CHINA PETROLEUM EXPLORATION Volume 21, Issue 5, September 2016 Major factors on wellbore stabilities of shale gas wells in the Jiang Yiming 1, Zhang Dingyu 2, Li Dahua 3, Chen Chaogang 3, Cheng Jun 1,3, Qiu Yigang 1, Zhu Yu 1,3 1. Schlumberger Zhongyu Shale Gas Technical Services (Chongqing) Co., Ltd.; 2. Land and Resource & Housing Management Bureau of Chongqing City; 3. Key Laboratory of Shale Gas Exploration Ministry of Land and Resources, Chongqing Institute of Geology and Mineral Resources Abstract: The massive marine shales in the Sichuan Basin and its periphery are one of the key targets for shale gas development in China. According to the drilling data of this region, many complexities often occur during the drilling of shale gas wells and cause wellbore instabilities. Such complexities include borehole collapses, drillpipe blocking/sticking, blowouts and lost circulation, which are great challenges for shale gas exploration and development, especially in regards to the drilling of horizontal wells and cluster wells. The in the east margin of the Sichuan Basin extends across two tectonic units (i.e. the Yangtze paraplatform and the Qinling geosyncline fold system) and features complicated geological structures and a diverse topography. Regardless of the engineering factors, the complexities that occurred during the drilling of shale gas wells in this region were found to occur with a certain regularity; namely, the wellbore instabilities are closely attributable to geological structures, the in-situ stress field distribution, and the physical-mechanical properties of the rocks, etc. Based on the sedimentary and tectonic evolution histories as well as the geological conditions, the is divided into four zones (I, II, III, and IV). Shale gas reservoirs in these zones are analyzed for the major factors that control wellbore instabilities, and special considerations are made regarding the geological and accumulation characteristics of the reservoirs as well as the drilling and laboratory data. The results indicate that formation pressure is the major factor for wellbore stability in the central and western, the risk of wellbore instability is lower in the southeastern if the drilling is conducted away from natural faults, and two zones in the northeastern are susceptible to shear sliding along faults, joints and weak planes as a result of high dip-angle formations and stress deflection. Key words:, wellbore stability, Longmaxi Formation, Niutitang Formation, shale gas, high pressure gas reservoir In order to increase shale gas production and decrease the costs of shale gas development, shale gas is usually developed by mode of cluster wells or horizontal wells [1]. The drilling data in both China and abroad indicates that the cost per unit of drilling footage for cluster wells and horizontal wells is 1.5 4 times that of vertical wells due to the complication of the drilling technology involved and the higher risks of wellbore instability [2 4]. Therefore, one way to deal with this key controlling factor of shale gas development costs is to effectively decrease the risk of wellbore instability and improve drilling efficiency. Chongqing city is located in the east margin of the Sichuan Basin. According to data announced by the Ministry of Land and Resources, the amount of shale gas geological resources in the total 12.75 10 12 m 3 and the recoverable resources total 2.05 10 12 m 3. Until 2014, over 200 shale gas wells had been drilled in the, including geological wells, parameter wells, exploration wells and production wells. The major target formations include the Upper Ordovician - Lower Silurian Wufeng Formation - Longmaxi Formation and the Niutitang Formation, Shuijingtuo Formation and Lujiaping Formation of the Lower Cambrian. The regional survey data indicates that the above shale formations are characterized by a high abundance of organic matter, an advantageous thermal evolution degree, and good preservation conditions, thus presenting them as favorable horizons for shale gas accumulation [5 6]. During previous drilling operations of shale gas wells in the, a series of wellbore instabilities occurred in the shale intervals, especially in the build-up sections and horizontal sections. For example, the collapse pressure coefficient at the top of the Longmaxi Formation shale gas reservoir in the Fuling Jiaoshiba block was 1.10 1.78 and the leakage pressure coefficient was 1.39 1.61, which may have caused lost circulation to occur in the same layer; with the prolonging of drilling fluid soaking, the collapse pressure tended to further increase [7 8]. When four horizontal wells (Pengye 1, Pengye 2HF, Pengye 3HF and Pengye 4HF) in the Pengshui block were drilled in the Longmaxi Formation, lost circulation occurred in the horizontal section during the third section, causing a huge amount of oil-based drilling fluid to be lost and resulting in Received date: 02 Mar. 2016; Revised date: 27 Jun. 2016. Corresponding author. E-mail: Yjiang2@slb.com Foundation item: Project of Chongqing Municipal Burau of Land Resources and Housing Managemnt Identification of wellbore stability in shale gas wells in Chongqing and relevant control technologies. Copyright 2016, Petroleum Industry Press, PetroChina. All rights reserved.
