石油实验地质

2014, 36(6): .

Abstract(357) PDF-CN(314)

Abstract:

Nano-meter petroleum geology: Discussion about geology theory and research method of unconventional petroleum

Wang Congxiao, Luo Qun, Song Yan, Jiang Zhenxue, Liu Yunsheng

2014, 36(6): 659-667. doi: 10.11781/sysydz201406659

Abstract(1053) PDF-CN(581)

Abstract:
At present, conventional petroleum explorations have become more and more difficult. On the contrary,unconventional petroleum reservoirs represented by nano-meter oil and gas have a great potential, and are the main fields for petroleum explorations. Due to the obvious differences between conventional and unconventional petroleum, traditional petroleum geology which was used to guide conventional petroleum explorations is no longer suitable for unconventional petroleum explorations. Nano-meter petroleum geology is an interdiscipline between nanotechnology and petroleum geology. It came into being due to the demands of unconventional petroleum explorations and the booming of nanotechnology. The mechanisms and laws of nano-meter petroleum generation, retention, migration, accumulation, preservation and escaping are the main research tasks of nano-meter petro-leum geology. The forming, output states and distribution features of unconventional petroleum are the main aims of nan-meter petroleum geology. Nanotechnological idea and its high-resolution testing techniques, physical simulation experiments, typical example analyses are the main guiding thought and research measures. As a new petroleum geology theory system, nano-meter petroleum geology will play an important role in future petroleum exploration and development.

Main controlling factors for tight oil accumulation in continental lacustrine basins in China

Ma Hong, Li Jianzhong, Yang Tao, Yan Weipeng, Tang Hui, Guo Bincheng, Huang Fuxi, Lü Weining

2014, 36(6): 668-677. doi: 10.11781/sysydz201406668

Abstract(1187) PDF-CN(1018)

Abstract:
Tight oils refer to the oils accumulated in tight reservoirs. The tight reservoirs mainly include tight sandstones and carbonate rocks, with in-situ permeability less than 0.1×10^-3 μm². There is no natural production normally, and commercial oil flows can be obtained through technical reconstructions. In China, the tight oil reservoirs in continental lacustrine basins are developed, and four controlling factors for tight oil accumulation have been concluded as followed: developing superior hydrocarbon source rocks, being preferable reservoirs, possessing original driving forces and accumulating near to source rocks. Two types of high-quality hydrocarbon source rocks developed in the continental lacustrine basins in China. The source rocks of type Ⅰ have superior organic type, high organic content, high maturity, and big hydrocarbon generation potential. The source rocks of type Ⅱ are outstanding in hydrocarbon transformation ratio. Tight sandstones and carbonate rocks work as the main reservoirs for tight oils, and are featured by strong heterogeneity (discontinuous in transverse and superimposed in vertical). Generated hydrocarbon pressurization is the main driving force for tight oils in China. Powerful pressure differential between source rocks and reservoirs displaced the generated oils to fill the tight reservoirs continuously which were close to high-quality hydrocarbons. Micro-crack in communication and micro-nanometer pore development were the key conditions for tight oil gathering. Micro-nanometer pore development increased the effective reservoir space and micro-crack in communication provided the effective channel for tight oil gathering. The tight oil resources are rich in China. The favorable exploration area is about 16×10⁴ km², and the geological resources are about (160-200)×10⁸ t. The favorable exploration areas mainly distribute in the Ordos, Junggar, Songliao, Bohai Bay, Qaidam and Sichuan basins, and so on.

Gas-bearing influential factors and estimation of shale reservoirs in Upper Paleozoic, Ordos Basin

Guo Shaobin, Zhao Keying

2014, 36(6): 678-683. doi: 10.11781/sysydz201406678

Abstract(1123) PDF-CN(532)

Abstract:
In the estimation of shale gas reservoirs, the shale gas content and the difficulty for fracture development are the main influencing factors. Six critical factors were chosen, including organic carbon content, the amount of adsorbed gas, maturity, porosity, and the content of I/S and brittle mineral. According to the theory of grey correlation grade, the shale reservoirs in the Upper Paleozoic in the Ordos Basin were studied. The reservoirs were classified into three types based on the Reservoir Estimating Index (REI). When REI≥0.5, the reservoirs belong to type Ⅰ. When 0.33≤REI<0.5, the reservoirs belong to type Ⅱ. When 0.3≤REI<0.33, the reservoirs belong to type Ⅲ. Combined with previous studies, an estimation scheme of transitional facies shale gas reservoirs in the study area was proposed, and the characteristics of different reservoirs were shown with images.

