Volume 20,Issue 1,2013 Table of Contents
2013, 20(1):1-5.
Abstract:
For the interface of different levels, different types, and different acting modes in petroliferous basins, what the petroleum geology study concern most is the different neogenic fluid action interface related to the hydrocarbon fluid generation, expulsion, migration, and accumulation. On the basis of definitions, characteristics, and mode of action analysis of interfaces which includes hydrocarbon generation, hydrocarbon expulsion, the overpressure, secondary pore development, water consumption, this paper presents reservoir-forming acting surface of rift basins. The reservoir-forming acting surface of rift basins is the reflection of coupling of basin neogenic fluid movement process, energy formation and its action mechanism. It is the result of 4 interface coupling that is not only the turnaround surface of fluid process and interfaces of different reservoir spaces, but also the turnaround surface of different energy and reservoir type distribution. Through the control of different fluid potential distribution and superimposition, different reservoir distribution features are affected. By means of identification, research and evaluation of different fluid acting surfaces, the reservoir types and distribution patterns can be predicted effectively. Thus, the reservoir richness of basin can be predicted. It is of great significance for basin evaluation.
For the interface of different levels, different types, and different acting modes in petroliferous basins, what the petroleum geology study concern most is the different neogenic fluid action interface related to the hydrocarbon fluid generation, expulsion, migration, and accumulation. On the basis of definitions, characteristics, and mode of action analysis of interfaces which includes hydrocarbon generation, hydrocarbon expulsion, the overpressure, secondary pore development, water consumption, this paper presents reservoir-forming acting surface of rift basins. The reservoir-forming acting surface of rift basins is the reflection of coupling of basin neogenic fluid movement process, energy formation and its action mechanism. It is the result of 4 interface coupling that is not only the turnaround surface of fluid process and interfaces of different reservoir spaces, but also the turnaround surface of different energy and reservoir type distribution. Through the control of different fluid potential distribution and superimposition, different reservoir distribution features are affected. By means of identification, research and evaluation of different fluid acting surfaces, the reservoir types and distribution patterns can be predicted effectively. Thus, the reservoir richness of basin can be predicted. It is of great significance for basin evaluation.
2013, 20(1):1-4.
Abstract:
Nanpu depression is one of the main oil-producing region in Huanghua depression, oil and gas reservoirs in this depression must be of favorable reservoir forming conditions. This paper applies reservoir anatomy, geochemical data analysis, fault activity periods, source rock hydrocarbon expulsion period, caprock identification and sand and stratum ratio analysis and other measures, uses the reservoir conditions of comprehensive analysis method to study in detail and analyze the source rock, caprock, fracture, reservoir and structural position in 5 aspects in terms of geological condition, we clearly determined hydrocarbon accumulation conditions and their relationship in Nanpu depression. It is considered that there are five favorable geological conditions for oil and gas accumulation in Nanpu depression: ① two source rocks whose thickness is high and the distribution is wide so as to provide adequate oil and gas for migration and accumulation; ②two source rocks provide transporting pathways for oil and gas to migrate; ③three regional caprocks provide sealing for oil and gas to accumulate; ④strata with high ratio between sand stone and stratum so as to provide reservoir space for oil and gas to accumulate; ⑤positive structures near faults connected source rock so as to provide favorable places for oil and gas to accumulate. Through the study of this paper, it will be enriched hydrocarbon accumulation in Nanpu depression, and provides a new thought for next exploration of oil and gas. The result of this study offers important significance to guide the oil-gas exploration in depression basin.
Nanpu depression is one of the main oil-producing region in Huanghua depression, oil and gas reservoirs in this depression must be of favorable reservoir forming conditions. This paper applies reservoir anatomy, geochemical data analysis, fault activity periods, source rock hydrocarbon expulsion period, caprock identification and sand and stratum ratio analysis and other measures, uses the reservoir conditions of comprehensive analysis method to study in detail and analyze the source rock, caprock, fracture, reservoir and structural position in 5 aspects in terms of geological condition, we clearly determined hydrocarbon accumulation conditions and their relationship in Nanpu depression. It is considered that there are five favorable geological conditions for oil and gas accumulation in Nanpu depression: ① two source rocks whose thickness is high and the distribution is wide so as to provide adequate oil and gas for migration and accumulation; ②two source rocks provide transporting pathways for oil and gas to migrate; ③three regional caprocks provide sealing for oil and gas to accumulate; ④strata with high ratio between sand stone and stratum so as to provide reservoir space for oil and gas to accumulate; ⑤positive structures near faults connected source rock so as to provide favorable places for oil and gas to accumulate. Through the study of this paper, it will be enriched hydrocarbon accumulation in Nanpu depression, and provides a new thought for next exploration of oil and gas. The result of this study offers important significance to guide the oil-gas exploration in depression basin.
2013, 20(1):6-10.
Abstract:
In response to the phenomenon of petroleum downward migration exist in Chexi sag of Chezhen depression, herein, beginning from the analysis of the basic geological characteristics and combined with the oil-source correlation, and the distribution of effective source rock, and the position of the source rock and reservoir, the research showed that there does exist the phenomenon of petroleum downward migration below the burried depth of 4 700 m under the effective source rock of the third member of Shahejie formation(Es3) in this area. By means of oil-source correlation, it is confirmed that the oil in the pools of the fourth member of Shahejie formation(upper Es4)layer in the north of Caojiazhuan fault terrace in the sag is from the upper layer, the Es3 effective source rock in this area. On the basis of analysis of reservoir formation factors, it is clear that there are four main factors which control the reservoir formation by the downward migration. These main factors are the lithological relationship between sandstone in upper Es4 layer and the thick mudstone in the upper Es3 layer , the overpressure of the effective Es3 source rock, subtle passage system and the pressure difference between the reservoir and effective source rock. There is a positive correlation between the distance of petroleum downward migration and residual pressure in the effective source rock. The oil saturation was controlled by the physical characteristics of the reservoir under the source rock. The viewpoint above further improves the theoretical understanding on the reservoir formation in Jiyang depression and can be used as reference for exploration practice in Bohaiwan basin.
In response to the phenomenon of petroleum downward migration exist in Chexi sag of Chezhen depression, herein, beginning from the analysis of the basic geological characteristics and combined with the oil-source correlation, and the distribution of effective source rock, and the position of the source rock and reservoir, the research showed that there does exist the phenomenon of petroleum downward migration below the burried depth of 4 700 m under the effective source rock of the third member of Shahejie formation(Es3) in this area. By means of oil-source correlation, it is confirmed that the oil in the pools of the fourth member of Shahejie formation(upper Es4)layer in the north of Caojiazhuan fault terrace in the sag is from the upper layer, the Es3 effective source rock in this area. On the basis of analysis of reservoir formation factors, it is clear that there are four main factors which control the reservoir formation by the downward migration. These main factors are the lithological relationship between sandstone in upper Es4 layer and the thick mudstone in the upper Es3 layer , the overpressure of the effective Es3 source rock, subtle passage system and the pressure difference between the reservoir and effective source rock. There is a positive correlation between the distance of petroleum downward migration and residual pressure in the effective source rock. The oil saturation was controlled by the physical characteristics of the reservoir under the source rock. The viewpoint above further improves the theoretical understanding on the reservoir formation in Jiyang depression and can be used as reference for exploration practice in Bohaiwan basin.
2013, 20(1):11-15.
