Petroleum Exploration and Development

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Gas-water relative permeability measurement of high temperature and high pressure tight gas reservoirs

Fang Jianlong; Guo Ping; Xiao Xiangjiao; Du Jianfen; Dong Chao; Xiong Yuming and Long Fang

, 2014, 41(6): 11-12.

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Generally, gas-water relative permeability curves of tight gas reservoirs are obtained from unsteady experiment under room temperature and normal pressure, which greatly differs from the curves under high temperature and high pressure. In this research, the relative permeability curves of three cores were firstly measured using conventional standard method by displacing formation water with nitrogen under room temperature and normal pressure. Then the relative permeability curves of the same cores were measured by displacing formation water with natural gas on one self-developed full-diameter seepage flow equipment (200 ℃, 200 MPa) under reservoir conditions (160 ℃, 116 MPa) after several processing of the cores. Difference between the relative permeability curves obtained by the two methods shows that, under high temperature and high pressure, there exists a larger two-phase seepage zone and lower irreducible water saturation. At the same gas saturation, gas relative permeability under high temperature and high pressure is higher than that under room temperature and normal pressure, which means, under reservoir situation, the two-phase flow ability of gas and water is stronger and the irreducible water saturation is lower in tight gas reservoirs. The gas-water viscosity ratio, gas-water density ratio and interfacial tension are lower under this situation, which leads to higher sweep efficiency.

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Movability of lacustrine shale oil: A case study of Dongying Sag, Jiyang Depression, Bohai Bay Basin

Zhang Linye; Bao Youshu; Li Juyuan; Li Zheng; Zhu Rifang and Zhang Jingong

, 2014, 41(6): 641-649.

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Taking the Paleogene Shahejie Formation lacustrine shale in Dongying Sag, Jiyang Depression, Bohai Bay Basin, as an example, this paper makes a systematic study on the properties of shale of lower part of Sha-3 Member (Es3x) and upper part of Sha-4 Member (Es4s), including porosity, compressibility, mechanical properties, oil saturation, gas-oil ratio and oil saturation pressure by lab analysis and well log data of shale cores taken from different depths. On this basis, the movability of shale oil is discussed in terms of formation energy. According to the study results, both the elastic movable oil ratios and the solution gas driving movable oil ratios of Es3x and Es4s increase with the shale burial depth, and both ratios of Es4s are generally higher than that of Es3x at the same depth. Within the depth of 2 800 – 4 000 m, the total movable oil ratio of Es3x varies from 8% to 28%, while the total movable oil ratio of Es4s varies from 9% to 30%. Combining with the profiles of oil saturation and movable oil ratio of shale, a conclusion is made that the shale of Es3x and Es4s deeper than 3 400 m in the study area are favorable objects for shale oil exploration.

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Characteristics and controlling factors of beach-controlled karst reservoirs in Cambrian Longwangmiao Formation, Moxi-Gaoshiti area, Sichuan Basin, NW China

Jin Mindong; Zeng Wei; Tan Xiucheng; Li Ling; Li Zongyin; Luo Bing; Zhang Jinglei and Liu Jiwei

, 2014, 41(6): 650-660.

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Based on data from boreholes, cores and lab analysis, the?characteristics, genesis and controlling factors of different types of reservoirs in Cambrian Longwangmiao Formation, Moxi-Gaoshiti area, Sichuan Basin, are examined, and the distribution?of favorable reservoir?zones is predicted. The reservoirs can be subdivided into four types according to the different types of reservoir space and their combination with the “piebald” karst system: pinhole, “piebald” pinhole, cave, and “piebald” cave. Among them, the “piebald” cave reservoir is the best in quality, followed by the cave and “piebald” pinhole reservoirs, and the pinhole reservoir is the worst in quality. The genesis and controlling factors of Longwangmiao Formation reservoir are that the regional shoal deposition gave rise to a large area of grain?dolomite, the layers with intergranular pores and small amount of intragranular dissolution pores of shoal facies provide a material base for later karst reformation. During the Caledonian period, the karst water flowing and corroding along the porous bed formed previously played a key role in the formation of premium reservoirs. During the period of the Caledonian-Hercynian, the tectonic paleogeomorphology controlled the fluid potential of karst water, which in turn decided the development of reservoirs. Karst is most developed on the slope of the paleotopography (along the well line of Moxi 201-Moxi 9-Moxi 12 ), where “piebald” cave or cave reservoirs usually occur, which are the most favorable reservoir zones.

