Lithologic Reservoirs

Tight sandstone gas and shale gas are currently two major unconventional hydrocarbon resources, which will be the significant resources for replacing the conventional oil and gas in next 10 to 20 years. Despite the understanding of geological property, or the technology of exploration and development, tight sandstone gas will be easily realized than shale gas in the next 10 years. However, precise prediction of favorable reservoir space has become a bottleneck for current tight sandstone gas exploration and development. Clarifying the deposition-diagenesis genetic mechanism of tight sandstone reservoir is the key to solve this problem. According to the research on the typical tight sandstone gas fields in China and data analysis abroad, tight sandstone generally deposited under weak hydrodynamic stability and relatively low depositional rate that much developed in coal-bearing（thin bed interbedded） strata of the transitional environments or deltas. Hence, these depositional mechanisms facilitate the requirement of forming tight sandstone. Continuous compaction during early diagenetic stage is the main process for their tight nature. The complex burial history under low geothermal gradients which were caused by multi-cycle movements of basin is the sufficient condition for forming tight sandstone reservoirs. Therefore, abnormal pressure zones in multi-cycle pre-Tertiary basins with low geothermal are the favorable area for exploring tight sandstone gas. The sandstones with thin interbedded coal-bearing strata in delta front are primary exploration and development intervals. Heterogeneity characteristics of tight sandstone play an important role on reservoir exploring and evaluating. The effect of microscopic pore structure change on permeability should be studied for evaluating pay reservoirs property. “Permeability blind area” and abnormal pressure data were employed for evaluating quality of reservoir. On the basis of this idea, we proposed six prospective areas for tight sandstone exploration and development in China in future.

Oil-gas accumulation models and their main controlling factors in Wuerxun-Beier Depression

FU Guang， WU Wei

2015, Vol.27(1): 14–20 Abstract ( 494 ) PDF (1681 KB) ( 290 )

doi: https://doi.org/10.3969/j.issn.1673-8926.2015.01.002

Based on the research of reservoir types and their distribution characteristics, oil-gas accumulation models and their main controlling factors in Wuerxun-Beier Depression were studied by analyzing the space allocation relation between oil-gas distribution and their accumulation conditions. The result shows that there are four kinds of oil-gas accumulation models in Wuerxun-Beier Depression: ①oil-gas accumulation model of fault trap in source area，mainly distributed in K1n1 of subdepression, and the main controlling factor of oil-gas accumulation is the development of fan delta front sand bodies K1n1 of the source area in subdepression; ②oil-gas accumulation model of fault trap out of source area，mainly distributed in K1n1of slope belt, and the main controlling factor of oil-gas accumulation is the development of sandstone pathway system connecting fault traps in slope belt and K1n1 source area in subdepression; ③oil gas accumulation model of bedrock cracks trap out of source area，mainly distributed in bedrock of paleo-buried hill flanking with K1n1 oil sources, and the main controlling factor of oil-gas accumulation is the development of bedrock of buried hill flanking with subdepression; ④oil-gas accumulation model of fault trap above source area，mainly distributed in K1d and part of K1n2 above K1n1 source area in subdepression, and the main controlling factor of oil-gas accumulation is the development of long-term development fault connecting fault traps in K1d and part of K1n2 with underlying K1n1 source area in subdepression.

Characteristics of clay minerals of tight reservoir and its geological significance of Nantun Formation in Wunan Sub-sag of Hailar Basin

PAN Zhongliang,CHEN Wei,WANG Zhenglai,LI Quan,SU Lei,ZHAO Ronghuai

2015, Vol.27(1): 21–25 Abstract ( 532 ) PDF (1076 KB) ( 493 )

doi: https://doi.org/10.3969/j.issn.1673-8926.2015.01.003

Clay mineral content in the tight reservoir of Nantun Formation in Wunan Sub-sag of Hailar Basin is high,which restricts oil and gas development. By using the data of SEM and X-ray diffraction from 767 core samples, this paper studied the types of clay minerals and their combination relation, as well as the distribution features and origin.The result shows that the content of montmorillonite is low and they are only developed on the upper Nantun Formation, and the content of illite is high and they are developed in the whole Nantun Formation. There are five types of clay mineral combination from bottom to top: S+K+I+I/S, K+I+C+I/S+C/S, I+C+I/S+C/S, I+K+I/S and I+C+I/S. The dissolution of volcano material and feldspar are the main reasons for resulting in the high content of clay minerals.

