Volume 21,Issue 3,2014 Table of Contents
2014, 21(3):1-5.
Abstract:
Dongying depression of Paleogene period broadly develops continental facies with red bed deposition from the first member of the Kongdian formation to the forth member of the Shahejie formation. According to statistics on the reservoir geological characteristics and distribution rules of Boxing area, it can be found that the four functional elements of the formation and distribution of oil and gas reservoirs are hydrocarbon source rocks (S), reservoir conditions (R), migration condition (M), preservation condition (P). This paper classifies the effective indexes that have influenced on the four functional factors controlling probability of oil and gas distribution, the capability index model of function elements including the capability index of hydrocarbon source rock (Si), the capacity index of reservoir storage (Ri), the capacity index of migration (Mi), and preserving ability index (Pi). The results show that, Si is the normalized result of the expulsion intensity of hydrocarbon (qe); and Ri is the normalized result of effective storage thickness (H); and Mi is the normalized result of the fluid potential, sand ratio, and the migration efficiency of the fault; the Pi is the normalized result of the product of the displacement pressure and the thickness of cover. And, based on that, this paper uses four capability index models of function elements and quantitatively evaluates the control probability function of a single element, eventually, it comprises four functional elements on the temporal and spatial domain, and gives weight coefficient to different function elements by weighted average, and then a probability index model of effective accumulation (SRMP) is set up. Using the calculation results of this model tests, the distribution of reservoir that has been founded, and the coupling results accord well with the current exploration situation.
Dongying depression of Paleogene period broadly develops continental facies with red bed deposition from the first member of the Kongdian formation to the forth member of the Shahejie formation. According to statistics on the reservoir geological characteristics and distribution rules of Boxing area, it can be found that the four functional elements of the formation and distribution of oil and gas reservoirs are hydrocarbon source rocks (S), reservoir conditions (R), migration condition (M), preservation condition (P). This paper classifies the effective indexes that have influenced on the four functional factors controlling probability of oil and gas distribution, the capability index model of function elements including the capability index of hydrocarbon source rock (Si), the capacity index of reservoir storage (Ri), the capacity index of migration (Mi), and preserving ability index (Pi). The results show that, Si is the normalized result of the expulsion intensity of hydrocarbon (qe); and Ri is the normalized result of effective storage thickness (H); and Mi is the normalized result of the fluid potential, sand ratio, and the migration efficiency of the fault; the Pi is the normalized result of the product of the displacement pressure and the thickness of cover. And, based on that, this paper uses four capability index models of function elements and quantitatively evaluates the control probability function of a single element, eventually, it comprises four functional elements on the temporal and spatial domain, and gives weight coefficient to different function elements by weighted average, and then a probability index model of effective accumulation (SRMP) is set up. Using the calculation results of this model tests, the distribution of reservoir that has been founded, and the coupling results accord well with the current exploration situation.
2014, 21(3):6-9.
Abstract:
Mixed sediments of carbonate and clastic origin are widely developed in Shiniulan formation of lower Silurian, southeast of Chongqing. Taking the typical Shiniulan profile as the study object, through the field observations, thin section analysis, isotope analysis and other means, the mixed sediments and the constraints on the reef of Siniulan formation are studied. The results show that, there mainly developed argillaceous limestone and sandy mudstone, micritic limestone and mudstone, biological limestone and lime mudstone, which have formed three diamictic strata. There develops the argillaceous limestone, sandy limestone, silty clay limestone, silty reef limestone (biogenic limestone), gray siltstone, lime mudstone, that is, six kinds of gray diamictites. In Siniulan formation, the depositional environments are mainly early shallow mixed continental shelf, that is, interim reef deposits-advanced reef slope sedimentary evolution, and the terrigeneous content reduces from bottom to top in the overall process, and the mixed deposition occurs mainly in shallow mixed continental shelf and reef and beach/ramp, two depositional environments. It is confirmed that, in the Shiniulan reef development process, the injected terrigeneous debris is the major cause which has constrained the development of the reef and the biological communities.
Mixed sediments of carbonate and clastic origin are widely developed in Shiniulan formation of lower Silurian, southeast of Chongqing. Taking the typical Shiniulan profile as the study object, through the field observations, thin section analysis, isotope analysis and other means, the mixed sediments and the constraints on the reef of Siniulan formation are studied. The results show that, there mainly developed argillaceous limestone and sandy mudstone, micritic limestone and mudstone, biological limestone and lime mudstone, which have formed three diamictic strata. There develops the argillaceous limestone, sandy limestone, silty clay limestone, silty reef limestone (biogenic limestone), gray siltstone, lime mudstone, that is, six kinds of gray diamictites. In Siniulan formation, the depositional environments are mainly early shallow mixed continental shelf, that is, interim reef deposits-advanced reef slope sedimentary evolution, and the terrigeneous content reduces from bottom to top in the overall process, and the mixed deposition occurs mainly in shallow mixed continental shelf and reef and beach/ramp, two depositional environments. It is confirmed that, in the Shiniulan reef development process, the injected terrigeneous debris is the major cause which has constrained the development of the reef and the biological communities.
2014, 21(3):10-14.
Abstract:
In order to clarify the problem of oil-gas source, and by means of the total hydrocarbon chromatography analysis and thermal evaporation hydrocarbon chromatography analysis of crude oils and oil sands, we discover that, there are similar light hydrocarbon geochemical characteristics between northern heavy oil and southern light oil. Its original organic matters are all sapropelic and the crude oils are all mature reflected by light hydrocarbon. Taking account of the fact that the light hydrocarbon characteristics of different type oil are similar, it is concluded that the light weight fractions of early charged oils are dissipated or degraded, and the light weight fractions of present heavy and light oil are mainly from the late charged oils, so the present oils show the characteristic of late charged oils.The source rocks of late charged oil in this area are rich in lower hydrobios. Based on the correlation of source rocks in Junggar Basin,it is concluded that, the late charged crude oil is derived from Permian source rocks of Changji sag.
In order to clarify the problem of oil-gas source, and by means of the total hydrocarbon chromatography analysis and thermal evaporation hydrocarbon chromatography analysis of crude oils and oil sands, we discover that, there are similar light hydrocarbon geochemical characteristics between northern heavy oil and southern light oil. Its original organic matters are all sapropelic and the crude oils are all mature reflected by light hydrocarbon. Taking account of the fact that the light hydrocarbon characteristics of different type oil are similar, it is concluded that the light weight fractions of early charged oils are dissipated or degraded, and the light weight fractions of present heavy and light oil are mainly from the late charged oils, so the present oils show the characteristic of late charged oils.The source rocks of late charged oil in this area are rich in lower hydrobios. Based on the correlation of source rocks in Junggar Basin,it is concluded that, the late charged crude oil is derived from Permian source rocks of Changji sag.
2014, 21(3):15-19.
Abstract:
The sub-layer lower NmⅠ3 in the south area of QHD32-6 oilfield is a multi-staged channel sand, therefore, how to correlate it into single stage is important for its development potential. Using the high resolution sequence stratigraphy, the different-staged channel sand can be identified and correlated. There are main 3 stacking patterns, which are superimposition type, cutting type and single channel type. Furthermore, the characteristics of micro-facies within the single-stage sand and interbed distribution can be studied. The tracer in experimental well group shows that, the driving rate of waterflooding front from one stage sand body to another is lower than the value in the same-staged sand body where there is also a discrepancy because of the change of microfacies. This paper con? cludes that, for the multi-staged channel sand, the stacking patterns, changing microfacies and interbeds distribution are the main factors effecting production performance. Meanwhile, which one is the most important among those factors depends on the relationship between the two sand bodies within which the injector and producer layers are located.
