Volume 28,Issue 3,2021 Table of Contents
SONG Mingshui
,
MAO Shuwei
,
LIN Huixi
,
HAO Xuefeng
,
GONG Jianqiang
,
ZHANG Pengfei
,
QIU Yibo
,
WANG Yuanyuan
2021, 28(3):1-13.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.03.001
Abstract:
Through comprehensive analysis of core observation and drilling，logging，and seismic data，and guided by highresolution sequence stratigraphy and theories of sedimentology，the sublacustrine fan sand bodies in the Middle Es3 in Minfeng area were finely characterized and studied by reconstructed wave impedance inversion. The results show that the deepwater sublacustrine fan deposits in Middle Es3 is mainly affected by the NE provenance system in Yong’an Town delta.Four sedimentary types of sand bodies are developed，i.e.，sliding-slump current，sandy debris current，turbidity current，and bottom current reworked sand bodies，and seven types of lithofacies are identified in the study area. On the plane，the sedimentary evolution of the sublacustrine fan are dominated by high-density sliding-slump current in the inner fan，sandy debris current in the middle fan，and turbidity current in the outer fan，which are differentially distributed on the strata with different relative paleoslopes. Further analysis shows that different lithofacies and their assemblages of the sand bodies are controlled by the multi-period base-level cycles，and most of them are developed at the top-bottom interfaces of short-and ultra-short-term cycles. Debris current tongues and turbidite lobes are developed well and they are mutually cut and superposed when the base level is in the descending semi-cycle（A/S falls）. On the contrary，they often are developed in isolation or in beads when the base level is in the ascending semi-cycle（A/S rises）；moreover，they are easily reformed by bottom current，forming small-scale vein-like or wave-like bedding，part of which can be cut and redeposited.
Through comprehensive analysis of core observation and drilling，logging，and seismic data，and guided by highresolution sequence stratigraphy and theories of sedimentology，the sublacustrine fan sand bodies in the Middle Es3 in Minfeng area were finely characterized and studied by reconstructed wave impedance inversion. The results show that the deepwater sublacustrine fan deposits in Middle Es3 is mainly affected by the NE provenance system in Yong’an Town delta.Four sedimentary types of sand bodies are developed，i.e.，sliding-slump current，sandy debris current，turbidity current，and bottom current reworked sand bodies，and seven types of lithofacies are identified in the study area. On the plane，the sedimentary evolution of the sublacustrine fan are dominated by high-density sliding-slump current in the inner fan，sandy debris current in the middle fan，and turbidity current in the outer fan，which are differentially distributed on the strata with different relative paleoslopes. Further analysis shows that different lithofacies and their assemblages of the sand bodies are controlled by the multi-period base-level cycles，and most of them are developed at the top-bottom interfaces of short-and ultra-short-term cycles. Debris current tongues and turbidite lobes are developed well and they are mutually cut and superposed when the base level is in the descending semi-cycle（A/S falls）. On the contrary，they often are developed in isolation or in beads when the base level is in the ascending semi-cycle（A/S rises）；moreover，they are easily reformed by bottom current，forming small-scale vein-like or wave-like bedding，part of which can be cut and redeposited.
2021, 28(3):14-24.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.03.002
Abstract:
With core，thin section，grading analysis，well log and seismic data，the types and sedimentary characteristics of sediment gravity flows of Ed3 Member in the east slope of Chengdao area，Bozhong Sag are studied，and the distribution of gravity flows sand is summarized to establish the gravity flow sedimentary models of the slope zone with gullies and slope breaks on it. Hyperpycnal flows，sandy debris flows，and turbidity currents are developed in Ed3 Member of the study area，according to the results. Hyperpycnal flows account for the largest proportion and are widely distributed in the first slopebreak zone，the second slope-break zone，sub-sag zone，and southeastern gullies in the central north of the study area. Inversely graded to normally graded mixed bedding as well as overstep of normally graded bedding and intrastratal erosion surface are developed in channels；massive，parallel，climbing ripple，and wavy bedding is developed in lobes；carbon dusts are seen mostly in sediments. Sandy debris flows are distributed under slope-break zones and in gullies where sedimentary structures such as massive bedding，planar structures，floating mud gravel，and coarse sand mass in fine sandstone are developed. Turbidity currents are distributed in the sub-sag zone where the Bouma sequence is developed，which is mostly thin interbedding of siltstone and lacustrine mudstone. The development of gravity flow sands is controlled by gullies and slope breaks. The sands are in a zonal distribution along gullies，and pinches out under slope breaks，forming a series of independent sands with poor continuity，which is of great significance for oil and gas exploration.
