Volume 23,Issue 4,2016 Table of Contents
2016, 23(4):1-10.
Abstract:
In recent years，commercial oil flow has been obtained in the lithologic reservoir found in Well Niu119，Niu100-side，and Feng14 where reservoir is known as slope-shifting fan. This reservoir rock is obviously different from turbidite and is presumed to be detached from the main delta and not completely liquefied. At present，there is little cognition and research on slope-shifting fan. In this paper，the sedimentary characteristics of the slope-shifting fan were studied in details through systematic core observation and outcrop description. The distribution pattern was established by detailed practical anatomy according to the sedimentary sequence of delta front-slope-shifting fan-turbidite. The results show that under the background of the wide slope zone in the fault depressed lacustrine basin，slope-shifting fan is formed when the front leaf of the delta，which accepts a rich sediment supply and progrades forwards rapidly，fractures under the influence of compressive settlement，earthquake and hydrodynamic conditions of lake water or flood，and then it slides forward，slumps and is fluidized，finally deposits at a suitable background of paleotopography before forming turbidite. This sand body is characterized by large thickness of single layer and multi-superimposed and continuous area. The slope-shifting fan sand has a typical longitudinal sequential pattern which，from bottom to top，successively includes dark color mudstone section，sliding deformation section，tensile deformation section，residual front section and block debris flow section. The slide sand，the slump sand and the debris flow sand，which are distributed in belts horizontally and have different longitudinal sequential patterns，are successively developed from slope belt to depression zone under the influence of sliding distance. Sliding sand/sliding-slumping sand，clastic sand and gravity turbidite are developed successively from slope to subsag area；gravity sands developed in different periods superimpose vertically from bottom to top，which are turbidite，clastic rock and sliding/ sliding-slumping rock.
In recent years，commercial oil flow has been obtained in the lithologic reservoir found in Well Niu119，Niu100-side，and Feng14 where reservoir is known as slope-shifting fan. This reservoir rock is obviously different from turbidite and is presumed to be detached from the main delta and not completely liquefied. At present，there is little cognition and research on slope-shifting fan. In this paper，the sedimentary characteristics of the slope-shifting fan were studied in details through systematic core observation and outcrop description. The distribution pattern was established by detailed practical anatomy according to the sedimentary sequence of delta front-slope-shifting fan-turbidite. The results show that under the background of the wide slope zone in the fault depressed lacustrine basin，slope-shifting fan is formed when the front leaf of the delta，which accepts a rich sediment supply and progrades forwards rapidly，fractures under the influence of compressive settlement，earthquake and hydrodynamic conditions of lake water or flood，and then it slides forward，slumps and is fluidized，finally deposits at a suitable background of paleotopography before forming turbidite. This sand body is characterized by large thickness of single layer and multi-superimposed and continuous area. The slope-shifting fan sand has a typical longitudinal sequential pattern which，from bottom to top，successively includes dark color mudstone section，sliding deformation section，tensile deformation section，residual front section and block debris flow section. The slide sand，the slump sand and the debris flow sand，which are distributed in belts horizontally and have different longitudinal sequential patterns，are successively developed from slope belt to depression zone under the influence of sliding distance. Sliding sand/sliding-slumping sand，clastic sand and gravity turbidite are developed successively from slope to subsag area；gravity sands developed in different periods superimpose vertically from bottom to top，which are turbidite，clastic rock and sliding/ sliding-slumping rock.
2016, 23(4):11-18.
Abstract:
Many abnormal sedimentary rocks are found in the lower Ganchaigou Formation，Kunbei step-fault zone of the southwestern margin of Qaidam Basin. The vertical sequence of seismites in the study area was researched further and its tectonic significance and importance to oil and gas accumulation were discussed. Through systemic observation and comparison of drilling cores from Well Qie8，Wu8，Yuedong110，Qie6，Hongdi107 and Lü13，symbols indicating the role of ancient earthquakes mainly include synsedimentary micro-fractures，earthquake cracks，liquefied sandstone veins，structures of vibration liquefaction and deformation，seismic turbidites，seismic breccia and collapsed structures. According to the occurring process of earthquake in the study area，the vertical vibration and liquefaction sequence of the seismites from top to bottom is as follows：seismically turbid bed，normal homogenized overlying bed，liquefied sandstone vein bed，seismites breccia bed，vibrational liquefaction deformation structure bed，ladder-shaped faulted bed and shattered rock bed. The discovery of the seismites can provide evidences for the study of ancient earthquakes. Through comparing the structural characteristics of the seismites，the seismic intensity was divided into five grades. Seismites can be used as a symbol of tectonic active period，indicating a strong period of tectonic activities. Seismites can not only be reservoir rock for oil and gas enrichment but also can be the carrier for oil and gas migration，which provides the conditions for hydrocarbon accumulation.
Many abnormal sedimentary rocks are found in the lower Ganchaigou Formation，Kunbei step-fault zone of the southwestern margin of Qaidam Basin. The vertical sequence of seismites in the study area was researched further and its tectonic significance and importance to oil and gas accumulation were discussed. Through systemic observation and comparison of drilling cores from Well Qie8，Wu8，Yuedong110，Qie6，Hongdi107 and Lü13，symbols indicating the role of ancient earthquakes mainly include synsedimentary micro-fractures，earthquake cracks，liquefied sandstone veins，structures of vibration liquefaction and deformation，seismic turbidites，seismic breccia and collapsed structures. According to the occurring process of earthquake in the study area，the vertical vibration and liquefaction sequence of the seismites from top to bottom is as follows：seismically turbid bed，normal homogenized overlying bed，liquefied sandstone vein bed，seismites breccia bed，vibrational liquefaction deformation structure bed，ladder-shaped faulted bed and shattered rock bed. The discovery of the seismites can provide evidences for the study of ancient earthquakes. Through comparing the structural characteristics of the seismites，the seismic intensity was divided into five grades. Seismites can be used as a symbol of tectonic active period，indicating a strong period of tectonic activities. Seismites can not only be reservoir rock for oil and gas enrichment but also can be the carrier for oil and gas migration，which provides the conditions for hydrocarbon accumulation.
2016, 23(4):19-26.