The sub-layer lower NmⅠ3 in the south area of QHD32-6 oilfield is a multi-staged channel sand, therefore, how to correlate it into single stage is important for its development potential. Using the high resolution sequence stratigraphy, the different-staged channel sand can be identified and correlated. There are main 3 stacking patterns, which are superimposition type, cutting type and single channel type. Furthermore, the characteristics of micro-facies within the single-stage sand and interbed distribution can be studied. The tracer in experimental well group shows that, the driving rate of waterflooding front from one stage sand body to another is lower than the value in the same-staged sand body where there is also a discrepancy because of the change of microfacies. This paper con? cludes that, for the multi-staged channel sand, the stacking patterns, changing microfacies and interbeds distribution are the main factors effecting production performance. Meanwhile, which one is the most important among those factors depends on the relationship between the two sand bodies within which the injector and producer layers are located.
2014, 21(3):20-23.
Abstract:
In order to meet the requirements of oilfield production in the late exploration period, fine tectonic units are divided in Xingbei district, by means of regional seismic data, dip variation and three-dimensional structure. Based on the condition that the position of anticlinal axis is accurately located, the Xingbei district has been divided into four tectonic units, including northwest slope area,southwest slope area, central anticline belt and east gentle slope belt. This classification can reasonably explain the hydrocarbon accumulation characteristics in Fuyu oil reservoir, so it is of great importance for petroleum geology in the following four aspects: ①northwest slope area tends to develop mature hydrocarbon source rocks in northwestern area, its hydrocarbon migration direction is parallel to the fault strike, so this area is unfavorable for oil and gas accumulation; ② southwest slope area tends to be in high hydrocarbon expulsion intensity area in the southwestern area, its hydrocarbon migration direction is vertical to the fault strike, so footwall of reverse fault in this area is favorable for oil and gas accumulating; ③ the structure ridge of central anticline belt is the high speed passway for hydrocarbon, so the traps adjacent to oil resource on both sides can be the main petroleum accumulation region; ④ east gentle slope belt is far away from the oil resource, with no migration passway, so this area can’t accumulate hydrocarbon. On the basis of those features, the well placement can be designed differently in various areas to reduce the risks of exploration.
In order to meet the requirements of oilfield production in the late exploration period, fine tectonic units are divided in Xingbei district, by means of regional seismic data, dip variation and three-dimensional structure. Based on the condition that the position of anticlinal axis is accurately located, the Xingbei district has been divided into four tectonic units, including northwest slope area,southwest slope area, central anticline belt and east gentle slope belt. This classification can reasonably explain the hydrocarbon accumulation characteristics in Fuyu oil reservoir, so it is of great importance for petroleum geology in the following four aspects: ①northwest slope area tends to develop mature hydrocarbon source rocks in northwestern area, its hydrocarbon migration direction is parallel to the fault strike, so this area is unfavorable for oil and gas accumulation; ② southwest slope area tends to be in high hydrocarbon expulsion intensity area in the southwestern area, its hydrocarbon migration direction is vertical to the fault strike, so footwall of reverse fault in this area is favorable for oil and gas accumulating; ③ the structure ridge of central anticline belt is the high speed passway for hydrocarbon, so the traps adjacent to oil resource on both sides can be the main petroleum accumulation region; ④ east gentle slope belt is far away from the oil resource, with no migration passway, so this area can’t accumulate hydrocarbon. On the basis of those features, the well placement can be designed differently in various areas to reduce the risks of exploration.
2014, 21(3):24-27.
Abstract:
Halahatang area is located in the northern Tarim Basin that is an important oil and gas exploration area. With the further exploration, plenty of oil and gas resources are discovered, but the complexity of distribution of oil and water, and the uncertainty of the reservoir characteristics and the main control factors seriously restricted the oil and gas exploration and development in the study area.Based on the analysis of Ha11 well block in Halahatang oilfield, we study the reservoir characteristics and main controlling factors in Halahatang area. It can be divided into two fracture-cavity belts in Ha11 well block: the Ha11 fracture-cavity belt and Ha12 fracturecavity belt. The Ha11 fracture-cavity belt is overall oil, and the drilling success rate is high with more efficient wells. But the Ha12 fracture-cavity belt is low in drilling success rate, and has a larger proportion of failure wells with abundant water. Analysis of the structure characteristics, formation characteristics, phase characteristics, fluid property variation characteristics, faults and reservoir types of the study area, we summarize the reasons accounting for the oil-water distribution differences between these 2 fracture-cavity belts in study area. The results show that the Ha11 fracture-cavity belt and the Ha12 fracture-cavity belt are similar in structure characteristic,formation characteristics and fluid property variation characteristics, and are all the same unsaturated oil reservoirs. But through the comparative analysis, the Ha11 fracture-cavity belt is mainly controlled by NW early-middle Caledonian large strike-slips and its small auxiliary faults. The Ha12 fracture-cavity belt is mainly controlled by NE early-middle Caledonian large strike-slips and its small auxiliary faults. So, that is why Ha11 well block was divided into two fracture-cavity belts, two oil-water systems. In addition, the relative level of structure and the reservoir types are also an important reason to cause these two fracture-cavity belts with different oilwater distributions.
Halahatang area is located in the northern Tarim Basin that is an important oil and gas exploration area. With the further exploration, plenty of oil and gas resources are discovered, but the complexity of distribution of oil and water, and the uncertainty of the reservoir characteristics and the main control factors seriously restricted the oil and gas exploration and development in the study area.Based on the analysis of Ha11 well block in Halahatang oilfield, we study the reservoir characteristics and main controlling factors in Halahatang area. It can be divided into two fracture-cavity belts in Ha11 well block: the Ha11 fracture-cavity belt and Ha12 fracturecavity belt. The Ha11 fracture-cavity belt is overall oil, and the drilling success rate is high with more efficient wells. But the Ha12 fracture-cavity belt is low in drilling success rate, and has a larger proportion of failure wells with abundant water. Analysis of the structure characteristics, formation characteristics, phase characteristics, fluid property variation characteristics, faults and reservoir types of the study area, we summarize the reasons accounting for the oil-water distribution differences between these 2 fracture-cavity belts in study area. The results show that the Ha11 fracture-cavity belt and the Ha12 fracture-cavity belt are similar in structure characteristic,formation characteristics and fluid property variation characteristics, and are all the same unsaturated oil reservoirs. But through the comparative analysis, the Ha11 fracture-cavity belt is mainly controlled by NW early-middle Caledonian large strike-slips and its small auxiliary faults. The Ha12 fracture-cavity belt is mainly controlled by NE early-middle Caledonian large strike-slips and its small auxiliary faults. So, that is why Ha11 well block was divided into two fracture-cavity belts, two oil-water systems. In addition, the relative level of structure and the reservoir types are also an important reason to cause these two fracture-cavity belts with different oilwater distributions.
2014, 21(3):28-32.
Abstract:
There are low-gamma ray mudstones present in V oil zone of Bi 125 block, and the natural gamma ray of effective reservoirs has a wide range which crosses with that of ineffective reservoirs; the reservoirs are shallow, the salinity of formation water is low, the amplitude anomaly of self-potential is minor and the self-potential of effective reservoirs also has a wide range and its range crosses with that of invalid reservoirs. These two curves of identifying lithology are both or partially invalid, which makes it difficult to identify the effective reservoirs in the area. According to the fact that there is no low limit of logging curves to determine effective reservoirs of the objective intervals, the geological factors causing the complex phenomenon have been studied, and together with the actual data, integrated with the useful information contained in a variety of logging data, then, the models appropriate for the area have been established, including models of natural gamma amplitude anomaly marginal limits, self-potential amplitude anomaly marginal limits and invalid reservoirs removal. The application of these models makes the logging interpretation of effective reservoirs in the area possible and turns the adverse situation that the identification of effective reservoirs could only depend on coring and borehole log. With the application of the newly-established marginal reservoir identification model, 108 wells in the area have been reinterpreted, and 37 oil layers, up to 26.4 m thick, have been added; moreover, the misinterpreted 18 oil layers, 15.6 m thick, have been removed; and the thickness of numerous pre-interpreted oil layers has been corrected. The established identification models of complex-lithology effective reservoirs are suitable for the fast-deposited fan deltaic system and are expected to be applied to other fast-deposited systems such as alluvial fan and subsea apron.