With core，thin section，grading analysis，well log and seismic data，the types and sedimentary characteristics of sediment gravity flows of Ed3 Member in the east slope of Chengdao area，Bozhong Sag are studied，and the distribution of gravity flows sand is summarized to establish the gravity flow sedimentary models of the slope zone with gullies and slope breaks on it. Hyperpycnal flows，sandy debris flows，and turbidity currents are developed in Ed3 Member of the study area，according to the results. Hyperpycnal flows account for the largest proportion and are widely distributed in the first slopebreak zone，the second slope-break zone，sub-sag zone，and southeastern gullies in the central north of the study area. Inversely graded to normally graded mixed bedding as well as overstep of normally graded bedding and intrastratal erosion surface are developed in channels；massive，parallel，climbing ripple，and wavy bedding is developed in lobes；carbon dusts are seen mostly in sediments. Sandy debris flows are distributed under slope-break zones and in gullies where sedimentary structures such as massive bedding，planar structures，floating mud gravel，and coarse sand mass in fine sandstone are developed. Turbidity currents are distributed in the sub-sag zone where the Bouma sequence is developed，which is mostly thin interbedding of siltstone and lacustrine mudstone. The development of gravity flow sands is controlled by gullies and slope breaks. The sands are in a zonal distribution along gullies，and pinches out under slope breaks，forming a series of independent sands with poor continuity，which is of great significance for oil and gas exploration.
2021, 28(3):25-34.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.03.003
Abstract:
With integrated data from core，well logging and laboratory analysis，the geological characteristics and main controlling factors of a giant marine delta of the Upper Kirkuk reservoir in the Halfaya Oilfield were studied. The results demonstrate that the Upper Kirkuk reservoir was developed under the background of giant marine delta，which underwent a complete cycle of sea level rising first and then declining from bottom to top. Near stretched distributary channels evolved into banded ones during the period of the maximum flooding surface（MFS），and finally into a stretch of distributary channels with width of 5-15 km as the sea level declined. Besides，the lithology of distributary channels is dominated by pure sandstone，which forms the best reservoir in the Upper Kirkuk reservoir. The overbank and sand sheets are thin，with limited lateral continuity，and particles are filled with debris and clay，indicating a poor storage capacity. The mudstone in the front delta and the silty mudstone in the interdistributary bay are mostly non-reservoirs，serving as the main barriers. Moreover，the distributary channels controlled by sedimentation are the main reservoirs distributing continuously in the Upper Kirkuk reservoir，and a stable mudstone barrier was developed during the MFS. The top and bottom are prone to dolomitization due to the contact with the near carbonate rock formation，leading to the stable barriers in the reservoir. Sedimentation and diagenesis jointly determine the layered structure in the Upper Kirkuk reservoir.
With integrated data from core，well logging and laboratory analysis，the geological characteristics and main controlling factors of a giant marine delta of the Upper Kirkuk reservoir in the Halfaya Oilfield were studied. The results demonstrate that the Upper Kirkuk reservoir was developed under the background of giant marine delta，which underwent a complete cycle of sea level rising first and then declining from bottom to top. Near stretched distributary channels evolved into banded ones during the period of the maximum flooding surface（MFS），and finally into a stretch of distributary channels with width of 5-15 km as the sea level declined. Besides，the lithology of distributary channels is dominated by pure sandstone，which forms the best reservoir in the Upper Kirkuk reservoir. The overbank and sand sheets are thin，with limited lateral continuity，and particles are filled with debris and clay，indicating a poor storage capacity. The mudstone in the front delta and the silty mudstone in the interdistributary bay are mostly non-reservoirs，serving as the main barriers. Moreover，the distributary channels controlled by sedimentation are the main reservoirs distributing continuously in the Upper Kirkuk reservoir，and a stable mudstone barrier was developed during the MFS. The top and bottom are prone to dolomitization due to the contact with the near carbonate rock formation，leading to the stable barriers in the reservoir. Sedimentation and diagenesis jointly determine the layered structure in the Upper Kirkuk reservoir.