Abstract:
The Triassic of Hami depression is an important source rock and reservoir stratum. It is divided into one second-class sequence and four third-class sequences. Each third-class sequence is consisted of two or three system tracts, including lowstand system tract, highstand system tract, transgressive system tract. The Triassic of Hami depression is mainly developed as braided river, meandering river, braided river delta, meandering river delta and lacustrine facies. Among these, the meandering river delta and braided river delta are main reservoir facies belt, the lacustrine facies is favorable source rock and cap rock facies belt. From early to middle Triassic epoch, south central gentle slope of Hami depression is extensively developed as braided river facies, north and the north-west of Hami depression is developed as meandering river facies. In late Triassic Huangshanjie group and Haojiagou group period, the braided river deltas are developed, in late Karamay group, the meandering river delta is developed, which is the favorable belt for locating lithologic reservoirs.
The Triassic of Hami depression is an important source rock and reservoir stratum. It is divided into one second-class sequence and four third-class sequences. Each third-class sequence is consisted of two or three system tracts, including lowstand system tract, highstand system tract, transgressive system tract. The Triassic of Hami depression is mainly developed as braided river, meandering river, braided river delta, meandering river delta and lacustrine facies. Among these, the meandering river delta and braided river delta are main reservoir facies belt, the lacustrine facies is favorable source rock and cap rock facies belt. From early to middle Triassic epoch, south central gentle slope of Hami depression is extensively developed as braided river facies, north and the north-west of Hami depression is developed as meandering river facies. In late Triassic Huangshanjie group and Haojiagou group period, the braided river deltas are developed, in late Karamay group, the meandering river delta is developed, which is the favorable belt for locating lithologic reservoirs.
2013, 20(1):16-19.
Abstract:
The South Sumatra Basin is the typical backarc rift basin of Cenozoic. The tectonic evolution controls the distribution of sedimentary systems and source rock, reservoir and seal from Eocene to Holocene. From early Eocene to early Oligocene, the South Sumatra Basin is in the early syn-rift stage and developed a set of grabens and half grabens with terrestrial facies, in which the prodelta shale is the main source rocks, and glutenites in the alluvial fan and braided river are the main reservoir rocks. During Late Oligocen,the South Sumatra Basin is in the early syn-rift later stage when there is the marine facies in the middle of the basin caused by the transgression from southwest, and delta and fluvial facies existed at the edge of the basin. The coal-bearing shale in the delta is the main source rock and the important cap rock, while the sandstones in the fluvial and delta facies are the important reservoir rocks. During the early Miocene, the South Sumatra Basin is in the last syn-rift later stage when the basin is deposited mainly as the marine facies, in which the mud shale and muddy limestone in the abysmal-bathyal facies are the important source rocks and regional seals,while the carbonate bank and biohermal limestone in the shore-shallow marine are the main reservoirs. From the middle Miocene to Pliocene, the South Sumatra Basin experienced the compaction and regression causing the development of marine, terrestrial and transitional facies at the same time. The regressive sandstone in the shore-shallow marine is the favorable reservoir, and the mud shale in the pre-delta is the good source and seal rocks. Definition of the evolution of the sedimentary system and the corresponding distribution of source rock, reservoir and seal in the South Sumatra Basin will provide the scientific foundation to establish the database of sedimentary system and hydrocarbon system in the petroliferous basins all over the world.
The South Sumatra Basin is the typical backarc rift basin of Cenozoic. The tectonic evolution controls the distribution of sedimentary systems and source rock, reservoir and seal from Eocene to Holocene. From early Eocene to early Oligocene, the South Sumatra Basin is in the early syn-rift stage and developed a set of grabens and half grabens with terrestrial facies, in which the prodelta shale is the main source rocks, and glutenites in the alluvial fan and braided river are the main reservoir rocks. During Late Oligocen,the South Sumatra Basin is in the early syn-rift later stage when there is the marine facies in the middle of the basin caused by the transgression from southwest, and delta and fluvial facies existed at the edge of the basin. The coal-bearing shale in the delta is the main source rock and the important cap rock, while the sandstones in the fluvial and delta facies are the important reservoir rocks. During the early Miocene, the South Sumatra Basin is in the last syn-rift later stage when the basin is deposited mainly as the marine facies, in which the mud shale and muddy limestone in the abysmal-bathyal facies are the important source rocks and regional seals,while the carbonate bank and biohermal limestone in the shore-shallow marine are the main reservoirs. From the middle Miocene to Pliocene, the South Sumatra Basin experienced the compaction and regression causing the development of marine, terrestrial and transitional facies at the same time. The regressive sandstone in the shore-shallow marine is the favorable reservoir, and the mud shale in the pre-delta is the good source and seal rocks. Definition of the evolution of the sedimentary system and the corresponding distribution of source rock, reservoir and seal in the South Sumatra Basin will provide the scientific foundation to establish the database of sedimentary system and hydrocarbon system in the petroliferous basins all over the world.
2013, 20(1):20-23.
Abstract:
Based on the sequence stratigraphy study, the relationship between dark mudstones content and sedimentary facies within different system tracts is observed and used to forecast the distribution of dark mudstones in the main formation combined with the seismic data and well log. However, not all dark mudstones can generate hydrocarbon, so, the source rock criterion is discussed by analyzing pyrolysis data of mudstones, and then the source rock quality is calculated by using logging data for the early-stage prediction of source rocks thickness. The results show that the favorable source rock in lacustrine progressive system tracts and the bottom of highstand system tracts of Xiagou Formation and Chijinpu Formation are related to a group of reflectors with medium-strong amplitude, medium-low frequency and medium to comparatively good lateral continuity. The source rock of Xiagou Formation with high organic content and wide-range distribution is the main hydrocarbon source in Ying’er Sag, while Chijinpu Formation with thick dark mudstones is the potential source rock and the target of the further exploration.
Based on the sequence stratigraphy study, the relationship between dark mudstones content and sedimentary facies within different system tracts is observed and used to forecast the distribution of dark mudstones in the main formation combined with the seismic data and well log. However, not all dark mudstones can generate hydrocarbon, so, the source rock criterion is discussed by analyzing pyrolysis data of mudstones, and then the source rock quality is calculated by using logging data for the early-stage prediction of source rocks thickness. The results show that the favorable source rock in lacustrine progressive system tracts and the bottom of highstand system tracts of Xiagou Formation and Chijinpu Formation are related to a group of reflectors with medium-strong amplitude, medium-low frequency and medium to comparatively good lateral continuity. The source rock of Xiagou Formation with high organic content and wide-range distribution is the main hydrocarbon source in Ying’er Sag, while Chijinpu Formation with thick dark mudstones is the potential source rock and the target of the further exploration.
2013, 20(1):24-27.
Abstract:
It is difficult to build the shale mineral component content models in Luojia area because of the rapid lithofacies change and unstable lithology. Two aspects of difficulties are solved by comparison, and three values including point-point, segment-point and segment-segment are compared. The result shows that the relative error of the segment-segment reading is minimum in error, less than8%, therefore, it is adopted. For the idea of modeling, the volume-based numerical method and inversion-based fitting method have been discussed. On the basis of the processing and analysis of well Luo 69, we suggest to build the mineral content explaining model bound by the geological conditions of lithofacies classification because of its simplicity and feasibility. The modeling methods and ideas provide the reference for the complex modeling in continental basins.