Effective sand body distribution and its main controlling factors in tight sandstone gas reservoirs: A case study of southern Sulige Gas Field

Guo Zhi, Jia Ailin, Bo Yajie, Tang Haifa, Guo Benxiao

2014, 36(6): 684-691. doi: 10.11781/sysydz201406684

Abstract(884) PDF-CN(492)

Abstract:
The southern Sulige area is the southward extension of the main part of the Sulige Gas Field, where is far from sediment provenance, buried deep and has a strong diagenesis. Understanding the distribution characteristics and main controlling factors of effective sand body is the basis of the efficient development of the edge regions of the Sulige Gas Field, such as the southern Sulige area. Focusing on the reservoirs of He8 member and Shan1 member, the areas of tectonic, sedimentation, reservoir and diagenesis were studied, and the distribution characteristics and main controlling factors of effective sand body were concluded. The effective sand bodies in the southern Sulige area mainly distribute in point bars and the bottom of distributary channels, and can be vertically classified into three types: isolated, vertically stacking, and laterally shiplap ones. Horizontally, they locate in the central and eastern sand belts of the study area. During the formation of effective reservoirs, a gentle structure background is necessary for the sedimentation and formation of gas reservoirs. The shallow braided-river delta plain deposits in the strong hydrodynamic environment determined the distribution pattern of reservoir, whereas the compaction, cementation and dissolution diagenesis before the formation progress of gas reservoirs greatly reformed the reservoirs and controlled the distribution of effective sand body.

Generation conditions of shale gas in Carboniferous Keluke Formation, northern Qaidam Basin

Yang Yunfeng, Rao Dan, Fu Xiaodong, Shen Baojian, Xu Jin

2014, 36(6): 692-697. doi: 10.11781/sysydz201406692

Abstract(988) PDF-CN(584)

Abstract:
Based on outcrop geological survey in the northern Qaidam Basin and integrated with other data of drillings, outcrops and previous research results, the Carboniferous Keluke Formation shale gas accumulation conditions and core area selection were investigated by delineating regional distribution of gas shale, organic geochemical features, mineral compositions, pore system and gas content in gas shale. Shale in the Keluke Formation is rich in organic matter. The TOC value ranges from 0.28% to 11.93%, and is over 2% in average. The thermal maturity value (R_o) ranges from 0.9% to 1.44%, and is 1.12% in average, indicating for the mature stage of organic matter thermal evolution. The available thickness of shale in the Keluke Formation is 30-150 m. The content of brittle minerals is greater than 40%. Pore systems of micro and nano scales are well-developed. Gas content ranges from 1.01 to 2.85 m³/t, and is 1.87 m³/t in average. The Gaqiu Sag, Ounan Sag and Delingha Fault Depression are favorable for the generation and accumulation of shale gas, hence are the targets for shale gas exploration in the Keluke Formation.

Diagenesis of tight sandstones and its controls on reservoirs genesis, Changling Faulted Depression, Songliao Basin

Li Yilong, Jia Ailin, Wu Chaodong

2014, 36(6): 698-705. doi: 10.11781/sysydz201406698

Abstract(1007) PDF-CN(569)

Abstract:
Based on rock analyses under microscope, organic matter analyses, fluid inclusion data and so on, the diagenesis stages of the Denglouku Formation and the first member of the Quantou Formation in the Changling Faulted Depression have reached the stages A2 and B. The diagenesis sequences of tight sandstones have been determined as followed: (1) Early calcite cement; (2) Albitization of plagioclase and generation of authigenic laumontite; (3) Ⅰ-grade quartz overgrowth; (4) Dissolution of potassium feldspar and generation of authigenic fibrous illite and authigenic chlorite; (5) Ⅱ- and Ⅲ-grade quartz overgrowth; (6) Subtle dissolution of remained potassium feldspar. Strong compaction and early calcite cement resulted in the densification of sandstones. Due to compaction, over 70% of primary pores lost in the sandstone reservoirs buried over 3 000 m deep, which was the main cause for reservoir densification. Secondary pores as a result of feldspar (especially potassium feldspar) corrosion which was controlled by the activity of diagenesis fluid in open system, were the main cause of high-quality reservoirs.

