Volume 24,Issue 4,2017 Table of Contents
2017, 24(4):1-7.
DOI: 10.13673/j.cnki.cn37-1359/te.2017.04.001
Abstract:
Seismic prestack depth migration is a key technology in hydrocarbon exploration，development，research and production. Based on study on prestack depth migration technology research and its application achievement and experience in Shengli oilfield，characteristics and practical prestack depth migration and modeling techniques were introduced firstly according to surface and subsurface geologic conditions of the study area，which could be used together in application to different study area and different geologic task according to the actual need. And secondly，effects on the prestack migration technique were analyzed based on the idea of integration of acquisition，processing and interpretation，and then the corresponding countermeasures were put forward. Finally，several industrial applications of the technique to typical examples in Shengli oilfield were used to verify effectiveness of integration solution of prestack depth migration technology for hydrocarbon exploration. A set of“depth domain+”prestack depth migration technology has been summarized to promote further development of the seismic technique in domain of depth and to provide better service for oilfield exploration and development.
Seismic prestack depth migration is a key technology in hydrocarbon exploration，development，research and production. Based on study on prestack depth migration technology research and its application achievement and experience in Shengli oilfield，characteristics and practical prestack depth migration and modeling techniques were introduced firstly according to surface and subsurface geologic conditions of the study area，which could be used together in application to different study area and different geologic task according to the actual need. And secondly，effects on the prestack migration technique were analyzed based on the idea of integration of acquisition，processing and interpretation，and then the corresponding countermeasures were put forward. Finally，several industrial applications of the technique to typical examples in Shengli oilfield were used to verify effectiveness of integration solution of prestack depth migration technology for hydrocarbon exploration. A set of“depth domain+”prestack depth migration technology has been summarized to promote further development of the seismic technique in domain of depth and to provide better service for oilfield exploration and development.
2017, 24(4):8-15.
DOI: 10.13673/j.cnki.cn37-1359/te.2017.04.002
Abstract:
Due to years of water-injection development，the distribution of oil and water is complex in the Upper Karamay Formation of eastern Block Wu2，Karamay Oilfield. To improve the development efficiency is very urgent. Based on the depositional model and characteristics of fan delta and the rock-electricity features of the sedimentary microfacies in the study area，the reservoir architecture unit of fan-delta plain and front facies belt in the study area were identified and divided into four levels，which includes compound distributary channel，single period distributary channel，single braided channel（underwater）and single sandbody. The results show that in the study area，the single period distributary channel interfaces mainly include argillaceous interlayer，calcareous interlayer and erosion interface. Four types of distinguishing marks of single braided distributary channel（underwater）were established as follows：the overbank（muddy deposition），the difference of the height of the channel sand body，the thickness difference of the channel sand body and the difference of logging response characteristics of the channel sand bodies. And then the distribution characteristics of sedimentary microfacies were determined based on analysis of reservoir architecture in the study area. The results show that the thickness of braided distributary channel is more than 4 m and the width is 300-1 500 m. The width of single nderwater distributary channel is 100-740 m and its thickness is 1-8 m. The channel bar is potato-like or block-like，and it is 3-9 m thick，150-750 m wide and 200-800 m long. Based on comprehensive analysis of the architecture interface and the simulation results of remaining oil saturation，it is concluded that the remaining oil distribution is comprehensively controlled by the architecture unit，interface and structure factors，forming a large amount of remaining oil accumulation areas.
Due to years of water-injection development，the distribution of oil and water is complex in the Upper Karamay Formation of eastern Block Wu2，Karamay Oilfield. To improve the development efficiency is very urgent. Based on the depositional model and characteristics of fan delta and the rock-electricity features of the sedimentary microfacies in the study area，the reservoir architecture unit of fan-delta plain and front facies belt in the study area were identified and divided into four levels，which includes compound distributary channel，single period distributary channel，single braided channel（underwater）and single sandbody. The results show that in the study area，the single period distributary channel interfaces mainly include argillaceous interlayer，calcareous interlayer and erosion interface. Four types of distinguishing marks of single braided distributary channel（underwater）were established as follows：the overbank（muddy deposition），the difference of the height of the channel sand body，the thickness difference of the channel sand body and the difference of logging response characteristics of the channel sand bodies. And then the distribution characteristics of sedimentary microfacies were determined based on analysis of reservoir architecture in the study area. The results show that the thickness of braided distributary channel is more than 4 m and the width is 300-1 500 m. The width of single nderwater distributary channel is 100-740 m and its thickness is 1-8 m. The channel bar is potato-like or block-like，and it is 3-9 m thick，150-750 m wide and 200-800 m long. Based on comprehensive analysis of the architecture interface and the simulation results of remaining oil saturation，it is concluded that the remaining oil distribution is comprehensively controlled by the architecture unit，interface and structure factors，forming a large amount of remaining oil accumulation areas.
2017, 24(4):16-21.
DOI: 10.13673/j.cnki.cn37-1359/te.2017.04.003
Abstract:
Statistics methods are often used in the oil-gas resource evaluation，mainly include scale sequence method，discovery process model method and generalized Pareto method. But reservoir number is hard to be determined during the process of oil-gas resource evaluation. In order to calculate the oil-gas resources more accurately and reasonably，the undiscovered large and medium-sized reservoirs were predicted by the trap additivity first. Then the overall number of pools was calculated by using the reserve scale sequence of large-medium-sized reservoirs both including discovered and undiscovered. At last，according to the number of pools，the oil-gas resources were calculated in this area by the multi-statistics method. This method can solve the problem that the number of pools is difficult to confirm，and it can enhance the accuracy of the results of oil-gas resource calculation.
Statistics methods are often used in the oil-gas resource evaluation，mainly include scale sequence method，discovery process model method and generalized Pareto method. But reservoir number is hard to be determined during the process of oil-gas resource evaluation. In order to calculate the oil-gas resources more accurately and reasonably，the undiscovered large and medium-sized reservoirs were predicted by the trap additivity first. Then the overall number of pools was calculated by using the reserve scale sequence of large-medium-sized reservoirs both including discovered and undiscovered. At last，according to the number of pools，the oil-gas resources were calculated in this area by the multi-statistics method. This method can solve the problem that the number of pools is difficult to confirm，and it can enhance the accuracy of the results of oil-gas resource calculation.