2021, 28(3):35-41.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.03.004
Abstract:
The source and formation mechanism of the colorless condensate oil produced in Well CBX394 on the east slope of Chengdao area are not clear. According to the feature analysis of light hydrocarbon composition，biomarkers，carbon isotopes，and adamantanes，the source of condensate oil and gas in Well CBX394 was identified and the formation mechanism was discussed. The results revealed that such colorless condensate oil is similar and relevant to the light-yellow condensate oil. The former is the product of the hydrocarbon source rocks at the high-maturity stage of Es3 in Bozhong Sag，and the light-yellow condensate oil is produced because the colorless condensate oil is mixed with a small amount of crude oil from the hydrocarbon source rock of Ed at the mature stage during production. Natural gas is the associated gas of the same source as condensate oil，and its maturity is slightly higher than that of condensate oil. On the whole，natural gas charging is featured by“early oil and late gas”. The light hydrocarbon index confirms that the evaporative fractionation of condensate oil is not obvious，and the mature thermal evolution and migration fractionation are the main mechanisms for the formation of condensate reservoirs.
The source and formation mechanism of the colorless condensate oil produced in Well CBX394 on the east slope of Chengdao area are not clear. According to the feature analysis of light hydrocarbon composition，biomarkers，carbon isotopes，and adamantanes，the source of condensate oil and gas in Well CBX394 was identified and the formation mechanism was discussed. The results revealed that such colorless condensate oil is similar and relevant to the light-yellow condensate oil. The former is the product of the hydrocarbon source rocks at the high-maturity stage of Es3 in Bozhong Sag，and the light-yellow condensate oil is produced because the colorless condensate oil is mixed with a small amount of crude oil from the hydrocarbon source rock of Ed at the mature stage during production. Natural gas is the associated gas of the same source as condensate oil，and its maturity is slightly higher than that of condensate oil. On the whole，natural gas charging is featured by“early oil and late gas”. The light hydrocarbon index confirms that the evaporative fractionation of condensate oil is not obvious，and the mature thermal evolution and migration fractionation are the main mechanisms for the formation of condensate reservoirs.
2021, 28(3):42-52.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.03.005
Abstract:
To clarify the Paleogene tectonic characteristics of the Dongpu Sag and the difference from those of other depressions in the Bohai Bay Basin，we conducted the tectonic analysis of the Dongpu Sag with seismic，drilling，well logging，gravity and magnetic data and studied the controlling effect of tectonic evolution on hydrocarbon accumulation with crude oil samples and related laboratory data. The results show that the Paleogene basin in the Dongpu Sag is a Phase 2 fracture basin developed at 51 Ma with deep sedimentation（6 400 m）and a high rate（246 m/Ma）. Influenced by NE fault cutting and frequent tectonic transition，the basin exhibits strong heterogeneity and drastic lateral change and enables the development of many uplifts and sags，laying the tectonic groundwork for the composite petroleum system. According to the distribution of effective source rocks，paleotectonic ridges during hydrocarbon accumulation，fluid differences，and other factors，the Dongpu Sag can be divided into 10 petroleum systems featured by near-source hydrocarbon accumulation. The forward structure of the Dongpu Sag has a large tectonic scale，high amplitude，and a steep slope，and is effectively arranged with the source-reservoir-cap assemblage，which is conducive to the migration and accumulation of oil and gas towards the high part of the structure and controls the distribution and enrichment of oil and gas. Through the methods of volume conservation，comprehensive formation thickness trend，comparison in adjacent thickness，and vitrinite reflectance，we think that denudation of the Dongying Formation in the Dongpu Sag is 200-800 m on the whole. The Paleogene formation is continuously deep buried and stably preserved，and the Dongpu Sag is a weakly transformed basin with the composite petroleum system，which is featured by near-source hydrocarbon accumulation as well as rich and continuous accumulation controlled by the forward structure.