Study progress of origin of fine-grained sedimentary rocks in deep-water area of lacustrine basin: Taking Yangchang Formation in Ordos Basin as an example

Pang Jungang, Li Sai, Yang Youyun, Liu Lijun, Zhu Jie, Chen Dong

2014, 36(6): 706-711. doi: 10.11781/sysydz201406706

Abstract(778) PDF-CN(727)

Abstract:
Since the exploration objects gradually changed from shallow-water to deep-water area in lacustrine basins for China's Meso-Cenozoic lacustrine basins, it will break the concept that the deep-water area is a forbidden zone for hydrocarbon exploration. Fine-grained deposits in the deep-water area were poorly studied in the past, and mainly focusing on the hydrocarbon-generating potential of source rocks. In order to determine the types and origins of the fine-grained deposits in the deep-water area, and to guide unconventional hydrocarbon explorations, a case study was made in the Yanchang Formation of the Ordos Basin. Based on a large amount of previous data and combined with modern testing techniques, the sedimentary facies and origins of rocks in the deep-water area were analyzed, especially the characteristics and origins of deep-water autochthonous sedimentation, tuff, deep thermal fluid, distal turbidite and radioactive uranium. It was emphasized that rock and mineral analysis together with geochemical analysis were the main methods to realize fine-grained deposits, among which nanotechnology would be the main research method in current and the future. A certain amount of pores developed in the fine-grained deposits in the deep-water area, which were close to source rocks, hence were favorable for hydrocarbon accumulation and exploration.

Distribution and genesis of hydrogen gas in natural gas

Meng Qingqiang, Jin Zhijun, Liu Wenhui, Hu Wenxuan, Zhang Liuping, Zhu Dongya

2014, 36(6): 712-717. doi: 10.11781/sysydz201406712

Abstract(939) PDF-CN(606)

Abstract:
The paper systemically studied the distribution and genesis of hydrogen gas in natural gas all over the world on the basis of former study. The hydrogen gas content was studied for some oil and gas wells in the Jiyang Depression, and their genesis was discussed at the same time. The hydrogen gas content was very low in the Jiyang Depression. The H₂/³He value was all lower than 20×10⁶ in the wells which had R/Ra value. It was suggested that the hydrogen gas raised from mantle.

Typical shale gas reservoirs in USA and enlightenment to exploration and development

Zhu Tong, Cao Yan, Zhang Kuai

2014, 36(6): 718-724. doi: 10.11781/sysydz201406718

Abstract(955) PDF-CN(865)

Abstract:
Through the comparative studies on the geological parameters of typical shale gas reservoirs, according to lithologic combination, reservoir pressure and shale mineral composition, the typical shale gas reservoirs in USA are divided into three categories: the layered ordinary-overpressure siliceous shale type (taking Barnett as the representative), the layered super-high pressure siliceous-calcium shale type (taking Haynesville as the representative) and the interbedded super-high pressure calcium shale type (taking Eagle Ford as the representative). Compared to those in USA, the shale gas reservoirs in the Sichuan Basin and the surrounding area are featured by multiple fields, layers and types. They are also divided into three categories: layered ordinary-low overpressure siliceous shale type on basin margin (taking Pengshui and Zhaotong Wufeng-Longmaxi Formation shale as the representative), layered super-high pressure siliceous shale type inside basin (taking Fuling, Changning and Fushun Wufeng-Longmaxi Formation shale as the representative), interbedded super-high pressure calcium-clay shale type inside basin (taking Fuling and Yuanba Da'anzhai segment as the representative). Learned from the successful exploration and development experience of similar shale gas reservoirs in USA, targeting to carry out development and engineering technology research and economic evaluation of different type shale gas reservoirs, this is the key to realize the effective development of multiple type shale gas reservoirs in China.

