Petroleum Exploration and Development

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Formation conditions and exploration prospects of Sinian large gas fields, Sichuan Basin

Wei Guoqi; Shen Ping; Yang Wei; Zhang Jian; Jiao Guihao; Xie Wuren and Xie Zengye

, 2013, 40(2): 2118-0.

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Exploration potential of natural gas in the Sinian, Sichuan Basin, was analyzed based on the research on evolution of Leshan-Longnüsi palaeouplift and reservoir forming conditions such as sedimentary facies, source rocks, reservoirs and caprocks. The Sinian has a potential to form large gas fields in the Sichuan Basin: (1) A large-scale inherited palaeouplift provides conditions for oil/gas formation and accumulation. (2) Stable sedimentary environment guarantees the extensive development of source rocks and reservoirs. (3) Sinian Deng-2, Deng-3 and Deng-4 reservoirs overlap each other and are developed widely. (4) Multiple source rocks overlay vertically and are distributed widely, superimposed between reservoirs like “sandwiches”. (5) The Sinian has good preservation conditions, regional mudstone cap rocks are thick and faults are not developed. Considering favorable reservoir forming conditions, four favorable prospective areas are selected: Leshan-Longnüsi Palaeouplift, Southeast Sichuan, East Sichuan, and Northwest Sichuan. The Leshan-Longnüsi palaeouplift is the most favorable area, where inherited palaeostructural traps in the core are first priority and the litho-stratigraphic gas reservoirs in the slope deserve exploration.

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Key controls on accumulation and high production of large non-marine gas fields in northern Sichuan Basin

Guo Tonglou

, 2013, 40(2): 2119-0.

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Based on the data from multiple sample analysis and tests and exploration practice, key factors controlling gas accumulation, enrichment and high production in the continental Triassic Xujiahe–Jurassic Ziliujing formations in Yuanba, Tongnanba and other areas, northern Sichuan Basin, were discussed. Natural gas in continental strata in this part of the basin are derived from the source rocks in the same strata, which are good - very good source rocks with high abundance of organic matter (mostly type III) and generally in high mature – overmature gas generating stage. Depending on provenance, multi-period (fan) delta systems are developed in the research area, where the main fluvial channel sands are superimposed in multi periods and distributed extensively, and reservoirs and source rocks form the “lower generation and upper storage” and “inter-bedded” assemblages. Five typical high-yield wells in the Jiulongshan, Malubei and Yuanba areas are investigated and an overall concept for exploration and research in the area is proposed: sedimentary source controls rock types, cementation types and sedimentary microfacies; source rocks control the size and location of gas accumulation; structural types control the magnitude and location of fractures; the combination of fracture and reservoir determines the level and retention duration of gas production. According to this model, the following areas have enriched gas and high production: Xu-3 and Xu-4 members of Xujiahe Formation in the western Yuanba and Jiange, Xu-4 member and Ziliujing Formation in the mid-eastern Yuanba, Zhenzhuchong and Xu-2 members in Malubei and Hebachang areas in the Tongnanba structure.

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Characteristics of tight oil in Triassic Yanchang Formation, Ordos Basin

Yao Jingli; Deng Xiuqin; Zhao Yande; Han Tianyou; Chu Meijuan and Pang Jinlian

, 2013, 40(2): 2120-0.

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By comprehensive study of reservoir and source rock distribution, petrology and geochemistry, the tight oil and its exploration potential was analyzed in the Triassic Yanchang Formation, Ordos Basin. The Triassic Yanchang Formation is rich in low permeability reservoirs. The proved geological reserves of tight oil, with the permeability less than 2×10-3 μm2, is about two billion tons by now. The tight oil mainly occurs in tight sandstone reservoirs of Chang6-Chang8 oil-bearing members which are close to or interbedded with the oil shale layers, without long-distance migration. The large-scale gravity flow sandstone reservoirs of Chang7 and Chang6 oil-bearing members in the center of the lacustrine basin are particularly tight, with the permeability less than 0.3×10-3 μm2 in general. The tight oil in the Yanchang Formation features large scale in sand body complex, tight reservoir, complicated pore throat structure, high content of rigid components, abundant fractures and saturation, good crude property, low fluid pressure and low oil yield. The formation of large-scale superimposed tight oil reservoirs is controlled by the interbeded lithologic combination of extensive source rocks and reservoirs and the strong hydrocarbon generation and expulsion during geological history. This type of pools is an important potential resource for future oil exploration and development.