To clarify the Paleogene tectonic characteristics of the Dongpu Sag and the difference from those of other depressions in the Bohai Bay Basin，we conducted the tectonic analysis of the Dongpu Sag with seismic，drilling，well logging，gravity and magnetic data and studied the controlling effect of tectonic evolution on hydrocarbon accumulation with crude oil samples and related laboratory data. The results show that the Paleogene basin in the Dongpu Sag is a Phase 2 fracture basin developed at 51 Ma with deep sedimentation（6 400 m）and a high rate（246 m/Ma）. Influenced by NE fault cutting and frequent tectonic transition，the basin exhibits strong heterogeneity and drastic lateral change and enables the development of many uplifts and sags，laying the tectonic groundwork for the composite petroleum system. According to the distribution of effective source rocks，paleotectonic ridges during hydrocarbon accumulation，fluid differences，and other factors，the Dongpu Sag can be divided into 10 petroleum systems featured by near-source hydrocarbon accumulation. The forward structure of the Dongpu Sag has a large tectonic scale，high amplitude，and a steep slope，and is effectively arranged with the source-reservoir-cap assemblage，which is conducive to the migration and accumulation of oil and gas towards the high part of the structure and controls the distribution and enrichment of oil and gas. Through the methods of volume conservation，comprehensive formation thickness trend，comparison in adjacent thickness，and vitrinite reflectance，we think that denudation of the Dongying Formation in the Dongpu Sag is 200-800 m on the whole. The Paleogene formation is continuously deep buried and stably preserved，and the Dongpu Sag is a weakly transformed basin with the composite petroleum system，which is featured by near-source hydrocarbon accumulation as well as rich and continuous accumulation controlled by the forward structure.
2021, 28(3):53-61.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.03.006
Abstract:
The deep marine carbonate gas reservoir plays an important role in increasing the reserve and production of conventional natural gas in Sichuan Basin. Qixia Formation in northwest Sichuan is an ultra-deep gas reservoir at a huge cost of development，so it is urgent to accurately evaluate the pore-throat structure of the reservoir and the production capacity of the block. However，we are now facing a lack of effective ways of precisely evaluating its diverse and multi-scale porethroat structure. To solve this，we made use of digital cores and high pressure mercury injection to work out a method for the evaluation of the complete micron-centimeter pore-throat structure of carbonate rocks. Then，we validated this method by laboratory seepage experiments and finally reached the following conclusions：①The correction of the capillary pressure curves obtained from high pressure mercury injection and the quantitative characterization of the vugs and macropores on the surface of rock samples by digital cores overcome the scale limitation of conventional high pressure mercury injection and can accurately evaluate the complete micron-centimeter pore-throat structure of carbonate rocks. ②This method results in wider pore-throat size distribution and higher sorting coefficients of rock samples from vuggy and fractured-vuggy reservoirs. The rock samples from fractured-vuggy reservoirs see obvious dual pore characteristics and great storage and seepage capacity，which are more consistent with basic physical properties of rocks. The complete pore-throat structure of Qixia Formation in Northwest Sichuan lays the groundwork for the high and stable production of gas wells，and finding fracture zones is the key to high production.
The deep marine carbonate gas reservoir plays an important role in increasing the reserve and production of conventional natural gas in Sichuan Basin. Qixia Formation in northwest Sichuan is an ultra-deep gas reservoir at a huge cost of development，so it is urgent to accurately evaluate the pore-throat structure of the reservoir and the production capacity of the block. However，we are now facing a lack of effective ways of precisely evaluating its diverse and multi-scale porethroat structure. To solve this，we made use of digital cores and high pressure mercury injection to work out a method for the evaluation of the complete micron-centimeter pore-throat structure of carbonate rocks. Then，we validated this method by laboratory seepage experiments and finally reached the following conclusions：①The correction of the capillary pressure curves obtained from high pressure mercury injection and the quantitative characterization of the vugs and macropores on the surface of rock samples by digital cores overcome the scale limitation of conventional high pressure mercury injection and can accurately evaluate the complete micron-centimeter pore-throat structure of carbonate rocks. ②This method results in wider pore-throat size distribution and higher sorting coefficients of rock samples from vuggy and fractured-vuggy reservoirs. The rock samples from fractured-vuggy reservoirs see obvious dual pore characteristics and great storage and seepage capacity，which are more consistent with basic physical properties of rocks. The complete pore-throat structure of Qixia Formation in Northwest Sichuan lays the groundwork for the high and stable production of gas wells，and finding fracture zones is the key to high production.