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Late Triassic gravity flow depositional systems in the southern Ordos Basin

Yang Renchao; He Zhiliang; Qiu Guiqiang; Jin Zhijun; Sun Dongsheng and Jin Xiaohui

, 2014, 41(6): 661-670.

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Based on a great deal of core observation and drilling data, the lacustrine gravity flow depositional systems were analyzed comprehensively in the Chang6 and Chang7 members of the Triassic Yanchang Formation, southern Ordos Basin. Such gravity flow depositional systems consist of slides, slumps, sandy debris flow, liquefied flow, turbidity current and other genetic units. In each cycle, from bottom to top, the association of massive bedding (MB), graded bedding (GB) and horizontal bedding (HB) is common, but parallel bedding (PB) and ripple bedding (RB) are poorly developed. The depositional sequence of gravity flow is different from the Bouma sequence of turbidite: MB was deposited by sandy debris flow, GB by turbidity current, PB and RB by bottom currents (traction flow), and HB by deep water residence environment, rather than gravity flows. Deposits are dominated by slides, slumps and massive bedding sandy debris flows at the fan root, by the association of MB-GB-HB sequence of massive bedding sandy debris flows, graded bedding turbidite and horizontal bedding lacustrine mudstone at the middle, and by mainly graded bedding turbidite and horizontal bedding lacustrine mudstone (GB-HB sequence) at the end of sublacustrine fan. Gravity flow depositional sandbodies are mainly developed from the delta front slope to basin plain, expanding by dozens of kilometers towards the center of the lake basin. These sandbodies directly overlay the source rocks in Chang7 Member, with the advantage of near source accumulation. The middle-lower pant of these sandbodies are mainly sandy debris flow depositional sandbodies, which are worth of great concern for their preferable properties and hydrocarbon potential.

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Facies classification and reservoir significance of the Cenozoic intermediate and mafic igneous rocks in Liaohe Depression, East China

Huang Yulong; Shan Junfeng; Bian Weihua; Gu Guozhong; Feng Yuhui; Zhang Bin and Wang Pujun

, 2014, 41(6): 671-680.

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The facies classification and corresponding features of the Cenozoic intermediate and mafic igneous rocks are studied by analyzing drilling cores, cuttings and corresponding thin sections, as well as well-loggings and seismic profiles related to the boreholes in Liaohe Depression of Bohai Bay Basin. Six facies and sixteen sub-facies are classified: volcanic conduit facies (diatreme, crypto-explosive breccia and post-intrusive sub-facies), explosive facies (pyroclastic flow, surge, and fall deposits sub-facies), effusive lava flow facies (compound flow, tabular flow, hyaloclastite sub-facies), extrusive dome facies (outer zone, intermediate zone, and inner zone sub-facies), volcaniclastic facies (resedimented volcaniclastics, epiclast-bearing volcanogenic deposits sub-facies), and intrusive facies (margin, core sub-facies). The characteristics and recognition of these sixteen volcanic sub-facies are described and summarized in detail concerning their primary volcanic textures, structures, lithologic assemblages, genesis and material source, spatial occurrence and distribution. Volcanic sub-facies is the primary controlling factor on volcanic reservoir spaces and their configurations. They constrain the styles and degrees of subsequent tectonic fracture and secondary dissolution of the volcanics, thus determining the porosity, permeability, and efficiency of volcanic reservoirs. Three favorable reservoir facies belts in the Cenozoic intermediate and mafic igneous rocks in Eastern Sag of Liaohe Depression are compound lava flows, outer zone of extrusive dome, and margin of intrusive sub-facies. They should be taken as the major exploration targets of the volcanic reservoirs.