Reservoir characterization and exploitation potential in Orinoco heavy oil belt in Venezuela

Hou Jun, Dai Guohan, Wei Jie, Xiao Yi, Xu Xuepin

2014, 36(6): 725-730. doi: 10.11781/sysydz201406725

Abstract(1395) PDF-CN(779)

Abstract:
The Orinoco heavy oil belt is on the southern slope of the Eastern Venezuela Basin, with an area of 55 000 km². The heavy oil reservoirs were buried 350-1 200 m deep. The unconsolidated sandstones in Oligocene and Miocene worked as the main reservoirs, with the average porosity and permeability of 33.4% and 4 760×10^-3 μm², respectively. Reservoir temperature is 40-55 ℃. Reservoir pressure coefficient is about 1. Super heavy oil API is 7.5 °-9 °. Situ viscosity is 1 000- 6 000 cP. Reservoir effective thickness is 6-120 m. The original proven geologic reserve is 11 220×10⁸ bbl, and the recoverable reserve is 2 600×10⁸ bbl. There are five heavy oil developing blocks with daily oil production of about 72 ×10⁴ bbl. A set of economic and feasible developing technology series has been formed. The recoverable reserve of the developing blocks is about 3% of the total recoverable reserves of heavy oil belt, showing great exploration potentials.

Organic geochemical characteristics and origin of solid bitumen and oil sands in northwestern Sichuan

Wang Guangli, Wang Tieguan, Han Keyou, Wang Lansheng, Shi Shengbao

2014, 36(6): 731-735. doi: 10.11781/sysydz201406731

Abstract(890) PDF-CN(728)

Abstract:
Hydrocarbon compositions extracted from a set of solid bitumen and oil sands collected in the northern Longmenshan Mountain, the northwestern Sichuan, South China, are unique and consistent. It is suggested that the bulk δ¹³C values (<-32‰) for the extracts and each fraction show overall depleted values, which is typical of pre-Cambrian source. The high concentrations of C₂₉ steranes relative to C₂₇ and C₂₈ steranes can be explained by the contribution of cyanobacteria, and the distribution of triaromatic steranes has similar characteristics. 24-n-propylcholestane and 24-isopropylcholestane are abundant, which should be derived from marine chrysophyte algae and demosponges. The high abundance of pregnane and homopregnane could be associated with such specific depositional environment as anoxic to euxinic bottom waters. The absence of rearranged steranes, abundant 30-norhopane, C₃₅ and C₂₄ hopane tetracyclic terpanes, and a wealth of dibenzothiophene compounds, reflect the hypoxic environment and higher carbonate rock content. The features of solid bitumen and oil sands in the northwestern Sichuan indicate that they originated from the Doushantuo Formation of Sinian, and can be compared with foreign crude oils which generated during the same period. The presence of UCM and 25-norhopane proved biological degradation during the preservation and destruction processes of ancient reservoir. The hydrocarbons were generated by sulfur-rich kerogens at the early oil windows with R_c values in the range of 0.57%-0.84%. Tectonic uplift and the following erosion and biodegradation might explain the destruction of ancient reservoir.

Geochemical characteristics and correlation of extracts from Silurian bituminous sandstones and Carboniferous oil sands in well Ha6, northern Tarim Basin

Cheng Bin, Wang Tieguan, Chang Xiangchun, Yuan Yuan, Wang Ning

2014, 36(6): 736-743. doi: 10.11781/sysydz201406736

Abstract(689) PDF-CN(673)

Abstract:
Five Silurian bituminous sandstone and Carboniferous oil sand samples were collected from well Ha6 in the Halahatang Sag of the Tarim Basin, and geochemical analyses including extraction, stable carbon isotope composition, saturate fraction gas chromatography and biomarkers were performed. The δ¹³C (‰) values for extracts from the Silurian bituminous sandstone and the Carboniferous oil sand samples are very close. The CPI values range from 0.95 to 1.06, the OEP values from 0.94 to 1.00, the Pr/Ph values from 0.34 to 0.76, the C₂₁/C₂₃ tricyclic terpane values from 0.37 to 0.47, the C₂₉/C₃₀ hopane values from 0.91 to 0.97, the C₃₅S/C₃₄S hopane values from 0.91 to 1.00, the gammacerane/C₃₀ hopane values from 0.69 to 0.79, the Ts/(Ts+Tm) values from 0.39 to 0.43. Besides, the relative concentration of C₂₇, C₂₈ and C₂₉ regular steranes for extracts from all samples is significantly similar and so does the relative concentration of fluorene, dibenzofurans and dibenzothiophene. Extracts from five samples all contain 25-norhopanes and n-alkanes and acyclic isoprenoids with different abundance and the saturated fraction gas chromatograms show baseline humps called UCM, i.e., n-alkanes and acyclic isoprenoids co-exist with UCM and 25-norhopanes. Based on the above analyses, it was concluded that Silurian and Carboniferous oils were derived from same source rocks and had undergone multiple charges and different degrees of biodegradation.