2 CHINA PETROLEUM EXPLORATION Vol. 21, No. 5, 2016 a big economic loss [9]. In the south of the Sichuan Basin, when Well WY 201-H1, the first horizontal shale gas well in the Weiyuan block, was drilled, an oil-based anti-collapse drilling fluid system was adopted and the drilling fluid density was gradually increased during drilling, but still a serious borehole wall collapse occurred in the main shale intervals [10]. Multiple factors may cause wellbore instabilities in the mud shale formations. They include tectonic stress, geological formation conditions [11 12], the physical and mechanical properties of rocks [13], the drilling fluid system [14], bottom hole assembly, drilling technology or any combination of these factors. Over the past decades, many scholars have analyzed the reasons for wellbore instabilities in a single well or an oil/gas block from one or several of the aspects mentioned above. However, few scholars have analyzed the wellbore stabilities in a structural area from the geotectonic prospective. In this paper, the data of shale gas wells in the was analyzed and statistical research was made on the factors controlling wellbore instabilities in the reservoir intervals. If the engineering factors (e.g. hole cleaning, surge pressure effect at the time of tripping) are neglected and only the objective factors (e.g. structure, deposition, and geological condition) are considered, it is found that the wellbore instabilities are closely correlative to geological structures, the in-situ stress field distribution and the physical-mechanical properties of rocks in the area, and that they have a certain regularity in certain regions. Thus, the is divided into four different zones (I, II, III and IV) [15] in this study in order to identify the major factors causing wellbore instabilities in the shale intervals in each zone. 1. Zone I: Fold belts in the central and western This zone is geotectonically located in the Yangtze paraplatform, bounded by the Qiyaoshan fault in the east and the Shashi buried fault in the north. It includes the Wanzhou arcuated folded belt, the Huayingshan quaquaversal fold cluster,the Longnüsi platform dome, the Zigong platform sag and other tectonic units (Fig.1). In the tectonic history, the Lower Paleozoic structure in the central and western was integrated. During the Caledonian movement, the uplifting of most areas led to the absence of the Devonian and Carboniferous systems in these areas. Since the Permian, the areas have subsided as a whole. The Indosinian movement in the Middle-Late Triassic ceased the marine deposition history and recorded the starting of continental sedimentation. In the Himalayan stage, the foreland Fig. 1 Division of tectonic units in the ( Modified from Literature [15])
Jiang Yiming et al., Major factors on wellbore stabilities of shale gas wells in the 3 thrusted nappe commonly occurred in the platform edge fold belt, and the buried decollement occurred in the basin, with many faults sliding and the shear structure forming in both sides of the faults. The Cambrian Niutitang Formation in the target strata of the shale gas has a large burial depth, with even the shallowest anticline reaching deeper than 4000 m, which causes it to have a high drilling cost. Thus, it has not been intensively explored yet. The Lower Silurian Longmaxi Formation, mainly composed of black carbonaceous shale and gray-black silty shale, is the main reservoir for shale gas development in the, and it has a moderate burial depth, abundant organic matter, a high thermal maturity, good reservoir properties and a great thickness. The Longmaxi Formation shale had a deep burial in the early stage and a big uplift amplitude and a high uplift rate in the later stage; as a result, it now has a general rock compaction with a medium strength, and its fracture development [16] has created the favorable pathway and reservoir space for the enrichment of absorbed gas and free shale gas. Due to the tectonic movements during and after the hydrocarbon generation process from the shale, the Longmaxi Formation shale was uplifted as a whole and the upper formation was denuded. This in turn increased the formation pressure of the shales with good burial conditions. The shales contain horizontally-laminated beds, showing characteristics of strong anisotropy. The tectonic stress near the faults (dominantly strike-slip faults) is high, and the maximum and minimum horizontal stresses differ greatly. At around a depth of 2500 3500 m in the reservoir, the maximum and minimum horizontal stress ratio is about 1.2 1.5. Consequently, the stress near the wellbore is too concentrated and the shear failure of rocks may easily occur. Selection of shale gas sweet spots is concentrated on the horizon, and ideal characteristics include relatively simple structures, no faults nearby, suitable burial depths (1500 3500 m), relatively gentle formations (with formation dip angle less than 15 ), good gas bearing properties and ample reservoir space. Once its development potential is