It is difficult to build the shale mineral component content models in Luojia area because of the rapid lithofacies change and unstable lithology. Two aspects of difficulties are solved by comparison, and three values including point-point, segment-point and segment-segment are compared. The result shows that the relative error of the segment-segment reading is minimum in error, less than8%, therefore, it is adopted. For the idea of modeling, the volume-based numerical method and inversion-based fitting method have been discussed. On the basis of the processing and analysis of well Luo 69, we suggest to build the mineral content explaining model bound by the geological conditions of lithofacies classification because of its simplicity and feasibility. The modeling methods and ideas provide the reference for the complex modeling in continental basins.
2013, 20(1):28-31.
Abstract:
The inner architecture characterization of reservoir is the base and key factor to improve the waterflooding effectiveness and enhance the oil recovery. Taking the Es281 sand unit of Shengtuo oilfield in Dongying depression as an example, which is a typical underwater distributary channel of delta front reservoir, the inner architecture of the composite sand body was characterized by close spacing architectural analysis. The study shows that the depositional interfaces in the underwater distributary channel can be classified into 5 levels. The fifth level interface restricts the composite underwater distributary channel, which is the stable mudstone with major thickness and near horizontal attitude. The fourth level interface restricts the single channel, which is mainly the muddy intercalation or lithological discontinuity surface with near horizontal attitude and continuous distribution in same single channel, but with discontinuous distribution among the different single channels. The third level interface restricts the accretion sand body in the single channel, and the upper and lower lithofacies of the third level interface is accordant. The distribution range of the third level is confined by single channel and the attitude is also near horizontal. The second and first level interfaces restrict the bedding system and cross bedding with core scale. The composite underwater distributary channel sand body is overrode vertically and built up laterally by single channel. The lateral border of the single channel can be identified by inter-distributary bay, channel marginal deposit, top surface altitude difference of sandbody and scale difference of sand body. The most important inner architecture characteristic of the underwater distributary channel is the contemporaneous deposit of single channel but independent sand body.
The inner architecture characterization of reservoir is the base and key factor to improve the waterflooding effectiveness and enhance the oil recovery. Taking the Es281 sand unit of Shengtuo oilfield in Dongying depression as an example, which is a typical underwater distributary channel of delta front reservoir, the inner architecture of the composite sand body was characterized by close spacing architectural analysis. The study shows that the depositional interfaces in the underwater distributary channel can be classified into 5 levels. The fifth level interface restricts the composite underwater distributary channel, which is the stable mudstone with major thickness and near horizontal attitude. The fourth level interface restricts the single channel, which is mainly the muddy intercalation or lithological discontinuity surface with near horizontal attitude and continuous distribution in same single channel, but with discontinuous distribution among the different single channels. The third level interface restricts the accretion sand body in the single channel, and the upper and lower lithofacies of the third level interface is accordant. The distribution range of the third level is confined by single channel and the attitude is also near horizontal. The second and first level interfaces restrict the bedding system and cross bedding with core scale. The composite underwater distributary channel sand body is overrode vertically and built up laterally by single channel. The lateral border of the single channel can be identified by inter-distributary bay, channel marginal deposit, top surface altitude difference of sandbody and scale difference of sand body. The most important inner architecture characteristic of the underwater distributary channel is the contemporaneous deposit of single channel but independent sand body.
2013, 20(1):32-35.
Abstract:
The microscopic pore structure of Chang 3 ultra-low permeability reservoir of the Yanchang Formation in the Ordos Basin Fuxian exploration area is thoroughly analyzed and investigated by using constant-speed mercury intrusion technique, combined with conventional casting thin sections, scanning electron microscopy, constant-pressure mercury injection and other analytical approaches for the first time. The main pore type of the reservoir is residual intergranular pore and dissolved intergranular pore. The pore structure is divided into five categories: lower displacement pressure-coarser throat type, low displacement pressure-coarse throat type, middle displacement pressure-middle throat type, high displacement pressure-fine throat type, higher displacement pressure-finer throat type. The result of the constant-speed mercury intrusion test shows that the distribution of the pore radius ranges from 100 to 200 μm,the pore is mainly the medium-small, few samples exhibit the large scale, and pore distribution curves are partial coarse, the distribution of throat radius ranges from 0.2 to 0.7 μm, the throat is mainly micro-throat, throat distribution curves are partial thin, reservoir flow capacity has poor correlation with the pore size, and it is mainly controlled by the size of the average radius of throat, distribution patterns of throat-size, and thus affecting the development effectiveness of super-low permeability and ultra-low permeability reservoirs.
The microscopic pore structure of Chang 3 ultra-low permeability reservoir of the Yanchang Formation in the Ordos Basin Fuxian exploration area is thoroughly analyzed and investigated by using constant-speed mercury intrusion technique, combined with conventional casting thin sections, scanning electron microscopy, constant-pressure mercury injection and other analytical approaches for the first time. The main pore type of the reservoir is residual intergranular pore and dissolved intergranular pore. The pore structure is divided into five categories: lower displacement pressure-coarser throat type, low displacement pressure-coarse throat type, middle displacement pressure-middle throat type, high displacement pressure-fine throat type, higher displacement pressure-finer throat type. The result of the constant-speed mercury intrusion test shows that the distribution of the pore radius ranges from 100 to 200 μm,the pore is mainly the medium-small, few samples exhibit the large scale, and pore distribution curves are partial coarse, the distribution of throat radius ranges from 0.2 to 0.7 μm, the throat is mainly micro-throat, throat distribution curves are partial thin, reservoir flow capacity has poor correlation with the pore size, and it is mainly controlled by the size of the average radius of throat, distribution patterns of throat-size, and thus affecting the development effectiveness of super-low permeability and ultra-low permeability reservoirs.
2013, 20(1):36-39.
Abstract:
The miscible systems, which are composed of hydrocarbon-water, other gases and mineral salts, are widely distributed in reservoir, with complicated phase transition attributes, and are also significant to the exploration and development of petroleum. After gathering domestic and international data about hydrocarbon-water miscible system and mainly analyzing conditions for occurrence of gaseous formation water and phases transition attributes of water bearing hydrocarbon system, this paper concludes that the regional sudden rising of temperature, reducing of pressure and increasing of hydrocarbon bearing content are all beneficial for the vaporization to the hydrocarbon-water miscible system. The current measured thickness of irreducible water is a fluctuated value, which is dependent on irreducible brine saturation and ineligible for low limit of reserve, and then, the present measured low limit of reserve can be decreased undoubtedly under suitable values of temperature and pressure and content of dissolved hydrocarbon, the actual stable thickness should be about 1.6 nm. The salting out effect, which is caused by vaporization of water, will reduce the permeability of oil/gas field and increase interfacial tension of oil-water, so, it is necessary to inspect the gaseous water change during production.
The miscible systems, which are composed of hydrocarbon-water, other gases and mineral salts, are widely distributed in reservoir, with complicated phase transition attributes, and are also significant to the exploration and development of petroleum. After gathering domestic and international data about hydrocarbon-water miscible system and mainly analyzing conditions for occurrence of gaseous formation water and phases transition attributes of water bearing hydrocarbon system, this paper concludes that the regional sudden rising of temperature, reducing of pressure and increasing of hydrocarbon bearing content are all beneficial for the vaporization to the hydrocarbon-water miscible system. The current measured thickness of irreducible water is a fluctuated value, which is dependent on irreducible brine saturation and ineligible for low limit of reserve, and then, the present measured low limit of reserve can be decreased undoubtedly under suitable values of temperature and pressure and content of dissolved hydrocarbon, the actual stable thickness should be about 1.6 nm. The salting out effect, which is caused by vaporization of water, will reduce the permeability of oil/gas field and increase interfacial tension of oil-water, so, it is necessary to inspect the gaseous water change during production.