Hydrocarbon supplying characteristics of tight oil source rocks in Pingdiquan Formation, northeastern Junggar Basin

Yuan Bo, Wang Xinqiang, Lu Jungang, Chen Shijia, Li Fenglei

2014, 36(6): 744-751. doi: 10.11781/sysydz201406744

Abstract(1652) PDF-CN(612)

Abstract:
In the northeastern Junggar Basin, oils were self-generated and self-preserved in the Pingdiquan Formation. Because of tight reservoir and frequent sand-shale interbedding, the hydrocarbon supplying ability of source rocks is the key factor of tight oil exploration in the study area. The studies of organic matter abundance, type and maturity of source rocks from the Pingdiquan Formation showed that the source rocks from the first and second members of the Pingdiquan Formation are featured by high organic matter abundance and favorable organic matter type, and are during the low-mature and mature stages, hence have high ability of hydrocarbon supplying, but the vertical distribution of main hydrocarbon supplying sections varies among different regions. The hydrocarbon supplying centers in the first and second members of the Pingdiquan Formation have inheritance. There are three hydrocarbon supplying centers including the Huoshaoshan anticline-Huodong-Huonan area, the Shishugou Sag, and the Cai2-Dinan1 well area in the Wucaiwan Sag. Source rock evolution was affected by structure. The source rocks in the Huodong Syncline and Shi-shugou Sag are the most mature, and have reached hydrocarbon generation peak, while those in the Huonan Slope and Wucaiwan Sag take the second place, and are in the early mature stage. The source rocks in the Huoshaoshan Anticline, Huobei, Shadong and Zhangpenggou areas have the lowest maturity. The present exploration achievements have been made mainly in the Huoshaoshan Anticline, Huodong and Huonan areas, while the Shishugou Sag and the Cai2-Dinan1 well area in the Wucaiwan Sag also have good potential.

Experimental investigation on sandstone sample disaggregation using a repetitive freezing and thawing technique

Zhang Youyu, Horst Zwingmann, Liu Keyu, Tao Shizhen, Luo Xiuquan

2014, 36(6): 752-761. doi: 10.11781/sysydz201406752

Abstract(1002) PDF-CN(539)

Abstract:
A repetitive freezing and thawing disaggregation technique, simplified as freezing technique, is des-cribed. The freezing technique is a new method for preparing clay suspension during the separation and enrichment of authigenic illites from reservoir sandstones. The disaggregating effects and the controlling factors have been investigated in detail using typical sandstone samples, and compared with a wet grinding technique, as a conventional disintegration method. Comparing with the wet grinding technique, the freezing technique has advantages and disadvantages. The freezing technique is more effective to avoid detrital potassium feldspar contamination. The obtained authigenic illite K-Ar ages are more reliable as void of detrital contamination. Sample disintegration time is mainly related to porosity and permeability and long disintegration timeframes can be a disadvantage for well cemented sandstone samples. The buried depth of the sandstone samples is the main controlling factor, as well as the shale content and organic content comprising coal seams or residual oil films or bitumen coatings. The experimental results show that the freezing technique can be used to disaggregate less consolidated or medium cemented sandstones mainly related to variable shallow to medium depths ranges. For well cemented and deeply buried sandstones with low porosity and permeability ranges, the method is less suited as long disintegration timeframes of several months or years are required. The experimental results also show that the wet grinding is still a practical and effective technique for preparing clay suspension, with the advantages of easy-operation, celerity and better effects, and has very bright application futures.