Formation mechanism of favorable reservoir of complex fault block reservoir in Hailaer Basin

WANG Zhenglai,JIANG Hongfu,GUAN Linlin,PAN Zhongliang,XU Yanlong

2015, Vol.27(1): 26–31 Abstract ( 533 ) PDF (1021 KB) ( 208 )

doi: https://doi.org/10.3969/j.issn.1673-8926.2015.01.004

In order to speed up the effective use of proved oil reserves in Hailaer Basin, under the guidance of influencing factors of complex fault block reservoir, combining with fine logging interpretation results of reservoir parameters, this paper analyzed the formation mechanism of favorable reservoir. The results show that sedimentary facies and sedimentary microfacies types control the original reservoir properties change of the first member of Nantun Formation in Hailaer Basin. Among three types of sedimentary facies, the reservoir properties of braided river delta are slightly better than that of fan delta and turbidite fan. The braided river delta underwater distributary channel, fan delta underwater distributary channel and turbidite channel are favorable sedimentary facies belts. Compaction and cementation are the main causes for reservoir tightness, which leads to reservoir microcosmic pore structure nowadays. Controlled by various factors, the reservoir properties are getting worse and worse with increasing burial depth, but there developed several reservoir property abnormal high value zones. This study points out the direction for the non producing reserves research, and provides a useful reference for other similar block potential prediction.

Reservoir forming conditions and exploration breakthrough of tight sandstone of Chang 9 member in Wangwazi area, Wuqi County

PANG Jungang,WANG Guicheng,SHI Yong,LI Sai,ZHU Penghui

2015, Vol.27(1): 32–38 Abstract ( 536 ) PDF (2399 KB) ( 267 )

doi: https://doi.org/10.3969/j.issn.1673-8926.2015.01.005

New discovery has been achieved in tight sandstone in the exploration of lower assemblage of Chang 9 member of Yanchang Formation in Ordos Basin. But the research of tight reservoir is still in the initial stage, and the lack of awareness seriously restrict the exploration and exploitation of tight reservoir. According to the data of well logging, well drilling and laboratory test, this paper discussed the forming condition, enrichment rule and exploration potential of the tight sandstone reservoir of Chang 9 member in Wangwazi area. The result shows that Chang 9 oil reservoir set has good reservoir forming conditions, several high-production wells have been found in Chang 91 and Chang 93 strata, and it has great breakthrough of petroleum exploration. The hydrocarbon source rocks, sedimentary microfacies, high quality sand bodies, nose-shaped structure are the key for exploration breakthrough of the tight sandstone reservoir of Chang 9 member. Based on comprehensive analysis, Wa 4, Wa 14 and Wa 11 well fields are favorable areas for further exploration.

Change rule of porosity and permeability of tight oil core of Permian Lucaogou Formation under reservoir condition in Junggar Basin

DENG Yong,YANG Long,LI Qiong,WANG Yumei,HU Bingyan

2015, Vol.27(1): 39–43 Abstract ( 586 ) PDF (701 KB) ( 366 )

doi: https://doi.org/10.3969/j.issn.1673-8926.2015.01.006

The relations of net overburden pressure with rock porosity and permeability under the reservoir condition are important for reserve calculation and study of oil and gas field development. Through CMS-300 overburden pressure test system, combined with core mercury injection, cast thin section, scanning electron microscope, field emission and many other experimental analysis data, this paper studied the difference of the relationship between porosity,permeability and the net overburden pressure under the reservoir condition and conventional reservoir condition. The results show that: ①with the increase of net overburden pressure, the overburden pressure porosity and permeability are diminishing with power function; ②compared with the low porosity and low permeability re servoir, the loss ratio of tight oil porosity and permeability caused by compaction is smaller; ③after the pressure recovery, the porosity and permeability of tight oil can return to the initial value almost, so the tight oil sample has good elasticity.

