geo-stress, the pore pressure, and several key reservoir properties by using diagnostic fracture injection test (DFIT) data from the Montney Shale. One horizontal well from the Wapiti field has been analyzed with a set of DFIT data, and its results show that the general pressure and Gdp/dG responses from Well-A indicate a signature of height recession/transverse storage. In the study, the Tangent Line method, the Compliance method, and the Variable Compliance method have been applied to estimate the key reservoir properties. As a result, the Well-A DFIT analysis estimates that the closure pressure is ranging from 34.367 to 39.344 MPa, contributing to the stress gradient from 14.09 to 16.13 KPa/m for the formation. The pore pressure is ranging from 20.82 to 24.58 MPa, contributing to the pore pressure gradient from 8.54 to 10.07 KPa/m for the formation. The porosity is ranging from 3% to 6%. These reservoir properties are contoured cross the Montney Shale formation. Using the DFIT’s numerical simulation and history matching, the reservoir permeability is 0.024 md, fracture length is 13.44 m, and fracture geometries are analyzed by different models. Moreover, the physics behind the DFIT are analyzed and discussed in detail. For the first time, three different analysis methods have been applied to estimate a series of key reservoir properties for the case wells in the Montney Shale formation. This approach can not only reduce the potential prediction error caused by a single method application but also increase the persuasiveness of the assessment and save time, ensuring the efficient implementation of engineering operations. Given the significance of quantifying in situ stress and reservoir pore pressure in unconventional hydrocarbon exploration and development, this study could help the operator to quickly understand the stress regimes, the fracture geometry, and the formation properties of the Montney Shale formation in the Wapiti field. Furthermore, the interpreted results demonstrated in this paper are adding substantial business value to the asset, especially in terms of improving the hydraulic fracturing design and, thus, accelerating the cashflow from production.

Imbibition controls mass transfer in the complex pore-fracture network in shale, which may change the porefracture network and lead to a low efficient flowback of fracturing fluid. Thus, it is necessary to accurately characterize the pore-fracture network alteration during the imbibition process. In this study, forced and spontaneous imbibition tests were conducted under the confining pressure on selected shale core samples with induced fractures, collected from Longmaxi Formation, Sichuan Basin, China. The low-field nuclear magnetic resonance (NMR) spectrometer was employed to monitor the variation of pores and micro-fractures in the shale core samples during the dynamic imbibition process. In addition, optimal surface relaxivities, ranging from 0.019 to 0.033 mu m/ms, were determined by comparing the NMR T2 distributions with the pore size distributions (PSDs) measured via high-pressure mercury intrusion (HPMI) tests. Then, the measured dynamic T2 spectra with three distinct peaks were converted into the corresponding PSDs to quantitatively analyze the number, size, and connectivity changes of small pores, large pores, and micro-fractures in shale. Results show that the total porosities of the four shale core samples are increased by 3.5%, 10.2%, 32.9%, and 36.3% after the imbibition tests. The forced imbibition leads to more remarkable improvements in the pore volume of large pores with radius between 0.2 and 3.6 mu m. In contrast, the spontaneous imbibition results in more significant increases in the number and size of small pores with radius between 0.0004 and 0.36 mu m. It is also found that the total porosity increment is primarily an outcome of small pore alteration during the imbibition. Moreover, the enlarged pores and micro-fractures are mainly categorized as the capillary bounded fluid pores and movable fluid pores, which significantly affect the efficiency of oil and gas transfer in shale. The findings of our study demonstrate the comprehensive effects of capillary force, clay hydration, osmotic potential, confining and pore pressures, and creep deformation and failure on the pore-fracture network alteration in shale and advance the understanding of the mechanisms behind the forced and spontaneous imbibition processes.

Cement sheath should provide zonal isolation and structural support during the full life cycle of a well. However, achieving long-term cement sheath integrity under complex geological and operational conditions, especially in bedding shales characterized by strong anisotropy, is still a great challenge. Thus, to better understand the effects of the anisotropy of shales on cement sheath integrity, this paper developed a 3D coupled thermal-hydro-mechanical model of the formation-cement-casing system. Stress generation and evolution within cement sheath are also considered in the modeling. The model is validated against analytical solutions and physical experimental results. Then, sensitivity analyses were performed to investigate the initial stress of cement sheath and shale anisotropy on cement sheath integrity. The results show that the anisotropy of Young’s modulus has a greater influence on cement sheath integrity compared to the anisotropy of Poisson’s ratio. Debonding between the cement sheath and formation can be easily generated due to the shale’s high anisotropy of Young’s modulus. The aperture of the microannulus along the cement interface varies with the angle between the wellbore axis and the bedding plane. The minimum microannulus is developed where the wellbore is parallel to the shale’s bedding planes. The results also indicate that initial stress generated in the cement sheath after its hardening is beneficial for the integrity of the cement-formation interface.