2013, 20(1):40-43.
Abstract:
The application of principles and methods of sequence stratigraphy, integrated with the seismic, logging and drilling data, we research the sequences and system-tracks for the Jiufotang formation in the west area of Lujiapu sag, and the 2 third grade sequence interface, the 3 fourth grade sequences or system-tracks, are all identified, which including the lowstand system-track, lacustrine transgressive system tract, highstand system-track, and they can be divided separately into 3, 4 and 4 subsequence sets. Thus, the sequence stratigraphy framework for the target formation of project area were formed, analysis system domain characteristics and plane exhibition cloth characteristics and the relationship between sequences growth and sedimentary succession and their distribution characteristics in horizontal and vertical direction, finally, the research achievement can provide a foundation for the further exploration of target formation.
The application of principles and methods of sequence stratigraphy, integrated with the seismic, logging and drilling data, we research the sequences and system-tracks for the Jiufotang formation in the west area of Lujiapu sag, and the 2 third grade sequence interface, the 3 fourth grade sequences or system-tracks, are all identified, which including the lowstand system-track, lacustrine transgressive system tract, highstand system-track, and they can be divided separately into 3, 4 and 4 subsequence sets. Thus, the sequence stratigraphy framework for the target formation of project area were formed, analysis system domain characteristics and plane exhibition cloth characteristics and the relationship between sequences growth and sedimentary succession and their distribution characteristics in horizontal and vertical direction, finally, the research achievement can provide a foundation for the further exploration of target formation.
12 Flow units division and feasibility for the sencond area of Dalugou oil reservoir, Jing’an oilfield
2013, 20(1):44-47.
Abstract:
In this paper, we provide a reasonable means for the flow units division and feasibility verification in the sencond area of Dalugou oil reservoir. According to the reservoir flow characteristics, we use the lithology property and physical property method to divide the flow unit, and use discrimination analysis, micro-flow experiment, the production dynamic method, interwell tracer method, and numerical simulation to give a reasonable validation. The results show that: ①The area is divided into four flow units, the distribution of the phases of different flow units is different and they have different physical properties and micro-flow characteristics; ②Integrated with a variety of identification methods of verification, the average correct rate of this division of flow units in this area is 91.4%, and it is feasible; ③B, C-type flow unit, and the combination of several types of flow units is the concentrated area for the remaining oil in the region, and they should be the focus of the potential adjustment; ④The priority direction, which water flow unit combination drives, decides the principle of water injection allocation.
In this paper, we provide a reasonable means for the flow units division and feasibility verification in the sencond area of Dalugou oil reservoir. According to the reservoir flow characteristics, we use the lithology property and physical property method to divide the flow unit, and use discrimination analysis, micro-flow experiment, the production dynamic method, interwell tracer method, and numerical simulation to give a reasonable validation. The results show that: ①The area is divided into four flow units, the distribution of the phases of different flow units is different and they have different physical properties and micro-flow characteristics; ②Integrated with a variety of identification methods of verification, the average correct rate of this division of flow units in this area is 91.4%, and it is feasible; ③B, C-type flow unit, and the combination of several types of flow units is the concentrated area for the remaining oil in the region, and they should be the focus of the potential adjustment; ④The priority direction, which water flow unit combination drives, decides the principle of water injection allocation.
2013, 20(1):48-51.
Abstract:
Based on the conclusion of the metamorphic rock reservoir characteristics in Archaean, which is difficult to identify the reservoir and parameters effectively. This paper presents the lithology identification by using the method of cross plot of CNL-GR logging data and content of dark mineral, based on research of reservoir characteristics of Chengbei metamorphic rock reservoir in Jiyang depression. The reservoir fracture identification through the FMI logging and fracture indicating curve is accomplished. This paper also applies porosity spectral analysis of FMI and porosity interpretation from normal logging to confirm the porosity of metamorphic rock fracture reservoir. Through the saturation calculation method of volume distribution and NMR logging, we can determine the reservoir oil saturation and formulate the effective reservoir identification standard. Based on this method, we have obtained a good result in identification of effective reservoir and parameters at Chengbeigu 7 and Shangu 6 blocks of metamorphic rock reservoir in Shengli oil field.
Based on the conclusion of the metamorphic rock reservoir characteristics in Archaean, which is difficult to identify the reservoir and parameters effectively. This paper presents the lithology identification by using the method of cross plot of CNL-GR logging data and content of dark mineral, based on research of reservoir characteristics of Chengbei metamorphic rock reservoir in Jiyang depression. The reservoir fracture identification through the FMI logging and fracture indicating curve is accomplished. This paper also applies porosity spectral analysis of FMI and porosity interpretation from normal logging to confirm the porosity of metamorphic rock fracture reservoir. Through the saturation calculation method of volume distribution and NMR logging, we can determine the reservoir oil saturation and formulate the effective reservoir identification standard. Based on this method, we have obtained a good result in identification of effective reservoir and parameters at Chengbeigu 7 and Shangu 6 blocks of metamorphic rock reservoir in Shengli oil field.
2013, 20(1):52-54.
Abstract:
The seismic attribute can be subtracted from seismic data, and then it is specially used for the measurement of seismic data in its geometry, dynamics or statistics feature. The purpose of seismic multi-attributes inversion is to provide reliable foundation data for reservoir prediction. There are two methods in forecasting well logging characteristics from seismic data: linear regression and nonlinear method. In nonlinear mode, neural network or support vector machine is trained, using the selected attributes as inputs. Seismic multi-attributes nonlinear inversion results match the geologic distribution regulation much more than linear regression. Taking spontaneous potential (SP) curve as the inversion goal, firstly, we can find the optimal seismic attributes for SP inversion by using linear regression. Secondly, the multi-attributes inversion is carried out by using the multilayer feed forward network (MLFN) based on these seismic attributes, and acquiring 3-D SP data volume. Finally, the progradation process of delta-front sandbody in Dongying delta are displayed clearly through seismic slice along the layer. The practical application results show that the proposed method has a good performance and is beneficial for further application and application.
The seismic attribute can be subtracted from seismic data, and then it is specially used for the measurement of seismic data in its geometry, dynamics or statistics feature. The purpose of seismic multi-attributes inversion is to provide reliable foundation data for reservoir prediction. There are two methods in forecasting well logging characteristics from seismic data: linear regression and nonlinear method. In nonlinear mode, neural network or support vector machine is trained, using the selected attributes as inputs. Seismic multi-attributes nonlinear inversion results match the geologic distribution regulation much more than linear regression. Taking spontaneous potential (SP) curve as the inversion goal, firstly, we can find the optimal seismic attributes for SP inversion by using linear regression. Secondly, the multi-attributes inversion is carried out by using the multilayer feed forward network (MLFN) based on these seismic attributes, and acquiring 3-D SP data volume. Finally, the progradation process of delta-front sandbody in Dongying delta are displayed clearly through seismic slice along the layer. The practical application results show that the proposed method has a good performance and is beneficial for further application and application.
2013, 20(1):55-58.