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Dynamics of hydrocarbon accumulation in the west section of the northern margin of the Qaidam Basin, NW China

Luo Xiaorong; Sun Ying; Wang Liqun; Xiao Ancheng; Ma Lixie; Zhang Xiaobao; Wang Zhaoming and Song Chengpeng

, 2013, 40(2): 2121-0.

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Studies were conducted on the dynamic processes of hydrocarbon migration and accumulation in the west part of the northern margin of the Qaidam Basin, based on previous studies on basin evolution and hydrocarbon system. Based on the dynamics of petroleum accumulation, basin analysis and the numerical stimulation method were applied to reconstruct the basin evolution. Simulation analysis of petroleum accumulation in the main reservoir-forming stages were conducted in the light of source rock properties in different stages, fluid potential field and physical property distribution of carrier beds. Controlling factors of reservoir formation in the northern margin of the Qaidam Basin were summarized. Studies showed that the Miocene is the main period of oil generation for the Jurassic source rocks in the studied area. The oil generation and migration volume were large. However, Saishiteng Sag was just on the slope in the northern part of Yiliping Sag. Structural traps were distributed at the margin of the basin. There was abundant oil migration to the north margin and a dissipation of the oil there during the later strong tectonic activities. During the late reservoir formation stage after the Pliocene, the source rocks generated mainly gas and not oil, and structural traps were well developed and provided good conditions for the natural gas reservoir formation. Deep structural traps in the basins were conducive to the formation of a large-scale low-permeability gas reservoir.

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An in-depth analysis of reservoir architecture of underwater distributary channel sand bodies in a river dominated delta: A case study of T51 Block, Fuyu Oilfield

Zhao Xiaoqing; Bao Zhidong; Liu Zongfei; Zhao Hua and Chai Qiuhui

, 2013, 40(2): 2122-0.

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Guided by the concept of “model fitting, dynamic validation”, and based on the data of 10 coring wells, 257 logging wells, and the production performance in the dense spacing area during the past ten years, the underwater distributary channel sand reservoir in K1q4 of T51 Block, Fuyu Oilfield, Songliao Basin, was analyzed to examine the spatial distribution and identification marks of the architectures within the reservoir. Results indicated that the single channel sand body is 300–500 m wide and can be identified by such marks as inter-channel sediments, sand elevation difference between wells, difference of channel sand thickness, and “thick-thin-thick” sands association; the dip angle of the fourth-order interface is 0°–2°. Besides, the logging response characteristics and identification method of single channel sand bodies and their interior accreted bodies were defined for the reservoir. A 3D architecture model is established for the underwater distributary channel reservoir in the study area, providing a quantitative and reliable geological model for analysis of underwater distributary channel sands in the whole area.

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Hydrocarbon charge history of the Tazhong Ordovician reservoirs, Tarim Basin as revealed from an integrated fluid inclusion study

Liu Keyu; Julien Bourdet; Zhang Baoshou; Zhang Nai; Lu Xuesong; Liu Shaobo; Pang Hong; Li Zhuo and Guo Xiaowen

, 2013, 40(2): 2123-0.