Abstract:
“Laminated marlstone”，which is an important part of the self-sourced tight reservoir system of Shulu sag，is defined simply as fine-grained carbonate rock with the single-layer thickness less than 1 cm and without any reference to the distinction in microscopic geometry and compositions of laminations. Based on the observation of cores and thin sections of the studied area，this paper focuses on studying the sedimentary characteristics and reservoir significance of laminations with the aid of X-ray diffraction，electron probe and stable isotope analysis. The carbonate-rich fine-grained laminations were grouped into two types：the seasonal rhythm laminae combination and the turbidity current graded laminae combination. The former constitute the laminated marlstone which consisted of lacustrine sediments formed by the physical，chemical and biological processes controlled by seasonal hydrology variations. The latter constitute the turbidity laminated marlstones and laminated calcisiltites which are turbidity current sediments deposited from a series of events. Laminae combination can influence reservoir property. Abundant interlayer fractures develop in seasonal rhythm laminae combinations，and the organic matter within the clastic lamina can improve reservoir quality through thermal maturation and hydrocarbon expulsion. Thus，the reservoir property of seasonal laminated marlstones are better than that of the turbidity laminated marlstone and laminated calcisiltites.
“Laminated marlstone”，which is an important part of the self-sourced tight reservoir system of Shulu sag，is defined simply as fine-grained carbonate rock with the single-layer thickness less than 1 cm and without any reference to the distinction in microscopic geometry and compositions of laminations. Based on the observation of cores and thin sections of the studied area，this paper focuses on studying the sedimentary characteristics and reservoir significance of laminations with the aid of X-ray diffraction，electron probe and stable isotope analysis. The carbonate-rich fine-grained laminations were grouped into two types：the seasonal rhythm laminae combination and the turbidity current graded laminae combination. The former constitute the laminated marlstone which consisted of lacustrine sediments formed by the physical，chemical and biological processes controlled by seasonal hydrology variations. The latter constitute the turbidity laminated marlstones and laminated calcisiltites which are turbidity current sediments deposited from a series of events. Laminae combination can influence reservoir property. Abundant interlayer fractures develop in seasonal rhythm laminae combinations，and the organic matter within the clastic lamina can improve reservoir quality through thermal maturation and hydrocarbon expulsion. Thus，the reservoir property of seasonal laminated marlstones are better than that of the turbidity laminated marlstone and laminated calcisiltites.
2016, 23(4):27-33.
Abstract:
On the basis of cores observation and samples analysis，the development features of deep-water turbidite fans in the block Che66 of Chezhen sag were analyzed and then the factors controlling development of deep-water turbidite fans were determined by using logging data and seismic data. The results show that deep-water turbidite fans in the block Che66 slumped and were buried deeply，and their lithology are cobble and pebble-conglomerates composed of micrite gravel，interbedded with thin or thick dark mudstone or shale. They graded poorly. Sand bodies of single stage are characterized by normal graded sequence，and they overlay each other in different stages in the whole with characters of reverse cycle changing coarse and thick upward. Four sets of sand body developed from the bottom in the lower third member of Shahejie Formation in the area with two provenances in northwest and northeast respectively，which overlay vertically. The sedimentary period of deep-water turbidite fans in Che66 area is corresponding to low stand system tract or lacustrine transgressive system tract of the 3rd grade sequences in the intensively faulting period. Their distributions are controlled by basin edge boundary fault activity，the occurrence and the development of the wide slope deep area in scraper structural fault resulted from the secondary fault and fracture development. There are typical turbidite rocks developed in such area under the configuration of source-slope-sag（source-faulted slope-sag）in the north of steep slope of Chezhen sag，and their distribution of fans are controlled by the double-source supply of different directions.
On the basis of cores observation and samples analysis，the development features of deep-water turbidite fans in the block Che66 of Chezhen sag were analyzed and then the factors controlling development of deep-water turbidite fans were determined by using logging data and seismic data. The results show that deep-water turbidite fans in the block Che66 slumped and were buried deeply，and their lithology are cobble and pebble-conglomerates composed of micrite gravel，interbedded with thin or thick dark mudstone or shale. They graded poorly. Sand bodies of single stage are characterized by normal graded sequence，and they overlay each other in different stages in the whole with characters of reverse cycle changing coarse and thick upward. Four sets of sand body developed from the bottom in the lower third member of Shahejie Formation in the area with two provenances in northwest and northeast respectively，which overlay vertically. The sedimentary period of deep-water turbidite fans in Che66 area is corresponding to low stand system tract or lacustrine transgressive system tract of the 3rd grade sequences in the intensively faulting period. Their distributions are controlled by basin edge boundary fault activity，the occurrence and the development of the wide slope deep area in scraper structural fault resulted from the secondary fault and fracture development. There are typical turbidite rocks developed in such area under the configuration of source-slope-sag（source-faulted slope-sag）in the north of steep slope of Chezhen sag，and their distribution of fans are controlled by the double-source supply of different directions.
2016, 23(4):34-40.
Abstract:
Oil wells are mainly drilled in mid-deep strata in Nanpu sag. Deep strata is the exploration focus in future.Based on high-quality seismic velocity data，speed correlation method and Fillippone formula calculation method were applied synthetically to the prediction of pressure distribution in mid-deep strata of Nanpu sag. This study shows that：①in the vertical，the top interface of overpressure is between 3 000 and 3 500 meters in Nanpu sag. Overpressure is mainly located in the second member of Dongying Formation and the strata below，which can be roughly divided into middle overpressure system and deep overpressure system；②in the plane，overpressure center migrates from south-central part to north-central part of the sag with depth increasing. The overpressure center of the Dongying Formation mainly locates in central Linque sub-sag and south seabeach area. The overpressure center in the Shahejie Formation mainly distributes in north Gaoshangpu-Liuzan Structure，Laoyemiao and Nanpu Structure5. The results may not only reduce the cost of exploration and development risk，but also provide reference to the exploration of mid-deep lithologic oil-gas reservoir. In terms of pressure prediction method，speed correlation method has higher precision，which is suitable for pressure prediction in Nanpu sag.