2017, 24(4):22-29.
DOI: 10.13673/j.cnki.cn37-1359/te.2017.04.004
Abstract:
It is very important to find the subtle reservoir by using the fine division of the sequence and the analysis of the sedimentary microfacies in the late stages of oil and gas exploration，especially when the structural oil-gas reservoirs are unable to meet the production needs. Through the comprehensive analysis of 3D seismic，drilling core and well log data，etc.，the spatial distribution of sedimentary facies was determined by using 3D seismic data，layers of sandbodies were divided by drilling and log data，by which the sedimentary facies and the sequence of the Qigequan area were described finely. And then the connectivity and spatial distribution of sandbodies were studied based on the sedimentary facies and sequence framework. The results show that the retrogradation is dominant during SSC5-SSC3 sedimentary period in the study area.After one regressive process occurs rapidly during SSC2，the sedimentary base level continues to decline during SSC2- SSC1 sedimentary period，and the fan delta sedimentation is dominant at the later period. It is found there are fan delta sedimentary facies and braided river delta sedimentary facies in the research area of lower member of Xiaganchaigou Formation of Oligocene. The braided river delta includes microfacies of underwater distributary channel，underwater distributary interchannel，mouth bar and sheet sand. Sedimentary facies of fan delta is divided into two subfacies：fan delta plain and fan delta front. According to the distribution of sandbodies and the porosity and permeability analysis and on the basis of sedimentary facies and sequence stratigraphic analysis，it is concluded that the sandstone lens and up-dip sandstone pinchout in the slope break near Well Qi32 are the key targets of reservoir exploration.
It is very important to find the subtle reservoir by using the fine division of the sequence and the analysis of the sedimentary microfacies in the late stages of oil and gas exploration，especially when the structural oil-gas reservoirs are unable to meet the production needs. Through the comprehensive analysis of 3D seismic，drilling core and well log data，etc.，the spatial distribution of sedimentary facies was determined by using 3D seismic data，layers of sandbodies were divided by drilling and log data，by which the sedimentary facies and the sequence of the Qigequan area were described finely. And then the connectivity and spatial distribution of sandbodies were studied based on the sedimentary facies and sequence framework. The results show that the retrogradation is dominant during SSC5-SSC3 sedimentary period in the study area.After one regressive process occurs rapidly during SSC2，the sedimentary base level continues to decline during SSC2- SSC1 sedimentary period，and the fan delta sedimentation is dominant at the later period. It is found there are fan delta sedimentary facies and braided river delta sedimentary facies in the research area of lower member of Xiaganchaigou Formation of Oligocene. The braided river delta includes microfacies of underwater distributary channel，underwater distributary interchannel，mouth bar and sheet sand. Sedimentary facies of fan delta is divided into two subfacies：fan delta plain and fan delta front. According to the distribution of sandbodies and the porosity and permeability analysis and on the basis of sedimentary facies and sequence stratigraphic analysis，it is concluded that the sandstone lens and up-dip sandstone pinchout in the slope break near Well Qi32 are the key targets of reservoir exploration.
2017, 24(4):30-35.
DOI: 10.13673/j.cnki.cn37-1359/te.2017.04.005
Abstract:
Based on analysis of matching relationship among oil reservoiring factors of source rock in the Toutunhe Formation，hydrocarbon infilling times，overpressure and oil source faults in the 4th Block of central Junggar Basin，effectiveness of fault transportation and effective configuration between fault and sandbodies were evaluated quantitatively by effective evaluation coefficient and fault open and closure coefficient. It is considered that hydrocarbon transports in aⅠ-shape way.Reasonable match of effective faults and traps is the basic condition for the accumulation of oil and gas in the Toutunhe Formation. Tectonic movement leads to fault opening. Hydrocarbon generation increases the stratigraphic pressure. The pressure transfer causes oil and gas to migrate upward along the effective fault. This is the key for the accumulation of oil and gas in the Toutunhe Formation. As a result，a hydrocarbon reservoiring mode is built，which describes a mode of hydrocarbon early filling-overpressure driving-fault connecting-episodic hydrocarbon accumulation. The comprehensive analysis shows that the hydrocarbon in the Toutunhe Formation are from the Badaowan Formation，and hydrocarbon charging occurred two times. The hydrocarbon accumulation process can be divided into three episodes. Hydrocarbon accumulation and distribution are controlled by the scale of hydrocarbon generation in the Badaowan Formation and the distribution of oil source faults，and hydrocarbon accumulation is more likely to happen where reservoir is adjacent to the oil source faults.
Based on analysis of matching relationship among oil reservoiring factors of source rock in the Toutunhe Formation，hydrocarbon infilling times，overpressure and oil source faults in the 4th Block of central Junggar Basin，effectiveness of fault transportation and effective configuration between fault and sandbodies were evaluated quantitatively by effective evaluation coefficient and fault open and closure coefficient. It is considered that hydrocarbon transports in aⅠ-shape way.Reasonable match of effective faults and traps is the basic condition for the accumulation of oil and gas in the Toutunhe Formation. Tectonic movement leads to fault opening. Hydrocarbon generation increases the stratigraphic pressure. The pressure transfer causes oil and gas to migrate upward along the effective fault. This is the key for the accumulation of oil and gas in the Toutunhe Formation. As a result，a hydrocarbon reservoiring mode is built，which describes a mode of hydrocarbon early filling-overpressure driving-fault connecting-episodic hydrocarbon accumulation. The comprehensive analysis shows that the hydrocarbon in the Toutunhe Formation are from the Badaowan Formation，and hydrocarbon charging occurred two times. The hydrocarbon accumulation process can be divided into three episodes. Hydrocarbon accumulation and distribution are controlled by the scale of hydrocarbon generation in the Badaowan Formation and the distribution of oil source faults，and hydrocarbon accumulation is more likely to happen where reservoir is adjacent to the oil source faults.