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This paper presents an integrated workflow for investigating hydrocarbon charge history using fluid inclusions using the Ordovician reservoirs from the Tazhong Oilfield, Tarim Basin as an example. The work flow involves the delineation of fluid inclusion assemblage (FIA) using fluid inclusion petrography and spectroscopy for microthermometric analysis. The interpretation of microthermometric data is based on data derived from synthetic inclusion experiments and takes consideration of the P-T re-equilibration of fluid inclusions in carbonate and over pressure effect on fluid inclusion trapping. The workflow also emphasizes on the requirements of adequate sample preparation, FIA identification, quantitative spectroscopic data (CIE), coeval petroleum and aqueous fluid inclusions, adequate number of microthermometric measurements and integrated interpretation using borehole temperature. In the study reservoirs in the Tazhong area, fluid inclusion spectroscopy reveals the presence of three groups of oil inclusions of near yellow, near blue and near white fluorescence colours. The fluid inclusion microthermometry data indicate the presence of at least two predominant hydrocarbon fluid inclusion assemblages including: homogenous liquid phase yellow fluorescence inclusions and liquid phase oil and condensate fluid inclusion assemblages with homogenous near blue, near white and near yellow fluorescence colours. The aqueous inclusions from the Ordovician reservoirs in the Tazhong area reveal the presence of low, moderate, high and very high salinities in the reservoirs. The extremely high salinity is believed to be caused by regional brine intrusions relating to regional structural movement and deformation.

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Physical simulation of improving the uniformity of steam chamber growth in the steam assisted gravity drainage

Ma Desheng; Guo Jia; Zan Cheng; Wang Hongzhuang; Li Xiuluan and Shi Lin

, 2013, 40(2): 2124-0.

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In steam assisted gravity drainage (SAGD) process, there is an uneven distribution of steam chamber growth along the whole length of the horizontal well. In order to solve this problem, a three-dimensional physical model of a high-temperature and high-pressure SAGD well pair was built. Several significant reservoirs and operation parameters for SAGD were also scaled in the model size, which was based on SAGD pilot development of a typical reservoir in China. Three experiments were conducted using the above-mentioned high-temperature and high-pressure physical model. Test 1 simulated the slow steam chamber growth at the toe end and uneven distribution of steam chamber growth. Test 2 tested the regulation strategy with dual tubing strings to adjust the steam chamber based on Test 1-combining the long and short tubing strings for injection well and production well. Test 3 tested the regulation strategy with U-shape wellbore to adjust the steam chamber. The results showed that the two regulation strategies were effective for recovering steam chamber growth at the toe end and making steam chamber growth uniform along the length of SAGD wellbore. After regulating, the oil rate increased significantly.

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Stress sensitive experiments for abnormal overpressure carbonate reservoirs: A case from the Kenkiyak low-permeability fractured-porous oilfield in the littoral Caspian Basin

Zhao Lun; Chen Yefei; Ning Zhengfu; Fan Zifei; Wu Xuelin; Liu Lifang and Chen Xi

, 2013, 40(2): 2125-0.

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According to the characteristics of overpressure carbonate reservoirs of Kenkiyak pre-salt oil field in the littoral Caspian Basin, cores were made artificially and the stress sensibility of matrix cores and cores with non-packed, semi-packed and fully packed fractures were analyzed. The method of gas measurement was used in the experiment. The confining pressure of the sample cores was first increased and then decreased. When the confining pressure became stable, porosity and permeability data from each pressure point were obtained to analyze stress sensibility of cores. The results showed that the stress sensibility of these four types of cores with a descending order is cores with non-packed fractures, cores with semi-packed fractures, cores with packed fractures, and matrix cores. With the decrease in packing degree of core fractures, the stress sensitivity of core permeability increased and the recovery degree of permeability decreased; the recovery degree of porosity and permeability of the matrix cores and cores with fully packed fractures was high with the recovery of pressure and these two types of cores showed elastic-plastic features. By contrast, the recovery degree of porosity and permeability of cores with partly packed and unpacked fractures was lower and these two types of cores showed plastic features. With the increase of confining pressure, the variation of porosity and permeability showed relatively regular exponential variations.

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Derivation of water flooding characteristic curve for high water-cut oilfields

Song Zhaojie; Li Zhiping; Lai Fengpeng; Liu Gang and Gan Huohua

, 2013, 40(2): 2126-0.