Oil wells are mainly drilled in mid-deep strata in Nanpu sag. Deep strata is the exploration focus in future.Based on high-quality seismic velocity data，speed correlation method and Fillippone formula calculation method were applied synthetically to the prediction of pressure distribution in mid-deep strata of Nanpu sag. This study shows that：①in the vertical，the top interface of overpressure is between 3 000 and 3 500 meters in Nanpu sag. Overpressure is mainly located in the second member of Dongying Formation and the strata below，which can be roughly divided into middle overpressure system and deep overpressure system；②in the plane，overpressure center migrates from south-central part to north-central part of the sag with depth increasing. The overpressure center of the Dongying Formation mainly locates in central Linque sub-sag and south seabeach area. The overpressure center in the Shahejie Formation mainly distributes in north Gaoshangpu-Liuzan Structure，Laoyemiao and Nanpu Structure5. The results may not only reduce the cost of exploration and development risk，but also provide reference to the exploration of mid-deep lithologic oil-gas reservoir. In terms of pressure prediction method，speed correlation method has higher precision，which is suitable for pressure prediction in Nanpu sag.
2016, 23(4):41-45.
Abstract:
Based on the seismic，core and slice data，it was found that the main factor for T sandstone reservoir abnormal variation in Colombia M oilfield is dynamic metamorphism caused by thrust fault through analyzing the characteristic of reservoir microscopic structure. The sedimentary environment of T sandstone is littoral-neritic sea，so the reservoir deposited steadily with good properties. Well-5 was drilled through a small thrust fault，of which two sets of T sandstones at the hanging wall and footwall were drilled. Those sandstones drilled are characterized by dense rock cementation，developed fracture，a large number of stylolites found out by microscope，concave and convex contact and stitching between particles，obvious quartz overgrowth and breccias and fracture and inter-granular pore filled with cement. It was analyzed firstly that the dynamic metamorphism resulted from thrust fault caused a local abnormal high pressure zone，in which the quartz grain was crushed and grounded to smaller grain size. Secondly，part quartz was dissolved by pressure solution to become stylolite.Thirdly，the dissolved siliceous cement deposited again and filled residual pore，leading to dense cementation and poor physical property. Combined with tectonic interpretation model and the surrounding well data，the scope of dynamic metamorphism was speculated to be within 15 m. In short，stress concentration is the geological background of dynamic metamorphism，and thrust fault is the direct reason of dynamic metamorphism. Because the range is limited，M oilfield could continue normal development.
Based on the seismic，core and slice data，it was found that the main factor for T sandstone reservoir abnormal variation in Colombia M oilfield is dynamic metamorphism caused by thrust fault through analyzing the characteristic of reservoir microscopic structure. The sedimentary environment of T sandstone is littoral-neritic sea，so the reservoir deposited steadily with good properties. Well-5 was drilled through a small thrust fault，of which two sets of T sandstones at the hanging wall and footwall were drilled. Those sandstones drilled are characterized by dense rock cementation，developed fracture，a large number of stylolites found out by microscope，concave and convex contact and stitching between particles，obvious quartz overgrowth and breccias and fracture and inter-granular pore filled with cement. It was analyzed firstly that the dynamic metamorphism resulted from thrust fault caused a local abnormal high pressure zone，in which the quartz grain was crushed and grounded to smaller grain size. Secondly，part quartz was dissolved by pressure solution to become stylolite.Thirdly，the dissolved siliceous cement deposited again and filled residual pore，leading to dense cementation and poor physical property. Combined with tectonic interpretation model and the surrounding well data，the scope of dynamic metamorphism was speculated to be within 15 m. In short，stress concentration is the geological background of dynamic metamorphism，and thrust fault is the direct reason of dynamic metamorphism. Because the range is limited，M oilfield could continue normal development.
2016, 23(4):46-52.
Abstract:
Based on the coexistence and asymmetric migration of coal bed methane（CBM）and coal roof tight sandstone （CRTS）gas of the southern area of Zhengzhuang-Fanzhuang block in Qinshui Basin，the concept of micro-transportation system was proposed for the process of symbiotic gas accumulation. The micro-transportation system was studied by using methods of the high pressure mercury injection，low-temperature liquid nitrogen adsorption and nuclear magnetic resonance（NMR）. After studying on the static characteristics and dynamic mechanism of micro-transportation system，it is found that the static micro-transportation system of the coal seam in the study area is mainly consist of transitional pores-micropores and high density and high angle fractures. The decreasing of pressure caused by tectonic uplift is the driving force for the coal seam gas micro-transportation. From the late Paleogene to now，changes in pressure caused by tectonic uplift result in the desorption of gas once adsorbed on coal and 14.29 m3 methane gas desorbed from one ton coal. Late in Paleogene （30 Ma），methane diffused according to Fick’s law within the scope of the coal rock aperture. Today methane diffuses transitionally in coal rock with the aperture of 5-15 nm，and diffuses according to Fick’s law in coal rock with the aperture of 15-100 nm.
Based on the coexistence and asymmetric migration of coal bed methane（CBM）and coal roof tight sandstone （CRTS）gas of the southern area of Zhengzhuang-Fanzhuang block in Qinshui Basin，the concept of micro-transportation system was proposed for the process of symbiotic gas accumulation. The micro-transportation system was studied by using methods of the high pressure mercury injection，low-temperature liquid nitrogen adsorption and nuclear magnetic resonance（NMR）. After studying on the static characteristics and dynamic mechanism of micro-transportation system，it is found that the static micro-transportation system of the coal seam in the study area is mainly consist of transitional pores-micropores and high density and high angle fractures. The decreasing of pressure caused by tectonic uplift is the driving force for the coal seam gas micro-transportation. From the late Paleogene to now，changes in pressure caused by tectonic uplift result in the desorption of gas once adsorbed on coal and 14.29 m3 methane gas desorbed from one ton coal. Late in Paleogene （30 Ma），methane diffused according to Fick’s law within the scope of the coal rock aperture. Today methane diffuses transitionally in coal rock with the aperture of 5-15 nm，and diffuses according to Fick’s law in coal rock with the aperture of 15-100 nm.
2016, 23(4):53-58.