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Ordovician carbonate rock matrix fractured-porous reservoirs in Tahe Oilfield

Mao Cui; Zhong Jianhua; Li Yong; Wang Youzhi; Niu Yongbin; Ni Liangtian and Shao Zhufu

, 2014, 41(6): 681-689.

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Features of porphyritic limestone matrix fracture-vug reservoirs in Tahe Oilfield was examined by core observation, thin section identification, cathodoluminescence, microscopic fluorescence, scanning electron microscope and energy spectrum analysis. Thick and widespread in the Lower-Middle Ordovician Yijianfang and Yingshan Formations, sand-clastic masses in the porphyritic limestone are rich in oil, quite a proportion of oil and gas produced currently is from their matrix rather than completely from the fracture cave system in the past understanding. In irregular spot or ribbon shape on cores, dolomitic sand-clastic masses usually account for about 40% of the total surface of core in many layers, arenite section has a surface porosity of around 39%. The arenite section is well-crystallized dolomite, the dolomite crystals are mainly 100-350 μm in diameter, equivalent to medium-fine sand; high-pressure mercury injection experiment results show that the reservoir physical property of sand-clastic masses is much better than that of micrite limestone, with a porosity of 12.57%-36.39%. There developed abundant stylolites and microcracks around the sand-clastic masses, which connect the oil bearing units of dolomitc sand-clastic masses, making micropores and microcracks communicate and become effective reservoir space.

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Thermodynamic analyses of dolomite dissolution and prediction of the secondary porosity zones: A case study of tight tuffaceous dolomites of the second member, Permian Lucaogou Formation reservoir, Santanghu Basin, NW China

Meng Yuanlin; Zhu Hengdong; Li Xinning; Wu Chenliang; Hu Anwen; Zhao Zitong; Zhang Lei and Xu Cheng

, 2014, 41(6): 690-696.

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The vertical distribution and geological origin of secondary porosity zones have been studied in the tight tuffaceous dolomites of the second member of Permian Lucaogou Formation, Santanghu Basin, Xinjiang, China, and the lateral distribution of secondary porosity zones is predicted using the thermodynamic method. There are three secondary porosity zones in Malang-Tiaohu Sag, formed by reservoir dissolution by the acids including the organic acids generated from decarboxylation of kerogen and the inorganic acids generated from the clay mineral transformations. Gibbs free energy increments of dissolution reactions for different minerals are calculated under various pressures and temperatures to investigate the lateral distribution of secondary porosity zones, combined with litho-facies distribution of the second member of the Lucaogou Formation. Calculation result shows deeply buried dolomite strata are most prone to be dissolved and secondary pores in the second member of the Lucaogou Formation have been formed by tuffaceous dolomites. In general, the most developed secondary porosity zones with favorable tight oil reservoir potentials are located in the central Malang-Tiaohu Sag, overlapped with the high-quality source rocks that are semi-deep to deep lacustrine facies in origin.

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Quartz surface morphology of Tertiary rocks from North East Sarawak, Malaysia: Implications for paleo-depositional environment and reservoir rock quality predictions

Abdullah Musa Ali and Eswaran Padmanabhan

, 2014, 41(6): 697-704.