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The linear relationship between relative permeability ratio (Kro/Krw) and water saturation (Sw) on the semi-log coordinate in the stage of middle water-cut is the theoretical basis for the derivation of traditional water flooding characteristic curve. However, the relationship of Kro/Krw versus Sw deviates from the straight line in the high water-cut stage, which results in the upwarping of water flooding characteristic curve. In order to accurately predict the production performance and recoverable reserves in the late development stage, the relative permeability curves of actual cores were averaged. Furthermore, using the core data in the reference, a new expression of Kro/Krw versus Sw was obtained by regression for the high water-cut stage. On the basis of the frontal-drive equation and the average water saturation equation proposed respectively by Buckley-Leverett and Welge, a new water flooding characteristic curve was derived which is more applicable for high water-cut oilfields. The calculation results indicate that the recoverable reserve calculated by the new approach is almost equal to the result of the production decline method, proving it is a practical tool in the prediction of production indexes in the late development stage of oilfields.

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Hydrodynamic geology effect during the waterflooding of seriously heterogeneous reservoirs

Li Zhongchao; Chen Hongde; Yu Chenglin; Du Li; Qiao Yong; Liu Weiwei and Sun Li

, 2013, 40(2): 2127-0.

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Hu12 Block of the Huzhuangji Oilfield is a typical strongly heterogeneous reservoir. The hydrodynamic geology effect was studied by comparing experimental results of cores before and after waterflooding. The experimental results show that the chemical force of acidic medium accelerates the dissolution of plagioclase, generating new kaolinite crystals in small pore throats at the same time. The chemical force has less impact on carbonate minerals. The physical force of the injected water caused the reduction of the total content of argillaceous minerals and the loss of quartz grains of silt to very fine sizes, which occurred in layers with good physical properties and developed channeling paths. In terms of changes in pore-throats, waterflooding resulted in the increase of the large pore-throats and improvement of percolation conditions, also gives rise to the reduction of pore throat sorting and the aggravation of micro-heterogeneity of reservoir. With respect to variations in reservoir macroscopic parameters, waterflooding leads to the drop of overall average effective porosity by 4.63% and the rise of overall average effective permeability by 8.93%. The physical property changes of reservoirs of different original properties take on obvious “Matthew Effect”.

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Prediction of accumulated outflow from a fractured hydrocarbon reservoir using metamodeling

Seifi A; Kazemzadeh M B and Mohammadi H

, 2013, 40(2): 2128-0.

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Three metamodels were established for predicting accumulated outflow from a fractured hydrocarbon reservoir over a planning horizon of 18 years, and the models were validated and compared using accumulated outflow predicted by numerical simulation. The reservoir was simulated and its basic parameters (porosity, permeability and water saturation) were estimated. The accumulated outflow over 18 years of a well in the reservoir was expressed as a function of the reservoir parameters. Low potential points were excluded using HIP (Hydrocarbon in Place) equation and 25 high potential points were chosen as design points using maximum entropy design. Three kinds of metamodels (quadratic model, multiplicative model and radial basis function model) were built and the accumulated outflows of 25 design points and 7 test points were predicted based on the models. The prediction results show that all of the three models can accurately predict the accumulated outflow of the reservoir studied in this paper and the radial basis function model outperforms the other two metamodels. Besides, the calculating time of the metamodeling method is much less than that of the numerical simulation.

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Experiment of complex flow in full size horizontal wells with perforated completion

Wei Jianguang; Wang Xiaoqiu; Chen Haibo and Zhang Quan

, 2013, 40(2): 2129-0.