Abstract:
By means of field geological survey，indoor rock slice observation，hydrocarbon source rock geochemical analysis and carbon isotope test，the characteristics of carbonate source rocks of late Paleozoic-Mesozoic in the northern margin of Beibu Gulf in Guangxi were studied in this paper. The results show that the abundance of organic matter in carbonate is generally high in the northern margin of Beibu Gulf in Guangxi，and its TOC ranges from 0.29% to 1.93% with mean value of 0.73%，which is above the hydrocarbon generation threshold. The type of organic matter is mainly typeⅠand a few of type Ⅱ. The thermal evolution of organic matter is in high maturity-over mature stage with Ro values ranging from 1.35% to 4.78%. The abundance of organic matter is characterized by low values of hydrocarbon generating potential，chloroform bitumen“A”content and total hydrocarbon content. The δ13C value of chloroform bitumen“A”ranges from -30.24‰ to -23.44‰，varying from light to heavy and then to light with the decreasing of stratigraphic age. And the distribution of normal paraffins also changes from unimodal to bimodal and then to unimodal，which suggests that the evolution of depositional environment is from marine facies to transitional facies and then to lake facies. The biomarker parameters such as Pr/Ph ratio，sterane and terpane indicate that lower aquatic organisms mainly contribute to the organic matter with some terrestrial organic matter and they were deposited in reducing environment of brackish water.
By means of field geological survey，indoor rock slice observation，hydrocarbon source rock geochemical analysis and carbon isotope test，the characteristics of carbonate source rocks of late Paleozoic-Mesozoic in the northern margin of Beibu Gulf in Guangxi were studied in this paper. The results show that the abundance of organic matter in carbonate is generally high in the northern margin of Beibu Gulf in Guangxi，and its TOC ranges from 0.29% to 1.93% with mean value of 0.73%，which is above the hydrocarbon generation threshold. The type of organic matter is mainly typeⅠand a few of type Ⅱ. The thermal evolution of organic matter is in high maturity-over mature stage with Ro values ranging from 1.35% to 4.78%. The abundance of organic matter is characterized by low values of hydrocarbon generating potential，chloroform bitumen“A”content and total hydrocarbon content. The δ13C value of chloroform bitumen“A”ranges from -30.24‰ to -23.44‰，varying from light to heavy and then to light with the decreasing of stratigraphic age. And the distribution of normal paraffins also changes from unimodal to bimodal and then to unimodal，which suggests that the evolution of depositional environment is from marine facies to transitional facies and then to lake facies. The biomarker parameters such as Pr/Ph ratio，sterane and terpane indicate that lower aquatic organisms mainly contribute to the organic matter with some terrestrial organic matter and they were deposited in reducing environment of brackish water.
2016, 23(4):59-63.
Abstract:
Conglomerate reservoir in Shengli Oil Region is of large scale of reserves，but a series of development difficulties，such as reservoir complexity，unclear connectivity patterns，poor correspondence between injection and production and unknown development laws，severely restrict the effective development of such reservoirs. Taking Yong1 conglomerate reservoir in Dongxin oilfield as an example，the sedimentary types in the area were determined with integrated application of multiple sources of data，by which the sedimentary sequence was classified to make reservoir connectivity patterns clear.The studied results show that conglomeratic reservoir development is controlled by sedimentary facies of the fourth member of Shahejie Formation in the study area，and the favorable reservoirs locate in the main channel at the root of the fan and the braided channel at the middle of the fan with lithology of fine conglomerate and pebbled sandstone. Nine sedimentary sequences were divided for the conglomerate in the area through seismic and drilling data. According to reservoir inversion results，it is considered that the reservoirs developed well in the 1st-5th sedimentary sequences which are characterized by good connectivity and physical properties，and they can be the later development targets. Three connectivity patterns of effective reservoirs were classified through dynamic and geologic data，which are connectivity within facies of the same sedimentary period，vertical connectivity in different sedimentary periods and horizontal connectivity in different sedimentary periods. On this basis，injection-production well patterns for Block Yong1 were optimized. As a result，the recovery capacity of old wells have been improved greatly. For example，the production capacity of Well Yong1-55 increased from 4 t/d to12 t/d after the optimization. The conglomeratic reservoir development is guided effectively.
Conglomerate reservoir in Shengli Oil Region is of large scale of reserves，but a series of development difficulties，such as reservoir complexity，unclear connectivity patterns，poor correspondence between injection and production and unknown development laws，severely restrict the effective development of such reservoirs. Taking Yong1 conglomerate reservoir in Dongxin oilfield as an example，the sedimentary types in the area were determined with integrated application of multiple sources of data，by which the sedimentary sequence was classified to make reservoir connectivity patterns clear.The studied results show that conglomeratic reservoir development is controlled by sedimentary facies of the fourth member of Shahejie Formation in the study area，and the favorable reservoirs locate in the main channel at the root of the fan and the braided channel at the middle of the fan with lithology of fine conglomerate and pebbled sandstone. Nine sedimentary sequences were divided for the conglomerate in the area through seismic and drilling data. According to reservoir inversion results，it is considered that the reservoirs developed well in the 1st-5th sedimentary sequences which are characterized by good connectivity and physical properties，and they can be the later development targets. Three connectivity patterns of effective reservoirs were classified through dynamic and geologic data，which are connectivity within facies of the same sedimentary period，vertical connectivity in different sedimentary periods and horizontal connectivity in different sedimentary periods. On this basis，injection-production well patterns for Block Yong1 were optimized. As a result，the recovery capacity of old wells have been improved greatly. For example，the production capacity of Well Yong1-55 increased from 4 t/d to12 t/d after the optimization. The conglomeratic reservoir development is guided effectively.
2016, 23(4):64-69.
Abstract:
Reef-beach limestone is the chief gas reservoir of Amu Darya Basin in Turkmenistan beneath the thick gypsum and salt formations. It is greatly difficult to identify and drill the reef. In order to solve the hard technical problems of reef recognition under salt in Amu Darya Right Bank gas field，several seismic and geological researches were carried out，including auxiliary interpretation of forward modeling，reconstruction of palaeo-geomorphology，discontinuous seismic multiattribute extraction，wave impedance inversion and isochronous stratigraphic slice，etc. A set of effective identification and geological evaluation techniques was established for reef beneath the salt. Conditions of trap formation and the spatial distribution characteristics of reef-beach traps beneath the gypsum were determined after research results of multi-methods were synthesized to be confirmed and supplemented by each other in the area. On that basis，the development characteristics and distribution of reef-beach in Amu Darya Right Bank Block were predicted and evaluated to help identify and optimize drilling targets. As a result，the success drilling rate of exploration wells and appraisal wells remained at more than 90% in the area.