Comparison of geological characteristics and types of typical tight oil in North America

ZHAO Junlong,ZHANG Junfeng,XU Hao,YU Tingxu,ZHAO Da,GENG Yunguang

2015, Vol.27(1): 44–50 Abstract ( 531 ) PDF (1134 KB) ( 916 )

doi: https://doi.org/10.3969/j.issn.1673-8926.2015.01.007

In order to understand tight oil comprehensively, learn the successful development experiences and then promote the development of tight oil in our country, this paper analyzed and compared the geological characteristics of Bakken Formation, Eagleford Formation and Cardium Formation in North America. From the aspect of the convenient reserve calculation, more reasonable tight oil definition was put forward, and the types were divided systematically. The study results show that tight oil is an unconventional light petroleum accumulation in tight sedimentary rocks, including tight source rocks （mudstones） in place in a free or adsorbed state and tight sandstones and carbonates interbedded with or adjacent to source rocks（Bakken Formation and Eagleford Formation）, as well as the reservoirs which have not been developed with conventional technology （Cardium Formation）. The reservoir permeability is extremely low and the reservoir oil can’t achieve economic recovery unless using horizontal well and multistage fracturing techniques. Among the three tight oil reservoirs, tight oil resource of Bakken Formation is the largest and mainly occurs in the tight sandstone, of which the permeability is between 0.01 mD and 1.00 mD. Tight oil resource of Cardium Formation comes the second, and the lithology is mainly sandy mudstone and the permeability is between 0.1 mD and 10.0 mD. Eagleford Formation has the minimum amount of tight oil, and this kind of tight oil mainly occurs in the tight limestone and the range of permeability is 0.000 001 mD to 0.000 100 mD.

Reservoir characteristics and pore evolution of Chang 6 oil reservoir set in Qilicun Oilfield

DU Guichao, HU Shuangquan, SHI Lihua, WEI Fanrong

2015, Vol.27(1): 51–57 Abstract ( 641 ) PDF (1793 KB) ( 275 )

doi: https://doi.org/10.3969/j.issn.1673-8926.2015.01.008

Based on porosity and permeability measurements, mercury penetration, thin section analysis and SEM observations, this paper studied the reservoir characteristics and pore evolution of Chang 6 oil reservoir set of Triassic Yanchang Formation in Qilicun Oilfield, Ordos Basin. The result shows that reservoir sandstones are mainly fine grained arkose sandstone and characterized by low compositional maturity and high textural maturity. Reservoir properties of the study area show low porosity and low to extra-low permeability features. There is poor correlation between porosity and permeability, indicating strong diagenetic reformation of the reservoir sandstones. The Chang 6 reservoir is mainly in late diagenetic A stage. The main factors, influencing reservoir properties and pore evolution, are compaction, dissolution and cementation, among which compaction plays a key role in reservoir property reformation. The main cementation types include carbonate cementation, quartz overgrowth and clay mineral cementation, and they destroyed reservoir pores further. Dissolutions of feldspar, rock debris and laumontite cements widely occurred in the reservoir sandstones, and they increased the secondary pore spaces and improved the reservoir properties.

Reservoir characteristics and controlling factors in H block of Triassic Basin, North Africa

KUANG Kexin,ZHANG Shangfeng,YU Shui,WANG Ruoli,HUANG Chun

2015, Vol.27(1): 58–65 Abstract ( 609 ) PDF (2742 KB) ( 264 )

doi: https://doi.org/10.3969/j.issn.1673-8926.2015.01.009

Triassic Basin is a large composite oil and gas-bearing basin in Algeria of north Africa，with excellent geologic conditions for hydrocarbon accumulation and multiple sets of source-reservoir-cap assemblages. There are two main reservoirs: Ordovician Hamra Formation and Triassic Tagi Formation sandstones in the study area, to study the reservoir characteristics and controlling factors is significant for both hydrocarbon exploration and well site deployment. Based on regional geological data, cores and thin section observation, this paper studied the sedimentary, petrological and physical properties and microscopic pore types of sandstone reservoir of Tagi Formation and Hamra Formation in H block of Triassic Basin. The result shows that Tagi Formation sandstone is mainly composed of quartz sandstone and lithic quartz sandstone of fluvial facies, with medium compositional and textural maturity, and the reservoir spaces are mainly intergranular pores and intergranular dissolved pores; while Hamra Formation mainly developed quartz sandstone and feldspar quartz sandstone of shore facies, with high textural and compositional maturity, and the reservoir spaces are mainly fractures with small amount of dissolved pores resulting from dissolution. These two Formations are considered to be extremely low porosity and extremely low permeability reservoir and low porosity, low permeability reservoir according to property data. Sedimentation is the main controlling factor for reservoir quality of Tagi Formation, while diagenesis has some rebuilding effect. The Hamra reservoir is mainly controlled by dissolution. The Tagi-2 member in the study area is predicted to be the favorable area for high quality reservoir with great exploration potential.