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A full size perforated casing of 139.7 mm in external diameter was adopted to simulate the horizontal wellbore. The influences of perforation parameters and injection rate on the pressure drop in horizontal wells were investigated by experiments. The results show that: (1) With the increase of perforation density, perforation diameter and perforation phase, both the frictional pressure drop and the total pressure drop increase and the mixture pressure drop decreases. (2) When the mainstream Reynolds number at the perforated casing exit remains constant, with the increase of injection rate, the total pressure drop and mixing pressure drop increase. When the injection rate is less than the critical injection rate (0.05%-0.10% under the study conditions), the mixing pressure drop is less than 0. When the injection rate is greater than the critical injection rate, the mixing pressure drop is greater than 0. The acceleration pressure drop can be neglected when the injection rate is less than 0.10%, otherwise the acceleration pressure drop rises significantly with the increase of injection rate. (3) With the increase of injection rate, the proportion of frictional pressure drop to total pressure drop decreases while that of acceleration pressure drop to total pressure drop increases. When the injection rate is less than 1.00%, the proportion of mixing pressure drop to total pressure drop tends to rise with the increase of injection rate. When the injection rate is greater than 1.00%, the proportion of mixing pressure drop to total pressure drop almost remains unchanged.

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Electromagnetic measurement while drilling technology based on the carrier communication principle

Su Yi; Qi Xin; Liu Yang and Zhang Jinguang

, 2013, 40(2): 2130-0.

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To improve data transfer rate and signal telemetry depth in electromagnetic measurement while drilling (EM-MWD), and to solve the problems of short life expectancy and poor reliability of drill pipes as well as serious electromagnetic scattering, this paper presents the measurement while drilling (MWD) method based on the carrier communication principle. Based on carrier technology, the electromagnetic wave signal was coupled with the drill pipe through the coupling transformer, where the drill pipe and formation can form the guiding wave system to achieve data transfer between the ground and the bottom. The transmission line equation is developed based on the analysis of the transmission characteristics of electromagnetic waves in strata and drill pipes, and the overall structure of the system is presented. The real transmitter and receiver are produced by using LM1893 as the carrier module. In addition, the system optimization is proposed. The electromagnetic waves loaded on the drill pipe using carrier technology can transmit drilling measurement parameters from the bottom to the surface in real time, and send setting parameters and commands from the surface to the bottom simultaneously through the drill pipe-formation channel, and thus achieve the implementation of bi-directional communication between the ground and the bottom.

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Laboratory research on degradable drilling-in fluid for complex structure wells in coalbed methane reservoirs

iu Dawei; Wang Qi; Wang Yishan; Wang Helin; Yu Haifa and Yuan Menglei

, 2013, 40(2): 2131-0.

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In order to address the contradiction between drilling safety and coalbed damage control, a degradable drilling-in fluid (DIF) was developed for complex structure wells in coalbed methane (CBM) reservoirs. Its conventional properties and degradability were analyzed, and the desorption rate and return permeability methods were presented to evaluate its protection on coal desorption and seepage performance. Laboratory experiments were carried out to optimize thickening agent, fluid loss additive and filtrate reducer in DIF which is applicable to complex structure wells, and to determine the DIF formula. The DIF, with good conventional properties, can effectively carry cuttings and protect sidewall. It is also degradable. The experiment results show that DIF degradation rate is up to 85% in three hours when degradation agent is added at a concentration of 2.0% to 4.0%, and there is less solid residue after degradation. The DIF can effectively protect the seepage performance and also coal desorption, similar to clean water. The return permeability is all above 60% at different flow back pressure and the return permeability becomes bigger with increase of the flow back pressure, the maximum is up to 100%.

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Experimental evaluation of fracture stabilizers

Zhang Jingchen; Zhang Shicheng; Bian Xiaobing; Zhuang Zhaofeng and Guo Tiankui

, 2013, 40(2): 2132-0.

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To avoid the closure of once created fractures in unconsolidated sandstone reservoirs after fracturing, an optimum fracture stabilizer was selected through experimental evaluation, dosage optimization and analysis of its suitability with other commonly used fracturing fluids. A modified resin was selected as the fracture stabilizer, which can form an adhesive film with certain adhesion intensity on the surface of the proppant to fill fractures despite the slightly decreased conductivity. The conductivity, sand control effect, suitability with guanidine gum and viscoelastic surfactant fracturing fluids (VES) of fracture stabilizers with different ratios were evaluated in the experiment. The dosage of the fracture stabilizer was optimized according to conductivity results and sand control effect. After a comprehensive evaluation, the fracture stabilizer whose content ranges from 3% to 5% was used to process the proppant and the guanidine gum fracturing fluid. The simulation experiments show that the flow conductivity of fractures could be maintained by fracture stabilizers and in the proppant processed by stabilizers the number of particles intruding into the formation was significantly reduced.