Abstract:
Pre-stack seismic inversion can offer more geophysical information, but its accuracy can be affected by variable factors. For this reason, firstly, geological models of various velocity characteristics are designed, then, the pre-stack inversion is carried out for the seismic data extracted based on the geological model, and then, based on comparison of the inversion error to the theoretical model, influential factors of pre-stack seismic inversion such as initial constrained model, signal-noise ratio, inversion wavelet and reflectivity computational formula are analyzed. The study indicates that: the more accurate the initial constrained model, the better the inversion results; the higher the signal-noise ratio of the seismic data, the better the inversion results; the closer the wavelet matching with the seismic dominant frequency, the more accurate the inversion results; and Zeoppritz equation can be used as reflectivity computational formula because of its relatively reasonable applicability. The geological model and actual data inversion shows that inversion accuracy can be increased by establishing initial inversion model with elastic properties close to those of the actual model, boosting signal-noise ratio through filtering and modifying seismic data, extracting wavelet matching with the seismic dominant frequency from well logging and seismic data, and using applicable reflectivity computational formula.
Pre-stack seismic inversion can offer more geophysical information, but its accuracy can be affected by variable factors. For this reason, firstly, geological models of various velocity characteristics are designed, then, the pre-stack inversion is carried out for the seismic data extracted based on the geological model, and then, based on comparison of the inversion error to the theoretical model, influential factors of pre-stack seismic inversion such as initial constrained model, signal-noise ratio, inversion wavelet and reflectivity computational formula are analyzed. The study indicates that: the more accurate the initial constrained model, the better the inversion results; the higher the signal-noise ratio of the seismic data, the better the inversion results; the closer the wavelet matching with the seismic dominant frequency, the more accurate the inversion results; and Zeoppritz equation can be used as reflectivity computational formula because of its relatively reasonable applicability. The geological model and actual data inversion shows that inversion accuracy can be increased by establishing initial inversion model with elastic properties close to those of the actual model, boosting signal-noise ratio through filtering and modifying seismic data, extracting wavelet matching with the seismic dominant frequency from well logging and seismic data, and using applicable reflectivity computational formula.
2013, 20(1):59-62.
Abstract:
The paper studied the effects of shear-mode on rheological properties of hydrophobic associating polymer AP-P4’solution,whose concentration is 1 750 mg/L, sheared by Waring blender and the simulation device near wellbore. In order to study the influence on the rheological properties of the solutions, we compare their solutions sheared by different methods. It displayed that the viscoelasticity & non-Newtonian behavior of the solutions are different, although the apparent viscosity of the solutions is equal. The viscoelasticity & non-Newtonian behavior of the solution sheared by the simulation device near wellbore is only changed in“magnitude”, but the “quality”is not changed. The viscoelasticity & non-Newtonian behavior of the solution sheared by Waring blender is changed both in “magnitude”and in“quality”. At the same time, the solution obtained by different shearing method is different in its molecular weight,and in its distribution, resistance coefficient and residual resistance coefficient, variable increment of oil enhance and water constrain capacity. It is thought that it is not correspondent to the reservoir behavior to shear by Waring blender, it can only get the solution with the same viscosity, but other different rheological properties. The shearing by near-wellbore simulator can be more feasible in field practice.
The paper studied the effects of shear-mode on rheological properties of hydrophobic associating polymer AP-P4’solution,whose concentration is 1 750 mg/L, sheared by Waring blender and the simulation device near wellbore. In order to study the influence on the rheological properties of the solutions, we compare their solutions sheared by different methods. It displayed that the viscoelasticity & non-Newtonian behavior of the solutions are different, although the apparent viscosity of the solutions is equal. The viscoelasticity & non-Newtonian behavior of the solution sheared by the simulation device near wellbore is only changed in“magnitude”, but the “quality”is not changed. The viscoelasticity & non-Newtonian behavior of the solution sheared by Waring blender is changed both in “magnitude”and in“quality”. At the same time, the solution obtained by different shearing method is different in its molecular weight,and in its distribution, resistance coefficient and residual resistance coefficient, variable increment of oil enhance and water constrain capacity. It is thought that it is not correspondent to the reservoir behavior to shear by Waring blender, it can only get the solution with the same viscosity, but other different rheological properties. The shearing by near-wellbore simulator can be more feasible in field practice.
2013, 20(1):63-66.
Abstract:
Heavy oil reserves exist in Canada, Venezuela, China and other parts of the world, whose reserves is equivalent or even higher than the existing reserves. Cold heavy oil production with sand is an effective technique, which can produces more oil than conventional solution gas drive reservoir by formulating foamy oil flow. So, enhancing the research of foamy oil is essential for developing such reservoir. This paper studied the research status and the recent development of foamy oil in cold heavy oil production with sand. Beginning with the analysis of foamy oil reservoir’s unconventional characteristics, definitions and properties of foamy oil are introduced systematically. The methods and research content of unconventional PVT and depletion experiments are presented here. The detailed overview about the research on the pore network modeling and reservoir simulation are summarized. Finally, the focus of future work and research direction are proposed, which may be of referential meaning in the further research on foamy oil.
Heavy oil reserves exist in Canada, Venezuela, China and other parts of the world, whose reserves is equivalent or even higher than the existing reserves. Cold heavy oil production with sand is an effective technique, which can produces more oil than conventional solution gas drive reservoir by formulating foamy oil flow. So, enhancing the research of foamy oil is essential for developing such reservoir. This paper studied the research status and the recent development of foamy oil in cold heavy oil production with sand. Beginning with the analysis of foamy oil reservoir’s unconventional characteristics, definitions and properties of foamy oil are introduced systematically. The methods and research content of unconventional PVT and depletion experiments are presented here. The detailed overview about the research on the pore network modeling and reservoir simulation are summarized. Finally, the focus of future work and research direction are proposed, which may be of referential meaning in the further research on foamy oil.
2013, 20(1):67-69.
Abstract:
Based on the generalized Darcy’s law, considering the effect of start-up pressure gradient, the permeability anisotropy of low permeability oil-water two phase seepage model is established herein. Based on the principle of virtual displacement, a finite element program is developed. Taking the Daqing Su301 fault block, a rectangular five-spot linear injection-production well pattern as an example, we analyze the effects of start-up pressure gradient on low permeability reservoir micro-seepage and macro development dynamic trends. The research shows that, influenced by start-up pressure gradient effect, the low permeability reservoir seepage has a significant delayed effect, seepage velocity shows a“ladder shape”changing trend; the smaller the start-up pressure gradient, the higher of the initial oil production, but later the water cut rises up increasingly fast, leading to a much more obvious reduction of daily production; the greater the start-up pressure gradient, the lower the reservoir recovery degree, and along with the producing continues, it has greater influence on reservoir recovery degree.
Based on the generalized Darcy’s law, considering the effect of start-up pressure gradient, the permeability anisotropy of low permeability oil-water two phase seepage model is established herein. Based on the principle of virtual displacement, a finite element program is developed. Taking the Daqing Su301 fault block, a rectangular five-spot linear injection-production well pattern as an example, we analyze the effects of start-up pressure gradient on low permeability reservoir micro-seepage and macro development dynamic trends. The research shows that, influenced by start-up pressure gradient effect, the low permeability reservoir seepage has a significant delayed effect, seepage velocity shows a“ladder shape”changing trend; the smaller the start-up pressure gradient, the higher of the initial oil production, but later the water cut rises up increasingly fast, leading to a much more obvious reduction of daily production; the greater the start-up pressure gradient, the lower the reservoir recovery degree, and along with the producing continues, it has greater influence on reservoir recovery degree.
2013, 20(1):70-73.
