Description: Publication date: February 2018 Source: Petroleum Exploration and Development, Volume 45, Issue 1 Author(s): Yujiao HAN, Cancan ZHOU, Yiren FAN, Chaoliu LI, Chao YUAN, Yunhai CONG It is difficult to accurately obtain the permeability of complex lithologic reservoirs using conventional methods because they have diverse pore structures and complex seepage mechanisms. Based on in-depth analysis of the limitation of classical nuclear magnetic resonance (NMR) permeability calculation models, and the understanding that the pore structure and porosity are the main controlling factors of permeability, this study provides a new permeability calculation method involving classifying pore sizes by using NMR T 2 spectrum first and then calculating permeability of different sizes of pores. Based on this idea, taking the bioclastic limestone reservoir in the A oilfield of Mid-East as an example, the classification criterion of four kinds of pore sizes: coarse, medium, fine and micro throat, was established and transformed into NMR T 2 standard based on shapes and turning points of mercury intrusion capillary pressure curves. Then the proportions of the four kinds of pore sizes were obtained precisely based on the NMR logging data. A new NMR permeability calculation model of multicomponent pores combinations was established based on the contributions of pores in different sizes. The new method has been used in different blocks. The results show that the new method is more accurate than the traditional ones.

Description: Publication date: December 2017 Source: Petroleum Exploration and Development, Volume 44, Issue 6 Author(s): Qiang LAI, Bing XIE, Yuyu WU, Ke HUANG, Xinggang LIU, Yan JIN, Wenjun LUO, Tao LIANG The petrophysical and logging response characteristics of asphaltene carbonate reservoirs were examined based on the measurement of porosity and permeability, density, compressional and shear wave slowness, resistivity and Nuclear Magnetic Resonance transverse relaxation time ( T 2 ) of cores before and after the bitumen dissolving. The results show that (1) the asphalt can damage the pore structure of the reservoir and cause reduction of effective reservoir space and permeability; (2) with the increase of asphalt content, the compression and shear wave slowness generally decrease while the density and resistivity increase; (3) with the increase of asphalt content, the compressional wave slowness and density change less, while the shear wave slowness and resistivity change larger; and (4) the T 2 values of asphalt are generally less than 3 ms, and the higher the maturity of the asphalt, the lower the T 2 value. Based on these experiments, a method based on conventional and special logging methods was presented to evaluate asphalt content, effective porosity and water saturation in asphaltene carbonate reservoirs. The method has already been applied to 80 wells in the Longwangmiao Formation of the Anyue gas field in the Sichuan Basin to pick out zones rich in asphalt on the plane, which has effectively guided the selection of well location in the gas reservoir development.

Description: Publication date: December 2017 Source: Petroleum Exploration and Development, Volume 44, Issue 6 Author(s): Hao SU, Zhengdong LEI, Diqiu ZHANG, Junchao LI, Zeren ZHANG, Binshan JU, Zhiping LI In consideration of the limited adaptability scope, low accuracy and high demand of great cost data of existent fracture prediction methods, a new fracture predicting method was advanced by implementing geological static data and production dynamic data from the Triassic Chang 6 3 reservoirs in the Huaqing Oilfield. Five constraints, lithology, sedimentary facies, thickness, rock rupture index and fracture intensity controlling the development of fractures were sorted out based on the static geological data. The multiple linear regression method was adopted to work out the quantitative relationships between the five constraints and fracture density, and the fracture density property of the whole area was calculated. Based on production dynamic data of well history, tracer, well interference test and intake profile test, the direction and distribution of fracture horizontally and vertically were figured out by reservoir engineering analysis method. The fracture density property was verified and quantitatively corrected with numerical simulation, and a 3D discrete fracture geological model in agreement with both geological cognition and dynamic production performance was built. The numerical simulation shows that the fracture model has higher fitting consistency, high reliability and adaptability.

Description: Publication date: December 2017 Source: Petroleum Exploration and Development, Volume 44, Issue 6 Author(s): Yanlong LI, Gaowei HU, Changling LIU, Nengyou WU, Qiang CHEN, Lele LIU, Chengfeng LI To deal with sand production problems during the process of producing natural gas from hydrate-bearing sediments (HBS) using reservoir-fluid extraction method, a new gravel sizing method for sand control packing named “Hold coarse while eliminate fine particle (HC & EF method)” was developed for the clayey hydrate-bearing formations. Site X, in Shenhu area, South China Sea was taken as an example to describe detailed gravel sizing procedure. On the basis of analyzing basic particle size distribution (PSD) characteristics of HBS at Site X, the formation sand was divided into two components, which are coarse component and fine component. The gravel sizes for retaining coarse component and eliminate fine component were calculated, respectively. Finally, intersection of these two gravel sizes was taken as the proper gravel size for Site X. The research results show that the formation at Site X is clayey sand with poor sorting and uniformity, proper gravel size for upper segment packing is 143−215 μm, while that for lower segment packing is 240−360 μm. In consideration of the difficulty of layered sand control operation on offshore platform, proper gravel packing size for Site X is recommended as 215−360 μm.