Reef-beach limestone is the chief gas reservoir of Amu Darya Basin in Turkmenistan beneath the thick gypsum and salt formations. It is greatly difficult to identify and drill the reef. In order to solve the hard technical problems of reef recognition under salt in Amu Darya Right Bank gas field，several seismic and geological researches were carried out，including auxiliary interpretation of forward modeling，reconstruction of palaeo-geomorphology，discontinuous seismic multiattribute extraction，wave impedance inversion and isochronous stratigraphic slice，etc. A set of effective identification and geological evaluation techniques was established for reef beneath the salt. Conditions of trap formation and the spatial distribution characteristics of reef-beach traps beneath the gypsum were determined after research results of multi-methods were synthesized to be confirmed and supplemented by each other in the area. On that basis，the development characteristics and distribution of reef-beach in Amu Darya Right Bank Block were predicted and evaluated to help identify and optimize drilling targets. As a result，the success drilling rate of exploration wells and appraisal wells remained at more than 90% in the area.
2016, 23(4):70-75.
Abstract:
Accessibility，stability and regeneration of the foam in various permeabilities and pore-throats were studied using etched glass micro-model and sand pack core model. Microscopic profile control and displacement mechanism under different permeabilities were studied. The foam has the lowest injection pressure. Foam stability gets better in high permeability layers；regeneration of foam is closely related to pore-throat size，pore-throat ratio and pore coordination number；oil washing and plugging by profile control of the foam in various pore-throats may enhance oil recovery with different contribution ratios. In high permeability and large pore-throat layers，the enhancement of recovery relies on plugging by profile control；while in low permeability and small pore-throat layers，oil washing is the main function. In the future，application of the foam to reservoir heterogeneity modification will be the research direction of oilfield chemistry.
Accessibility，stability and regeneration of the foam in various permeabilities and pore-throats were studied using etched glass micro-model and sand pack core model. Microscopic profile control and displacement mechanism under different permeabilities were studied. The foam has the lowest injection pressure. Foam stability gets better in high permeability layers；regeneration of foam is closely related to pore-throat size，pore-throat ratio and pore coordination number；oil washing and plugging by profile control of the foam in various pore-throats may enhance oil recovery with different contribution ratios. In high permeability and large pore-throat layers，the enhancement of recovery relies on plugging by profile control；while in low permeability and small pore-throat layers，oil washing is the main function. In the future，application of the foam to reservoir heterogeneity modification will be the research direction of oilfield chemistry.
2016, 23(4):76-81.
Abstract:
In order to analyze the effect of lithology on in-situ combustion better and to improve its recovery efficiency，advance mechanism of in-situ combustion front and composition changes of output must be understood clearly. One dimensional simulation model of the in-situ combustion was applied to study the effect of sandstone and glutenite on front advance distance，front advance rate and peak temperature of the in-situ combustion under different gas injection pressures or gas injection flow rates，as well as the content and composition of produced liquid，gas and residual oil sands and their variation patterns. The results show that as the gas injection flow rate and pressure increased，the front advance distance in the glutenite is longer than that in the sandstone，while its advance rate and peak temperature is lower than that in the sandstone；liquid and oil produced from the glutenite is more than those from the sandstone，and except under lower pressure or flow rate，the proportion of low-carbon number saturated hydrocarbon in the produced liquid of the glutenite is relatively high，while that of high-carbon number saturated hydrocarbon in the produced liquid of sandstone is relatively high. When the gas injection pressure is below 2.0 MPa，the proportion of aromatic hydrocarbon in the produced liquid of the sandstone is relatively high，while that of aromatic hydrocarbon in the produced liquid of the glutenite is relatively high when the gas injection pressure is above 2.0 MPa. In flow experiment，the proportion of aromatic hydrocarbon in the produced liquid of the glutenite is higher than that in the produced liquid of the sandstone. Experiment results of elemental microanalysis and infrared spectra analysis show that organic element content of the residual oil sands in the glutenite is higher，and colloid and asphaltine is more likely to be driven out of the glutenite. Considering various factors，glutenite reservoir is more suit? able than sandstone reservoir for the in-situ combustion.
In order to analyze the effect of lithology on in-situ combustion better and to improve its recovery efficiency，advance mechanism of in-situ combustion front and composition changes of output must be understood clearly. One dimensional simulation model of the in-situ combustion was applied to study the effect of sandstone and glutenite on front advance distance，front advance rate and peak temperature of the in-situ combustion under different gas injection pressures or gas injection flow rates，as well as the content and composition of produced liquid，gas and residual oil sands and their variation patterns. The results show that as the gas injection flow rate and pressure increased，the front advance distance in the glutenite is longer than that in the sandstone，while its advance rate and peak temperature is lower than that in the sandstone；liquid and oil produced from the glutenite is more than those from the sandstone，and except under lower pressure or flow rate，the proportion of low-carbon number saturated hydrocarbon in the produced liquid of the glutenite is relatively high，while that of high-carbon number saturated hydrocarbon in the produced liquid of sandstone is relatively high. When the gas injection pressure is below 2.0 MPa，the proportion of aromatic hydrocarbon in the produced liquid of the sandstone is relatively high，while that of aromatic hydrocarbon in the produced liquid of the glutenite is relatively high when the gas injection pressure is above 2.0 MPa. In flow experiment，the proportion of aromatic hydrocarbon in the produced liquid of the glutenite is higher than that in the produced liquid of the sandstone. Experiment results of elemental microanalysis and infrared spectra analysis show that organic element content of the residual oil sands in the glutenite is higher，and colloid and asphaltine is more likely to be driven out of the glutenite. Considering various factors，glutenite reservoir is more suit? able than sandstone reservoir for the in-situ combustion.
2016, 23(4):82-87.
Abstract:
In order to further understand the seepage characteristics and differences of oil displacement agent in artificial cores and natural cores，pore structure of the artificial cores and natural cores and its effect on the seepage characteristics of oil displacement agent were tested in Sazhong reservoirs of Daqing oilfield by means of test，chemical analysis and physical simulation theoretically guided by polymer materials science，physical chemistry and reservoir engineering. The results show that the natural cores have the features of more complicated pore structure，poorer sorting system，worse connectivity，stronger heterogeneity and different pore-throat size compared with the artificial cores. The main difference of pore structure between low permeability and high permeability artificial cores is the pore-throat radius. When the flow of polymer solution，polymer/surfactant binary compound system，strong base ternary compound system and weak base ternary compound system gets stable，the average ratio of resistance coefficient of the natural cores to that of the artificial cores is 1.69，1.73，1.78 and 1.65 respectively，which indicates that the natural cores have larger hold-up volume of oil displacement agent，greater seepage resistance and higher injection pressure but the pressure value still tends to be stable and plugging will not occur in the natural cores compared with the artificial cores.