Sedimentary microfacies analysis of the Middle Triassic Leikoupo Formation-Tianjingshan Formation boundary in Hanzeng area, Jiangyou

LIU Chiheng,HU Zuowei,LI Yun,LUO Wen

2015, Vol.27(1): 66–73 Abstract ( 687 ) PDF (2737 KB) ( 363 )

doi: https://doi.org/10.3969/j.issn.1673-8926.2015.01.010

The distribution range of Middle Triassic Tianjingshan Formation is limited to the northwest Sichuan Basin, affected by the Indosinian movement. The in-depth study of sedimentary transformation from Leikoupou Formation to Tianjingshan Formation of Middle Triassic is of great significant to understand the sedimentary environment evolution. By measuring the field profile of the Middle Triassic Leikoupo Formation-Tianjingshan Formation boundary in Hanzeng area and observing microfacies characteristics indoor, we identified five types of microfacies according to fossil assemblages, granular characteristics, filler types and architecture features of carbonate rocks, and recognized four sedimentary facies belts, including platform-margin sand shoal, open platform, restricted platform and evaporate platform. Based on the longitudinal change characteristics of sedimentary facies belts, it is concluded that sea level in Hanzeng area presents overall rise for a long period, and salt sea desalts gradually from Anisian Age to Ladinian Age in Middle Triassic.

Evaluation and optimization of flow unit division methods

LU Mingzhen,LIN Chengyan,ZHANG Xianguo,ZHANG Jiangtao

2015, Vol.27(1): 74–80 Abstract ( 458 ) PDF (1315 KB) ( 458 )

doi: https://doi.org/10.3969/j.issn.1673-8926.2015.01.011

Research on flow units is significant for the studies of reservoir heterogeneity and remaining oil distribution, as well as improving accuracy of well log interpretation models. Methods of flow unit identification are various, and their applicability is also different. Taking W oilfield in the Pearl River Mouth Basin as an example, this paper respectively used four methods to identify flow units, including modified stratigraphic Lorenz plot, flow zone indicator, integrated index of reservoir heterogeneity and pore throat aperture. Both modified stratigraphic Lorenz plot method and flow zone indicator method are based on permeability and porosity ratio, so it is difficult to identify tight reservoir. Pore throat aperture method can be used to identify tight reservoir, but it is difficult to differentiate high quality reservoir and meticulous to divide low quality reservoirs. Integrated index of reservoir heterogeneity synthesizes various qualitative and quantitative parameters, it divides tight reservoir as a separate kind of flow unit which can be effectively distinguished from other oil layer, and the division result can reflect reservoir heterogeneity reasonably, so it is the best method for flow unit division in the study area.

Study on the lower limit of physical properties of tight sandstone gas reservoirs in Dibei area, Tarim Basin

ZHANG Baoshou,LU Xuesong,SUN Xiongwei,LU Hui,LU Yuhong,TIAN Hua

2015, Vol.27(1): 81–88 Abstract ( 658 ) PDF (1276 KB) ( 429 )

doi: https://doi.org/10.3969/j.issn.1673-8926.2015.01.012

The Jurassic Ahe Formation in Dibei gas reservoir is characterized by low porosity and low permeability tight sandstone reservoir, strong heterogeneity and the complex oil and gas distribution. The lower limit of effective reservoir properties is uncertain, which is critical for reservoir evaluation, gas reserve and resources computation. Based on the data of reservoir properties, logging, oil testing and mercury measurement, combined with NMR and lowtemperature adsorption experiment results, this paper applied six methods including minimum flow pore throat radius, displacement pressure, bound water saturation, oil occurrence, oil testing and distribution curve to determine the lower limit of effective reservoir properties of Ahe Formation in Dibei area. The result shows that the lower limit of porosity and permeability of the Formation are 2.6% and 0.08 mD respectively. From J1a1, J1a2 to J1a3, that is the three lithology members from top to bottom, reservoir properties gradually decrease, and the lower limits of reservoir properties gradually decrease correspondingly. The lower limits of porosity of J1a1, J1a2 and J1a3 reservoir are 3.0%, 2.6% and 2.2% respectively, and the lower limits of permeability are 0.14 mD, 0.09 mD and 0.065 mD respectively. The understanding of lower limit of reservoir properties has some significance for the resource and gas reserve re-evaluation, reservoir evaluation and gas development design in Dibei gas reservoir.