There are low-gamma ray mudstones present in V oil zone of Bi 125 block, and the natural gamma ray of effective reservoirs has a wide range which crosses with that of ineffective reservoirs; the reservoirs are shallow, the salinity of formation water is low, the amplitude anomaly of self-potential is minor and the self-potential of effective reservoirs also has a wide range and its range crosses with that of invalid reservoirs. These two curves of identifying lithology are both or partially invalid, which makes it difficult to identify the effective reservoirs in the area. According to the fact that there is no low limit of logging curves to determine effective reservoirs of the objective intervals, the geological factors causing the complex phenomenon have been studied, and together with the actual data, integrated with the useful information contained in a variety of logging data, then, the models appropriate for the area have been established, including models of natural gamma amplitude anomaly marginal limits, self-potential amplitude anomaly marginal limits and invalid reservoirs removal. The application of these models makes the logging interpretation of effective reservoirs in the area possible and turns the adverse situation that the identification of effective reservoirs could only depend on coring and borehole log. With the application of the newly-established marginal reservoir identification model, 108 wells in the area have been reinterpreted, and 37 oil layers, up to 26.4 m thick, have been added; moreover, the misinterpreted 18 oil layers, 15.6 m thick, have been removed; and the thickness of numerous pre-interpreted oil layers has been corrected. The established identification models of complex-lithology effective reservoirs are suitable for the fast-deposited fan deltaic system and are expected to be applied to other fast-deposited systems such as alluvial fan and subsea apron.
2014, 21(3):33-35.
Abstract:
A new surface constrain modeling method is proposed herein for the lateral accretion shale beds of point bar sand by using Petrel. In order to characterize the internal configuration of point bar, top and bottom boundaries of the lateral accretion shale beds distributing with curved surface are created based on the patterns and analysis results of point bar architecture, then the reservoir architecture model is established in the point bar sand by the method of multi-order surface constrain. For ease of numerical reservoir simulation, we designed the method of nonuniform grid upscaling to ensure the accuracy of the laterally-accreted mudstone model and reduce the grids. Then, the validity of the modeling method is validated in a point bar sand of Dagang oilfield. The results show that the modeling can reflect the spatial distribution of different levels of architectural element such as channel sand body, point bar and lateral accretion interbeds, and the result can characterize the internal configuration of point bar and reflect the actual situation in the reservoir.
A new surface constrain modeling method is proposed herein for the lateral accretion shale beds of point bar sand by using Petrel. In order to characterize the internal configuration of point bar, top and bottom boundaries of the lateral accretion shale beds distributing with curved surface are created based on the patterns and analysis results of point bar architecture, then the reservoir architecture model is established in the point bar sand by the method of multi-order surface constrain. For ease of numerical reservoir simulation, we designed the method of nonuniform grid upscaling to ensure the accuracy of the laterally-accreted mudstone model and reduce the grids. Then, the validity of the modeling method is validated in a point bar sand of Dagang oilfield. The results show that the modeling can reflect the spatial distribution of different levels of architectural element such as channel sand body, point bar and lateral accretion interbeds, and the result can characterize the internal configuration of point bar and reflect the actual situation in the reservoir.
2014, 21(3):36-40.
Abstract:
The conglomerate reserves abundant heavy oil in Luojia and Kenxi area, Bonan sub-sag. By analyzing drilling, logging and kinds of analytical data in detail, their sedimentary characteristics are studied herein. The study shows that, the conglomerates are subaqueous alluvial fan and fan delta. The subaqueous alluvial fan in Luojia area is developed in a background of ancient landform, and driven by gravity flow. The conglomerate is developed within it primarily, and its structure type mainly contains coarse complex matrix and mixed matrix. Its probability cumulative grain-size curves are mainly one-part form. The fining-upward normal-cycle phase sequence is developed. The fan delta in Kenxi area is developed in a background of shallow-lake flat slope sediments and controlled by the boundary fault, it has a dual-flow mechanism of gravity flow and tractive flow, and the pebbly sandstone is developed within it primarily, and its structure type mainly contains supported grain. Its probability cumulative grain-size curves are mainly two-part form and three-part form. The coarsening-upward inverse-cycle phase sequence is developed. Their reservoir capabilities, oil saturation and fluid kinematical character during exploitation have large discrepancy, and it is the different sedimentary model that have controlled the above discrepancy in fan delta of Luojia area and subaqueous alluvial fan of Kenxi area.
The conglomerate reserves abundant heavy oil in Luojia and Kenxi area, Bonan sub-sag. By analyzing drilling, logging and kinds of analytical data in detail, their sedimentary characteristics are studied herein. The study shows that, the conglomerates are subaqueous alluvial fan and fan delta. The subaqueous alluvial fan in Luojia area is developed in a background of ancient landform, and driven by gravity flow. The conglomerate is developed within it primarily, and its structure type mainly contains coarse complex matrix and mixed matrix. Its probability cumulative grain-size curves are mainly one-part form. The fining-upward normal-cycle phase sequence is developed. The fan delta in Kenxi area is developed in a background of shallow-lake flat slope sediments and controlled by the boundary fault, it has a dual-flow mechanism of gravity flow and tractive flow, and the pebbly sandstone is developed within it primarily, and its structure type mainly contains supported grain. Its probability cumulative grain-size curves are mainly two-part form and three-part form. The coarsening-upward inverse-cycle phase sequence is developed. Their reservoir capabilities, oil saturation and fluid kinematical character during exploitation have large discrepancy, and it is the different sedimentary model that have controlled the above discrepancy in fan delta of Luojia area and subaqueous alluvial fan of Kenxi area.
2014, 21(3):41-44.
Abstract:
This paper presents a three-dimension (3D) fluid potential method based on Hubbert fluid potential model and 3D pore pressure. First, combing 3D interval velocity data which is inverted through log-constrained seismic inversion and well logging data, it can obtain the 3D pore pressure based on spatial interpolation method and the single point hypothesis. Then, we calculate the 3D fluid potential using the mutual correspondence between the fluid potential and pore pressure. Finally, we calculate 3D fluid potential of Boxing sag as an example to illustrate the process of this method and analyze its characteristic and predict the favorable exploration area.Compared with fluid potential contour map, this method has high accuracy, good continuity.
This paper presents a three-dimension (3D) fluid potential method based on Hubbert fluid potential model and 3D pore pressure. First, combing 3D interval velocity data which is inverted through log-constrained seismic inversion and well logging data, it can obtain the 3D pore pressure based on spatial interpolation method and the single point hypothesis. Then, we calculate the 3D fluid potential using the mutual correspondence between the fluid potential and pore pressure. Finally, we calculate 3D fluid potential of Boxing sag as an example to illustrate the process of this method and analyze its characteristic and predict the favorable exploration area.Compared with fluid potential contour map, this method has high accuracy, good continuity.
2014, 21(3):45-47.