determined, the horizontal wells are sidetracked or cluster wells are drilled to increase the production. For example, the Jiaoshiba block is located in the wide and gentle anticline among the Tiantaichang fault, the Diaoshuiyan fault and the Shimen fault (Fig.2). At a burial depth of about 2500 3000 m, the Longmaxi Formation shale in the target strata has a small formation dip angle (5 10 ). The fault on top of the anticline is not developed and the formation pressure is high with good reservoir conditions. The Longmaxi Formation shale reservoirs of Well JY1 are mainly comprised of black siliceous shale and carbonaceous shale with argillaceous siltstone and silty mudstone, all of which is favorable to hydrocarbon generation and accumulation [17]. Fig. 2 Section of the Longmaxi Formation shale gas reservoir in the Pengshui-Jiaoshiba area [17] According to statistics of the complexities of drilled wells and the laboratory results of core hydration and inhibition [18 19], the wellbore instabilities of mud shale intervals in this area are mainly related to in-situ stress conditions and the physical-mechanical properties of rocks: (1) The shale gas reservoir has a high formation pressure, and the maximum and minimum horizontal stresses greatly differ. During drilling, borehole collapse often occurs, so the usage of a drilling fluid with a higher density is required to balance the formation pressure. Especially in the highly deviated wells and horizontal wells, the stress near the wellbore is too concentrated, so the usage of a drilling fluid with a higher density is also needed to prevent borehole collapse. (2) Micro fractures are developed in the shale reservoirs, and usage of a drilling fluid with a higher density may activate the fractures to connect the faults, thereby leading to leakage. (3) Experimental results show that some rocks, characterized by the existence of micro fractures and a high content of clay minerals, are prone to hydrate and that the rock strength greatly decreases after hydration. In some wells using water-based drilling fluids in this zone, the drilling fluid filtrate invades the micro fractures to destroy the rock consolidation due to its poor inhibition, resulting in a decrease in rock strength. Consequently, the fracture pressure of the rocks decreases and lost circulation occurs. In order to reduce the risk of wellbore instabilities, in the shale gas well drilling design and development of this zone, rock mechanics should be adopted to analyze and optimize a safe drilling fluid density window. Furthermore, drilling
4 CHINA PETROLEUM EXPLORATION Vol. 21, No. 5, 2016 fluid properties should be optimized and strong inhibitive, anti-sloughing and low-damage drilling fluid systems should be selected to reduce the damage of drilling fluid to the formation. As for the intervals with micro fractures, lost circulation materials may be properly re-added and the drilling fluid volume monitored in real time by detecting the liquid level of the drilling fluid tank, thus decreasing the risk of lost circulation. 2. Zone II: Fold belt of the sag in the southeastern This zone, as a part of the Upper Yangtze syneclise of the Yangtze paraplatform, is located on the east of the Qiyaoshan fault, including the Qiyaoshan arcuated folded belt, the Jinfoshan quaquaversal fold cluster, the Qianjiang arcuated folded belt and the Xiushan quaquaversal fold cluster (Fig.1). Marine formations mainly occur in the Palaeozoic of the southeastern. The Lower Palaeozoic formation has the most intact outcrop, while the Upper Palaeozoic formation is incomplete with parts missing. The Mesozoic and Quaternary overlay over the old strata. Due to the effect of the Caledonian tectonic movement, the formation was continuously uplifted in the early Silurian. In the Yanshan movement period, the formation was strongly compressed, giving rise to a series of NNE fold uplifts that showed a regular zonal distribution. Due to the surface denudation and nappe thrust, the regional formation is mainly characterized by the outcrop of the Lower Paleozoic, and Wufeng Formation-Longmaxi Formation target strata are exposed in parts of the area at the surface and display serious denudation. The Niutitang Formation differs greatly in terms of burial depth. The core of the syncline has a deep burial depth (>5000 m) while the anticline is near the surface. Shale gas exploration in the southeastern is mainly focused on the Longmaxi Formation, with its moderate burial depth, and the Niutitang Formation at the top and flanks of the anticline [20 21]. During the selection of the sweet spot for the black shale exploration of the Longmaxi Formation in the southeastern, the first choice well location was far away from the big fault (>3000 m) and was characterized by a shale thickness greater than 20 m, a burial depth of 1500 3500 m, good 2D or 3D seismic interpretation results, a gentle formation, and a tip angle of less than 15. The logging data of shale gas wells in the southeastern indicates that the organic carbon