In order to further understand the seepage characteristics and differences of oil displacement agent in artificial cores and natural cores，pore structure of the artificial cores and natural cores and its effect on the seepage characteristics of oil displacement agent were tested in Sazhong reservoirs of Daqing oilfield by means of test，chemical analysis and physical simulation theoretically guided by polymer materials science，physical chemistry and reservoir engineering. The results show that the natural cores have the features of more complicated pore structure，poorer sorting system，worse connectivity，stronger heterogeneity and different pore-throat size compared with the artificial cores. The main difference of pore structure between low permeability and high permeability artificial cores is the pore-throat radius. When the flow of polymer solution，polymer/surfactant binary compound system，strong base ternary compound system and weak base ternary compound system gets stable，the average ratio of resistance coefficient of the natural cores to that of the artificial cores is 1.69，1.73，1.78 and 1.65 respectively，which indicates that the natural cores have larger hold-up volume of oil displacement agent，greater seepage resistance and higher injection pressure but the pressure value still tends to be stable and plugging will not occur in the natural cores compared with the artificial cores.
2016, 23(4):88-94.
Abstract:
In order to better exert the effect of controlling water and stabilizing oil for nano/micron-sized polymer particles dispersion system in low permeability reservoir，viscosity properties，rheological properties and plugging performances of the system were studied，and the influence of injection pressure，permeability，hydration time，mass concentration and injection rate on plugging performances in cores were investigated. The test results show that the polymer particles dispersion system has a small viscosity which is a pseudo plastic fluid with shear thinning. Meanwhile，it has good injection characteristics and plugging effect. When polymer particles dispersion system is injected into cores，its injection pressure has the trend of fluctuation. With a certain hydration time，mass concentration and injection rate，the interval where the ratio of average particle diameter to average throat diameter is less than 0.16 is the weak plugging region，and where the ratio of average particle diameter to average throat diameter is more than 0.32 is the strong plugging region，and where the ratio is between 0.16 and 0.32 is the medium plugging region. Moreover，the area of the weak plugging region increases and the strong region decreases with increasing hydration time. With a certain hydration time，injection rate and core permeability，the interval where particle concentration is less than 1.0 g/L is the weak plugging region and where particle concentration is more than 2.0 g/L is the strong plugging region. With a certain hydration time，mass concentration and core permeability，the interval where injection rate is less than 0.1 mL/min is the weak plugging region and where injection rate is more than 0.5 mL/min is the strong plugging region.
In order to better exert the effect of controlling water and stabilizing oil for nano/micron-sized polymer particles dispersion system in low permeability reservoir，viscosity properties，rheological properties and plugging performances of the system were studied，and the influence of injection pressure，permeability，hydration time，mass concentration and injection rate on plugging performances in cores were investigated. The test results show that the polymer particles dispersion system has a small viscosity which is a pseudo plastic fluid with shear thinning. Meanwhile，it has good injection characteristics and plugging effect. When polymer particles dispersion system is injected into cores，its injection pressure has the trend of fluctuation. With a certain hydration time，mass concentration and injection rate，the interval where the ratio of average particle diameter to average throat diameter is less than 0.16 is the weak plugging region，and where the ratio of average particle diameter to average throat diameter is more than 0.32 is the strong plugging region，and where the ratio is between 0.16 and 0.32 is the medium plugging region. Moreover，the area of the weak plugging region increases and the strong region decreases with increasing hydration time. With a certain hydration time，injection rate and core permeability，the interval where particle concentration is less than 1.0 g/L is the weak plugging region and where particle concentration is more than 2.0 g/L is the strong plugging region. With a certain hydration time，mass concentration and core permeability，the interval where injection rate is less than 0.1 mL/min is the weak plugging region and where injection rate is more than 0.5 mL/min is the strong plugging region.
2016, 23(4):95-101.
Abstract:
A binary system was formed with the addition of the anionic surfactant SDS into amphiphilic polymer solution with different hydrophobic groups. The interactions between hydrophobic groups，SDS and amphiphilic polymer and the binary system were studied by using rheological measurements，dynamic light scattering and pyrene fluorescence probe. The results show that due to the effect of hydrophobic association and electrical property，SDS will interact with amphiphilic polymers in the aqueous solution. At a low concentration of SDS（0-50 mg/L），the apparent viscosity of the binary system solution will have dynamic increase and the fluorescence spectrum of pyrene I1/I3 value will be decreased obviously. This suggests that the increasing of apparent viscosity is mainly because the hydrophobic association of micro ranges is enhanced by surfactant，and the size and strength of the original space grid structure are also increased in the solution. When the concentration of SDS is higher，the apparent viscosity of the solution starts to go down rapidly. Strong association and electrostatic action result in the separation of the aggregations of the amphiphilic polymer and the formation of mixed aggregations. A lot of small-molecule surfactants is added，which makes the dynamic diameter of the mixed aggregations fluid decrease. And viscosity and viscoelasticity of the solution drop. Comparing rules of different number of carbon atoms（dodecyl，hexadecyl and octadecyl）in hydrophobic groups，it is found that the influence of SDS on the amphiphilic polymer with hydrophobic monomer of N-octadecyl acrylamide is minimal. This is because that along with the increasing of the number of carbon atoms，the association strength of the hydrophobic groups in the amphiphilic polymer is higher，and repulsive interactions among high molecules become weaker and the aggregate structure is closer，and it will be harder to be dissociated and recombined by SDS.