Abstract:
At present, depending only on the P wave inversion may result in multiple solutions in the exploration of oil and gas. Using the technology of the joint inversion of P wave and converted wave seismic data, it can effectively improve the shear wave impedance calculation accuracy and reliability of reservoir prediction. Due to the change of the reservoir lithology in Es1 of the Shahejie formation of Luojia area, it’s difficult to accurately predict reservoir and oil water distribution only through conventional P-wave prestacking inversion. However, based on the multi-wave and multi-component seismic exploration technology, and by means of the study of joint inversion, it can realize the joint calibration and compression matching of transformed S wave, as well as the fine structure interpretation,so as to construct the initial joint inversion model, and then, we can obtain the elastic parameters for reservoir prediction and description, such as the compressional and shear wave velocity ratio and the density. The application results show that the elastic parameters,and compressional and shear wave joint inversion can not only identify Es1 biolithite limestone reservoir variation, but also reflect the reservoir fluid distribution. Compared with the 85 wells in the study area, the result may coincide up to 85%.
At present, depending only on the P wave inversion may result in multiple solutions in the exploration of oil and gas. Using the technology of the joint inversion of P wave and converted wave seismic data, it can effectively improve the shear wave impedance calculation accuracy and reliability of reservoir prediction. Due to the change of the reservoir lithology in Es1 of the Shahejie formation of Luojia area, it’s difficult to accurately predict reservoir and oil water distribution only through conventional P-wave prestacking inversion. However, based on the multi-wave and multi-component seismic exploration technology, and by means of the study of joint inversion, it can realize the joint calibration and compression matching of transformed S wave, as well as the fine structure interpretation,so as to construct the initial joint inversion model, and then, we can obtain the elastic parameters for reservoir prediction and description, such as the compressional and shear wave velocity ratio and the density. The application results show that the elastic parameters,and compressional and shear wave joint inversion can not only identify Es1 biolithite limestone reservoir variation, but also reflect the reservoir fluid distribution. Compared with the 85 wells in the study area, the result may coincide up to 85%.
2014, 21(3):48-51.
Abstract:
The Sha III formation in Bonan subsag is widely developed with turbidite, and the reservoir has the characteristics of small size, limited area, highly variable lateral distribution, and complex vertical stacking, moreover, it is of weak reflection in the seismic signal and low in resolution, and unable to meet the requirements of reservoir description. Based on the seismic, drilling, logging, seismic reflection data, and in response to the seismic reflection features, we propose the 4 techniques to delineate the turbidite reservoir, including the blind source separation based on independent component analysis automatic layer fine interpretation, stochastic inversion and small sand picking techniques. The 4 kinds of techniques are utilized in the Bonan depression to realize the automatic interpretation of Sha III formation. The recognition of sand body in reservoir prediction is increased to 5-8 m, which has met the requirement of automatic tracking and mapping of the turbidite sand bodies. The techniques have been carried out in the study area to locate more than 70 sand bodies, and achieving good performance.
The Sha III formation in Bonan subsag is widely developed with turbidite, and the reservoir has the characteristics of small size, limited area, highly variable lateral distribution, and complex vertical stacking, moreover, it is of weak reflection in the seismic signal and low in resolution, and unable to meet the requirements of reservoir description. Based on the seismic, drilling, logging, seismic reflection data, and in response to the seismic reflection features, we propose the 4 techniques to delineate the turbidite reservoir, including the blind source separation based on independent component analysis automatic layer fine interpretation, stochastic inversion and small sand picking techniques. The 4 kinds of techniques are utilized in the Bonan depression to realize the automatic interpretation of Sha III formation. The recognition of sand body in reservoir prediction is increased to 5-8 m, which has met the requirement of automatic tracking and mapping of the turbidite sand bodies. The techniques have been carried out in the study area to locate more than 70 sand bodies, and achieving good performance.
2014, 21(3):52-54.
Abstract:
Considering that there is no simple and mature analysis calculation method for fire flood front at present, on the basis of the characteristics of fire flooding, the proper tracer is chosen to monitor the gas channeling direction. Taking the field test area of fire flooding in Liaohe oilfield as an example, in the light of the fundamental idea of material balance, the new method of determining the position of combustion front for in-situ combustion has been established, six well groups have been calculated and the factors influencing fire flooding front development direction have been analyzed in the combination with the engineering geological factors. Compared to the traditional production allocation calculation method, the new method of using the tracer to assist in determining the combustion front of in-situ combustion can indicate the gas streaming directions between the wells and the gas flow from different directions more accurately, thereby avoiding the calculation error of blindly allocating gas production rate. This calculation method is more simple, convenient and feasible and the calculation results are more accurate and impressive.
Considering that there is no simple and mature analysis calculation method for fire flood front at present, on the basis of the characteristics of fire flooding, the proper tracer is chosen to monitor the gas channeling direction. Taking the field test area of fire flooding in Liaohe oilfield as an example, in the light of the fundamental idea of material balance, the new method of determining the position of combustion front for in-situ combustion has been established, six well groups have been calculated and the factors influencing fire flooding front development direction have been analyzed in the combination with the engineering geological factors. Compared to the traditional production allocation calculation method, the new method of using the tracer to assist in determining the combustion front of in-situ combustion can indicate the gas streaming directions between the wells and the gas flow from different directions more accurately, thereby avoiding the calculation error of blindly allocating gas production rate. This calculation method is more simple, convenient and feasible and the calculation results are more accurate and impressive.
2014, 21(3):55-57.
Abstract:
Steam flooding can enhance the heavy oil recovery obviously. However, a single steam flooding can not achieve good heavy oil development efficiency by the gravity overlap and steam channeling due to the Gudao viscous heavy oil with respect to interface properties of crude oil and rock wettability. Addition of oil displacement agent in the process of steam drive can obviously improve the recovery efficiency. Excessive addition of oil displacement agent can easily cause formation plugging and increase the production difficulty. With the PVP as the displacement agent, this paper has studied the variation of colloidal stability, structural composition and recombinant sub-particles size of Gudao viscous crude oil reacted by chemical auxiliary steam drive. The results show that it can improve the recovery factor under the action of PVP auxiliary steam-heavy oil reservoir; when increasing the amount of displacement agent, the oil’s starting point of coagulation of asphaltene decreases, colloidal stability becomes worse, and the molecular weight of asphaltene increases; with the increase of the temperature, the oil’s starting point of coagulation of asphaltene decreases, colloidal stability becomes worse, asphaltene content increases gently, the ratio of resin and asphaltene of oil sample decreases, and the molecular weight of asphaltene increases.
Steam flooding can enhance the heavy oil recovery obviously. However, a single steam flooding can not achieve good heavy oil development efficiency by the gravity overlap and steam channeling due to the Gudao viscous heavy oil with respect to interface properties of crude oil and rock wettability. Addition of oil displacement agent in the process of steam drive can obviously improve the recovery efficiency. Excessive addition of oil displacement agent can easily cause formation plugging and increase the production difficulty. With the PVP as the displacement agent, this paper has studied the variation of colloidal stability, structural composition and recombinant sub-particles size of Gudao viscous crude oil reacted by chemical auxiliary steam drive. The results show that it can improve the recovery factor under the action of PVP auxiliary steam-heavy oil reservoir; when increasing the amount of displacement agent, the oil’s starting point of coagulation of asphaltene decreases, colloidal stability becomes worse, and the molecular weight of asphaltene increases; with the increase of the temperature, the oil’s starting point of coagulation of asphaltene decreases, colloidal stability becomes worse, asphaltene content increases gently, the ratio of resin and asphaltene of oil sample decreases, and the molecular weight of asphaltene increases.
2014, 21(3):58-61.