Description: Publication date: October 2017 Source: Petroleum Exploration and Development, Volume 44, Issue 5 Author(s): Jing WANG, Huiqing LIU, Jing XIA, Yuetian LIU, Cheng HONG, Qingbang MENG, Yang GAO Abstract The mechanism model of both static and dynamic imbibition considering capillary pressure and gravity was presented based on the imbibition mechanisms and seepage theory. The validation of the model was performed using published experiment data. Then, this model was employed to study the impacts of oil viscosity, matrix permeability, core size, interface tension, and displacement rate on imbibitions. The results show that, the recovery decreases as oil viscosity increases, and the initial imbibition rate is much faster for lower viscosity oil. Imbibitions recovery is positively related to matrix permeability, the differences of oil recovery for low-permeability to tight oil reservoirs are obvious. Imbibitions effect is negatively related to core size. If the interface tension is low, imbibitions cannot occur without consideration of gravity. But it can occur even in very low interface tension scenario with consideration of gravity. On the whole, the recovery first increases and then decreases as the interface tension decreases. The gravity and capillary play different roles at different ranges of interface tension. There exists an optimal value range of displacement rate in fractured reservoir, which should be optimized with a sufficient oil production rate to achieve higher recovery.

Description: Publication date: February 2018 Source: Petroleum Exploration and Development, Volume 45, Issue 1 Author(s): Xinhua MA, Jun XIE The Ordovician Wufeng Formation-Silurian Longmaxi Formation organic-rich shales distributed widely and stably in Southern Sichuan Basin were investigated based on drilling data. Geological evaluation of wells show that the shale reservoirs have good properties in the Yibin, Weiyuan, Zigong, Changning, Luzhou, Dazu areas, with key parameters such as TOC, porosity, gas content similar to the core shale gas production zones. Moreover, these areas are stable in structure, good in preservation conditions and highly certain in resources. The shale reservoirs have a burial depth of 4 500 m or shallow, a total area of over 2×10 4 km 2 and estimated resource of over 10×10 12 m 3 , so they are the most resource-rich and practical areas for shale gas exploitation in China. Through construction of the Changning-Weiyuan national demonstration region, the production and EUR of shale gas wells increased significantly, the cost of shale gas wells decreased remarkable, resulting in economic benefit better than expected. Moreover, the localized exploration and development technologies and methods are effective and repeatable, so it is the right time for accelerating shale gas exploitation. Based on the production decline pattern of horizontal wells at present and wells to be drilled in the near future, at the end of the 13th Five Year Plan, the production of shale gas in southern Sichuan Basin is expected to reach or exceed 10 billion cubic meters per year. The resources are sufficient for a stable production period at 30 billion cubic meters per year, which will make the South Sichuan basin become the largest production base of shale gas in China.

Description: Publication date: December 2017 Source: Petroleum Exploration and Development, Volume 44, Issue 6 Author(s): Qingcai ZENG, Tongsheng ZENG, Yonglin OUYANG, Chunmeng DAI, Yaying SONG The seismic imaging has three difficulties in the Keshen area of the Kuqa depression in Tarim Basin: difficult static correction, poor original data, difficult velocity modeling and pre-stack depth migration. A dual-scale tomography inversion approach based on BP neural network and LSQR was developed to obtain the accurate near-surface velocity of the complex near-surface structure, to address the static correction of subsalt high steep structure imaging. On the basis of applying high-precision static correction and root-mean-square (RMS) velocity to the seismic data, three dimensional cone filtering and spherical spreading amplitude compensation were used to enhance the signal to noise ratio and restore the deep effective signals to cope with the poor quality of original seismic data. Under the constraints of geologic, well logging and drilling data, the dual-scale velocity modeling technology based on model-based velocity updating and grid-based tomography was adopted to obtain the precise velocity model of the complex substructure, and then the pre-stack depth migration was taken to improve the imaging effect of structure with complex surface conditions, to solve the problem of subsalt high steep structure velocity modeling and pre-stack depth migration. By applying these three techniques, the high-quality imaging achievements of subsalt high steep structure were obtained. The results of seismic imaging prediction are in good agreement with drilling results and three ultra-deep wells have been drilled successfully.

