Description: Publication date: February 2018 Source: Petroleum Exploration and Development, Volume 45, Issue 1 Author(s): Xizhe LI, Zhenhua GUO, Yong HU, Ruilan LUO, Yunhe SU, Hedong SUN, Xiaohua LIU, Yujin WAN, Yongzhong ZHANG, Lei LI Through analyzing the development of large ultra-deep structural gas fields in China, strategies for the efficient development of such gas fields are proposed based on their geological characteristics and production performance. According to matrix properties, fracture development degree and configuration between matrix and fractures, the reservoirs are classified into three types: single porosity single permeability system, dual porosity dual permeability system, and dual porosity single permeability system. These three types of gas reservoirs show remarkable differences in different scales of permeability, the ratio of dynamic reserves to volumetric reserves and water invasion risk. It is pointed out that the key factors affecting development efficiency of these gas fields are determination of production scale and rapid identification of water invasion. Figuring out the characteristics of the gas fields and working out pertinent technical policies are the keys to achieve efficient development. The specific strategies include reinforcing early production appraisal before full scale production by deploying high precision development seismic survey, deploying development appraisal wells in batches and scale production test to get a clear understanding on the structure, reservoir type, distribution pattern of gas and water, and recoverable reserves, controlling production construction pace to ensure enough evaluation time and accurate evaluation results in the early stage, in line with the development program made according to the recoverable reserves, working out proper development strategies, optimizing pattern and proration of wells based on water invasion risk and gas supply capacity of matrix, and reinforcing research and development of key technologies.

Description: Publication date: February 2018 Source: Petroleum Exploration and Development, Volume 45, Issue 1 Author(s): Guangwei LIU, Daiyu ZHOU, Hanqiao JIANG, Tao WANG, Junjian LI Based on geological analysis, reservoir numerical simulation and production performance analysis, water-out performance and pattern of horizontal wells in Tarim marine sandstone reservoir were studied. Compared with continental sandstone reservoirs, the marine sandstone reservoirs in Tarim Basin were characterized by low oil viscosity, good reservoir continuity, and development of interbeds, which together with the large amount of horizontal wells, resulted in fast production rate and high recovery degree of the reservoirs. The main controlling factors of uneven water-out in horizontal wells were reservoir seepage barrier, injection-production well pattern, and dominant seepage channel. Thus 9 types in 4 categories of typical water-out pattern of horizontal wells in Tarim marine sandstone reservoirs were identified, and water-out management measures were proposed for them respectively according to their water-out mechanism and remaining oil distribution characteristics. Finally, the water-out pattern can be identified based on the inflection characteristics of derivative curve of water-oil ratio. This study of the water-out pattern can provide guidance for the adjustment policy of water injection in horizontal wells in marine sandstone reservoirs of Tarim Oilfield.

Description: Publication date: February 2018 Source: Petroleum Exploration and Development, Volume 45, Issue 1 Author(s): Xiushan LIU In order to accurately calculate drilled trajectories, the method of quantitatively recognizing borehole trajectory models was provided, and a case analysis was conducted. Because the measurement-while-drilling data provide with measured values of tool-face angle besides inclination angle and azimuth angle, this paper presents the technological approach of recognizing borehole trajectory models based on tool-face angle. A universal tool-face angle equation was established based on the directional deflection mechanism of steerable drilling tools, and it can calculate the tool-face angles with characteristic parameters of various borehole trajectory models. Then, by evaluating the error between the theoretical values and the measured values of tool-face angle, the trajectory model most consistent with the actual well trajectory can be selected. The model recognition of borehole trajectory provides with the quantitative evaluation index and selection basis of survey calculation methods, which can avoid subjectively and randomly selecting the survey calculation method, and consequently improve the monitoring accuracy and reliability of borehole trajectory.