2017, 24(4):36-42.
DOI: 10.13673/j.cnki.cn37-1359/te.2017.04.006
Abstract:
There are complex hydrocarbon accumulation conditions in Huanghekou sag，Bohai Sea. The systematical analysis of fault control effect on hydrocarbon accumulation is conducive to guiding further hydrocarbon exploration in the area.Based on the analysis of faults characteristics of the central structural ridge in Huanghekou sag，including fault extension length，density，fault throw in individual geologic period，fault activity rate，faulted caprock thickness and fractal dimensions，it is considered that the source fault activity rate during accumulation stages controls the capacity of vertical hydrocarbon migration，and the hydrocarbon vertical migration along source fault is more likely to happen when fault activity rate is more than15 m/Ma. The faulted caprock thickness controls hydrocarbon vertical distribution，and the caprock is difficult to impede the migration of oil when the faulted caprock thickness is less than 60 m. The fault fractal dimensions control the migration and accumulation efficiency of hydrocarbon in shallow reservoirs，and the migration and accumulation efficiency of hydrocarbon is relatively high when the value of fault fractal dimensions is higher than 1.30. Aa a result，the quantitative evaluation method of fault-control hydrocarbon accumulation was established based on three factors including activity rate，faulted caprock and fractal dimension，and the fault control effect on hydrocarbon accumulation in Structure area Bozhong 29 near Huanghekou central structural ridge was evaluated quantitatively and 6 benefit targets were optimized as the next hydrocarbon targets.
There are complex hydrocarbon accumulation conditions in Huanghekou sag，Bohai Sea. The systematical analysis of fault control effect on hydrocarbon accumulation is conducive to guiding further hydrocarbon exploration in the area.Based on the analysis of faults characteristics of the central structural ridge in Huanghekou sag，including fault extension length，density，fault throw in individual geologic period，fault activity rate，faulted caprock thickness and fractal dimensions，it is considered that the source fault activity rate during accumulation stages controls the capacity of vertical hydrocarbon migration，and the hydrocarbon vertical migration along source fault is more likely to happen when fault activity rate is more than15 m/Ma. The faulted caprock thickness controls hydrocarbon vertical distribution，and the caprock is difficult to impede the migration of oil when the faulted caprock thickness is less than 60 m. The fault fractal dimensions control the migration and accumulation efficiency of hydrocarbon in shallow reservoirs，and the migration and accumulation efficiency of hydrocarbon is relatively high when the value of fault fractal dimensions is higher than 1.30. Aa a result，the quantitative evaluation method of fault-control hydrocarbon accumulation was established based on three factors including activity rate，faulted caprock and fractal dimension，and the fault control effect on hydrocarbon accumulation in Structure area Bozhong 29 near Huanghekou central structural ridge was evaluated quantitatively and 6 benefit targets were optimized as the next hydrocarbon targets.
2017, 24(4):43-48.
DOI: 10.13673/j.cnki.cn37-1359/te.2017.04.007
Abstract:
Based on measured data of 103 CBM wells in Changzhi and Anze Block in Southern Qinshui Basin，the adsorption time of coals with different degrees of deformation and its influencing factors were discussed，which can provide guidance for production prediction of coalbed methane well. The pore structures of coals with different degrees of deformation result in great difference in their desorption characteristics. As the degree of coal deformation increases，the adsorption time decreases quickly. In contrast to undeformed coal and weakly deformed coal，the desorption rate of strongly deformed coal is higher，and its amount of desorption increases sharply and the adsorption time become shorter because of well-developed fractures，macropores and mesopores which provide better connectivity and shorter migration path. In the late of de? sorption，the well-developed small pores and micropores of strongly deformed coal have strong adsorption ability and poorer connectivity，which increases difficulty in methane desorption and migration and therefore the desorption rate reduces markedly. However，the desorption rate of undeformed coal and weakly deformed coal changes slightly and their adsorption time is very long，which is the integrated result influenced by pore and fracture characteristics and geometry shape of coal core. Based on the drainage date of coalbed methane well，it can be drawn that the difference of coal deformation is the major reason for the production change of coalbed methane well. The adsorption time of coal can provide guidance for production prediction of coalbed methane well.
Based on measured data of 103 CBM wells in Changzhi and Anze Block in Southern Qinshui Basin，the adsorption time of coals with different degrees of deformation and its influencing factors were discussed，which can provide guidance for production prediction of coalbed methane well. The pore structures of coals with different degrees of deformation result in great difference in their desorption characteristics. As the degree of coal deformation increases，the adsorption time decreases quickly. In contrast to undeformed coal and weakly deformed coal，the desorption rate of strongly deformed coal is higher，and its amount of desorption increases sharply and the adsorption time become shorter because of well-developed fractures，macropores and mesopores which provide better connectivity and shorter migration path. In the late of de? sorption，the well-developed small pores and micropores of strongly deformed coal have strong adsorption ability and poorer connectivity，which increases difficulty in methane desorption and migration and therefore the desorption rate reduces markedly. However，the desorption rate of undeformed coal and weakly deformed coal changes slightly and their adsorption time is very long，which is the integrated result influenced by pore and fracture characteristics and geometry shape of coal core. Based on the drainage date of coalbed methane well，it can be drawn that the difference of coal deformation is the major reason for the production change of coalbed methane well. The adsorption time of coal can provide guidance for production prediction of coalbed methane well.
2017, 24(4):49-54.