Abstract:
Due to high viscosity, thin reservoir and the serious situation of steam channeling and overriding, it is urgent for Henan specific oil field to change its development pattern. Based on physical experiments and numerical simulation, the suitability of nitrogen-foam flooding is studied. As indicated in the experiments, it is beneficial to use foam static comprehensive evaluation index to unify the criteria of foam screening. Under the same condition of steam and foam injection parameters, compared with cold foam flooding,the oil production of unit foaming agent of hot foam flooding stays 24.4 percents higher. In the development of multi-layer co-injection and combined reservoir, start-up pressure of each layer is affected by foam injection pattern and permeability contrast. When injected with cold foam, the start pressure of each layer increases linearly along with the increase of permeability grade. But, for hot foam, this value increases in function of power. Because of permeability divergence, each layer’s contribution to the recovery percent is different,and to middle and low level permeability layers, foam has the similar producing degree. The optimized program of nitrogen-foam flooding is determined that the appropriate foaming injection mode is slug injection, and on the condition that the steam injection rate is 4.5 t/(d?m) and foaming agent mass concentration of 0.5%, the optimum injection volume is 0.01 PV; the optimum gas(steam)as(nitrogen) ratio is 20∶1; the optimum production factor is 1.3∶1 and the best foam spacing interval is 90 days.
Due to high viscosity, thin reservoir and the serious situation of steam channeling and overriding, it is urgent for Henan specific oil field to change its development pattern. Based on physical experiments and numerical simulation, the suitability of nitrogen-foam flooding is studied. As indicated in the experiments, it is beneficial to use foam static comprehensive evaluation index to unify the criteria of foam screening. Under the same condition of steam and foam injection parameters, compared with cold foam flooding,the oil production of unit foaming agent of hot foam flooding stays 24.4 percents higher. In the development of multi-layer co-injection and combined reservoir, start-up pressure of each layer is affected by foam injection pattern and permeability contrast. When injected with cold foam, the start pressure of each layer increases linearly along with the increase of permeability grade. But, for hot foam, this value increases in function of power. Because of permeability divergence, each layer’s contribution to the recovery percent is different,and to middle and low level permeability layers, foam has the similar producing degree. The optimized program of nitrogen-foam flooding is determined that the appropriate foaming injection mode is slug injection, and on the condition that the steam injection rate is 4.5 t/(d?m) and foaming agent mass concentration of 0.5%, the optimum injection volume is 0.01 PV; the optimum gas(steam)as(nitrogen) ratio is 20∶1; the optimum production factor is 1.3∶1 and the best foam spacing interval is 90 days.
2013, 20(1):74-76.
Abstract:
The non-Darcy unsteady seepage flow model containing moving boundary conditions in low-permeability reservoirs is highly nonlinear, and it is hard to obtain its accurate analytical solution. In this paper, the characteristics of the existence of threshold pressure gradient of the non-Darcy seepage flow is incorporated into the continuous equation, and then, the mathematical model of non-Darcy unsteady seepage flow is built, which can describe the characteristics of moving boundary in low-permeability reservoirs.However, it doesn’t contain any moving boundary conditions so as to be convenient for the numerical computation. The Douglas-Jones predictor-corrector method is masterly adopted to obtain the numerical solution of transient pressure of the model, and its accuracy is verified by the fixed-point iteration numerical method. Result analysis shows that the curve of transient wellbore pressure of the non-Darcy unsteady seepage flow model in low-permeability reservoirs is different from that of the classical Darcy seepage flow model.And, there is an inflexion in its curve. Before the inflexion, the moving boundary hasn’t arrived at the outer boundary with constant pressure yet, when the crude oil is produced by the elastic expansion of fluid and rock; after the inflexion, the moving boundary has propagated to the outer boundary with constant pressure, and the energy of the outer boundary with constant pressure is supplemented.
The non-Darcy unsteady seepage flow model containing moving boundary conditions in low-permeability reservoirs is highly nonlinear, and it is hard to obtain its accurate analytical solution. In this paper, the characteristics of the existence of threshold pressure gradient of the non-Darcy seepage flow is incorporated into the continuous equation, and then, the mathematical model of non-Darcy unsteady seepage flow is built, which can describe the characteristics of moving boundary in low-permeability reservoirs.However, it doesn’t contain any moving boundary conditions so as to be convenient for the numerical computation. The Douglas-Jones predictor-corrector method is masterly adopted to obtain the numerical solution of transient pressure of the model, and its accuracy is verified by the fixed-point iteration numerical method. Result analysis shows that the curve of transient wellbore pressure of the non-Darcy unsteady seepage flow model in low-permeability reservoirs is different from that of the classical Darcy seepage flow model.And, there is an inflexion in its curve. Before the inflexion, the moving boundary hasn’t arrived at the outer boundary with constant pressure yet, when the crude oil is produced by the elastic expansion of fluid and rock; after the inflexion, the moving boundary has propagated to the outer boundary with constant pressure, and the energy of the outer boundary with constant pressure is supplemented.
2013, 20(1):77-80.
Abstract:
In order to study the influence of polymer aging effect on oil recover during the transportation, the dynamic aging experiments of polymer are designed herein, and the results indicate that the mixture aging process is very similar to static aging process as usual, so, the traditional static aging process can be used to simulate the mixture aging process. By data analysis, the viscosity estimation of polymer after mixing has been proposed. The maximum difference is under 1 mPa?s comparing with actual measurement. On the basis of that, the corresponding algorithm of numerical simulation has been given. The Calculation results indicate that, the aging effect of polymer solution has great influence on oil recovery. Therefore, the effect is needed to be considered in numerical simulation, and thermal stability is needed to be estimated in reservoir development
In order to study the influence of polymer aging effect on oil recover during the transportation, the dynamic aging experiments of polymer are designed herein, and the results indicate that the mixture aging process is very similar to static aging process as usual, so, the traditional static aging process can be used to simulate the mixture aging process. By data analysis, the viscosity estimation of polymer after mixing has been proposed. The maximum difference is under 1 mPa?s comparing with actual measurement. On the basis of that, the corresponding algorithm of numerical simulation has been given. The Calculation results indicate that, the aging effect of polymer solution has great influence on oil recovery. Therefore, the effect is needed to be considered in numerical simulation, and thermal stability is needed to be estimated in reservoir development
2013, 20(1):81-84.
Abstract:
Depletion exploitation of deep heavy oil reservoir with water sensitivity is not effective, so, how to choose an effective method to development deep heavy oil reservoir with water sensitivity and further improve the recovery are the technical problems urgently needed to be solved. Starting from the reservoir features, and based on injected water damage, anti-swelling agent, swelling and other physical evaluation experiments, the feasibility argumentation and optimization calculation of many recovery methods such as depletion exploitation, conventional water flooding, huff and puff of nitrogen and gas, gas flooding after huff and puff, gas flooding are carried out by reservoir simulation. Studies have shown that water injection will reduce reservoir permeability significantly. Anti-swelling agents can improve the water injection performance, but poorer than gas injection. The gas flooding after huff and puff is the best model for development of deep heavy oil reservoir with water sensitivity economically and technologically. Compared with depletion exploitation,the recovery percent of gas flooding after huff and puff rises by 19.6% and the cumulative oil production of gas flooding after huff and puff increases by 98 203.66 m3 in ten years. Research findings can provide a reference for this kind of reservoir.