2021, 28(3):62-69.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.03.007
Abstract:
The calculation of oil and gas reserves by the probability method represents the trend in the oil industry. To study the reserves per unit volume of Ordovician fracture-cavity carbonate oil reservoir in Tahe Oilfield，we fitted the reserves per unit volume in cave，vuggy and fractured reservoirs with the probability method and established a probability distribution model. The research demonstrates that the reserves per unit volume of fracture-cavity reservoirs in Tahe Oilfield conform to the Beta distribution model. To be specific，the reserves per unit volume in cave reservoirs are the highest，and the Pmean value calculated by the probability method reaches 10.7×104 t（/ km2·m）. The reserves per unit volume in vuggy reservoirs are 0.61×104-2.2×104 t（/ km2·m），while those in fractured reservoirs are 0.08×104-0.19×104 t（/ km2·m）. The geological distribution of reserves per unit volume in fracture-cavity reservoirs is clarified. It is pointed out that the scale of fracture-cavity reservoirs and crude oil density greatly influence the reserves per unit volume，revealing a positive correlation. The larger reservoir scale and the higher crude oil density indicate the greater reserves per unit volume. Under the same geological conditions，the reserves per unit volume based on the sample values and the probability method are similar，showing a slight positive correlation. As the exploration progresses，the probability method is more accurate for calculating the reserves of oil reservoirs.
The calculation of oil and gas reserves by the probability method represents the trend in the oil industry. To study the reserves per unit volume of Ordovician fracture-cavity carbonate oil reservoir in Tahe Oilfield，we fitted the reserves per unit volume in cave，vuggy and fractured reservoirs with the probability method and established a probability distribution model. The research demonstrates that the reserves per unit volume of fracture-cavity reservoirs in Tahe Oilfield conform to the Beta distribution model. To be specific，the reserves per unit volume in cave reservoirs are the highest，and the Pmean value calculated by the probability method reaches 10.7×104 t（/ km2·m）. The reserves per unit volume in vuggy reservoirs are 0.61×104-2.2×104 t（/ km2·m），while those in fractured reservoirs are 0.08×104-0.19×104 t（/ km2·m）. The geological distribution of reserves per unit volume in fracture-cavity reservoirs is clarified. It is pointed out that the scale of fracture-cavity reservoirs and crude oil density greatly influence the reserves per unit volume，revealing a positive correlation. The larger reservoir scale and the higher crude oil density indicate the greater reserves per unit volume. Under the same geological conditions，the reserves per unit volume based on the sample values and the probability method are similar，showing a slight positive correlation. As the exploration progresses，the probability method is more accurate for calculating the reserves of oil reservoirs.
2021, 28(3):70-76.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.03.008
Abstract:
Carbonate reservoirs are characterized by strong heterogeneity and complex pore throat structures，with poor correlation between porosity and permeability. Typical porous carbonate reservoirs develop in the Cretaceous Mishrif Formation in the Middle East，with the permeability differing by three orders of magnitude under the same porosity，bringing a huge challenge to accurately evaluate permeability and properly categorize reservoirs. To deeply analyze the key controlling factors of permeability in porous carbonate reservoirs of the Mishrif Formation in the Middle East，we find different models of pore throat structures coexist in the carbonate reservoirs of the research area through 415 MICP samples from the M Oilfield. To be specific，porosity and permeability correlate much better in a uni-modal pore throat structure than in bi-modal and multi-modal structures. Then the characteristic parameters of pore throat structures are analyzed quantitatively to explain the regularity in porosity and permeability of carbonate reservoirs with a multi-modal pore throat structure when the parameters of the pore throat structure are changed. Results demonstrate that the pore throat radius（R20），corresponding to 20% mercury injection saturation，correlates best with permeability. With R20 as the characteristic pore throat radius，its correlation study with porosity and permeability reveals that porosity first increases linearly with the greater R20 and then remains stable，while permeability keeps rising with the growth in R20.