content, maturity and other indexes meet and even exceed the domestic development standard of shale gas. The Longmaxi Formation shales consist of black carbonaceous shale, gray-black silty shale and siliceous shale, and they contain a large amount of natural fractures, most of which are filled, and a lesser amount of open fractures. Due to the uplift of the Paleozoic strata by the tectonic movement, parts of the Longmaxi Formation rocks are outcropped on the surface and the formation pressure is lower (with the formation pressure coefficient being about 1). The triaxial stress is in the typically strike slip-compressing state. The maximum and minimum horizontal stresses differ greatly, and their stress ratio is about 1.2 1.5. The Niutitang Formation shales are composed of gray-black and black carbonaceous shales with yellow siltstones. The cores show the existence of natural fractures which were filled by calcite (or organic matter, pyrite and quartz occasionally) in the early stage and have been partially corroded to recently form karst caves. The poor integrity of the rocks led to the weak anisotropy of their physical and mechanical properties. An intact rock has a high strength, but because the rock is subject to the effect of fractures and karst caves, there is a great variation of strength among the rocks [22]. The formation pressure is low and the pressure coefficient is about 1. The triaxial stress is in the state of strike slip-compressing state. The maximum and minimum horizontal stresses differ greatly, and their stress ratio is about 1.3 1.7. The stress near the wellbore is too concentrated, so the risk of borehole enlargement caused by the shear failure of rocks is high. Most of the shales in the southeastern are normal pressure formations. Because of the area s historically intense tectonism, the in-situ stress is in the strike slip-compressing state. As depth increases, the in-situ stress becomes more imbalanced. In the formation where the borehole wall collapses and hole enlargement occurs in the inclined wells and horizontal wells, the imbalance of the in-situ stress plays a leading role. The well trajectory is far away from the faults and the formation pressure is low, so usage of drilling fluids with low densities is generally adopted in the southeastern, and no severe loss of circulation of drilling fluid has occurred in the Longmaxi and Niutitang shale reservoirs. From the cores and borehole images of the Longmaxi Formation and Niutitang Formation in the southeastern, a large number of natural fractures can be observed. According to the results of the core hydration and rock mechanical experiments, if natural micro fractures exist in the rocks, then the drilling fluid filtrate invades the fractures and the rock strength greatly decreases g. Through comparison of the drilling fluid system, logging data, borehole diameter, and imaging logging data, it is found that in
Jiang Yiming et al., Major factors on wellbore stabilities of shale gas wells in the 5 wells using water-based drilling fluid with poor inhibition, obvious borehole enlargement occurs in faults with many micro fractures; in wells using water-based or oil-based drilling fluid with good inhibition, the borehole circumstances are generally good. As the southeastern has a low formation pressure and a high strength of intact shales, the drilling fluid density has a large range of adjustability. Therefore, low-density drilling fluid is preferred for drilling in this zone and the drilling fluid properties should be optimized. The selection of oil-based or water-based drilling fluids that cause minimal amounts of damage to the formation, have strong anti-damage abilities and good lubrication can reduce the risk of borehole wall collapses and other complexities. 3. Zone III: Fold-thrust belt of the South Dabashan in the northeastern This zone, located in the northeast of Chongqing City, belongs to the marginal depression of the Dabashan platform. It is bounded by the Shashi buried fault in the south and the Chengba fracture in the north, including the Chengkou basement thrust belt and the South Dabashan thrust belt (Fig.1). This zone is a narrow Lower Paleozoic depression, and the cover fold was caused by the Indosinian movement. Due to the uplift of the depression, the formation above the Jurassic is often missing, and the Devonian and Carboniferous are also missing in this zone. Later, as a result of the effect caused by the Yanshan and Himalayan tectonic movements, this zone became a part of the leading edge imbricate fold fault zone in the North Dabashan nappe structure, and a series of alignment folds and overthrust nappe faults constitute the composite folds. The fold strata near the Chengba fault are steep, upright and even overturned, and the torsion and crumble of the formation can be observed. In the southern Chengba fault, the fold deformation of the formation gradually weakens from north to south and the scale of the thrust faults decrease e and even disappear. The Cambrian Shuijingtuo Formation