Tight sandstone reservoir characteristics and influencing factors of He-1 member of the Lower Shihezi Formation in Dingbei area

MA Chao

2015, Vol.27(1): 89–94 Abstract ( 520 ) PDF (1058 KB) ( 276 )

doi: https://doi.org/10.3969/j.issn.1673-8926.2015.01.013

He-1 member in Dingbei area is the main producing formation and belongs to typical tight sandstone reservoir, but the study of reservoir characteristics and influencing factors is less, which severely restricts gas reservoir evaluation and optimization. Based on the data of rock thin sections, casting thin sections, porosity and permeability analysis, this paper studied tight sandstone reservoir characteristics and its influencing factors of He-1 member from the reservoir petrology characteristic. The results show that pore types of the tight sandstone reservoir of He-1 member are mainly intergranular dissolved pores and residual intergranular pores. Delta plain distributary channel sand body is favorable reservoir development area. Compaction, pressure solution and cementation are the main factors leading to the reservoir densification and the significant reduction in primary intergranular pores. The reservoir properties are improved due to intergranular dissolved pores produced by dissolution. This study provides basis and methodology for tight sandstone reservoir evaluation and exploration.

Sedimentary features of the Lower Cambrian Longwangmiao Formation in the central Sichuan Basin

YANG Xuefei,WANG Xingzhi,DAI Lincheng,YANG Yueming,XIE Jirong,LUO Wenjun

2015, Vol.27(1): 95–101 Abstract ( 593 ) PDF (2431 KB) ( 304 )

doi: https://doi.org/10.3969/j.issn.1673-8926.2015.01.014

Combining with geological background of Sichuan Basin, this paper studied the sedimentary features of Longwangmiao Formation in the central Sichuan Basin by means of cores, thin section observations and logging analysis. It indicates that the study area was located in restricted-evaporated platform during Longwangmiao period, which includes lagoon, intra-platform shoal, platform flat and tidal flat. During the Longwangmiao period, two episodes of transgression and regression process had occurred, and two sets of lagoon-intra-platform shoal-platform flat-tidal flat sediments developed upward. Lagoon developed in the bottom of Longwangmiao Formation, with deep and low fluid energy. Intraplatform shoal developed in the middle part of Longwangmiao Formation, and it was composed of thick dolarenite and oolitic dolostone with steady distribution in the study area. The fine crystalline dolostone generated in the platform flat with shallow and low energy, where was easy to be exposed to the surface and dissolved by meteoric fresh water. Tidal flat only developed in the top of Longwangmiao Formation, and often formed in the end of the regression. Affected by Leshan-Longnvsi paleouplift under the water, the study area was mainly located in intra-platform shoal with high energy.

Application of pre-stack simultaneous inversion to fluid identification of carbonate reservoir: A case study from district 6-7 in Tahe Oilfield

LIU Junzhou,SUN Zandong,LIU Zhengtao,SUN Yongyang,DONG Ning,XIA Hongmin

2015, Vol.27(1): 102–107 Abstract ( 549 ) PDF (1856 KB) ( 414 )

doi: https://doi.org/10.3969/j.issn.1673-8926.2015.01.015

Ordovician carbonate dissolved cave reservoirs are widely developed in the district 6-7of Tahe Oilfield. The P-wave impedance is low whether or not there are fluids within cave reservoir, so P-impedance acquired frompost-stack inversion is not enough to identify the filled materials effectively. Pre-stack simultaneous inversion can be used to obtain S-wave information except P-wave information outside, and the combination of P-wave and S-wave information is in favor of distinguishing fluid. Pre-stack simultaneous inversion is applied in the district 6-7 of Tahe Oilfield. Multiple elastic parameters are acquired, including P-wave impedance, S-wave impedance and v p /v s . Based on rock physic analysis, cross-plots of P-wave impedance and vp/vs were used to distinguish oil-bearing reservoir and predict the fluid distribution. The fit rate between prediction results and actual drilling data is 72.7%, which indicates the pre-stack simultaneousinversionispractical andreliable.