Description: Publication date: December 2017 Source: Petroleum Exploration and Development, Volume 44, Issue 6 Author(s): Jinxing DAI, Yunyan NI, Shipeng HUANG, Weilong PENG, Wenxue HAN, Deyu GONG, Wei WEI Researches were carried out on the origin of gas hydrate samples from the tundra in the Qilian Mountain, Pearl River Mouth Basin in the northern South Sea and the continental slope of Taixinan Basin in China. Gases of the gas hydrate samples from the Jurassic Jiangcang Formation in the Muli County in Qilian Mountain are mainly of oil-derived origin, characterized by self-generation and self-preservation. δ 13 C 1 values range from −52.7‰ to −35.8‰, and the δ 13 C 2 values vary from −42.3‰ to −29.4‰. There was a small amount of coal-derived gases, which might source from the coal-bearing Middle-Jurassic Muli Formation with δ 13 C 1 of −35.7‰ – −31.3‰ and δ 13 C 2 of −27.5‰ – −25.7‰. Gases of the gas hydrate samples from the Pearl River Mouth Basin and Taixinan Basin are dominated by bacterial origin of carbonate reduction, with δ 13 C 1 of −74.3‰ – −56.7‰ and δ D 1 of −226‰ – −180‰. A trace amount of thermogenic gases were also found in these basins with δ 13 C 1 of −54.1‰ – −46.2‰. This study combined the geochemical data of gas hydrates from 20 areas (basins) in the world, and concluded that thermogenic gases of the gas hydrates in the world can be either of coal-derived or oil-derived origin, but dominated by oil-derived origin. A small amount of coal-derived gas was also found in the Qilian Mountain in China and the Vancouver Island in Canada. The coal-derived gas has relatively heavy δ 13 C 1 ≥ −45‰ and δ 13 C 2 > −28‰, while the oil-derived gas has δ 13 C 1 from −53‰ – −35‰ and δ 13 C 2 〈 −28.5‰. Gas hydrates in the world mainly belong to bacterial origin of carbonate reduction. Methanogensesis of acetate fermentation was only found in some gas hydrates from the Baikal basin in Russia. Bacterial gases of carbonate reduction have relatively heavy δ D 1 ≥ −226‰, while gases of acetate fermentation have δ D 1 〈 −294‰. The bacterial gas of gas hydrates in the world has the highest δ 13 C 1 value of −56.7‰ and lowest of −95.5‰, with a peak range of −75‰ – −60‰. Gas hydrate in the world has the highest δ 13 C 1 of −31.3‰ and lowest of −95.5‰ and the highest δ D 1 of −115‰ and lowest of −305‰.

Description: Publication date: December 2017 Source: Petroleum Exploration and Development, Volume 44, Issue 6 Author(s): Xiaoyu GU, Chunsheng PU, Hai HUANG, Feifei HUANG, Yuejing LI, Yang LIU, Hengchao LIU Taking the Chang 8 tight sandstone reservoir of the Yanchang Formation of Fuxian area in Ordos Basin as an example, the influencing mechanism of permeability on imbibition recovery in tight sandstone was explored by spontaneous imbibition experiment, combining nuclear magnetic resonance (NMR) and CT Scanning. Results show that: (1) spontaneous imbibition played a vital role in water–flooding of the tight sandstone reservoir, the recovery by spontaneous imbibition of experimental core samples can reach 5.24% – 18.23%, and the higher the matrix permeability, the higher the recovery degree by spontaneous imbibition; (2) because of the thickness of adsorbed layer, pores above sub-micron scale made a great contribution to the imbibition recovery of tight sandstone reservoir, and nano-submicron pores made less contribution to imbibition recovery; (3) the connectivity of pore and throat was the major microscopic mechanism of the positive correlation between matrix permeability and spontaneous imbibition recovery. Samples of different permeability didn't differ much in the sizes of sub-micron to micron pores, but with the rise of permeability, the connected pores and throats and surface porosity increased exponentially, leading to significant increase of imbibition recovery.

Description: Publication date: December 2017 Source: Petroleum Exploration and Development, Volume 44, Issue 6 Author(s): Jiqiang WANG, Chengfang SHI, Shuhong JI, Guanlin LI, Yingqiao CHEN A function expression of the oil-water relative permeability ratio with normalized water saturation at high water saturation was proposed based on statistics of measured oil-water relative permeability data in oilfields. This expression fits the later section of conventional relative permeability ratio curve more accurately. Two new water drive characteristic curves at the ultra-high water cut stage ( f w >90%) were derived by combining the new oil-water relative permeability ratio expression and reservoir engineering method. Then, the numerical simulation results of five-point well pattern and production data of Yangerzhuang Oilfield and Liuzan Oilfield were used to verify the adaptability of the new water drive characteristic curves. The results showed that the new water drive characteristic curves are more accurate than conventional water drive characteristic curves after A type and B type water drive curves rise, and can be used to predict production performance at ultra-high water cut stage, ultimate recovery efficiency and recoverable reserves.