outcrops in the north end of the zone and gradually transits to the Triassic system. Due to the nappe and torsion of the formation, the Longmaxi Formation shale is less distributed in this zone and is mostly exposed on the earth s surface, displaying signs of very serious denudation [23]. All of the parameter wells of the Longmaxi Formation shale drilled in this zone have fault development and broken strata. The whole well section is in an open system that connects with the surface, so the formation has poor gas-bearing properties and the formation pressure coefficient is low. During the parameter well drilling process, excessive focus is placed on the intervals of the broken formation, where the borehole wall s collapse often occurs. The borehole enlargement is serious and the construction period is extended. The Cambrian Shuijingtuo Formation shale, as the main target formation in this zone [24], is characterized by a high formation dip angle and fault joints development. The closer the shale gets to the Chengba fault, the bigger the dip angle of the shale is (Fig.3). In this zone, wells are often drilled directly to the Shuijingtuo Formation after penetrating the topsoil and remain in the formation until well completion. The Shuijingtuo Formation consists of black carbonaceous shale, silty shale and siliceous shale. The low strength carbonaceous shale contains a large number of natural fractures, and the rock strength sharply decreases after encountering water. The siliceous shale has a low clay content, and most of its natural fractures are filled by calcite. The fillers and rocks that display a compact cohesion and a high bonding strength do not easily react with water. The Shuiingtuo Formation shale is susceptible to failure along joints, faults and other weak planes with low strengths as a result of high dip-angle formations and contorted folds caused by the tectonic compression. Due to the severe tectonic movement, a number of Tongtian faults have resulted in the relatively poor preservation conditions of the Shuijingtuo Formation shale. Although good gas shows occur in the carbonaceous Fig. 3 Section of shale gas reservoirs in the northeastern C 1 s - Shuijingtuo Formation; C 1 b - Bashan Formation; C 1 l - Lujiaping Formation; C 1 sp - Shipai Formation; C 1 t-sl - Tianheban Formation-Shilongdong Formation; C 1 j - Jianzhuba Formation; C 2 qn - Tanjiamiao Formation; C 2 m - Maobaguan Formation; C 2 b - Baguamiao Fomation; C 3 sh - Sanyoudong Formation; Q 3 w - Wufeng Formation; S l l - Longmaxi Formation; S l x - Xintan Formation
6 CHINA PETROLEUM EXPLORATION Vol. 21, No. 5, 2016 shale intervals and broken siliceous shale intervals, the measured formation pressure coefficient is still lower (<1.0). This zone is located between two tectonic structures (i.e. the Yangtze paraplatform and the Qinling geosyncline) and has a complex tectonic stress because it has been compressed many times in the past. The stress increases with the depth, and the triaxial stress state gradually transits from a thrust fault state to a strike-slip fault state. Moreover, the directional torsion of the in-situ stress is affected by the compression action, so the vertical stress is no longer the major stress, and shear stress exists in the vertical borehole walls. The maximum and minimum horizontal stress difference is large and increases with depth. The ratio of the two stresses can reach 1.4 1.8. The maximum and minimum horizontal stress ratio of the stress concentration intervals at the bottom of the Shuijingtuo Formation (2500 3000 m) can reach more than 2.0. An excessive stress concentration and the shear stress of borehole walls destroy weak planes (i.e. faults and joints planes), and the asymmetric hole enlargement occurs near the weak planes. The drilling data shows that the drilling rate is slow when attempting to drill through the high strength Shuijingtuo Formation siliceous shale, and the borehole is regular. The low strength carbonaceous shale softens easily when it encounters water, which means that a large scale borehole wall collapse phenomena can often occur as a result of the fracture development. Obvious hole enlargement also exists in the vicinity of the joints and faults of the siliceous shale and the carbonaceous shale, and increasing the drilling fluid density does not have any obvious effects in terms of maintaining the well stability. Although lost circulation does not occur in both the parameter wells and the exploratory wells in the zone that use low density drilling fluid, the seismic data show subsurface fault development, and the fracturing data indicates that the fracture pressure of weak planes (i.e. faults and joints) is far lower than that of the siliceous shale. Therefore, the most important considerations in the drilling of this zone is to control the density of the drilling fluid and to reduce the disturbance to the fault fracture zone. At same time, tectonic movement still exists in this zone nowadays, so possible borehole risks of compressional deformation and