The integrity of cement sheath and the interface bonds of the cement-casing-formation system is critical in the oil and gas wells' productive life and even after its abandonment. For many years, cement bond logs (CBL) tools, as one of the vital logging techniques, have been extensively employed in industry to monitor and evaluate cement-casing-formation bonds. Though these techniques provide a clear view of cement sheath integrity quality, some controversies surround their applications. First, it is challenging to deploy these logs in extremely harsh environments. Second, it is impossible to obtain real-time diagnostic values with CBL logs since they only provide a snapshot in time. Undoubtedly, real-time monitoring of cement sheath integrity is critical to operational safety in oil and gas wells. Distributed acoustic sensing (DAS) has emerged as a novel technology to provide the industry with an opportunity to improve safety during production and minimize operational costs. There are various aspects of well integrity in which DAS would provide invaluable information to support decision-making for well integrity management. In this paper, we firstly present a review of cement sheath integrity evaluation with conventional logs, then a comprehensive review of distributed acoustic sensing technology, including deployment methods, working principle, data processing/analysis techniques, and the current advancement in the use of DAS in wells' integrity monitoring. We find that specially packaged DAS sensors exhibit extreme sensitivity to events occurring downhole and thus provide a trove of valuable information. Once this data is acquired, it is processed and analyzed to highlight acoustic components related to a particular event signature enabling events classification. However, we have noted that there is still a long way to go in realizing the full potential of DAS in cement sheath integrity monitoring. Therefore, to fast-track the maturation of DAS application in oil and gas well integrity evaluation, there is a need to develop laboratory simulation tools and methods.

There are many inter-salt rhythmic shale reservoirs in Qianjiang sag, and the mineral composition content with different rhythms is different. The thin interbedding characteristics of inter-salt shale oil reservoirs bring technical challenges to hydraulic fracturing. Taking one shale oil well in Qianjiang depression as an example, the mechanical properties and interface characteristics of rock under temperature and confining pressure are analyzed. The physical simulation test of fracture propagation under different fracturing fluid is completed, and the effects of four different factors on fracture propagation are analyzed by numerical analysis method. The results show that the mechanical characteristic and failure modes with different rhythms are obvious differences. Under uniaxial and triaxial compression, glauberite mudstone and shale have high strength, and salt rock shows obvious plastic deformation characteristics. The interbedded rock has clear interface characteristics. The cohesion of glauberite mudstone and shale bedding surface obtained from direct shear test is 0.60 MPa and 0.99 MPa. The fracture morphology of inter-salt shale is mainly affected by the development degree of rock bedding. The mechanical parameters, in situ stress difference, and the displacement have an important impact on the longitudinal propagation of fracturing fractures. The width and height of fracture propagation decrease, with the increase in the minimum horizontal principal stress in the salt layer, and the width of fracture in shale increases. The crack height decreases with the increase in tensile strength of the interlayer. With the increase in fracturing fluid injection rate from 3.0 to 7.0 ml/min, the propagation height of hydraulic fractures and the width of fractures in shale increase significantly. The research results can apply to understanding the mechanism of hydraulic fracture propagation in inter-salt shale formation.

Casing deformation problem caused by hydraulic fracturing treatments has seriously reduced the number of fracturing stages. A well understanding of the mechanism and controlling method for this problem is very necessary. Based on the detected results, shear deformation is the main type of casing deformation in Weirong shale gas field, Sichuan province of China. According to the analysis on the special geological condition in this area, the reactivation and slip of natural fractures in shale gas formation are treated as the main reason for causing deformation in shale gas well. Model for calculating fracture reactivation and slippage are established. The shear reactivity trend factors in different condition are calculated to judge the reactivation of fractures. Based on the slippage calculation model, the slippages of fractures in four shale gas wells are calculated. Compared with the geological conditions and hydraulic fracturing treatment in Fuling and Yongchuan shale gas field with no casing deformation in China, the existence of dominant natural fracture is one of the most important factors for casing deformation. The results coincide with the field detected casing deformation incidents which certifies the theory that reactivation and slip of dominant fractures induced the casing deformation. In the end, the useful methods for controlling casing deformation in shale gas wells, including temporary plugging, fracture identification, and changing casing size are proposed. The research in this paper provides reference values for controlling casing deformation in exploiting unconventional oil and gas with hydraulic fracturing treatment and reservoirs contains plenty of activated dominant natural fractures.