A binary system was formed with the addition of the anionic surfactant SDS into amphiphilic polymer solution with different hydrophobic groups. The interactions between hydrophobic groups，SDS and amphiphilic polymer and the binary system were studied by using rheological measurements，dynamic light scattering and pyrene fluorescence probe. The results show that due to the effect of hydrophobic association and electrical property，SDS will interact with amphiphilic polymers in the aqueous solution. At a low concentration of SDS（0-50 mg/L），the apparent viscosity of the binary system solution will have dynamic increase and the fluorescence spectrum of pyrene I1/I3 value will be decreased obviously. This suggests that the increasing of apparent viscosity is mainly because the hydrophobic association of micro ranges is enhanced by surfactant，and the size and strength of the original space grid structure are also increased in the solution. When the concentration of SDS is higher，the apparent viscosity of the solution starts to go down rapidly. Strong association and electrostatic action result in the separation of the aggregations of the amphiphilic polymer and the formation of mixed aggregations. A lot of small-molecule surfactants is added，which makes the dynamic diameter of the mixed aggregations fluid decrease. And viscosity and viscoelasticity of the solution drop. Comparing rules of different number of carbon atoms（dodecyl，hexadecyl and octadecyl）in hydrophobic groups，it is found that the influence of SDS on the amphiphilic polymer with hydrophobic monomer of N-octadecyl acrylamide is minimal. This is because that along with the increasing of the number of carbon atoms，the association strength of the hydrophobic groups in the amphiphilic polymer is higher，and repulsive interactions among high molecules become weaker and the aggregate structure is closer，and it will be harder to be dissociated and recombined by SDS.
2016, 23(4):102-107.
Abstract:
In recent years，as a main mechanism of water driving in fractured tight sandstone reservoirs，imbibition is widely concerned. In view of the shortcomings of the current experimental research of imbibition，taking Chang8 reservoir of Wuqi area in Ordos Basin as target，the characteristics of the reservoir and the main influence factors of imbibition were analyzed by using low-temperature nitrogen adsorption，high pressure mercury injection and Amott methods，as well as nuclear magnetic resonance（NMR）technology. The experimental results show that as a water-wet reservoir，the formation is dominant by narrow slit-like pores with micro-and mesopore size. The throat is scattered and the reservoir belongs to fine throat and micro-fine pore type. Among the main factors which affect recovery efficiency of the imbibition，reservoir quality and maximum pore throat radius have positive correlation with the recovery efficiency of the imbibition，and specific surface area has negative correlation with the recovery efficiency. The increase of relative wettability index and the decrease of interfacial tension are favorable to the process of imbibition. So imbibition is obvious in hydrophilic tight sandstone reservoir with good pore structure and pore-throat connectivity，and imbibition after the hydraulic fracturing will play a positive role in the development of reservoir.
In recent years，as a main mechanism of water driving in fractured tight sandstone reservoirs，imbibition is widely concerned. In view of the shortcomings of the current experimental research of imbibition，taking Chang8 reservoir of Wuqi area in Ordos Basin as target，the characteristics of the reservoir and the main influence factors of imbibition were analyzed by using low-temperature nitrogen adsorption，high pressure mercury injection and Amott methods，as well as nuclear magnetic resonance（NMR）technology. The experimental results show that as a water-wet reservoir，the formation is dominant by narrow slit-like pores with micro-and mesopore size. The throat is scattered and the reservoir belongs to fine throat and micro-fine pore type. Among the main factors which affect recovery efficiency of the imbibition，reservoir quality and maximum pore throat radius have positive correlation with the recovery efficiency of the imbibition，and specific surface area has negative correlation with the recovery efficiency. The increase of relative wettability index and the decrease of interfacial tension are favorable to the process of imbibition. So imbibition is obvious in hydrophilic tight sandstone reservoir with good pore structure and pore-throat connectivity，and imbibition after the hydraulic fracturing will play a positive role in the development of reservoir.
2016, 23(4):108-111.
Abstract:
Horizontal well productivity in bottom-water reservoir is an important content in the research of reservoir engineering analysis. The existing productivity formula for the bottom-water reservoir are based on short horizontal well flow model，which is not applicable to long horizontal well productivity calculation. In order to evaluate long horizontal well productivity more accurately，productivity formula for long horizontal well in bottom-water reservoir was deduced by using equivalent filtrational resistance，potential superposition principle and mirror image method considering both anisotropy and height of water avoidance. The case study shows that the anisotropy has a significant effect on the long horizontal well productivity. The production predicted by the new formula decreased by 53.52% compared with that obtained from the formula that neglects the effect of anisotropy. Oil production will be exaggerated when using short horizontal well productivity model to predict the long horizontal well. The maximum value can reach 5.01 times that of actual production. Calculation result of long horizontal well productivity model proposed in this paper for the bottom-water reservoir is more accurate than that before.
Horizontal well productivity in bottom-water reservoir is an important content in the research of reservoir engineering analysis. The existing productivity formula for the bottom-water reservoir are based on short horizontal well flow model，which is not applicable to long horizontal well productivity calculation. In order to evaluate long horizontal well productivity more accurately，productivity formula for long horizontal well in bottom-water reservoir was deduced by using equivalent filtrational resistance，potential superposition principle and mirror image method considering both anisotropy and height of water avoidance. The case study shows that the anisotropy has a significant effect on the long horizontal well productivity. The production predicted by the new formula decreased by 53.52% compared with that obtained from the formula that neglects the effect of anisotropy. Oil production will be exaggerated when using short horizontal well productivity model to predict the long horizontal well. The maximum value can reach 5.01 times that of actual production. Calculation result of long horizontal well productivity model proposed in this paper for the bottom-water reservoir is more accurate than that before.
2016, 23(4):112-116.
Abstract:
In order to solve the problem of long water drainage period with low efficiency in No.15 coalbed methane of Qinshui basin and to avoid the effect of the aquifer in the K2 limestone above the No.15 coal bed on CBM development，horizontal well was applied for gas recovery by water drainage in roof water of the coalbed methane reservoir to enhance coalbed methane recovery efficiency. Flow mechanism model was established by numerical simulation. Effect of gas recovery by water drainage on the No.15 coal seam and K2 roof limestone and its influencing factors were researched. The simulation results show that the technique can significantly reduce the time of the water drainage and pressure drop and increase the cumulative gas production. The location of horizontal well in the roof，the angle between horizontal well and vertical fracturing crack and horizontal section length are related to CBM production. Water drainage intensity is related to the gas breakthrough time of CBM. The longer the horizontal section length is，the higher the gas production is. The production effect of the horizontal well that is located in the middle of the K2 limestone is better than that of the well located in the bottom.When the angle between horizontal well and the vertical fracturing crack is 45 degree，the gas production effect is the best.The water drainage intensity of horizontal well has a great influence on the time of gas breakthrough，and less influence on the cumulative gas production.