DOI: 10.13673/j.cnki.cn37-1359/te.2017.04.008
Abstract:
There are many discoveries in Ordovician oil and gas development in the northwest of central Tarim Basin，but there are few studies on types and main controlling factors of Lianglitage reservoirs，which has seriously restricted the oil and gas exploration and development in recent years. Based on core observations，rock section and casting section analysis and logging data and combing with experimental data on petrology and geochemistry of the Lianglitage Formation，it is concluded that the reservoir space is dominated by cavities and fractures in this area. The reservoirs are mainly of fracture-cavity type，fracture type and cavity type. The carbonate reservoirs in the Lianglitage Formation are controlled by many factors.The sedimentary microfacies provide the material foundation for the development of the reservoir，among which high energy grain beach at the platform margin is the most advantageous place for hydrocarbon entrapment. The karstification and tectonic rupture of reef beach bodies play an important role in controlling the size and distribution of high quality reservoirs.Integrated analyses indicate that platform margin in A-Dong area，where the degree of exploration is low，and its inner fault zones are favorable for development of cavity-fracture in the Lianglitage Formation.
There are many discoveries in Ordovician oil and gas development in the northwest of central Tarim Basin，but there are few studies on types and main controlling factors of Lianglitage reservoirs，which has seriously restricted the oil and gas exploration and development in recent years. Based on core observations，rock section and casting section analysis and logging data and combing with experimental data on petrology and geochemistry of the Lianglitage Formation，it is concluded that the reservoir space is dominated by cavities and fractures in this area. The reservoirs are mainly of fracture-cavity type，fracture type and cavity type. The carbonate reservoirs in the Lianglitage Formation are controlled by many factors.The sedimentary microfacies provide the material foundation for the development of the reservoir，among which high energy grain beach at the platform margin is the most advantageous place for hydrocarbon entrapment. The karstification and tectonic rupture of reef beach bodies play an important role in controlling the size and distribution of high quality reservoirs.Integrated analyses indicate that platform margin in A-Dong area，where the degree of exploration is low，and its inner fault zones are favorable for development of cavity-fracture in the Lianglitage Formation.
2017, 24(4):55-60.
DOI: 10.13673/j.cnki.cn37-1359/te.2017.04.009
Abstract:
Lithologic reservoir developed well in Mesozoic Yanchang Formation of hydrocarbon accumulation area of Zhenjing area. In order to reveal the characteristics of low permeability reservoir formation and laws of hydrocarbon migration and accumulation in Zhenjing area，Chang7 and Chang8 members in Zhenjing area were selected as study targets to analyze the characteristics of clay compaction and fluid overpressure distribution in the Yanchang Formation. The results showed that the fluid overpressure of Chang7 member ranges from 8 MPa to 13 MPa，and the fluid overpressure of Chang8 member is lower and can reach to 10 MPa only in several areas. There are obvious differences in fluid overpressure between Chang7 and Chang8 members. The high overpressure difference offers the driving forces for oil and gas migrating from Chang7 member to Chang8 member. High oil production zones are areas where high overpressure difference exists between the two members and areas with relatively low overpressure difference are favorable for hydrocarbon migration and accumulation.The northeast and the southeast regions of the study area, which respectively have high overpressure difference and largescale low overpressure difference, are expected to be oil and gas enrichment zones.
Lithologic reservoir developed well in Mesozoic Yanchang Formation of hydrocarbon accumulation area of Zhenjing area. In order to reveal the characteristics of low permeability reservoir formation and laws of hydrocarbon migration and accumulation in Zhenjing area，Chang7 and Chang8 members in Zhenjing area were selected as study targets to analyze the characteristics of clay compaction and fluid overpressure distribution in the Yanchang Formation. The results showed that the fluid overpressure of Chang7 member ranges from 8 MPa to 13 MPa，and the fluid overpressure of Chang8 member is lower and can reach to 10 MPa only in several areas. There are obvious differences in fluid overpressure between Chang7 and Chang8 members. The high overpressure difference offers the driving forces for oil and gas migrating from Chang7 member to Chang8 member. High oil production zones are areas where high overpressure difference exists between the two members and areas with relatively low overpressure difference are favorable for hydrocarbon migration and accumulation.The northeast and the southeast regions of the study area, which respectively have high overpressure difference and largescale low overpressure difference, are expected to be oil and gas enrichment zones.
2017, 24(4):61-66.
DOI: 10.13673/j.cnki.cn37-1359/te.2017.04.010
Abstract:
Amu Darya Basin is an exploration area with huge potential of natural gas. It is known as the most important source of Mid-Asian nature gas pipeline. There is still a shortage in research of reservoir forming rules even though many researches have been carried out in recent 10 years，and controlling factors for gas reservoir forming are also uncertain. In order to find the next gas reservoir target in the further exploration，a series of comprehensive analysis was conducted. It focused on the main controlling factors that led to various types of gas reservoirs. Using a combination of geophysical data interpretation，gas reservoir accumulation analysis，trap evaluation，sedimentary facies analysis，reservoir evaluation and single well production capacity analysis，etc.，the research concluded the main controlling factors of gas accumulation from two aspects-structure and sedimentation. The former includes basement paleo-uplift which controls the trap distribution，faults which are pathway for hydrocarbon migration and tectonic movement since Neogene that results in hydrocarbon redistribution. The latter includes anhydrock and salt shelter which is necessary for the trap of effective hydrocarbon，reef-beach bodies which are closely related to high-production gas well and reservoir type which determines gas-water interface and types of gas reservoirs. The distribution of each type of gas reservoir is determined by one or several main factors，forming bulklike gas accumulation and stripped distribution.
Amu Darya Basin is an exploration area with huge potential of natural gas. It is known as the most important source of Mid-Asian nature gas pipeline. There is still a shortage in research of reservoir forming rules even though many researches have been carried out in recent 10 years，and controlling factors for gas reservoir forming are also uncertain. In order to find the next gas reservoir target in the further exploration，a series of comprehensive analysis was conducted. It focused on the main controlling factors that led to various types of gas reservoirs. Using a combination of geophysical data interpretation，gas reservoir accumulation analysis，trap evaluation，sedimentary facies analysis，reservoir evaluation and single well production capacity analysis，etc.，the research concluded the main controlling factors of gas accumulation from two aspects-structure and sedimentation. The former includes basement paleo-uplift which controls the trap distribution，faults which are pathway for hydrocarbon migration and tectonic movement since Neogene that results in hydrocarbon redistribution. The latter includes anhydrock and salt shelter which is necessary for the trap of effective hydrocarbon，reef-beach bodies which are closely related to high-production gas well and reservoir type which determines gas-water interface and types of gas reservoirs. The distribution of each type of gas reservoir is determined by one or several main factors，forming bulklike gas accumulation and stripped distribution.