Depletion exploitation of deep heavy oil reservoir with water sensitivity is not effective, so, how to choose an effective method to development deep heavy oil reservoir with water sensitivity and further improve the recovery are the technical problems urgently needed to be solved. Starting from the reservoir features, and based on injected water damage, anti-swelling agent, swelling and other physical evaluation experiments, the feasibility argumentation and optimization calculation of many recovery methods such as depletion exploitation, conventional water flooding, huff and puff of nitrogen and gas, gas flooding after huff and puff, gas flooding are carried out by reservoir simulation. Studies have shown that water injection will reduce reservoir permeability significantly. Anti-swelling agents can improve the water injection performance, but poorer than gas injection. The gas flooding after huff and puff is the best model for development of deep heavy oil reservoir with water sensitivity economically and technologically. Compared with depletion exploitation,the recovery percent of gas flooding after huff and puff rises by 19.6% and the cumulative oil production of gas flooding after huff and puff increases by 98 203.66 m3 in ten years. Research findings can provide a reference for this kind of reservoir.
2013, 20(1):85-88.
Abstract:
Water drive curve and decline curve method for reserves estimation have the problems of time-lagging and hard to reflect the additional reserves increased by adjustment well. By analyzing oil well performance index and applying reservoir engineering and statistics method, it can be found either from theory or field test that the initial rate and decline rate are two main influencing factors for oil well EUR, and the controlling factor for decline rate are reservoir type, single well controlled reserves, initial water content, liquid production and its fluctuation with watercut level. we have correlated decline rate with its’controlling factor and established 19 calculating models for single well EUR which cover reservoir types as water drive, heavy oil, high and low permeability and different well types including straight and horizontal well. An example shows that, using these forecasting models can predict the EUR of new wells promptly and simply with dynamic data such as initial rate.
Water drive curve and decline curve method for reserves estimation have the problems of time-lagging and hard to reflect the additional reserves increased by adjustment well. By analyzing oil well performance index and applying reservoir engineering and statistics method, it can be found either from theory or field test that the initial rate and decline rate are two main influencing factors for oil well EUR, and the controlling factor for decline rate are reservoir type, single well controlled reserves, initial water content, liquid production and its fluctuation with watercut level. we have correlated decline rate with its’controlling factor and established 19 calculating models for single well EUR which cover reservoir types as water drive, heavy oil, high and low permeability and different well types including straight and horizontal well. An example shows that, using these forecasting models can predict the EUR of new wells promptly and simply with dynamic data such as initial rate.
2013, 20(1):89-91.
Abstract:
In response to the problem of water cut rising rapidly during the development of horizontal wells, a system of 3-D physical model for horizontal wells in reservoirs with bottom water is established. The position and development process of water crest are studied, which include many factors such as pressure loss along the wellbore, well track changes and reservoir heterogeneity. Results of the study indicates that the wellbore pressure drop has significant impact on the water crest, which causes the water cresting at the heel end of the well and breaking through earlier obviously. The well track changes and reservoir heterogeneity are both sensible factor to the water crest, which determines the water crest position combined with wellbore pressure drop. The bottom water tends to break through at the concave down part of the horizontal well. If the concave down part appears near the heel end of the well, one water crest will form at the heel with less swept area. While when the concave down part appears far away from the heel end, there would be several water crests in the model with more swept area. Bottom water will break through at the higher permeability part in the heterogeneous model.While putting the heel end at the lower permeability area would make the water crest distribute on the horizontal plane. The development of water crest influences the performance after water breakthrough. A concave down part adjacent to the heel end can accelerate the progress of the water crest, which leads to the earliest breakthrough time and fastest water cut rising. A concave down part that departs from the heel end can make the water crest grow slower. Reservoir heterogeneity accelerates the water cresting. While fixing heel end at the lower permeability area offsets the negative effect of heterogeneity, which may postpone the breakthrough time and lower the water cut rising.
In response to the problem of water cut rising rapidly during the development of horizontal wells, a system of 3-D physical model for horizontal wells in reservoirs with bottom water is established. The position and development process of water crest are studied, which include many factors such as pressure loss along the wellbore, well track changes and reservoir heterogeneity. Results of the study indicates that the wellbore pressure drop has significant impact on the water crest, which causes the water cresting at the heel end of the well and breaking through earlier obviously. The well track changes and reservoir heterogeneity are both sensible factor to the water crest, which determines the water crest position combined with wellbore pressure drop. The bottom water tends to break through at the concave down part of the horizontal well. If the concave down part appears near the heel end of the well, one water crest will form at the heel with less swept area. While when the concave down part appears far away from the heel end, there would be several water crests in the model with more swept area. Bottom water will break through at the higher permeability part in the heterogeneous model.While putting the heel end at the lower permeability area would make the water crest distribute on the horizontal plane. The development of water crest influences the performance after water breakthrough. A concave down part adjacent to the heel end can accelerate the progress of the water crest, which leads to the earliest breakthrough time and fastest water cut rising. A concave down part that departs from the heel end can make the water crest grow slower. Reservoir heterogeneity accelerates the water cresting. While fixing heel end at the lower permeability area offsets the negative effect of heterogeneity, which may postpone the breakthrough time and lower the water cut rising.
2013, 20(1):92-95.
Abstract:
Low permeability reservoir has a lower permeability, hydraulic fracturing is often used to improve the productivity of the well. The evaluation of the productivity of fracturing well is essential to the development of the low permeability reservoir. On the basis of a new model which describes the low-velocity nonlinear seepage law, the formulas are established for the vertical fractured wells with both infinite and finite conductivity. A comparison and analysis are made on productivity between Darcy’s model and start-up pressure gradient model. The results show that there are some differences on productivity only under very low production pressure difference, and with the pressure difference increasing, and the fracturing well productivity predicted by three models becomes almost same. The productivity of fracture with finite conductivity that is equivalent to the vertical well productivity makes it easy for engineering practice. Results show that the equivalent vertical well radius increases with dimensionless conductivity increasing and decreasing of dimensionless oil drainage radius.
Low permeability reservoir has a lower permeability, hydraulic fracturing is often used to improve the productivity of the well. The evaluation of the productivity of fracturing well is essential to the development of the low permeability reservoir. On the basis of a new model which describes the low-velocity nonlinear seepage law, the formulas are established for the vertical fractured wells with both infinite and finite conductivity. A comparison and analysis are made on productivity between Darcy’s model and start-up pressure gradient model. The results show that there are some differences on productivity only under very low production pressure difference, and with the pressure difference increasing, and the fracturing well productivity predicted by three models becomes almost same. The productivity of fracture with finite conductivity that is equivalent to the vertical well productivity makes it easy for engineering practice. Results show that the equivalent vertical well radius increases with dimensionless conductivity increasing and decreasing of dimensionless oil drainage radius.
2013, 20(1):96-99.
Abstract:
Taking bottom water H oilfield in Sudan for example, various rhythm bottom-water reservoir numerical models are established, and the effect of inter-bed size, height and location on development performance is studied, and the technology strategy is pointed out herein. The result shows that the inter-bed is helpful to improve the development performance, and the effect of water cut control is improved with the increment of inter-bed radius; and the height of inter-bed has a few effect on development performance; and the good water cut control effect is obtained in positive rhythm reservoir during low water-cut stage and in reverse rhythm during high water water-cut stage; the inter-bed located on the area near the water-oil-contact and multi-inter-bed in bottom-water reservoir show great performance; and the remaining oil is mainly located on the area between and under the inter-bed. The development technique strategy of various rhythm bottom-water reservoirs for controlling water coning is proposed, such as the perforation optimization by making full use of inter-bed, off-take rate optimization by controlling vertical-horizontal permeability ratio, and artificial inter-bed implementation and so on. The development practice of H oilfield shows great performance using optimization completion technique after making full use of inter-bed and deploying horizontal well.