sliding along joints, planes, etc. after the completion of drilling should be considered in the casing design. Considering the long-term development of the shale gas, the carbonaceous shale interval is not only the best gas-bearing horizon in this zone, but it is also the key horizon for the layout of the extended horizontal wells. The rock in this horizon has a low strength and is prone to hydration and deformation, so the bolehole collapse of the horizontal wells will be the key challenge faced by shale gas exploration in this zone. 4. Zone IV: Thrust nappe belt of North Dabashan in the northeastern This area belongs to the southern edge of the Qinling geosyncline, bounded by the Chengba fault and the Yangtze paraplatform in the south (Fig.1). In the, the Lower Paleozoic Cambrian and Ordovician outcrop and the strata above the Ordovician are missing. A number of fold belts formed because of the compression of the Indosinian orogenic movement. Then, after the Yanshan and Himalayan tectonic movement, a series of N-W tight linear composite folds and oblique reversed faults was gradually developed to compose the imbricate overthrust nappe structure. The syncline, which constitutes the composite fold, has a relatively complete form, and the anticline is commonly susceptible to fault failure. The Wufeng Formation-Longmaxi Formation shales are not distributed in this tectonic belt in the. The Cambrian Lujiaping Formation outcrops near the Chengba fault and is the major target horizon for shale gas exploration in this zone. At a burial depth of 1000 3500 m, the Cambrian Lujiaping Formation shale has a true thickness of 300 400 m. The lithology is mainly black carbonaceous shale, silty shale, siliceous shale and siliceous rock. Due to the effect of tectonic processes, the Lujiaping Formation shale is relatively broken, displaying a large number of natural fractures that are partly filled by calcite. The rocks greatly vary in terms of strength. Complete rocks and the ones with the packed fractures have high levels of strength while rocks with unpacked fractures have low levels of strength. The siliceous content of the rocks is high, so the hydration effect is weak. According to the logging and gas testing analysis for the explored wells, the Lujiaping Formation shale gas formation pressure coefficient is low. Due to the effect of a multiphase tectonic process, the formation dip angle is high and almost upright. Due to the complicated in-situ stress conditions and the triaxial stress deflection along the formation, the vertical stress is no longer the major stress. The maximum and minimum horizontal stresses differ greatly, and the ratio of the two stresses at 1000 1500 m can reach 1.4 1.8. The tectonic history of this zone is similar to that of Zone III, and a low formation pressure results in a small risk of a gas cut. The borehole wall collapse often occurs in the vicinity of the folded broken formation (unpacked in the later stage) and weak planes (i.e. faults and joints). Thus, the usage of drilling fluids with low densities can be adopted for drilling in this zone, and the inhibitory requirements for the drilling fluids are not high. Considering the effect of faults, joints and rock broken belts, lost circulation materials may
Jiang Yiming et al., Major factors on wellbore stabilities of shale gas wells in the 7 be properly added to reduce both the disturbance to fault broken belts and the risk of lost circulation along natural fault fissures. In summary, the factors for the wellbore stabilities of shale gas wells in all zones of the are shown in Table 1. Geological structure characteristics of target reservoirs In-situ stress field distribution characteristics Shale physical characteristics Influencing factors on wellbore instabilities Zone Target stratum of shale gas Favorable position for exploration Table 1 Major factors for wellbore stabilities in shale gas zones in the I II III IV Fold belt in the central and western Fold belt of the sag in the southeastern Fold-thrust belt of the South Dabashan in the northeastern Thrust nappe belt of North Dabashan in the northeastern Longmaxi Formation Longmaxi Formation Niutitang Formation Shuijingtuo Formation Lujiaping Formation Top of the wide and gentle anticlines, far way from big faults Flanks of the syncline, far away from big faults Top and flanks of the anticline, far away from big faults The position with a big formation thickness and a relatively small formation dip angle, far away from big faults The position with a big formation thickness and a relatively small formation dip angle, far away from big faults Formation dip 40 65 in average and nearly upright <15 <15 <30 angle/( ) in parts of formation Burial depth/m 2000 3000 1500 2500 2000 3500 1000 3000 1000 2000 Thickness/m 80 110 70 120 120 140 300 700( true thickness) 500 700( true thickness) Formation pressure coefficient >1.3 <1 <1 1 1 Stress relations With the triaxial stress deflection, the shallow parts are Dominated by Dominated by strike-slip faults dominated by thrust