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The relationship between quartz surface textural defects (derived from weathering and diagenesis), palaeo-depositional environment and reservoir quality were studied using Tertiary outcrop rock samples obtained from the Belait and Lambir formations of the Sarawak Basin, Malaysia. Thin sections were used for mineral identification and to make observations regarding grain size and texture. Morphological characterization of the samples was performed using scanning electron microscopy (SEM) attached with energy-dispersive X-ray spectrometry (EDX) system, to show variations in quartz surface texture. The SEM images of Belait conglomerates reveal euhedral quartz crystals characterized with prominent mechanical weathering defects (such as straight and conchoidal fractures and striations). Conversely, the analysis of the Lambir sandstones identified chemical weathering features (such as chemical etchings, pitting, solution pits and notches). On the basis of petrology, SEM and CT scan images, evaluation results of reservoir quality indicate that the Lambir Formation in this study area is high-energy coast deposit, with apparent tide-dominated features; while Belait Formation is neritic-delta deposit, with obvious wave-dominated features; reservoir quality of the Belait Formation and Lambir Formation are poor, but the porosity of the Belait Formation is relatively higher than that of the Lambir Formation.

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A near-surface seismic scattered wave separation method

Xu Jixiang; McLean B F and Song Xuejuan

, 2014, 41(6): 705-711.

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Considering that near-surface scattered waves could not be suppressed by conventional denoise method, this paper analyzes the characteristics of scattered waves and achieves the near-surface scattered wave separation by the seismic interferometry theory. Seismic data in mountain area is generally characterized by low signal to noise ratio, weak effective wave energy and strong near-surface scattered wave energy, so the near-surface seismic scattered waves must be firstly separated to improve the signal to noise ratio of seismic data during seismic data processing. The events of the near-surface seismic scattered wave in the adjacent common shot gathers are parallel. According to the near-surface scattered wave kinematics, the seismic interferometry method is used to eliminate the influence of seismic wave propagation in the same path, coherently enhance near-surface scattered waves, and then separate them from original seismic records. Taking the seismic data in mountain area in west China as an example, the energy of near-surface scattered wave is enhanced by direct wave field and full wave field seismic interferometry to separate the waves. As a result, the seismic data after processing generally eliminates near-surface scattered waves, verifying the validity and feasibility of the near-surface seismic scattered wave separation method.

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Sensitivity parameters of tight sand gas: A case study of Lower Cretaceous Yingcheng Formation of Yingtai gas field in Songliao Basin, NE China

Xu Cuixia; Ma Pengshan; Lai Lingbin; Sun Yuanhui and Li Zhongcheng

, 2014, 41(6): 712-716.

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Aiming at the difficulty in distinguishing gas-bearing layers and surrounding rocks due to the small differences between their impedance, the gas-bearing sensitivity parameters are studied in tight sandstone to identify thin layer tight gas accurately. According to elastic parameters sensitivity analysis of fluid in tight sandstone, a new combined elastic parameter is proposed, i.e. the ratio of the first Lame coefficient to S-wave velocity. Furthermore, considering different geological conditions, extending attribute (the ratio of Russell fluid phase to S-wave velocity) is deduced, and it can be simplified as the ratio of the first Lame coefficient to S-wave velocity in certain condition. Fluid replacement process is conducted by Gassmann equation and Brie empirical equation, and the new combined elastic parameter is more sensitive to gas saturation than common parameters such as the product of the first Lame coefficient and density, the ratio of P-wave to S-wave velocity, verifying the validity of the new combined elastic parameter. The pre-stack inversion is applied in the second member of Lower Cretaceous Yingcheng Formation in Yingtai gas field. Compared with section of the product of the first Lame coefficient and density, it shows that the new combined elastic parameter improves the accuracy of identifying gas-bearing layers, well conforms to the logging interpretation, and greatly enhances the identification ability and prediction accuracy towards gas-bearing layers.

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Macroscopic three-dimensional physical simulation of water flooding in multi-well fracture-cavity unit

Hou Jirui; Li Haibo; Jiang Yu; Luo Ming; Zheng Zeyu; Zhang Li and Yuan Dengyu

, 2014, 41(6): 717-722.