Abstract:
When analyzing the effect of nitrogen injection assisted steam stimulation on the basis of the same amount of steam injection, many scholars have ignored the effects of total heat injection of steam stimulation. Through the analysis of characteristics of heavy oil reservoir in Gudao oilfield under the same heat injection, we select reservoir thickness at 2-5, 5-8, 8 m above, and permeability of 500×10-3，1 000×10-3，2 000×10-3 μm2, corresponding to a porosity of 30%, 35% and 40% respectively. In experiments, we compare the nitrogen-assisted steam stimulation performance by using numerical simulation technology through three aspects: oil increment, heating radius and the degree of bottom water coning. At last, new methods of selecting zone for nitrogen-assisted steam stimulation are ac?complished, which consider the bottom water and viscosity. The methods can be utilized to effectively analyze the feasibility of nitrogen-assisted steam stimulation in heavy oil reservoir. Study has shown that the nitrogen-assisted steam stimulation is suitable in eastern Ng3 and Zhongerbei Ng5 and not applicable in Gubei Ng3.
When analyzing the effect of nitrogen injection assisted steam stimulation on the basis of the same amount of steam injection, many scholars have ignored the effects of total heat injection of steam stimulation. Through the analysis of characteristics of heavy oil reservoir in Gudao oilfield under the same heat injection, we select reservoir thickness at 2-5, 5-8, 8 m above, and permeability of 500×10-3，1 000×10-3，2 000×10-3 μm2, corresponding to a porosity of 30%, 35% and 40% respectively. In experiments, we compare the nitrogen-assisted steam stimulation performance by using numerical simulation technology through three aspects: oil increment, heating radius and the degree of bottom water coning. At last, new methods of selecting zone for nitrogen-assisted steam stimulation are ac?complished, which consider the bottom water and viscosity. The methods can be utilized to effectively analyze the feasibility of nitrogen-assisted steam stimulation in heavy oil reservoir. Study has shown that the nitrogen-assisted steam stimulation is suitable in eastern Ng3 and Zhongerbei Ng5 and not applicable in Gubei Ng3.
2014, 21(3):62-65.
Abstract:
Water crossflow is one of the main problems encountered during the development of homogeneous reservoirs. Multi-cycle operations of water shutoff are short of detailed description. In this paper, the visible plate models are designed, and systematical research on parameter optimization is launched with ideal modal, while the best position to deploy plugging agents is also studied in modals with bended channels. The results show that there is a limit on the injection volume, and when it equals to 0.1 PV, the operation may get economical success. The sweep efficiency can be higher with the deeper location, and different styles of remaining oil distribution show different results. When the remaining oil is near the producing well, the plugging agents should be put deeper; while the range is little with the remaining oil adjacent to injecting well. For models with worm-shaped channels, the best location for plugging agents is just after breakpoint near injecting well, which can make full use of the pressure drop (flowing rate) and fluid diverting. Under this condition,the synergism, as well as the recovery rate, can both reach the optimum.
Water crossflow is one of the main problems encountered during the development of homogeneous reservoirs. Multi-cycle operations of water shutoff are short of detailed description. In this paper, the visible plate models are designed, and systematical research on parameter optimization is launched with ideal modal, while the best position to deploy plugging agents is also studied in modals with bended channels. The results show that there is a limit on the injection volume, and when it equals to 0.1 PV, the operation may get economical success. The sweep efficiency can be higher with the deeper location, and different styles of remaining oil distribution show different results. When the remaining oil is near the producing well, the plugging agents should be put deeper; while the range is little with the remaining oil adjacent to injecting well. For models with worm-shaped channels, the best location for plugging agents is just after breakpoint near injecting well, which can make full use of the pressure drop (flowing rate) and fluid diverting. Under this condition,the synergism, as well as the recovery rate, can both reach the optimum.
2014, 21(3):66-69.
Abstract:
The oilfield sewage is usually re-injected in chemical flooding units and the water quality has a significant influence on the performance of chemical flooding. In this paper, the variation of injection water over years in Shengli oilfield is statistically analyzed.Our results show that the total salinity and divalent-cation (Ca2+ and Mg2+) content keep increasing, meanwhile, the impurities such as Fe2+, S2- and COD are contained in the injection water. The influence of water quality on the viscosity and interfacial tension is investigated. Experimental results show that the viscosity of polymer decreases due to the interaction between ions and polymer. The interfacial tension increases because the Shengli petroleum sulfonate (SLPS) precipitates with divalent cations. Furthermore, the viscosity at wellhead is much lower than that of measured in laboratory, implying that the chemical concentration used in the field has to be considerably increased in order to reach the same viscosity.
The oilfield sewage is usually re-injected in chemical flooding units and the water quality has a significant influence on the performance of chemical flooding. In this paper, the variation of injection water over years in Shengli oilfield is statistically analyzed.Our results show that the total salinity and divalent-cation (Ca2+ and Mg2+) content keep increasing, meanwhile, the impurities such as Fe2+, S2- and COD are contained in the injection water. The influence of water quality on the viscosity and interfacial tension is investigated. Experimental results show that the viscosity of polymer decreases due to the interaction between ions and polymer. The interfacial tension increases because the Shengli petroleum sulfonate (SLPS) precipitates with divalent cations. Furthermore, the viscosity at wellhead is much lower than that of measured in laboratory, implying that the chemical concentration used in the field has to be considerably increased in order to reach the same viscosity.
2014, 21(3):70-72.
Abstract:
The Chang 6 reservoir of Wangyao block in Ansai oilfield belongs to extra-low permeability formation, and prominent problems exist during the current water flooding. In order to enhance the oil recovery and evaluate the effect of CO2 flooding, optimization design of injection and production parameters for water alternating gas flooding is conducted with reservoir numerical simulation method. The PVTi module of Eclipse is used to simulate the gas-injection expansion experiment to analyze the effect of injected CO2 on the phase behavior of crude oil. With the orthogonal experiment design, four injection and production parameters are studied, including gas-oil ratio, CO2 injection rate, shut-in gas oil ratio and CO2 slug size. Visual analysis method is applied to analyze the test result. The results show that when the mole fraction of the dissolved CO2 reaches 60%, the viscosity of the oil reduces by 80.51% and the coeffi?cient of volumetric expansion reaches 1.44. The optimal combination of parameters is that the gas-oil ratio is 1∶1, gas injection rate at 13 000 m3/d, shut-in gas oil ratio at 1 000 m3/m3 and CO2 slug size at 0.005 pore volume.
The Chang 6 reservoir of Wangyao block in Ansai oilfield belongs to extra-low permeability formation, and prominent problems exist during the current water flooding. In order to enhance the oil recovery and evaluate the effect of CO2 flooding, optimization design of injection and production parameters for water alternating gas flooding is conducted with reservoir numerical simulation method. The PVTi module of Eclipse is used to simulate the gas-injection expansion experiment to analyze the effect of injected CO2 on the phase behavior of crude oil. With the orthogonal experiment design, four injection and production parameters are studied, including gas-oil ratio, CO2 injection rate, shut-in gas oil ratio and CO2 slug size. Visual analysis method is applied to analyze the test result. The results show that when the mole fraction of the dissolved CO2 reaches 60%, the viscosity of the oil reduces by 80.51% and the coeffi?cient of volumetric expansion reaches 1.44. The optimal combination of parameters is that the gas-oil ratio is 1∶1, gas injection rate at 13 000 m3/d, shut-in gas oil ratio at 1 000 m3/m3 and CO2 slug size at 0.005 pore volume.
2014, 21(3):73-77.