faults and the stress mode is converted strike-slip faults to a strike-slip fault mode with the increase of the depth. Maximum and minimum horizontal stress 1.2 1.5 1.2 1.5 1.3 1.7 1.4 1.8 1.4 1.8 ratio of the reservoirs Lithology Black carbonaceous shale and gray-black silty shale Black carbonaceous shale, gray-black silty shale and siliceous shale Gray-black and black carbonaceous shales with yellow siltstones Black carbonaceous shale, silty shale and siliceous shale Black carbonaceous shale, silty shale, siliceous shale and siliceous rock Organic carbon 0.55 5.89 0.5 3.0 2.0 7.0 2.38 7.31 2.38 7.31 content/% (Well JY1) R o /% 1.85 2.23 1.9 2.7 1.6 3.55 1.27 3.72 1.27 3.72 Rock strength Medium-strong Medium-strong Medium-strong Hydration phenomenon Main behaviors of wellbore instabilities Major factors Secondary factors Exists Well kick, borehole wall collapse and prone to lost circulation near the faults Exists but the effect is Exists small Borehole wall collapse and prone to lost circulation near the faults 1 High formation pressure Great imbalance of in-situ stress 2 Great imbalance of Carbonate karst caves exist at the top in-situ stress of the formation, and faults exist 1 The existence of the The existence of the natural fractures natural fractures reduces reduces the rock strength the rock strength 2 3 Rock strength is reduced after shale hydration Rock strength is reduced after shale hydration The strength is strong and the carbonaceous shale and the rock of the fault joint planes have low strength Carbonaceous shale is prone to hydration The strength is strong and the rocks of the fault joint planes have low strength Not obvious Borehole wall collapse and hole deformation Tectonic stress and the imbalance of in-situ stress are great The strength is severely reduced after the hydration of the carbonaceous shale Low rock strength near faults and joints Due to the big formation dip angle, well deviation needs to be controlled Due to strong tectonic action, hole deformation in the later stage requires attention 5. Conclusions One of the most important means to achieve cost control and large-scale development of shale gas reservoirs is to fully realize the major factors that cause wellbore instability in shale reservoirs and to proactively mitigate or avoid risks by using proper techniques. The drilling data of shale gas wells in the indicate that the wellbore stabilities are closely attributable to tectonics, the sedimentary history, the in-situ stress field distribution and fault fracture properties. The major factors that control wellbore instabilities during drilling in each zone are introduced below. (1) The Silurian Longmaxi Formation shale of the fold belt in the central and western, with a high formation pressure and great in-situ stress imbalance, is prone to borehole wall collapse. The reservoirs contain micro fractures and parts of rocks are susceptible to hydration. Consequently, the rock strength is reduced; thus the fracture pressure of the wellbore is decreased. (2) The Longmaxi Formation and Niutitang Formation shales of the fold belt in the southeastern have low formation pressures but great in-situ stress imbalances, so the risk of a borehole wall collapse exists in the inclined wells and horizontal wells. In general, rock hydra-
8 CHINA PETROLEUM EXPLORATION Vol. 21, No. 5, 2016 tion results in a reduction of the rock s fracture pressure, including in minority blocks, so the risk of borehole instability is small. (3) The Cambrian Shuijingtuo Formation shale in the fold-thrust belt of the South Dabashan in the northeastern has a large number of fault folds and natural fractures due to the severe tectonic process and the high formation dip angle, and the formation pressure is low. The carbonaceous shale may soften when encountering water, thus causing its strength to be greatly reduced. Therefore, borehole wall collapses mainly occur in the weak planes (i.e. faults and joints) and carbonaceous shale reservoirs. If the drilling is conducted away from natural faults, there is basically no risk of serious lost circulation in the borehole. (4) The Cambrian Lujiaping Formation shale in the thrust nappe belt of the North Dabashan in the northeastern is characterized by its low formation pressure, its high in-situ stress level and its formation dip angle, so any borehole wall collapse will mainly occur in the vicinity of faults, joints and broken rock belts. The usage of drilling fluids with low densities can be adopted because of their minimal disturbance to the faults and joints, and so the risk of a large scale loss of borehole circulation will not occur. References [1] Tang Daixu, Zhao Jinhai, Wang Hua, et al. Technology analysis and enlightenment of drilling engineering applied in the development of Barnett shale gas in America [J]. Sino-Global Energy, 2011, 16(1): 47 52. [2] Joshi S D. Cost/benefits of horizontal wells [C]. SPE83621, 2003. [3] Albert Atnagulov, Rinat Ismagilov, Nekipelov Y K. et al. 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