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A macroscopic three-dimensional physical simulating model of multi-well fracture-cavity units was designed and constructed based on similarity theory. The characteristics and the water breakthrough pattern of fracture-cavity reservoirs developed in bottom water depletion and water injection modes were investigated by the model. The results show that, in bottom water drive, under the effect of bottom water depletion and water breakthrough, the wells had high productivity in early stage and fast decline. After energy supplement by injecting water, the productivity rebounded in a short time and then began a slow decline. The bottom water tended to coning to the wells at the place of bottom water entry. The water breakthrough pattern is punctiform and the water breakthrough time is controlled by the well’s connectivity to the bottom water; the water injection can inhibit coning and intrusion of bottom water, turning the punctiform water breakthrough in bottom water drive period into planar line form, and the water breakthrough time in water injection period was mainly influenced by the well depth. The water cut of wells in water flooding multi-well fracture-cavity units changes in three patterns: slow rise, staircase rise and abrupt watered-out, which is influenced by the reservoir type and the coordination number. When the well encounters cavity, the water cut increasing rate slows down with the increase of the coordination number; when the well drilled fractures, the water cut changes in staircase pattern with the increase of coordination number.

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Varying law of water saturation in the depletion-drive development of sandstone gas reservoirs

Hu Yong; Li Xizhe; Lu Xiangguo; Lu Jialiang; Xu Xuan; Jiao Chunyan and Guo Changmin

, 2014, 41(6): 723-726.

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The varying law of on-way water saturation in the depletion-drive development (the formation pressure: 20 MPa depleting to abandonment pressure) of water-bearing gas reservoirs was studied through four groups of cores whose physical properties represent the rocks in Sichuan Xujiahe gas reservoirs, and the cores permeabilities are 1.630×10-3 μm2, 0.580×10-3 μm2, 0.175×10-3 μm2, 0.063×10-3 μm2, respectively. Combined with the rock characteristics of microscopic pore structure and capillary pressure, the interaction mechanism between different permeability sandstone and water was analyzed and was verified on two wells. The conclusions are as follows: (1) The water trapping effect in the sandstone reservoir is dependent on the sandstone reservoir permeability (the critical value is 0.175×10-3- 0.580×10-3 μm2). (2) The formation with permeability greater than 0.580×10-3 μm2 is characterized with big size pore and throat, low capillary pressure and weak trapping effect. So a portion of pore water would be displaced by gas and became movable water. (3) The tight formation with permeability less than 0.175×10-3 μm2 is characterized with small size pore and throat, high capillary pressure and strong trapping effect. When the rock core is saturated by moisture gas, the pore water would not be displaced by gas and would be trapped in the sandstone, which results in the water saturation increases rather than decreases. Drawdown pressure should be kept within a proper range to extend the life cycle of wells.

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Injection parameters optimization of cross-linked polymer microspheres and polymer composite flooding system

Yang Junru; Xie Xiaoqing; Zhang Jian; Zheng Xiaoyu and Wei Zhijie

, 2014, 41(6): 727-730.

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Based on the facts that there is no obvious improvement in injection conformance and no significant water cut reduction in production wells after polymer flooding in S oilfield in Bohai Bay, this study used cross-linked polymer microspheres-polymer composite flooding to research the effect of chemical system composition, displacement speed, injection volume on polymer flooding by physical simulation experiments, and to optimize injection parameters of composite system. The results showed that the higher the concentration of cross-linked polymer microspheres at a total concentration of 1 750 mg/L, the more the oil recovery enhancement; the 1 350- 1 650 mg/L polymer composite system can achieve better oil recovery when the cross-linked polymer microsphere concentration reaches 400-100 mg/L; compared with single polymer flooding, the cross-linked polymer microspheres polymer composite system flooding can enhance recovery factor by 8%-11%; in addition, it was found that the composite system could better improve polymer flooding at the displacement rate of 3.5 m/d and the injection volume of 530 mg/L×PV.

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Oil well perforation technology: Status and prospects

Liu He; Wang Feng; Wang Yucai; Gao Yang and Cheng Jianlong

, 2014, 41(6): 731-737.