Prospect of shale gas evaluation in view of measurement techniques development of coal seam gas content

Bao Yunjie

2014, 36(6): 762-766. doi: 10.11781/sysydz201406762

Abstract(1001) PDF-CN(668)

Abstract:
It was introduced in this paper the development process of coal seam gas content measurement techniques, the experimental modeling results of methane escaping and desorption in coal cores, as well as the application conditions and constraints for the present coal seam gas content measurement standards. During the sampling, atmospheric exposure and sealing desorption phases of coal cores, the conditions and mechanisms for gas escaping and desorption were various. Uncertainty and risk remained when coal core gas loss estimation method was applied in shales. The basic studies of gas escaping and desorption in shale cores during the above-mentioned three phases should be focused on. Shale gas was classified into three types: gas in drilling fluids, gas exposed and escaped, and gas remained in cores. Some proposals were made as followed to set up a new measurement techniques standard of gas content in shales: developing detection devices for gas in drilling fluids, and establishing rapid detection and calculation methods for gas in drilling fluids combined with comprehensive logging data; improving the existing core desorption gas and residual gas measurement technology, and establishing a rapid determination method for core residual gas; exploring for the detection or calculation method for exposed and escaped gas based on desorbed gas tests.

A method of determining movable fluid saturation of tight oil reservoirs: A case study of tight oil reservoirs in seventh member of Yanchang Formation in Heshui area

Yu Jian, Yang Xiao, Li Bin, Liu Xiaojing, Tian Jianfeng

2014, 36(6): 767-772. doi: 10.11781/sysydz201406767

Abstract(836) PDF-CN(816)

Abstract:
The movable fluid saturation is one of the key factors in tight oil evaluation, and can be tested accurately by nuclear magnetic resonance (NMR) technology. The high cost and long cycle prohibited the widespread use of NMR technology to determine movable fluid saturation. The testing principles of NMR, constant-speed mercury injection and high-pressure mercury injection indicated that the relaxation time distributions, constant-speed mercury injection curves and high-pressure mercury injection curves are the reflections of pore structures and have the ingenerate consistency. The movable fluid saturations and total mercury saturations of the same samples were tested by NMR and constant-speed mercury injection respectively. Correlation between the movable fluid saturation and the total mercury saturation was closely strong. The movable fluid saturation can be calculated from total mercury saturation. Considering the similarity between total mercury saturation of constant-speed mercury injection and mercury saturation at 7.0 MPa of high-pressure mercury injection, a method to determine movable fluid saturation of tight oil reservoirs was proposed based on high-pressure mercury injection data. The calculation results indicated that the tight oil reservoirs, with high movable fluid saturation, are mainly type-Ⅲ and type-Ⅳ reservoirs, followed by type-Ⅱreservoir.

Application of NMR core experimental analysis in evaluation of low-porosity and low-permeability sandstone reservoirs

Wang Zhenhua, Chen Gang, Li Shuhen, Zhang Huiruo, Huang Deshun, Yang Fu, Lei Panpan, Liu Xiaoshen

2014, 36(6): 773-779. doi: 10.11781/sysydz201406773

Abstract(979) PDF-CN(920)

Abstract:
Nuclear magnetic resonance (NMR) core experimental analysis is a new developing technique in experi-mental geology. Based on the principles and methods of NMR core experimental analysis, as well as some improved parametric models, a series of reservoir parameters of Chang6 low-porosity and low-permeability oil-bearing sandstone core samples from well 3062 in the ZC Oil Field in the eastern Ordos Basin were systematically measured by NMR. Additionally, the accuracy and relative error of the NMR analysis were calculated and discussed by means of recognized exact method of conventional core experimental analysis as control group. It is revealed that the Chang6 oil-bearing sandstones are typical low-porosity and low-permeability reservoirs, with porosity ranging from 8.6% to 13.0%, and permeability from 0.07×10^-3 to 1.27×10^-3 μm². NMR core experimental analysis has advantages of convenience, high efficiency and accepted accuracy with a smaller relative error for testing the low-porosity and low-permeability reservoir parameters of porosity, microscopic pore structure and irreducible water saturation. However, compared with the results of conventional core analysis, there is a larger relative error in NMR prediction for the permeability parameters, which is most probably due to some uncertainty of the reservoir permeability predictive models.