Taking bottom water H oilfield in Sudan for example, various rhythm bottom-water reservoir numerical models are established, and the effect of inter-bed size, height and location on development performance is studied, and the technology strategy is pointed out herein. The result shows that the inter-bed is helpful to improve the development performance, and the effect of water cut control is improved with the increment of inter-bed radius; and the height of inter-bed has a few effect on development performance; and the good water cut control effect is obtained in positive rhythm reservoir during low water-cut stage and in reverse rhythm during high water water-cut stage; the inter-bed located on the area near the water-oil-contact and multi-inter-bed in bottom-water reservoir show great performance; and the remaining oil is mainly located on the area between and under the inter-bed. The development technique strategy of various rhythm bottom-water reservoirs for controlling water coning is proposed, such as the perforation optimization by making full use of inter-bed, off-take rate optimization by controlling vertical-horizontal permeability ratio, and artificial inter-bed implementation and so on. The development practice of H oilfield shows great performance using optimization completion technique after making full use of inter-bed and deploying horizontal well.
2013, 20(1):100-103.
Abstract:
In western slope of Jinhu depression in Subei Basin, there is a set of lacustrine carbonate rocks that its oil storage ability is quite good. Because of the influence of nonuniform dissolution, the reservoir’s plane heterogeneity is serious. Local area has much bigger pores, but the pores’connectivity is poor. So, the permeability of the reservoir is low. Oil wells show completely different production characteristics from those wells which in sandstone reservoirs. In lacustrine carbonate reservoir, the wells’natural capacity is low and their productions have a large extent of improving after being acidified; the productions of wells in different locations are quite different; the water cut is very high in initial production stage; and there are two forms of production decline: conventional decline and mutational decline. Based on the analysis of testing, production test information and production performance data, and further studying on the influence factors of production capacity, we summarize that the reservoir total effective thickness and reservoir effective seepage radius of single well are two major factors for oil wells yielding, and further determine the screening conditions of reservoir which will put into production. According to lacustrine carbonate reservoir characteristics, the development technical measures of acidification, fracturing, sidetracking well, horizontal well and multi-lateral horizontal well are accordingly proposed.
In western slope of Jinhu depression in Subei Basin, there is a set of lacustrine carbonate rocks that its oil storage ability is quite good. Because of the influence of nonuniform dissolution, the reservoir’s plane heterogeneity is serious. Local area has much bigger pores, but the pores’connectivity is poor. So, the permeability of the reservoir is low. Oil wells show completely different production characteristics from those wells which in sandstone reservoirs. In lacustrine carbonate reservoir, the wells’natural capacity is low and their productions have a large extent of improving after being acidified; the productions of wells in different locations are quite different; the water cut is very high in initial production stage; and there are two forms of production decline: conventional decline and mutational decline. Based on the analysis of testing, production test information and production performance data, and further studying on the influence factors of production capacity, we summarize that the reservoir total effective thickness and reservoir effective seepage radius of single well are two major factors for oil wells yielding, and further determine the screening conditions of reservoir which will put into production. According to lacustrine carbonate reservoir characteristics, the development technical measures of acidification, fracturing, sidetracking well, horizontal well and multi-lateral horizontal well are accordingly proposed.
2013, 20(1):104-106.
Abstract:
The water control mechanism of relative permeability modifier (RPM) are studied with molecular simulation technology and core flow apparatus for further study at molecular level, and then building the dynamic model of oil(n-hexadecane)/water mixed phase passing the RPM-laden SiO2 surface. The model shows that the RPM has swelling state in water phase, but contracting in oil(n-hexadecane) phase. The ratio of oil(n-hexadecane)/water mixed phase diffusion coefficient is 4.2, it is equal to the experimental data based on core flow apparatus. The water control mechanism of relative permeability modifier(RPM) can be explained by swelling-contracting mechanism and oil-water fluid partitioning mechanism.
The water control mechanism of relative permeability modifier (RPM) are studied with molecular simulation technology and core flow apparatus for further study at molecular level, and then building the dynamic model of oil(n-hexadecane)/water mixed phase passing the RPM-laden SiO2 surface. The model shows that the RPM has swelling state in water phase, but contracting in oil(n-hexadecane) phase. The ratio of oil(n-hexadecane)/water mixed phase diffusion coefficient is 4.2, it is equal to the experimental data based on core flow apparatus. The water control mechanism of relative permeability modifier(RPM) can be explained by swelling-contracting mechanism and oil-water fluid partitioning mechanism.
2013, 20(1):107-110.
Abstract:
Considering the pore pressure variation of sidewall rock, which is caused by drilling fluid filtering, and additional stress and strain which is caused by temperature difference between drilling fluid and formation rock, the theoretical model of variation of porosity, which has considered variation of pore pressure and temperature difference, is derived, and the calculation model of safe window of drilling fluid density in deep well, which has considered variation of porosity, temperature difference and pore pressure, is finally established. Application of this calculation model shows that: when temperature difference between sidewall rock and drilling fluid in deep well is definite, with increased function of drilling fluid filtering, as increased as pore pressure of sidewall rock, the caving pressure is increased, fracturing pressure is decreased, safe window of drilling fluid density is narrowing, and unfavorable for safety drilling; and when pore pressure of sidewall rock is definite, if drilling fluid lower the temperature of sidewall rock, then as increased as temperature difference, the caving pressure is decreased, fracturing pressure is increased, safe window of drilling fluid density is widen, and favorable for the safe drilling. Moreover, if drilling fluid rises the temperature of sidewall rock, then as increased as temperature difference,the caving pressure is increased, fracturing pressure is decreased, safe window of drilling fluid density is narrowing, and unfavorable for the safety drilling. In this paper, the effects of drilling fluid filtering and temperature difference between drilling fluid and formation rock on safe window of drilling fluid density are theoretically explained, which is a of significance to the present calculation model of safe window of drilling fluid density.
Considering the pore pressure variation of sidewall rock, which is caused by drilling fluid filtering, and additional stress and strain which is caused by temperature difference between drilling fluid and formation rock, the theoretical model of variation of porosity, which has considered variation of pore pressure and temperature difference, is derived, and the calculation model of safe window of drilling fluid density in deep well, which has considered variation of porosity, temperature difference and pore pressure, is finally established. Application of this calculation model shows that: when temperature difference between sidewall rock and drilling fluid in deep well is definite, with increased function of drilling fluid filtering, as increased as pore pressure of sidewall rock, the caving pressure is increased, fracturing pressure is decreased, safe window of drilling fluid density is narrowing, and unfavorable for safety drilling; and when pore pressure of sidewall rock is definite, if drilling fluid lower the temperature of sidewall rock, then as increased as temperature difference, the caving pressure is decreased, fracturing pressure is increased, safe window of drilling fluid density is widen, and favorable for the safe drilling. Moreover, if drilling fluid rises the temperature of sidewall rock, then as increased as temperature difference,the caving pressure is increased, fracturing pressure is decreased, safe window of drilling fluid density is narrowing, and unfavorable for the safety drilling. In this paper, the effects of drilling fluid filtering and temperature difference between drilling fluid and formation rock on safe window of drilling fluid density are theoretically explained, which is a of significance to the present calculation model of safe window of drilling fluid density.
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