考虑影响钩载、扭矩的因素复杂多样及钻井过程的时序性特点,优选BP神经网络和长短期记忆神经网络,设计双输入网络架构,建立大钩载荷与转盘扭矩智能预测模型.该模型同时考虑影响钩载、扭矩的多种复杂参数以及钩载、扭矩等时序数据随时间变化的趋势和前后关联,通过时序性数据和非时序性数据共同预测大钩载荷与转盘扭矩.利用国内某油田钻井现场数据进行大钩载荷与转盘扭矩的预测,均方根误差分别为39.05 kN和1.6274 kN·m,平均相对误差分别为1.202％和9.038％.

针对顺北油气田奥陶系破碎性地层井壁失稳频发的技术难题,通过开展X射线衍射、扫描电子显微镜和滚动回收率等室内实验,建立了考虑多弱面效应和力化耦合作用的井壁失稳模型,分析了井壁失稳机理及影响因素.研究表明:奥陶系破碎性地层以方解石为主,黏土矿物质量分数低,水化分散能力弱,多尺度非连续破碎结构和非黏土水化型水岩损伤作用是井壁失稳的关键因素;随弱面组数的增加,岩石强度的各向异性愈发显著,坍塌压力增大,安全钻井的优势方位角与倾角选择减少;随着弱面倾角由0°增大到90°,坍塌压力呈现先增加、后平稳、再逐渐减小的趋势;坍塌压力随弱面内聚力、内摩擦角的增大而显著降低,且内摩擦角的影响更显著,但随弱面胶结强度的升高,坍塌压力的降低率具有一定的极限.

The highly efficient development of shale gas is a research hotspot in the world oil and gas industry. When drilling long horizontal wells in shale gas formation with water-based drilling fluid, the problems of wellbore collapse always happened. In this article, the Longmaxi formation shale in Sichuan Province was taken as the research object. Through the friction experiment, it was found that the lubricity of the fracture wall would be enhanced after aqueous solution intrusion into the shale fractures. Compared to pH 7, the maximum static friction coefficient of shale decreased by 23.6% and the root mean square roughness decreased from 41.9 nm to 25 nm after soaking in aqueous solution with pH 13. With the addition of viscosity modifiers CMC-Na and PAC, the friction coefficient even reduced by 37.5% in our experiment and the CMC-Na is more suitable for the stability of shale than PAC. The aqueous solution with 4% bentonite slurry makes the friction coefficient reduced by 26%. The increase of the lubricity of the fracture wall will make the maximum static friction coefficient between shale fracture and the time of the static friction stage decreased, resulting in the decrease of the friction force on the fracture wall. The shear slip on the fracture wall surface is more likely to happen with the decrease of the friction force, ultimately lead to the collapse of wellbore, which is not conducive to the stability of fractured shale formation.

There was nearly 1.7 billion tons proved reserve in SINOPEC Shunbei oilfield, which is the deepest (>8000m) fault controlled marine carbonate oilfield in the world with high-temperature (>170 °C) and high -pressure (>140MPa). The formation geological conditions are complicated, high rock strength, easy leakage and collapse, multiple pressure systems co-exist in the slim borehole, which caused a series of directional drilling technical problems such as difficulty in controlling the tool surface, PDM build-up capacity prediction and so on. Therefore, the related research for ultra-deep direction drilling technology were carried out aiming at solving the directional drilling problem for Shunbei oilfield. Firstly, the optimized wellbore structure scheme design method was proposed, in which the geological characteristics, borehole size and the directional efficiency were considered. And then a double augmented well profile designed model was established based on optimizing the production casing size, through which the directional efficiency and the drilling rate of a trip were increased significantly, and the nonproductive time can be greatly reduced easily. Secondly, an ultra-deep directional well torque transmission prediction model was established based on the mechanical analysis of ultra-deep drilling string and based which a rapid tool face control method was formed. Furthermore, an innovative build-up rate prediction method was established based on both big Data analysis and balanced tendency build-up rate prediction method, and the accuracy is more than 90%. Moreover, the PDM rubber seal, stator and rotor dimensions are optimized to achieve high power output within a certain high temperature range to prolong the service life according to the wellbore temperature field. Finally, the optimization of high temperature MWD instrument and matching process technology was proposed, such as surface assisted cooling, borehole size enlarging and high displacement cooling technology effectively improve the reliability. The series of ultra-deep directional drilling technology has been applied in Shunbei oilfield. The field application results show that the average ROP of directional section is increased by more than 30%, directional efficiency is greatly improved, and the directional drilling cycle is shortened by more than 20%. Nearly 40 ultra-deep directional wells above 8000m have been constructed, setting more than 10 new Asia records of petroleum engineering onshore directional well. There are two innovations in this paper. The first is to put forward the design method of wellbore profile with the shortest drilling time as the goal, which can save 1-2 trips and improve the directional efficiency by more than 20%. The second is to introduce the prediction method of build-up rate based on borehole tendency angle, which improves the prediction accuracy of build-up rate by 28% in Shunbei ultra deep directional well.