Effects of hydration swelling and wettability on propagation mechanism of shale formation crack

Liang Lixi, Xiong Jian, Liu Xiangjun

2014, 36(6): 780-786. doi: 10.11781/sysydz201406780

Abstract(1182) PDF-CN(767)

Abstract:
The shale formation cracks have an important influence on the borehole stability of shale well, and the interaction between drilling fluidand shale (capillary effect and hydration swelling) would impact on the propagation mechanism of shale formation crack. In this thesis, experiments were done for the outcrop and well core of the Longmaxi Formation shale of the southern Sichuan Basin to determine shale wettability and hydration swelling. Based on fracture mechanics, the propagation model of shale formation crack was established with the hydration swelling stress and capillary force, and the effects of hydration swelling and wettability on the propagation mechanism of shale formation crack were studied. The result shows that the wettability of the Longmaxi Formation shale is both water-wet and oil-wet, and is more likely to be oil-wet. The hydration swelling stress of the shale tend to ascent first and then become stable with the increase in time. For the shale rocks first soak in oil or KCl, the rise velocity of hydration swelling stress would decrease.The fractures on the sample surface are parallel plane of bedding in the process of immersing in water. With the increasing of immersion time, the sample would keep its integrality or spall to pieces. While the number of the fractures soaking in KCl is less and the cracked degree of the rocks is lighter. The hydration swelling has a great influence on the increment of the stress intensity factor, and the drilling fluid systems need to decrease the drilling fluid filter loss and increase the clay minerals hydrate inhibitor. The wetting behavior has a great influence on the propagation mechanism, and the drilling fluid systems need to reduce the drilling fluid interfacial tension and enlarge the wetting angle between drilling fluid and rock medium. The contact angles of oil-based drilling fluids and shale surface and the interfacial tension are little, which result in small capillary force. Therefore, the oil-based drilling fluid is used to inhibit crack propagation, hence the wellbore will be easy to maintain stable.

Saturation method of low-permeability reservoir cores based on CO₂ displacement

Han Xuehui, Li Fengbi, Dai Shihua, Zhang Juanjuan, Tang Jun, Wang Xueliang, Wang Hongliang

2014, 36(6): 787-791. doi: 10.11781/sysydz201406787

Abstract(707) PDF-CN(758)

Abstract:
In order to improve the saturation of low-permeability reservoir core, the saturation method and experimental device were developed based on CO₂ displacement of absorbed gas. The saturation effect was investigated by the measurement of saturated porosity with the employment of 26 cores from low-permeability reservoirs. It was demonstrated that saturation effect was significantly improved and was close to complete saturation because the saturated porosity of the new saturation method was 0.54% on average larger than that of the traditional saturation method and 0.14% on average smaller than helium porosity. Also, it was illustrated that the new saturation method had highly pertinence in reducing the effect of absorbed gas in tight cores and was able to be widely used for the saturation of low-permeability reservoir cores because the relative increment of saturated porosity by the new method increased positively with shale content and negatively with average grain size, helium porosity and permeability.

Three-dimensional inversion of geostress in Xinchang gas field, Western Sichuan Sag

Wang Zhengrong, Deng Hui, Huang Runqiu

2014, 36(6): 792-797. doi: 10.11781/sysydz201406792

Abstract(969) PDF-CN(753)

Abstract:
According to the formation lithology, geological structure and structure evolution of Xinchang area and its vicinity in the Western Sichuan Sag, the geologic model of research area was established, combining with the analysis results of drilling core fracture development characteristics, well reports, geostress and crack analysis. Geostress data were obtained from the analysis of borehole breakout data, drilling-induced fracture, hydraulic fracturing curve and rock Kaiser effect test. Those data were used as modern geostress reference values during model boundary conditions computing and geostress field inversion. The research results show that generally the maximum horizontal principal stress is nearly NEE-SWW. But it is apparently deflected near to the faults. And main subject orientation and regional tectonic stress are in the same direction. On the whole, main stress value increases with depth, and it has a good linear relationship with depth. Since fault structures developed in every stratum in the second member of the Xujiahe Formation, stress field shows obvious discontinuity, which makes geostress change in values and direction. There are obvious maximum principal stress and shear stress concentration phenomenon in fault ends and turning parts. However, stress dissipating appears in both sides of fault.

2014, 36(6): 798-798.

Abstract(375) PDF-CN(760)

Abstract:

2014 Vol. 36, No. 6

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