Abstract:
In order to further study the dynamic gelation of phenol formaldehyde resin (PFR) gel in porous media, the dynamic gelation of PFR gel under different permeabilities and injected speeds are studied with the device of circular flow in porous media. The results show that, along with the increase of permeability, the initial dynamic gelation time (IGT) and the final dynamic gelation time (FGT) increase and the gel strength decreases. Furthermore, we determined the relationship between viscosity after dynamic gelation and permeability. The IGT of PFR gel declines at first and then increases as injected speed increases, while FGT of PFR gel increases and gel strength decreases. At the same time, the quantitative relationship of viscosity after dynamic gelation and injected speed is established.The relationship between injected speed and shear rate under different permeabilities is established on the basis of effects of permeabilities and injected speed on dynamic gelation of PFR gel in porous media. And, this paper can provide the theory basis for the selection of injected speed under different permeabilities in profile control.
In order to further study the dynamic gelation of phenol formaldehyde resin (PFR) gel in porous media, the dynamic gelation of PFR gel under different permeabilities and injected speeds are studied with the device of circular flow in porous media. The results show that, along with the increase of permeability, the initial dynamic gelation time (IGT) and the final dynamic gelation time (FGT) increase and the gel strength decreases. Furthermore, we determined the relationship between viscosity after dynamic gelation and permeability. The IGT of PFR gel declines at first and then increases as injected speed increases, while FGT of PFR gel increases and gel strength decreases. At the same time, the quantitative relationship of viscosity after dynamic gelation and injected speed is established.The relationship between injected speed and shear rate under different permeabilities is established on the basis of effects of permeabilities and injected speed on dynamic gelation of PFR gel in porous media. And, this paper can provide the theory basis for the selection of injected speed under different permeabilities in profile control.
2014, 21(3):75-78.
Abstract:
The CO2 flooding in high temperature and salinity reservoirs of Zhongyuan oilfield is a new approach to improve the recovery when the reservoirs are at the late high water-cut period after water flooding.Application of foam sealing channeling in those reservoirs is an effective method.Aiming at the problem of severe gas channeling in test field，a system of CO2 foam system with heat resistance and tolerance to salt is developed.The system temperature-resistant reaches 100 ℃，salt-tolerant reaches 25×104 mg/L，Ca2+and Mg2+resistance up to 5×103 mg/L.A new understanding，the pressure is greater，foaming ability is stronger，is obtained through CO2 foam experiment in high temperature and high pressure.The CO2 foam phase change experiments show that the foaming ability and stability of supercritical CO2 foam are significantly higher than the gas CO2 foam and the maximum stabilizing time reaches 3 144.3 min.The CO2 foam system has been used in 16 wells in Zhongyuan oilfield and Yaoyingtai oilfield.The gas injection pressure rises by an average of 1-3 MPa and the success rate of operation is 100%.All wells get good seal channeling effects.The technology will provide a support for gas channeling control during CO2 flooding in high temperature and salinity reservoirs of Zhongyuan oilfield and also will provide references for similar reservoirs home and abroad.
The CO2 flooding in high temperature and salinity reservoirs of Zhongyuan oilfield is a new approach to improve the recovery when the reservoirs are at the late high water-cut period after water flooding.Application of foam sealing channeling in those reservoirs is an effective method.Aiming at the problem of severe gas channeling in test field，a system of CO2 foam system with heat resistance and tolerance to salt is developed.The system temperature-resistant reaches 100 ℃，salt-tolerant reaches 25×104 mg/L，Ca2+and Mg2+resistance up to 5×103 mg/L.A new understanding，the pressure is greater，foaming ability is stronger，is obtained through CO2 foam experiment in high temperature and high pressure.The CO2 foam phase change experiments show that the foaming ability and stability of supercritical CO2 foam are significantly higher than the gas CO2 foam and the maximum stabilizing time reaches 3 144.3 min.The CO2 foam system has been used in 16 wells in Zhongyuan oilfield and Yaoyingtai oilfield.The gas injection pressure rises by an average of 1-3 MPa and the success rate of operation is 100%.All wells get good seal channeling effects.The technology will provide a support for gas channeling control during CO2 flooding in high temperature and salinity reservoirs of Zhongyuan oilfield and also will provide references for similar reservoirs home and abroad.
2014, 21(3):78-81.
Abstract:
The east Sha 20 reservoir in fault block of Shanian oilfield is one of the typical narrow strip reservoirs with edge water. The overall reservoir is of high water cut at 2012, and also flooded seriously in the well area, so it is difficult to maintain a stable production in addition to the complex remaining oil distribution. By means of comprehensive evaluation method of multiple factors and the capacitance model principle, we can identify block water flooding channel, and study the sand body on fluid channeling and the direction of it. Results show that the causes of water drive advantage channel include not only the continuous injection of injection wells of edge,but also the long-term water invasion of edge water, therefore, the effective water injection strategy research will be based on the advantage of water drive channel identification results. Combined with the planar characteristics of the reservoir and vertical remaining oil distribution, it is suitable to block layers, fill holes, infill and transfer oil wells on reservoir, and then adjust the injection-production system in different fluid channeling regions. By adjusting the water injection mode, the recovery of optimal plan can increase by 2.71% for 15 years, and the initial water cut decreases by 25%, so we can enhance and improve water flooding development of the narrow strip of reservoir, therefore providing experience for similar oilfield exploitation and later adjustment.
The east Sha 20 reservoir in fault block of Shanian oilfield is one of the typical narrow strip reservoirs with edge water. The overall reservoir is of high water cut at 2012, and also flooded seriously in the well area, so it is difficult to maintain a stable production in addition to the complex remaining oil distribution. By means of comprehensive evaluation method of multiple factors and the capacitance model principle, we can identify block water flooding channel, and study the sand body on fluid channeling and the direction of it. Results show that the causes of water drive advantage channel include not only the continuous injection of injection wells of edge,but also the long-term water invasion of edge water, therefore, the effective water injection strategy research will be based on the advantage of water drive channel identification results. Combined with the planar characteristics of the reservoir and vertical remaining oil distribution, it is suitable to block layers, fill holes, infill and transfer oil wells on reservoir, and then adjust the injection-production system in different fluid channeling regions. By adjusting the water injection mode, the recovery of optimal plan can increase by 2.71% for 15 years, and the initial water cut decreases by 25%, so we can enhance and improve water flooding development of the narrow strip of reservoir, therefore providing experience for similar oilfield exploitation and later adjustment.
2014, 21(3):82-85.
Abstract:
Fewer studies are addressed about the non-Darcy seepage rule of the offshore heavy oil reservoirs at home and abroad, especially in the aspects of threshold pressure gradient, but the phenomenon is very important for offshore heavy oilfield development, and for in-depth research. According to the percolation characteristics in heavy oil reservoir, a new experimental method for rational determination of the threshold pressure gradient is designed, by which the threshold pressure gradient of heavy oil and flux mobility are deduced using the similar natural cores from QHD32-6 oilfield. The empirical formulas of relations between the threshold pressure gradient and the flow mobility are obtained by regression experimental data. The experimental results indicate that: the threshold pressure gradient is influenced by crude oil viscosity, permeability, and temperature. Through the linear regression above, we can propose the calculation method to determine the technical limit of well spacing and then apply it to the QHD32-6 oilfield. The study above can provide theoretical basis for the offshore development of heavy reservoir.
Fewer studies are addressed about the non-Darcy seepage rule of the offshore heavy oil reservoirs at home and abroad, especially in the aspects of threshold pressure gradient, but the phenomenon is very important for offshore heavy oilfield development, and for in-depth research. According to the percolation characteristics in heavy oil reservoir, a new experimental method for rational determination of the threshold pressure gradient is designed, by which the threshold pressure gradient of heavy oil and flux mobility are deduced using the similar natural cores from QHD32-6 oilfield. The empirical formulas of relations between the threshold pressure gradient and the flow mobility are obtained by regression experimental data. The experimental results indicate that: the threshold pressure gradient is influenced by crude oil viscosity, permeability, and temperature. Through the linear regression above, we can propose the calculation method to determine the technical limit of well spacing and then apply it to the QHD32-6 oilfield. The study above can provide theoretical basis for the offshore development of heavy reservoir.