Carbonate reservoirs are characterized by strong heterogeneity and complex pore throat structures，with poor correlation between porosity and permeability. Typical porous carbonate reservoirs develop in the Cretaceous Mishrif Formation in the Middle East，with the permeability differing by three orders of magnitude under the same porosity，bringing a huge challenge to accurately evaluate permeability and properly categorize reservoirs. To deeply analyze the key controlling factors of permeability in porous carbonate reservoirs of the Mishrif Formation in the Middle East，we find different models of pore throat structures coexist in the carbonate reservoirs of the research area through 415 MICP samples from the M Oilfield. To be specific，porosity and permeability correlate much better in a uni-modal pore throat structure than in bi-modal and multi-modal structures. Then the characteristic parameters of pore throat structures are analyzed quantitatively to explain the regularity in porosity and permeability of carbonate reservoirs with a multi-modal pore throat structure when the parameters of the pore throat structure are changed. Results demonstrate that the pore throat radius（R20），corresponding to 20% mercury injection saturation，correlates best with permeability. With R20 as the characteristic pore throat radius，its correlation study with porosity and permeability reveals that porosity first increases linearly with the greater R20 and then remains stable，while permeability keeps rising with the growth in R20.
2021, 28(3):77-83.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.03.009
Abstract:
The conventional technology regards the process of deep water shutoff and profile control as a dynamic nonlinear problem with a long delay. The conventional evaluation methods for near-well water shutoff and profile control will cause large deviations. Therefore，considering the effect on water injection wells and oil wells，a comprehensive evaluation index for deep water shutoff and profile control is constructed. On this basis，the Hurst index of time series of the comprehensive evaluation index is calculated through V/S analysis and the stability of the time series is analyzed. A comprehensive evaluation method of deep water shutoff and profile control is developed. This method is applied to a certain well group subject to deep water shutoff and profile control in Gudao Oilfield. The results demonstrated that the measures of deep water shutoff and profile control began to take effect after 30 days. The Hurst index was greater than 0.5，and VN，characterizing the stability of the time series，continued to increase. It is predicted that the effect of those measures on this well group will last for a certain period of time，and this coincides with the change in the dynamic curves of production. It is proven this method can provide reliable guidance for the field application of deep water shutoff and profile control.
The conventional technology regards the process of deep water shutoff and profile control as a dynamic nonlinear problem with a long delay. The conventional evaluation methods for near-well water shutoff and profile control will cause large deviations. Therefore，considering the effect on water injection wells and oil wells，a comprehensive evaluation index for deep water shutoff and profile control is constructed. On this basis，the Hurst index of time series of the comprehensive evaluation index is calculated through V/S analysis and the stability of the time series is analyzed. A comprehensive evaluation method of deep water shutoff and profile control is developed. This method is applied to a certain well group subject to deep water shutoff and profile control in Gudao Oilfield. The results demonstrated that the measures of deep water shutoff and profile control began to take effect after 30 days. The Hurst index was greater than 0.5，and VN，characterizing the stability of the time series，continued to increase. It is predicted that the effect of those measures on this well group will last for a certain period of time，and this coincides with the change in the dynamic curves of production. It is proven this method can provide reliable guidance for the field application of deep water shutoff and profile control.
10 Application and comparison of two production decline models in shale gas wells and tight gas wells
2021, 28(3):84-89.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.03.010
Abstract:
The production decline model is of vital importance to predicting the production rates and recoverable reserves of oil-gas wells and reservoirs. Its effective application is not limited by the ways it is reserved，driven，fractured，and recovered as well as the fluid in it.In the decline stage of production rates，the production rates and recoverable reserves can be predicted with enough production data. After years of application，Arps，in 1945，created the exponential decline model，the harmonic decline model，and，more importantly，the representative hyperbolic decline model. Moreover，the pan exponential decline model is practically valuable. Theoretically，the decline exponent n of the hyperbolic decline model ranges from 0 to 1 and the model is practical when n falls between 0 and 0.5. However，the pan exponent m of the pan exponential decline model can be valued at，in theory，between 0 and 1. The model is feasible when m ranges from 0.5 to 1. For n=0 or m=1 of the corresponding models，the exponential decline model can be obtained. For both n=0.5 and m=0.5，practical models can be built. The formulas of production rates，cumulative productions，recoverable reserves，decline rates，dimensionless production rates，and dimensionless cumulative productions of shale gas wells and tight gas wells，and dimensionless cumulative productions are proposed. According to application cases，the two models made similar predictions.