2017, 24(4):67-71.
DOI: 10.13673/j.cnki.cn37-1359/te.2017.04.011
Abstract:
Separate layer water injection is an effective measure to weaken interlayer interference and alleviate the interlayer inconsistency. Sectional water injection is a common approach used in reservoirs with multi-layer in the vertical by combining layers with similar physical properties. The layers were classified according to the differential absorption index as the dividing standard. Based on Buckley-Leverett displacement theory，the method of calculating the water allocation of each section was established to achieve equilibrium displacement. Calculation program was made and verified by numerical simulation model. The result shows that the differential absorption index is a scientific dividing standard，and the injected water distribution is influenced by reservoir physical property，residual oil saturation and adjusting time. As the extension of adjusting time，the difference of injected water quantity between sections becomes smaller and the water saturation rises when the equilibrium reaches. Larger average water saturation in sections brings smaller water allocation for unit thickness. With the increase of differential absorption index，the required quantity of water for unit thickness decreases gradually.
Separate layer water injection is an effective measure to weaken interlayer interference and alleviate the interlayer inconsistency. Sectional water injection is a common approach used in reservoirs with multi-layer in the vertical by combining layers with similar physical properties. The layers were classified according to the differential absorption index as the dividing standard. Based on Buckley-Leverett displacement theory，the method of calculating the water allocation of each section was established to achieve equilibrium displacement. Calculation program was made and verified by numerical simulation model. The result shows that the differential absorption index is a scientific dividing standard，and the injected water distribution is influenced by reservoir physical property，residual oil saturation and adjusting time. As the extension of adjusting time，the difference of injected water quantity between sections becomes smaller and the water saturation rises when the equilibrium reaches. Larger average water saturation in sections brings smaller water allocation for unit thickness. With the increase of differential absorption index，the required quantity of water for unit thickness decreases gradually.
2017, 24(4):72-77.
DOI: 10.13673/j.cnki.cn37-1359/te.2017.04.012
Abstract:
Large numbers of preferential flow paths exist in the multi-layer waterflooding reservoirs in high water cut stage.Being different with general oil reservoirs，the injection water obeys high velocity non-Darcy flow in the preferential flow paths. However，the present methods of development index prediction for the multi-layer waterflooding reservoirs do not take the preferential flow paths into account. Based on reservoir engineering theory and fluid mechanics in porous medium，considering the high velocity non-Darcy flow of injection water in the preferential flow paths，a method of development index calculation for multi-layer waterflooding reservoir was derived and proposed. This method can calculate the development indices such as water cut and oil recovery degree. It can reflect the effect of permeability and thickness of the preferential flow paths on production performance quantitatively. Results present that the interlayer contradiction increases with the increasing of permeability and thickness of the preferential flow paths. The recovery degree of normal reservoirs in the layer decreases. The injected water volume of the preferential flow path becomes larger，resulting in lower utilization factor of water injection and worse development effect. This method can exactly reflect the production characteristic of multi-layer waterflooding reservoir with preferential flow path and it can be used to guide the development adjustment for this kind of reservoir.
Large numbers of preferential flow paths exist in the multi-layer waterflooding reservoirs in high water cut stage.Being different with general oil reservoirs，the injection water obeys high velocity non-Darcy flow in the preferential flow paths. However，the present methods of development index prediction for the multi-layer waterflooding reservoirs do not take the preferential flow paths into account. Based on reservoir engineering theory and fluid mechanics in porous medium，considering the high velocity non-Darcy flow of injection water in the preferential flow paths，a method of development index calculation for multi-layer waterflooding reservoir was derived and proposed. This method can calculate the development indices such as water cut and oil recovery degree. It can reflect the effect of permeability and thickness of the preferential flow paths on production performance quantitatively. Results present that the interlayer contradiction increases with the increasing of permeability and thickness of the preferential flow paths. The recovery degree of normal reservoirs in the layer decreases. The injected water volume of the preferential flow path becomes larger，resulting in lower utilization factor of water injection and worse development effect. This method can exactly reflect the production characteristic of multi-layer waterflooding reservoir with preferential flow path and it can be used to guide the development adjustment for this kind of reservoir.
2017, 24(4):78-82.
DOI: 10.13673/j.cnki.cn37-1359/te.2017.04.013
Abstract:
The wettability of gas reservoir has great influence on original occurrence of oil，single well production and ultimate recovery. By comparing tight sandstone reservoir core and steel core，the water invasion degree was simulated through evaluating the variation of oil/water volume ratio，and the change of wettability of the tight sandstone gas reservoir under circumstances of water invasion with low temperature was researched. The results show that the oil/water volume ratio decreased continuously and the probability of contact between sandstone surface and oil components in the gas reservoir was reduced after water invasion in the gas reservoir，which results in hydrophilicity instead of hydrophobicity in both steel core and rock core of the tight sandstone gas reservoir. The hydrophobicity of the steal core is weaker than that of the sandstone core under the same water invasion degree. The reason is that the tight sandstone has clay minerals，and the clay minerals can absorb some of the oil components and make more surface area hydrophilic. The rising rate of the surface contact angle of the gas reservoir sandstone will increase with the volume of water invasion.