2014, 21(3):86-88.
Abstract:
Low-frequency resonant wave-based oil recovery and polymer gel technology have been widely used in production stimulation. To avoid the possible disturbance between the two technologies when combining the two technologies in application, the analysis of the effect of low-frequency vibration on the gel properties is conducted. Based on the viscosity method, the experiment is conducted to evaluate the vibration parameters in the influence on the crosslink of gel. The results show that the low-frequency resonant wave can improve the crosslink with the acceleration from 0.05 G to 0.08 G while it will lead to inhibition in the range of 0.08 G to 0.19 G, and the frequency between 12 Hz and 30 Hz will damage the gelation. Therefore, when combining the two techniques in the oilfield, the frequency and acceleration of vibration should be cautiously chosen in order to avoid the reduction of performance.
Low-frequency resonant wave-based oil recovery and polymer gel technology have been widely used in production stimulation. To avoid the possible disturbance between the two technologies when combining the two technologies in application, the analysis of the effect of low-frequency vibration on the gel properties is conducted. Based on the viscosity method, the experiment is conducted to evaluate the vibration parameters in the influence on the crosslink of gel. The results show that the low-frequency resonant wave can improve the crosslink with the acceleration from 0.05 G to 0.08 G while it will lead to inhibition in the range of 0.08 G to 0.19 G, and the frequency between 12 Hz and 30 Hz will damage the gelation. Therefore, when combining the two techniques in the oilfield, the frequency and acceleration of vibration should be cautiously chosen in order to avoid the reduction of performance.
2014, 21(3):89-91.
Abstract:
The square inverted nine-spot pattern is widely used in Wangyao low permeability oilfield, and the infilling pilot is carried out in the west part. In order to evaluate the EOR potential of pattern infilling program, the infilling inverted nine-spot pattern physical simulation program is designed. Considering the geological features of pilot area, the natural sandstone outcrops are selected, which have the similar porosity, permeability, oil displacement efficiency and throat radius for the waterflooding experiment. According to the actual timing and manner of infilling adjustment of the pilot area, we simulate the infilling injection during the experiment to study the impact of infilling adjustment on development performance. Results show that, after infilling adjustment, the EOR is increased by about 4.94%. If the infilling timing is postponed for five years, the EOR might reduce by 1.2%. Therefore, the infilling adjustment should be implemented as soon as possible in the pilot area.
The square inverted nine-spot pattern is widely used in Wangyao low permeability oilfield, and the infilling pilot is carried out in the west part. In order to evaluate the EOR potential of pattern infilling program, the infilling inverted nine-spot pattern physical simulation program is designed. Considering the geological features of pilot area, the natural sandstone outcrops are selected, which have the similar porosity, permeability, oil displacement efficiency and throat radius for the waterflooding experiment. According to the actual timing and manner of infilling adjustment of the pilot area, we simulate the infilling injection during the experiment to study the impact of infilling adjustment on development performance. Results show that, after infilling adjustment, the EOR is increased by about 4.94%. If the infilling timing is postponed for five years, the EOR might reduce by 1.2%. Therefore, the infilling adjustment should be implemented as soon as possible in the pilot area.
2014, 21(3):92-94.
Abstract:
For bottom water reservoir, it is regularly to avoid shooting the water layer so as to prevent the bottom water intrusion, but now there has been a“shooting gas and water layers, both gas and water producing”pattern to produce gas, and may also prevent the water intrusion. The Moxi gas field is a typical water bearing gas field in Sichuan. To further understand the relations between the dynamic production characteristics and reservoir features, five types of water-gas ratio curves are summarized after comparison between avoiding shoot water layer and water-gas commingle production, that is, the plateau, a slow ascent, rapid ascent, down segment and hops. We analyze each curve type and its reservoir characteristics, and then draw the water/gas ratio plate. In the study area, we identify the range of slopes of water/gas ratio curve. The field application has proved that the dynamic characteristics of recovery of both gas and water are overall accordant to the reservoir characteristics, indicating that the plate is practically helpful to correctly understand the water flooding patterns of gas reservoirs with bottom water. And, the internal reservoir gas and water two-phase flow changes should be further studied.
For bottom water reservoir, it is regularly to avoid shooting the water layer so as to prevent the bottom water intrusion, but now there has been a“shooting gas and water layers, both gas and water producing”pattern to produce gas, and may also prevent the water intrusion. The Moxi gas field is a typical water bearing gas field in Sichuan. To further understand the relations between the dynamic production characteristics and reservoir features, five types of water-gas ratio curves are summarized after comparison between avoiding shoot water layer and water-gas commingle production, that is, the plateau, a slow ascent, rapid ascent, down segment and hops. We analyze each curve type and its reservoir characteristics, and then draw the water/gas ratio plate. In the study area, we identify the range of slopes of water/gas ratio curve. The field application has proved that the dynamic characteristics of recovery of both gas and water are overall accordant to the reservoir characteristics, indicating that the plate is practically helpful to correctly understand the water flooding patterns of gas reservoirs with bottom water. And, the internal reservoir gas and water two-phase flow changes should be further studied.
2014, 21(3):95-97.
Abstract:
Considering the restriction of oceanic condition and water depth in offshore oilfield, and higher cost of drilling and data acquiring, the oilfield evaluation is constantly studied to maximize the case evaluation optimization and reduce the time of drilling, coring and testing jobs, and therefore speed up new oilfield evaluation economically and effectively. In this paper, based on example of marine-facies high-quality sandstone from NH-AB oilfield evaluation in Pearl River Mouth Basin of Miocene stratum, and based on feasible analysis of evaluation case optimization, and by means of evaluation optimization on well location and numbers, coring and testing,we successfully reduced two evaluation wells, and only one coring and testing needed, therefore saving about a hundred million RMB of exploration cost, and accelerating the evaluation jobs and reserve estimation. It can improve the work efficiency and economics of offshore oilfield evaluation, and provide a reference for quick evaluation of similar oilfield in Pearl River Mouth Basin.
Considering the restriction of oceanic condition and water depth in offshore oilfield, and higher cost of drilling and data acquiring, the oilfield evaluation is constantly studied to maximize the case evaluation optimization and reduce the time of drilling, coring and testing jobs, and therefore speed up new oilfield evaluation economically and effectively. In this paper, based on example of marine-facies high-quality sandstone from NH-AB oilfield evaluation in Pearl River Mouth Basin of Miocene stratum, and based on feasible analysis of evaluation case optimization, and by means of evaluation optimization on well location and numbers, coring and testing,we successfully reduced two evaluation wells, and only one coring and testing needed, therefore saving about a hundred million RMB of exploration cost, and accelerating the evaluation jobs and reserve estimation. It can improve the work efficiency and economics of offshore oilfield evaluation, and provide a reference for quick evaluation of similar oilfield in Pearl River Mouth Basin.
2014, 21(3):98-101.