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Perforation is a key link in well completion. To meet the development requirements of different types of oil and gas fields, after over ten years of research and development, a series of perforation methods and matching processes have been established, such as deep penetration shaped perforation, composite perforation, directional perforation etc, which on the one hand improve the result and efficiency of perforation completion and stimulation, on the other hand prolong the service life of reservoir by protecting the reservoir. Meanwhile, the optimization of perforation design and the improvement of perforation check method further enhance the safety and success rate of perforation, and make the perforation test process and field application more standardized. For unconventional tight oil and gas reservoirs, deep-ultra-deep reservoirs, thin and poor reservoirs, reservoirs with edge or bottom water, staged fracturing of horizontal wells, and re-perforating of old wells, perforation techniques such as 3D perforation, ultra-deep penetration perforation, and high temperature high pressure perforation, and supplement perforation etc should be studied according to the features of the specific oil and gas reservoir and well.

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Disintegrating fracturing ball used in ball injection sliding sleeve for staged fracturing

Pei Xiaohan; Wei Songbo; Shi Bairu; Shen Zejun; Wang Xinzhong; Tong Zheng and Fu Tao

, 2014, 41(6): 738-741.

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A disintegrating fracturing ball used for multi-stage fracturing stimulation was studied and developed, the disintegrating characteristics and mechanical properties of the disintegrating material were analyzed, and the ball was tested in both ground pressure test and field operation. The disintegrating material is an Mg-based alloy with the density of 1.8-2.0 g/cm3. The disintegrating material can dissolve in KCl solution and the disintegration rate increases with increasing temperature, while the disintegration rate is low in the guar gum fracturing fluid; the compressive strength of the disintegrating material can reach 360 MPa, and the material breaks when the deformation reaches 20% with a mixed ductile-brittle fracture. The ground pressure test shows that the ball can hold pressure of 70 MPa and keep for 4 hours under 80 ℃ with the sealing performance between fracturing ball and ball seat meeting operation needs. Field fracturing operation shows that the disintegrating fracturing ball demonstrates high quality performance during the operation and dissolves in-situ after fracturing, eliminating the operation risk that might be caused by fracturing ball flow-back, thereby decreasing production cost and saving operation time.

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Field test of volume fracturing for horizontal wells in Sulige tight sandstone gas reservoirs

Ma Xu; Hao Ruifen; Lai Xuan’ang; Zhang Yanming; Ma Zhanguo; He Mingfang; Xiao Yuanxiang; Bi Man and Ma Xinxing

, 2014, 41(6): 742-747.

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Based on the development degree of natural micro-fractures, rock brittleness and two-direction stress and other geological conditions of the Sulige gas field, the feasibility of using volume fracturing to increase production was analyzed and verified by field test. The Sulige gas field, a typical tight sandstone gas reservoir, has developed natural micro-fractures, with fracture complex index of 0.3-0.5, rock brittleness index of 36-52 and two-direction stress heterogeneity factor of 0.17. From the development experiences of unconventional gas reservoirs abroad, the geological conditions in the Sulige gas field is suitable for volume fracturing. Through lab experiments and pilot field tests, a volume fracturing technology for horizontal wells has been developed, which features “fracturing with low-viscosity liquid, carrying proppant with high-viscosity liquid, combination of multi-scale proppants, and massive fracturing at a high injection rate”. The technique had been applied in 42 wells of the Sulige tight gas field by the end of 2013. The initial production of wells treated by this approach is 1.2 times that of the adjacent wells treated by conventional fracturing, indicating that the technique can enhance the production of the horizontal wells in the Sulige gas field substantially.

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A chemo-mechanical coupling model of deviated borehole stability in hard brittle shale

Wen Hang; Chen Mian; Jin Yan; Wang Kai; Xia Yang; Dong Jingnan and Niu Chengcheng

, 2014, 41(6): 748-754.