The wettability of gas reservoir has great influence on original occurrence of oil，single well production and ultimate recovery. By comparing tight sandstone reservoir core and steel core，the water invasion degree was simulated through evaluating the variation of oil/water volume ratio，and the change of wettability of the tight sandstone gas reservoir under circumstances of water invasion with low temperature was researched. The results show that the oil/water volume ratio decreased continuously and the probability of contact between sandstone surface and oil components in the gas reservoir was reduced after water invasion in the gas reservoir，which results in hydrophilicity instead of hydrophobicity in both steel core and rock core of the tight sandstone gas reservoir. The hydrophobicity of the steal core is weaker than that of the sandstone core under the same water invasion degree. The reason is that the tight sandstone has clay minerals，and the clay minerals can absorb some of the oil components and make more surface area hydrophilic. The rising rate of the surface contact angle of the gas reservoir sandstone will increase with the volume of water invasion.
2017, 24(4):83-87.
DOI: 10.13673/j.cnki.cn37-1359/te.2017.04.014
Abstract:
There are lots of faults in complicated fault block reservoir. And their distributions are quite complicated. Especially in the fault block reservoir with many sub-order faults developed in the fault block，the sub-order faults will influence the water flooding development effect. And the influence rule should be studied to guide flooding pattern deployment and adjustment. According to the distributions and characteristics of the sub-order faults in the complicated fault block reservoir，three flooding patterns were designed and an idealized model of fault distribution was built. Water flooding development effect of different flooding patterns was studied by physical simulation and reservoir numerical simulation. The research results show that development effect of No.3 flooding patterns was the best under the condition of low injection-production pressure drawdown，and No.2 flooding pattern was the best under the condition of high injection-production pressure drawdown. The length of sub-order faults in the fault block will affect the swept volume of the injected water. The longer the fault length is，the larger the unswept reservoir volume of the injected water in the fault block is，and the lower the development efficiency is.
There are lots of faults in complicated fault block reservoir. And their distributions are quite complicated. Especially in the fault block reservoir with many sub-order faults developed in the fault block，the sub-order faults will influence the water flooding development effect. And the influence rule should be studied to guide flooding pattern deployment and adjustment. According to the distributions and characteristics of the sub-order faults in the complicated fault block reservoir，three flooding patterns were designed and an idealized model of fault distribution was built. Water flooding development effect of different flooding patterns was studied by physical simulation and reservoir numerical simulation. The research results show that development effect of No.3 flooding patterns was the best under the condition of low injection-production pressure drawdown，and No.2 flooding pattern was the best under the condition of high injection-production pressure drawdown. The length of sub-order faults in the fault block will affect the swept volume of the injected water. The longer the fault length is，the larger the unswept reservoir volume of the injected water in the fault block is，and the lower the development efficiency is.
15 Well test model of CO2 miscible flooding in the lowpermeability reservoirs with stress sensitivity
2017, 24(4):88-93.
DOI: 10.13673/j.cnki.cn37-1359/te.2017.04.015
Abstract:
Analyzing the double logarithm curve characteristics of bottom hole pressure from CO2 injection well is an efficient method to evaluate the performance of CO2 miscible flooding in the low-permeability reservoirs. Strong stress sensitivity exists in the low-permeability reservoirs，which will affect the reliability of interpretation results. However，there is no report about well test model with the consideration of stress sensitivity. Based on the percolation theory of three-region composite reservoirs，physical model and well test model of CO2 miscible flooding considering the stress sensitivity were established to know the double logarithm curve characteristics of bottom hole pressure. The results present that the well test model curve of CO2 miscible flooding can be divided into five flow regions. The stress sensitivity makes the well test curve no longer follow the rule of 0.5M，and the well test curve will appear obvious upward trend in the late stage. The higher wellbore storage coefficient will cover the pure CO2 radial flow region. Mobility ratio and displacement front radius play an important role in the process of CO2 miscible flooding. This model was applied to the CO2 injection well. The displacement front radius and other relevant parameters in pure CO2 region and transition region can be accurately determined，and the interpretation accuracy of the relevant parameters of CO2 miscible flooding in the low-permeability reservoir may be improved.
Analyzing the double logarithm curve characteristics of bottom hole pressure from CO2 injection well is an efficient method to evaluate the performance of CO2 miscible flooding in the low-permeability reservoirs. Strong stress sensitivity exists in the low-permeability reservoirs，which will affect the reliability of interpretation results. However，there is no report about well test model with the consideration of stress sensitivity. Based on the percolation theory of three-region composite reservoirs，physical model and well test model of CO2 miscible flooding considering the stress sensitivity were established to know the double logarithm curve characteristics of bottom hole pressure. The results present that the well test model curve of CO2 miscible flooding can be divided into five flow regions. The stress sensitivity makes the well test curve no longer follow the rule of 0.5M，and the well test curve will appear obvious upward trend in the late stage. The higher wellbore storage coefficient will cover the pure CO2 radial flow region. Mobility ratio and displacement front radius play an important role in the process of CO2 miscible flooding. This model was applied to the CO2 injection well. The displacement front radius and other relevant parameters in pure CO2 region and transition region can be accurately determined，and the interpretation accuracy of the relevant parameters of CO2 miscible flooding in the low-permeability reservoir may be improved.
2017, 24(4):94-98.
DOI: 10.13673/j.cnki.cn37-1359/te.2017.04.016
Abstract:
Preheating phase of steam assisted gravity drainage（SAGD）has direct effect on its early production response and corresponding performance in heavy oil reservoirs. Therefore，it is important to develop an effective method to improve SAGD performance. A pilot test of the fast and uniform start-up enhancement technology（FUSE）was taken as a case study.The high pressure dilation mechanism of the FUSE was revealed and its related operating pressure was optimized by using numerical simulation method. The results show that a zone with high porosity，high permeability and high water cut was formed between the injector and producer，and the heat convection between steam and reservoir rocks was enhanced，and thus the heat exchange rate and thermal connectivity between double horizontal wells were improved. There was an optimal operating pressure for the FUSE and it was closely related to the in-situ stress and the rock deformation characteristics.Field production data was applied to analyze the performance of the FUSE. The result presents that the number of days for preheating and the steam consumption in the preheating phase are reduced significantly，and the SAGD performance in the early production stage is improved obviously. It has important guiding significance for the realization of efficient SAGD development.