Description: Publication date: February 2018 Source: Petroleum Exploration and Development, Volume 45, Issue 1 Author(s): Xianggang DUAN, Zhiming HU, Shusheng GAO, Rui SHEN, Huaxun LIU, Jin CHANG, Lin WANG The high pressure static adsorption curves of shale samples from Silurian Changning-Weiyuan Longmaxi Formation were tested by using high pressure isothermal adsorption equipment. The physical modeling of depletion production was tested on single cores and multi-core series by using self-developed shale gas fluid-solid coupling experiment system. The adsorption and desorption laws were summarized and a high pressure isothermal adsorption model was established. The calculation formula of gas content was corrected, and the producing law of adsorption gas was determined. The study results show that the isothermal adsorption law of the shale reservoir under high pressure was different from the conventional low pressure. The high pressure isothermal adsorption curve had the maximum value in excess adsorption with pressure change, and the corresponding pressure was the critical desorption pressure. The high pressure isothermal curve can be used to evaluate the amount of adsorbed gas and the producing degree of adsorption gas. The high pressure isothermal adsorption model can fit and characterize the high pressure isothermal adsorption law of shale. The modified gas content calculation method can evaluate the gas content and the proportion of adsorbed gas more objectively, and is the theoretical basis of reserve assessment and production decline analysis. The producing degree of adsorption gas is closely related to the pressure, only when the reservoir pressure is lower than the critical desorption pressure, the adsorption gas can be produced effectively. In the process of gas well production, the pressure drop in the near-well area is large, the production of adsorption gas is high; away from the wellbore, the adsorption gas is low in production, or no production.

Description: Publication date: February 2018 Source: Petroleum Exploration and Development, Volume 45, Issue 1 Author(s): Ming CHEN, Shicheng ZHANG, Ming LIU, Xinfang MA, Yushi ZOU, Tong ZHOU, Ning LI, Sihai LI For the issue of proppant embedment in hydraulic fracturing, a new calculation method of embedment depth considering elastic-plastic deformation was proposed based on the mechanism of proppant embedment into rocks by combining proppant embedment constitutive equations and contact stresses on the rock-proppant system. And factors affecting embedment depth of proppant were analyzed using the new method. Compared with the elastic embedment model, the results calculated by the new method match well with the experimental data, proving the new method is more reliable and more convenient to make theoretical calculation and analysis. The simulation results show the process of proppant embedment into rocks is mainly elastic-plastic. The embedment depth of monolayer proppants decreases with higher proppant concentration. Under multi-layer distribution conditions, increasing the proppant concentration will not change its embedment depth. The larger the proppant embedment ratio, the more the stress-bearing proppants, and the smaller the embedment depth will be. The embedment depth under higher closure stress is more remarkable. The embedment depth increased with the drawdown of fluid pressure in the fracture. Increasing proppant radius or the ratio of proppant Young's modulus to rock Young's modulus can reduce the proppant embedment depth.

Description: Publication date: February 2018 Source: Petroleum Exploration and Development, Volume 45, Issue 1 Author(s): Alireza NASIRI, Mohammad Javad AMERI SHAHRABI, Mohammad Amin SHARIF NIK, Hamidreza HEIDARI, Majid VALIZADEH To improve the thermal stability of starch in water-based drilling fluid, monoethanolamine (MEA) was added, and the effect was investigated by laboratory experiment. The experimental results show that the addition of monoethanolamine (MEA) increases the apparent viscosity, plastic viscosity, dynamic shear force, and static shear force of the drilling fluid, and reduces the filtration rate of drilling fluid and thickness of mud cake apparently. By creating hydrogen bonds with starch polymer, the monoethanolamine can prevent hydrolysis of starch at high temperature. Starch, as a natural polymer, is able to improve the rheological properties and reduce filtration of drilling fluid, but it works only below 121 °C. The MEA will increase the thermal stability of starch up to 160 °C. There is a optimum concentration of MEA, when higher than this concentration, its effect declines.

Description: Publication date: February 2018 Source: Petroleum Exploration and Development, Volume 45, Issue 1 Author(s): Meiqin LIN, Zhao HUA, Mingyuan LI Based on adhesion models between rock surface groups and organic molecules, the interactions between the chemical groups on the rock surface and the components of crude oil and the interactions of the electrical double layers at the rock surface and oil-water interface were analyzed to investigate the abilities and microscopic mechanisms of wettability control by H + , OH − and inorganic salt ions in brine, and a new method of wettability control for reservoir rocks was built. The results show that the interaction forces between rock surface groups and oil molecules are van der Waals forces, Coulomb forces, hydrogen bonds, and surface forces. By changing these forces, the control mechanisms of surface wettability of reservoir rocks by brine are: transformation of chemical groups, change of interfacial potential, pH variation of injected water, multicomponent ionic exchange, and salting-in or salting-out effect. For sandstone reservoirs, with the decrease of concentration and valence state of positive ions in brine or the increase of pH (increasing pH has a negligible impact on the brine salinity), the interaction between rock surface and oil becomes weak, thus resulting in increase of water wettability of rock surface. For carbonate reservoirs, CaSO 4 or MgSO 4 brine with high concentration is beneficial to increase water wettability of rock surface. Therefore, it is feasible to control rock wettability and improve oil recovery by adjusting the ion components of injected water.

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: 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): 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‰.