Abstract:
Based on the summary of achievements and technologies of oilfield development for Ecuador reservoirs with low relief structure and strong natural aquifer since 2006, the current situation and challenges are analyzed herein, and then, some expected techniques and solutions for stabilizing oil production are proposed. The suitable technologies for exploration and development of this block include: techniques for identification of low-relief traps and integrated predication for thin reservoirs, fine reservoir description techniques, remaining oil distribution prediction, cluster horizontal wells with large displacement in jungle, techniques for controlling water cut and stabilizing oil rate in ultra-high water cut stage. The current situation and challenges of the block include: due to the low reserve-production ratio and reserve replacement rate, the block has weak reserve basis for stable oil production; the remaining oil in main fields is distributed very complex and scattered, and very difficult to locate; there’s no space for infilling wells in oil areas; the unique pay zone has small remaining thickness, the wells have little potential for stimulation; due to the large liquid production, the capacity of surface equipment cannot meet the requirement for stimulation, therefore, some wells with high water cut have to be shut off to control the water yielding. Aiming at the current situation and challenges mentioned above, this paper presented some expected techniques and solution for stabilizing oil production, including identification of low relief traps, remaining oil distribution prediction, horizontal well techniques, integrated stimulation techniques and optimization of injection-production system.
Based on the summary of achievements and technologies of oilfield development for Ecuador reservoirs with low relief structure and strong natural aquifer since 2006, the current situation and challenges are analyzed herein, and then, some expected techniques and solutions for stabilizing oil production are proposed. The suitable technologies for exploration and development of this block include: techniques for identification of low-relief traps and integrated predication for thin reservoirs, fine reservoir description techniques, remaining oil distribution prediction, cluster horizontal wells with large displacement in jungle, techniques for controlling water cut and stabilizing oil rate in ultra-high water cut stage. The current situation and challenges of the block include: due to the low reserve-production ratio and reserve replacement rate, the block has weak reserve basis for stable oil production; the remaining oil in main fields is distributed very complex and scattered, and very difficult to locate; there’s no space for infilling wells in oil areas; the unique pay zone has small remaining thickness, the wells have little potential for stimulation; due to the large liquid production, the capacity of surface equipment cannot meet the requirement for stimulation, therefore, some wells with high water cut have to be shut off to control the water yielding. Aiming at the current situation and challenges mentioned above, this paper presented some expected techniques and solution for stabilizing oil production, including identification of low relief traps, remaining oil distribution prediction, horizontal well techniques, integrated stimulation techniques and optimization of injection-production system.
2014, 21(3):102-104.
Abstract:
Water absorption profile prediction models have been established and layer optimized combination has been done to improve the recovery of Ⅱ and Ⅲ layer in lower sub member of the Es2 Formation of Pucheng oilfield. The water absorption profile prediction models contain different geological factors and the weight coefficient on the basis of stratigraphic information and well parameters,and by means of intelligent swarm calculation. The prediction models can predict the variation of different stratification conditions, and optimize water injection measurements to improve water displacement utilization degree, so as to enhance the development performance in ultra-high water cut period of Wen 51 reservoir. Since the application of this technique in December 2008, the comprehensive water cut of study area has reduced by 4.7% and oil production has a steady improvement in 5 years, with cumulative incremental oil of 1.2 ×104 t. The reservoir development performance has been significantly improved.
Water absorption profile prediction models have been established and layer optimized combination has been done to improve the recovery of Ⅱ and Ⅲ layer in lower sub member of the Es2 Formation of Pucheng oilfield. The water absorption profile prediction models contain different geological factors and the weight coefficient on the basis of stratigraphic information and well parameters,and by means of intelligent swarm calculation. The prediction models can predict the variation of different stratification conditions, and optimize water injection measurements to improve water displacement utilization degree, so as to enhance the development performance in ultra-high water cut period of Wen 51 reservoir. Since the application of this technique in December 2008, the comprehensive water cut of study area has reduced by 4.7% and oil production has a steady improvement in 5 years, with cumulative incremental oil of 1.2 ×104 t. The reservoir development performance has been significantly improved.
2014, 21(3):105-107.
Abstract:
Interlayers are one of the main factors controlling the formation and distribution of remaining oil and development performance. Interlayers are controlled and influenced by different geological processes, such as sedimentation and diagenesis. The features,distribution and origin of the interlayers are different, which lead to different rule of oil-water movement. Based on designed ideal model of interlayers, twelve physical experiment models are built. Impact of interlayers on perforations of injection well in rhythmicity reservoir and the impact of distribution, range of the interlayer on water flooding recovery efficiency are studied. It can be concluded that,the injection well should be perforated at high permeability zone for rhythmicity reservoir. And, for reverse rhythm reservoir, when the interlayer is distributed around production well the influence degree on water flooding recovery efficiency is the lowest. As interlayer grows in size in reverse rhythm reservoir, the water flooding recovery efficiency gets worse.
Interlayers are one of the main factors controlling the formation and distribution of remaining oil and development performance. Interlayers are controlled and influenced by different geological processes, such as sedimentation and diagenesis. The features,distribution and origin of the interlayers are different, which lead to different rule of oil-water movement. Based on designed ideal model of interlayers, twelve physical experiment models are built. Impact of interlayers on perforations of injection well in rhythmicity reservoir and the impact of distribution, range of the interlayer on water flooding recovery efficiency are studied. It can be concluded that,the injection well should be perforated at high permeability zone for rhythmicity reservoir. And, for reverse rhythm reservoir, when the interlayer is distributed around production well the influence degree on water flooding recovery efficiency is the lowest. As interlayer grows in size in reverse rhythm reservoir, the water flooding recovery efficiency gets worse.
2014, 21(3):108-110.
Abstract:
At present, there is no injected water standard or recommended water quality criteria for the fractured-vuggy reservoir. Taking the Tahe oilfield fractured-vuggy carbonate reservoir as study object, the influence of suspended substances concentration, particle size and oil content on 0.1 mm fractured and 0.1-2 mm vuggy man-made cores is studied. And, the result indicates that, two kinds of core have the same regularity with respect to suspended substances concentration, particle size and oil content change. when the core has been injected 5 000 PV injected water, the particle median diameter of suspending substances is 30 μm, and the core permeability declines less than 40 percent accordingly; when it runs up to 40 μm, then its permeability declines about 99 percent; when the suspending substances concentration is 30 mg/L, core permeability declines less than 5 percent, but when it is 45 mg/L, its permeability declines about 99 percent; when the oil content is 40 mg/L, the core permeability declines less than 50 percent, when it is 60 mg/L, its permeability descends about 70 percent. Because of large water channels and low injected pressure, it is suggested that the core permeability declining no more than 50 percent can be the quality criterion of injected water for these kinds of reservoirs. So, the particle median diameter of suspending substances of no more than 30 μm, suspending substances concentration of no more than 30 mg/L and oil content of no more than 40 mg/L might be three injected water quality criteria for fractured-vuggy carbonate reservoir in Tahe oilfield.
At present, there is no injected water standard or recommended water quality criteria for the fractured-vuggy reservoir. Taking the Tahe oilfield fractured-vuggy carbonate reservoir as study object, the influence of suspended substances concentration, particle size and oil content on 0.1 mm fractured and 0.1-2 mm vuggy man-made cores is studied. And, the result indicates that, two kinds of core have the same regularity with respect to suspended substances concentration, particle size and oil content change. when the core has been injected 5 000 PV injected water, the particle median diameter of suspending substances is 30 μm, and the core permeability declines less than 40 percent accordingly; when it runs up to 40 μm, then its permeability declines about 99 percent; when the suspending substances concentration is 30 mg/L, core permeability declines less than 5 percent, but when it is 45 mg/L, its permeability declines about 99 percent; when the oil content is 40 mg/L, the core permeability declines less than 50 percent, when it is 60 mg/L, its permeability descends about 70 percent. Because of large water channels and low injected pressure, it is suggested that the core permeability declining no more than 50 percent can be the quality criterion of injected water for these kinds of reservoirs. So, the particle median diameter of suspending substances of no more than 30 μm, suspending substances concentration of no more than 30 mg/L and oil content of no more than 40 mg/L might be three injected water quality criteria for fractured-vuggy carbonate reservoir in Tahe oilfield.
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