In order to solve the problem of long water drainage period with low efficiency in No.15 coalbed methane of Qinshui basin and to avoid the effect of the aquifer in the K2 limestone above the No.15 coal bed on CBM development，horizontal well was applied for gas recovery by water drainage in roof water of the coalbed methane reservoir to enhance coalbed methane recovery efficiency. Flow mechanism model was established by numerical simulation. Effect of gas recovery by water drainage on the No.15 coal seam and K2 roof limestone and its influencing factors were researched. The simulation results show that the technique can significantly reduce the time of the water drainage and pressure drop and increase the cumulative gas production. The location of horizontal well in the roof，the angle between horizontal well and vertical fracturing crack and horizontal section length are related to CBM production. Water drainage intensity is related to the gas breakthrough time of CBM. The longer the horizontal section length is，the higher the gas production is. The production effect of the horizontal well that is located in the middle of the K2 limestone is better than that of the well located in the bottom.When the angle between horizontal well and the vertical fracturing crack is 45 degree，the gas production effect is the best.The water drainage intensity of horizontal well has a great influence on the time of gas breakthrough，and less influence on the cumulative gas production.
2016, 23(4):117-121.
Abstract:
Effect of hydraulic sand fracturing depends on flow conductivity of fracture to some extent. Influenced by formation lithology，proppant type and closure pressure，flow conductivity of the fractures dropped quickly in tight carbonate reservoirs，which may has an impact on recovery percent of reserves. How to choose the proppant to improve fracture flow conductivity at high closure pressure is very important. The evaluation experiment of flow conductivity of propped fracture by hydraulic sand fracturing in the tight carbonate rocks was carried out with various types of proppants using multi-function testing and analysis system for flow conductivity of the fractures. The results show that with the increase of the closure pressure，the drop rate of fracture flow conductivity using 16/30 mesh medium-tenacity ceramsite proppant is significantly higher than that using 20/40 mesh medium-tenacity ceramsite proppant；when the closure pressure exceeds 69 MPa，the flow conductivities were similar for both proppants；however，the flow conductivities of fractures are quite different from each other if using high-tenacity ceramsite proppants having the same size with the former two. The flow conductivity of multisized high-tenacity ceramsite proppant is similar to that of 16/30 mesh high-tenacity ceramsite proppant，but the breakage rate of single-sized proppant is larger，which cause more formation damage. Under high closure pressure，the flow conductivity of several kinds of multi-sized proppant was tested，and the best was selected as 16/30 mesh（60%）+20/40 mesh（20%）+30/50 mesh（20%）.
Effect of hydraulic sand fracturing depends on flow conductivity of fracture to some extent. Influenced by formation lithology，proppant type and closure pressure，flow conductivity of the fractures dropped quickly in tight carbonate reservoirs，which may has an impact on recovery percent of reserves. How to choose the proppant to improve fracture flow conductivity at high closure pressure is very important. The evaluation experiment of flow conductivity of propped fracture by hydraulic sand fracturing in the tight carbonate rocks was carried out with various types of proppants using multi-function testing and analysis system for flow conductivity of the fractures. The results show that with the increase of the closure pressure，the drop rate of fracture flow conductivity using 16/30 mesh medium-tenacity ceramsite proppant is significantly higher than that using 20/40 mesh medium-tenacity ceramsite proppant；when the closure pressure exceeds 69 MPa，the flow conductivities were similar for both proppants；however，the flow conductivities of fractures are quite different from each other if using high-tenacity ceramsite proppants having the same size with the former two. The flow conductivity of multisized high-tenacity ceramsite proppant is similar to that of 16/30 mesh high-tenacity ceramsite proppant，but the breakage rate of single-sized proppant is larger，which cause more formation damage. Under high closure pressure，the flow conductivity of several kinds of multi-sized proppant was tested，and the best was selected as 16/30 mesh（60%）+20/40 mesh（20%）+30/50 mesh（20%）.
2016, 23(4):122-126.
Abstract:
Tight oil reservoirs require higher fracture conductivity compared to the tight gas reservoirs，and shale content is usually higher in the tight oil reservoirs resulting in serious embedment of fracturing proppant in rock. Conventional proppant embedment tests do not consider the influence of rock mineral composition，mechanical properties and fracturing fluids，which leads to the incorrect understand of the impact of proppant embedment on the conductivity and great difficulty of optimization on sand concentration and proppant selection. Mineral composition and mechanical parameters of the rock in tight oil reservoirs were analyzed. Self-developed measuring instrument of embedment and conductivity was applied to embedment test using cores soaked with various liquids and non-soaked ones. The results of experimental data show that the embedded depth of the proppant increases with the closure pressure and the proppant diameter and decreases with the sand concentration increasing. The embedded depth is relatively small when the brittle mineral content is relatively high and the clay content is relatively low. The embedded depth in soaked core is larger than that in the original core. The cores soaked with KCl can obtain a smaller embedded depth than the cores soaked with fresh water. The research concludes that the damage of the proppant embedment on the conductivity can be reduced by strengthening anti-swelling capacity of fracturing fluid and applying proppant with diameter as large as possible.
Tight oil reservoirs require higher fracture conductivity compared to the tight gas reservoirs，and shale content is usually higher in the tight oil reservoirs resulting in serious embedment of fracturing proppant in rock. Conventional proppant embedment tests do not consider the influence of rock mineral composition，mechanical properties and fracturing fluids，which leads to the incorrect understand of the impact of proppant embedment on the conductivity and great difficulty of optimization on sand concentration and proppant selection. Mineral composition and mechanical parameters of the rock in tight oil reservoirs were analyzed. Self-developed measuring instrument of embedment and conductivity was applied to embedment test using cores soaked with various liquids and non-soaked ones. The results of experimental data show that the embedded depth of the proppant increases with the closure pressure and the proppant diameter and decreases with the sand concentration increasing. The embedded depth is relatively small when the brittle mineral content is relatively high and the clay content is relatively low. The embedded depth in soaked core is larger than that in the original core. The cores soaked with KCl can obtain a smaller embedded depth than the cores soaked with fresh water. The research concludes that the damage of the proppant embedment on the conductivity can be reduced by strengthening anti-swelling capacity of fracturing fluid and applying proppant with diameter as large as possible.
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