Preheating phase of steam assisted gravity drainage（SAGD）has direct effect on its early production response and corresponding performance in heavy oil reservoirs. Therefore，it is important to develop an effective method to improve SAGD performance. A pilot test of the fast and uniform start-up enhancement technology（FUSE）was taken as a case study.The high pressure dilation mechanism of the FUSE was revealed and its related operating pressure was optimized by using numerical simulation method. The results show that a zone with high porosity，high permeability and high water cut was formed between the injector and producer，and the heat convection between steam and reservoir rocks was enhanced，and thus the heat exchange rate and thermal connectivity between double horizontal wells were improved. There was an optimal operating pressure for the FUSE and it was closely related to the in-situ stress and the rock deformation characteristics.Field production data was applied to analyze the performance of the FUSE. The result presents that the number of days for preheating and the steam consumption in the preheating phase are reduced significantly，and the SAGD performance in the early production stage is improved obviously. It has important guiding significance for the realization of efficient SAGD development.
2017, 24(4):99-104.
DOI: 10.13673/j.cnki.cn37-1359/te.2017.04.017
Abstract:
In order to optimize the design of gas injection process and improve the oil recovery，a hydrocarbon phase behavior model was developed for flash calculation and phase stability analysis according to the theory of equation of state and miscible oil displacement. Under the setting experimental temperature and pressure，the composition change of injected gas and reservoir oil in the multiple-contact mixing process was simulated using designed composition of oil and gas. The behavior of the phase composition change during this process was discussed by use of pseudo-ternary phase diagram to determine if miscible displacement could be achieved. The simulation results showed that vaporizing-gas drive mechanism dominates if lean-gas is used as injected gas，and the vaporizing-gas drive is unable to achieve miscible displacement for the oil sample；if rich-gas is used as injected gas，the miscible process is not dominated by a single driving mechanism（vaporizing or condensing）. The simulated results indicated a combined vaporizing/condensing mechanism to explain the phase behavior of two immiscible reservoir fluids in the transition zone. The developed model and modules are able to be applied in any oil and gas system at miscible conditions，and the calculation results cast light on production.
In order to optimize the design of gas injection process and improve the oil recovery，a hydrocarbon phase behavior model was developed for flash calculation and phase stability analysis according to the theory of equation of state and miscible oil displacement. Under the setting experimental temperature and pressure，the composition change of injected gas and reservoir oil in the multiple-contact mixing process was simulated using designed composition of oil and gas. The behavior of the phase composition change during this process was discussed by use of pseudo-ternary phase diagram to determine if miscible displacement could be achieved. The simulation results showed that vaporizing-gas drive mechanism dominates if lean-gas is used as injected gas，and the vaporizing-gas drive is unable to achieve miscible displacement for the oil sample；if rich-gas is used as injected gas，the miscible process is not dominated by a single driving mechanism（vaporizing or condensing）. The simulated results indicated a combined vaporizing/condensing mechanism to explain the phase behavior of two immiscible reservoir fluids in the transition zone. The developed model and modules are able to be applied in any oil and gas system at miscible conditions，and the calculation results cast light on production.
2017, 24(4):105-109.
DOI: 10.13673/j.cnki.cn37-1359/te.2017.04.018
Abstract:
It is difficult to achieve a desired development effect in low permeability oil reservoir. Experiment of stress sensitivity at various fluid pressures was made to test the permeability of the cores in a certain low permeability oil reservoir under the condition of constant confining pressure. The results show that the core permeability decreases gradually with the decrease of the fluid pressure，and then tends to be gently. The lower the permeability of the rock，the stronger the stress sensitivity，and the core permeability cannot recover to the former after the fluid pressure recovers. Its reason is that the stress sensitivity of the low permeability rock is irreversible. Based on radial flow theory，a new productivity equation for oil well was derived considering the effect of stress sensitive on the permeability. The effect of formation pressure on single well productivity was calculated. Under the constant producing differential pressure of 4 MPa，the single well productivity is reduced by 10% to 30% when the formation pressure drops by 5 MPa. The lower the reservoir permeability，the larger the fall. In order to develop the low permeability reservoir with stress sensitivity reasonably and efficiently，reservoir protection should be made in the process of fracturing，perforation and operation. In the process of production，the change of bottomhole pressure should be observed and reasonable producing differential pressure should be maintained in the production.After the oil well production declines obviously，real-time aciding should be made to increase the permeability of the near wellbore area.
It is difficult to achieve a desired development effect in low permeability oil reservoir. Experiment of stress sensitivity at various fluid pressures was made to test the permeability of the cores in a certain low permeability oil reservoir under the condition of constant confining pressure. The results show that the core permeability decreases gradually with the decrease of the fluid pressure，and then tends to be gently. The lower the permeability of the rock，the stronger the stress sensitivity，and the core permeability cannot recover to the former after the fluid pressure recovers. Its reason is that the stress sensitivity of the low permeability rock is irreversible. Based on radial flow theory，a new productivity equation for oil well was derived considering the effect of stress sensitive on the permeability. The effect of formation pressure on single well productivity was calculated. Under the constant producing differential pressure of 4 MPa，the single well productivity is reduced by 10% to 30% when the formation pressure drops by 5 MPa. The lower the reservoir permeability，the larger the fall. In order to develop the low permeability reservoir with stress sensitivity reasonably and efficiently，reservoir protection should be made in the process of fracturing，perforation and operation. In the process of production，the change of bottomhole pressure should be observed and reasonable producing differential pressure should be maintained in the production.After the oil well production declines obviously，real-time aciding should be made to increase the permeability of the near wellbore area.
2017, 24(4):110-115.