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Water consumption in hydrocarbon generation and its significance to reservoir formation

Wang Yongshi; Zhang Shouchun and Zhu Rifang

, 2013, 40(2): 2133-0.

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The geochemical effects of water consumption during hydrocarbon generation were studied on the basis of evolution laws of source rocks and simulation experiments on hydrocarbon generation. Water consumption statistics were obtained in order to study the relationship between water consumption during hydrocarbon generation and hydrocarbon migration and reservoir formation. The simulation experiments of hydrocarbon generation were performed under hydrous and anhydrous conditions for correlation. The geochemical characteristics of organic evolution under these two conditions were analyzed and the variations of hydrocarbon generation potential and carbon transformation ratio were emphasized. The results show the effects that organic matter and water have on each other during hydrocarbon generation: part of unavailable carbon is activated in kerogen and hydrogen is increased in degraded products, which leads to the increase of total hydrocarbon generation potential. According to water consumption mechanisms, the quantitative evaluation method of water consumption in hydrocarbon generation was put forward and used in the studies of the main source rocks in the Dongying Sag. Both of the water consumption and the depth range of the Upper Es4 Member are larger, while those of the Lower and Middle Es3 Members are smaller. Water consumption affects hydrocarbon migration and accumulation by increasing organic carbon degradation rate to increase fluid volume. Pore fluid pressure and oil-bearing saturation are consequently increased. The matching relationship between water-consuming hydrocarbon generation intervals and water-consuming diagenesis intervals enhances the dynamic forces of hydrocarbon migration, which benefits the formation of self-generating and self-preserving reservoirs or lower-generating and upper-preserving reservoirs.

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Discussions on the gas source of the Triassic Xujiahe Formation tight sandstone gas reservoirs in Yuanba and Tongnanba, Sichuan Basin: An answer to Yinfeng et al.

Dai Jinxing; Liao Fengrong and Ni Yunyan

, 2013, 40(2): 2134-0.

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Gas-source correlation is generally focused on the genetic type of the main gas components, dominantly oil-associated gas or coal-derived gas. Gases from the Yuanba and Tongnanba gas reservoirs are dominated by methane with an average content of 95.36%. The average contents of ethane, propane, butane are 1.60%, 0.29% and 0.09%, respectively. In general, for the Yuanba and Tongnanba gas reservoirs, alkane gas has an average content of 97.34%, and CO2 has an average content of 0.63%, which only accounts for 6.5‰ of the methane. According to the discrimination criteria that δ13C2 value is greater than –28‰ for coal-derived gas and lower than –28.5‰ for the oil-associated gas, Yin et al. suggested that the gases from the Yuanba gas reservoir be a mixture of coal-derived and oil-associated gases, and the gases from the Tongnanba gas reservoir be oil-associated gas. However, the discrimination criteria of δ13C2 for coal-derived and oil-associated gases are only valid when the alkane gases have not undergone secondary alteration and have positive carbon isotopic series among C1-C4 alkanes. Hence, it is concluded that gases from the Yuanba and Tongnanba gas reservoirs are coal-derived gases due to their high content and heavy carbon isotopic values of methane (–31.3‰), which is typical for high mature coal-derived gases in the world. Though Yin et al. suggested that abiogenic CO2 of these two reservoirs is originated from metamorphism or hydrolysis of deep carbonate rocks, we proposed that these CO2 gases be self-generated and self-accumulated under the corrosion of calcarenaceous sandstone of the Triassic Xujiahe Formation.

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, Volume 40 Issue 2