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A chemo-mechanical coupling model of borehole stability in hard brittle shale considering structure characteristics and targeted hydration was established, the influencing factors of the distribution of collapse pressure were analyzed based on the model, and a field case analysis was conducted. Based on the physicochemical properties of hard brittle shale, a drilling fluid activity window was proposed for calculating collapse pressure by establishing the relationships of drilling fluid activity vs. swelling ratio of rock and rock activity vs. moisture content to determine critical swelling ratio of rock and reasonable moisture content. The results show that, when fixing the dip angle of weak plane, the collapse pressure appears a quarter symmetric distribution with the change in tendency, there is no azimuth angle who has a monotonic increasing or decreasing collapse pressure, and dangerous sections and safe sections exist alternately; compared with cohesion of weak plane, collapse pressure is more sensitive to internal friction angle. Field case shows that, accurate prediction of collapse pressure distribution can be obtained by the chemo-mechanical coupling model, in which borehole stability can be ensured and the density of drilling fluid can be decreased as long as the drilling fluid activity is controlled in the window.

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Gas hydrate risks and prevention for deep water drilling and completion: A case study of well QDN-X in Qiongdongnan Basin, South China Sea

Zhang Liang; Zhang Chong; Huang Haidong; Qi Dongming; Zhang Yu; Ren Shaoran; Wu Zhiming and Fang Manzong

, 2014, 41(6): 755-762.

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Taking a deep-water exploration well of natural gas located in the Qiongdongnan Basin in the South China Sea as an example, the hydrate risks of the well under operational conditions during drilling and testing processes were analyzed, and the corresponding hydrate prevention solutions were presented and verified by lab experiments and field application. Based on the predicted gas hydrate equilibrium curves and the calculated wellbore pressure-temperature fields, the hydrate risks were analyzed. The maximum sub-cooling temperature is 6.5 ℃ during normal drilling with a small hydrate stability zone in the wellbore; when the drilling or testing stops, the hydrate stability zone in the wellbore becomes larger and the maximum sub-cooling temperatures are 19 ℃ and 23 ℃ respectively; the maximum sub-cooling temperature at the beginning of testing is no more than that when testing stops; when the tested production rate of natural gas increases, the hydrate stability zone in the wellbore decreases or even disappears if the gas rate is more than 25×104 m3/d. The designed hydrate prevention solutions include: adding muriate of potash and ethylene glycol into drilling fluid during normal drilling and when drilling stops; adding calcium chloride/potassium formate and ethylene glycol into testing fluid; applying downhole methyl alcohol injection when the production rate of natural gas is lower than 25×104 m3/d; filling the testing string with testing fluid when the test shuts down for a long time. Lab experiments and field operations have indicated that all the designed solutions can meet the requirements of hydrate prevention.

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Propagation area evaluation of hydraulic fracture networks in shale gas reservoirs

Hou Bing; Chen Mian; Li Zhimeng; Wang Yonghui and Diao Ce

, 2014, 41(6): 763-768.

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Based on hydraulic fracturing experiments in laboratory, the hydraulic fracture propagation in shale was analyzed, a method for evaluating the fracture propagation extent was proposed, and the effects of geological factors and engineering factors on fracture propagation were studied. “Stimulated Rock Area (SRA)” was proposed as an evaluation index for the hydraulic fracturing results. By analyzing the experiment results, it is found that hydraulic fracturing in shale reservoirs can generate a complex fracture network; a lower stress difference in brittle shale formation and a shorter distance between hydraulic fracture and bedding plane lead to a larger SRA and more complex fracture morphology; a fracture network is more likely to generate in the case that the angle between horizontal maximum stress and bedding plane is 90° or large enough, or the approaching angle between hydraulic fracture and well-opened natural fracture is close to 90°; a higher brittle mineral content leads to better fracturing ability; a lower fluid viscosity and higher flow rate leads to a larger SRA; a variable flow rate increases the possibility that the hydraulic fracture communicates bedding planes and natural fractures.

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23 December 2014, Volume 41 Issue 6