DOI: 10.13673/j.cnki.cn37-1359/te.2017.04.019
Abstract:
Liquid production increase is an effective measure to reduce the decline of production in offshore oilfield at high water cut. Compared with traditional method，the dynamic analysis method based on dynamic production data of oil wells can evaluate liquid production increase potential and overcome the limitations and dependence on regional static data. But the conventional dynamic method can only calculate the dimensionless liquid production index and is hard to quantify the potential of liquid production increase. Dimensionless maximum reasonable production pressure difference of oil wells was calculated based on the direct quantitative relation between the dimensionless liquid production index and water cut which is established based on percolation theory. On this basis，the maximum daily liquid production of oil wells can be real-time calculated，achieving the purpose of quantifying oil well liquid production increase potential directly by the dynamic method. Application results show that the daily liquid production of each well has reached the design value after implementation in W oilfield，which proves the rationality of the method. Since only the data of daily liquid production and daily oil production of the wells are required，the proposed method overcomes the shortage of static data in offshore oilfield. This method has the features of accessible data，reliable calculation results and convenient implementation，showing a broad application prospect in offshore oilfield at medium-high water cut stage.
Liquid production increase is an effective measure to reduce the decline of production in offshore oilfield at high water cut. Compared with traditional method，the dynamic analysis method based on dynamic production data of oil wells can evaluate liquid production increase potential and overcome the limitations and dependence on regional static data. But the conventional dynamic method can only calculate the dimensionless liquid production index and is hard to quantify the potential of liquid production increase. Dimensionless maximum reasonable production pressure difference of oil wells was calculated based on the direct quantitative relation between the dimensionless liquid production index and water cut which is established based on percolation theory. On this basis，the maximum daily liquid production of oil wells can be real-time calculated，achieving the purpose of quantifying oil well liquid production increase potential directly by the dynamic method. Application results show that the daily liquid production of each well has reached the design value after implementation in W oilfield，which proves the rationality of the method. Since only the data of daily liquid production and daily oil production of the wells are required，the proposed method overcomes the shortage of static data in offshore oilfield. This method has the features of accessible data，reliable calculation results and convenient implementation，showing a broad application prospect in offshore oilfield at medium-high water cut stage.
20 Discussion on the method of determining the benefit output of oilfield enterprises at low oil price
2017, 24(4):116-120.
DOI: 10.13673/j.cnki.cn37-1359/te.2017.04.020
Abstract:
The tumble of the oil price brings huge impact on oil production and operation of the oilfield enterprises. There is confusion among many oilfield enterprises about how much oil should be produced for the sake of the most economic benefit. Aimed at the problem that method of determining benefit output is lack of standard，profit-benefit output model，cash flow-benefit output model and marginal revenue-benefit output model were established starting from the cost attribute and benefit evaluation. The evaluation of the benefit output of an oilfield was taken as an example. At oil prices of 50 $/bbl，the benefit output calculated from the three models was 310×104，1 967×104 and 2 416×104 t，respectively. The influence of the benefit output obtained from the three models on the production and operation of oilfield enterprises at different oil prices was analyzed. It was pointed out that oilfield enterprises should make different management strategies according to different oil prices. At high oil price，the profit-benefit output model should hold the leadership role with emphasis on development.At low oil price，the marginal revenue-benefit output model should hold the leadership role with emphasis on survival.Maintaining rational production scale is the basic for oilfield enterprise to survive and develop sustainably.
The tumble of the oil price brings huge impact on oil production and operation of the oilfield enterprises. There is confusion among many oilfield enterprises about how much oil should be produced for the sake of the most economic benefit. Aimed at the problem that method of determining benefit output is lack of standard，profit-benefit output model，cash flow-benefit output model and marginal revenue-benefit output model were established starting from the cost attribute and benefit evaluation. The evaluation of the benefit output of an oilfield was taken as an example. At oil prices of 50 $/bbl，the benefit output calculated from the three models was 310×104，1 967×104 and 2 416×104 t，respectively. The influence of the benefit output obtained from the three models on the production and operation of oilfield enterprises at different oil prices was analyzed. It was pointed out that oilfield enterprises should make different management strategies according to different oil prices. At high oil price，the profit-benefit output model should hold the leadership role with emphasis on development.At low oil price，the marginal revenue-benefit output model should hold the leadership role with emphasis on survival.Maintaining rational production scale is the basic for oilfield enterprise to survive and develop sustainably.
2017, 24(4):121-126.
DOI: 10.13673/j.cnki.cn37-1359/te.2017.04.021
Abstract:
Due to the separate production of gas and oil，the production cycle is too long and the recovery ratio is low in Bozhong29-4 Oilfield，and the electric load cannot meet the needs of multi-well production at the same time since it reached its upper limit. Aiming at these problems，gas and ESP combination lift was proposed using the self-produced gas in the production wells to achieve the goal of oil and gas production at the same time. Production system composed of reservoir，wellbore and ESP-gas lift system was taken as the study object. The method of node analysis and dual system coupling design was used. Regarding the efficient coordination of production of gas lift and ESP as the goal，the method and steps of working parameters design under different conditions were given based on the power of the ESP. The optimized production project was determined eventually. The calculation results of a certain well show that the combination lift can effectively reduce the pump series and pump power to 40.2% and 40.6% of the original compared with single ESP lift system under the condition of same flow rate. The problem of large load of single lift system was solved，so that multiple wells can product at the same time and the production of platform may be increased.
Due to the separate production of gas and oil，the production cycle is too long and the recovery ratio is low in Bozhong29-4 Oilfield，and the electric load cannot meet the needs of multi-well production at the same time since it reached its upper limit. Aiming at these problems，gas and ESP combination lift was proposed using the self-produced gas in the production wells to achieve the goal of oil and gas production at the same time. Production system composed of reservoir，wellbore and ESP-gas lift system was taken as the study object. The method of node analysis and dual system coupling design was used. Regarding the efficient coordination of production of gas lift and ESP as the goal，the method and steps of working parameters design under different conditions were given based on the power of the ESP. The optimized production project was determined eventually. The calculation results of a certain well show that the combination lift can effectively reduce the pump series and pump power to 40.2% and 40.6% of the original compared with single ESP lift system under the condition of same flow rate. The problem of large load of single lift system was solved，so that multiple wells can product at the same time and the production of platform may be increased.
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