Logging identification method of volcanic rock lithology: A case study from volcanic rock in Junggar Basin

ZHANG Daquan,ZOU Niuniu,JIANG Yang,MA Chongyao,ZHANG Shuncun,DU Shekuan

2015, Vol.27(1): 108–114 Abstract ( 726 ) PDF (2663 KB) ( 649 )

doi: https://doi.org/10.3969/j.issn.1673-8926.2015.01.016

Reservoir lithology identification is the foundation of volcanic reservoir exploration. Based on core observation,combined with detailed analysis of thin sections and logging data, this paper summarized the logging response characteristics of volcanic rocks, proposed logging identification method of volcanic lithology. Conventional logging data were used to identify the mineral composition of volcanic rock, and imaging logging data were applied to distinguish the structure and texture of volcanic rocks, of which the natural gamma raylogging （ GR ） , density logging （ DEN ） and acoustic time logging （ AC ） are the more advantageous three logging curves to identify the lithology of volcanic rocks. The crossplot of GR-R t /AC can be used to effectively identify volcanic rocks and sedimentary rocks,and then the crossplots of GR-DEN and GR-AC can be applied to identify the volcanic rock types. Finlly,combined withFMI,thestructureandtexturecharacteristicsofvolcanicrockscanbefurtherdistinguished.

Study on electric structure in a hydrocarbon accumulation area, Qaidam Basin

PENG Yonghui,LI Diquan

2015, Vol.27(1): 115–121 Abstract ( 494 ) PDF (1852 KB) ( 332 )

doi: https://doi.org/10.3969/j.issn.1673-8926.2015.01.017

The geological conditions in a hydrocarbon accumulation area of Qaidam Basin are complex, and the seismic exploration effect is not obvious. By applying wide field electromagnetic method, this paper conducted field experiment with five survey lines and studied the electric structure of the study area by a continuous periodic 2n sequence pseudo-random signal. The results show that five main electric layers exist and the gas layers perform relatively high electrical resistivity. The inversion resistivity values of the gas layers are two times more than that of non-gas layers. Comparing with the well drilling and seismic data, the wide field electromagnetic method is effective for oil and gas identification. Due to the simple field work and low costs, the value of wide field electromagnetic method is tremendous in popularization and application in Qaidam Basin.

New method for determining critical rate of horizontal well in gas cap and bottom water reservoirs

YUAN Lin 1,LI Xiaoping 1,LIU Panpan 2

2015, Vol.27(1): 122–126 Abstract ( 554 ) PDF (559 KB) ( 335 )

doi: https://doi.org/10.3969/j.issn.1673-8926.2015.01.018

Critical rate of horizontal well in gas cap and bottom water reservoirs is an important factor to measure whether the water and gas had breaked through oil-well earlier or not, so calculating its value accurately is of great significance during developing the gas cap and bottom water reservoirs. Based on the cresting mechanism of bottom water and gas cap around bore hole of horizontal well, this paper considered the ellipsoid constant pressure surfaces as family of the rectangles, used the principle of elliptical flow to deduct a new model for calculating the critical rate of horizontal well in gas cap and bottom water reservoirs. Through actual calculation and contrast, the result calculated by new model only has a small relative error with that calculated by numerical simulation method, only 9.08%. Moreover, when the reservoir thickness is big enough, the error will become smaller, which demonstrates that the new model has higher accuracy and practicability. Sensitivity analysis shows that with the increasing of dimensionless wellbore location, the critical rate presents increasing early, but decreasing when the dimensionless wellbore location has reached a high value. The critical rate gets maximum value when the dimensionless wellbore position is 0.4 because of the physical character differences between gas and water. So during developing the gas cap and bottom water reservoirs with horizontal well, it would be best to prefer the horizontal wellbore location so as to keep higher critical rate.

Determination of the minimum miscibility pressure of CO₂ and crude oil system by hanging drop method

HUANG Chunxia,TANG Ruijia,YU Huagui,JIANG Shaojing

2015, Vol.27(1): 127–130 Abstract ( 463 ) PDF (576 KB) ( 685 )

doi: https://doi.org/10.3969/j.issn.1673-8926.2015.01.019

The minimum miscibility pressure of CO 2 and crude oil system is an important parameter for the research of CO 2 flooding technology. The interfacial tension data of CO 2 and crude oil system were measured by pendant drop method under the conditions of reservoir temperature of 44℃ and different pressure. The oil samples are produced in low permeability reservoir of Yanchang Oilfield. The experiment results show that the interfacial tension of CO 2 and crude oil decreased almost linearly as increasing pressure. According to the extrapolated method, the minimum miscibility pressure is 23.56 MPa when the interfacial tension of CO 2 and crude oil is zero. This method can be used to not only obtain the minimum miscibility pressure of CO 2 and crude oil system, but also directly observe the miscible phase picture of CO 2 and crude oil. The experiment is easier in operation and needs less time than the others, so it has a certain reference value on the measurement for similar experiments.