The production decline model is of vital importance to predicting the production rates and recoverable reserves of oil-gas wells and reservoirs. Its effective application is not limited by the ways it is reserved，driven，fractured，and recovered as well as the fluid in it.In the decline stage of production rates，the production rates and recoverable reserves can be predicted with enough production data. After years of application，Arps，in 1945，created the exponential decline model，the harmonic decline model，and，more importantly，the representative hyperbolic decline model. Moreover，the pan exponential decline model is practically valuable. Theoretically，the decline exponent n of the hyperbolic decline model ranges from 0 to 1 and the model is practical when n falls between 0 and 0.5. However，the pan exponent m of the pan exponential decline model can be valued at，in theory，between 0 and 1. The model is feasible when m ranges from 0.5 to 1. For n=0 or m=1 of the corresponding models，the exponential decline model can be obtained. For both n=0.5 and m=0.5，practical models can be built. The formulas of production rates，cumulative productions，recoverable reserves，decline rates，dimensionless production rates，and dimensionless cumulative productions of shale gas wells and tight gas wells，and dimensionless cumulative productions are proposed. According to application cases，the two models made similar predictions.
2021, 28(3):90-95.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.03.011
Abstract:
The water production mechanism of thermal recovery horizontal wells is complicated，and detect the water breakthrough point is the key to efficient water blocking. At present，the common water detection methods have difficulty in raising and lowering the instrument and high cost of dynamic test in oil well. Therefore，this paper proposes an analysis method of the wellbore temperature profile to detect the water breakthrough point of thermal recovery horizontal wells. According to the theory of heat conduction and multiphase pipe flow，under the condition of oil-water two-phase flow in the wellbore，we analyze the heat convection and heat conduction at the wellbore，the Joule-Thomson effect，the temperature change of the wellbore induced by the work of gravity，and the pressure drop of the wellbore caused by the joint work of gravity and shear.Then we construct a calculation model of wellbore temperature of thermal recovery horizontal wells during production，obtaining the wellbore temperature profile of the horizontal wells. Since the water production from the horizontal section during production will cause abnormal fluid temperature in this interval，the water breakthrough point can be determined by comparing the difference between the theoretical profile and the measured temperature curve. Then the source of the produced water can be analyzed according to the temperature.
The water production mechanism of thermal recovery horizontal wells is complicated，and detect the water breakthrough point is the key to efficient water blocking. At present，the common water detection methods have difficulty in raising and lowering the instrument and high cost of dynamic test in oil well. Therefore，this paper proposes an analysis method of the wellbore temperature profile to detect the water breakthrough point of thermal recovery horizontal wells. According to the theory of heat conduction and multiphase pipe flow，under the condition of oil-water two-phase flow in the wellbore，we analyze the heat convection and heat conduction at the wellbore，the Joule-Thomson effect，the temperature change of the wellbore induced by the work of gravity，and the pressure drop of the wellbore caused by the joint work of gravity and shear.Then we construct a calculation model of wellbore temperature of thermal recovery horizontal wells during production，obtaining the wellbore temperature profile of the horizontal wells. Since the water production from the horizontal section during production will cause abnormal fluid temperature in this interval，the water breakthrough point can be determined by comparing the difference between the theoretical profile and the measured temperature curve. Then the source of the produced water can be analyzed according to the temperature.
2021, 28(3):96-102.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.03.012
Abstract:
Whether chemical flooding projects can gain large-scale benefits at low oil prices is under heated discussion.For this reason，post-project evaluation has been carried out for some implemented projects，and the key to reasonable evaluation results is the cost value. According to the cost level in the starting year of evaluation，the relationship between cost elements and development indicators is established to recalculate the historical cost of the projects. Then，in light of the development law，future cost is predicted to reconstruct the life cycle cost of the projects. On this basis，a post-project evaluation method for chemical flooding projects is proposed for some chemical flooding projects that have been implemented. Results show that chemical flooding projects can get very good economic benefits at low oil prices，and the cost per ton of oil is 10%-20% lower than that of water flooding units with the same water cut. In addition，when the oil price is 40 $/bbl，the economic limit on oil increment per ton of polymer for chemical flooding projects is about 15 t/t. The chemical flooding resources that meet this requirement in Shengli Oilfield have great potential，and chemical flooding at low oil prices still has great prospects of promotion. Further analysis indicates that the fluctuation in oil prices has little impact on the benefits of chemical flooding projects，and their benefits can be significantly improved by optimizing the dosage of reagents and extending their peak periods of working.
Whether chemical flooding projects can gain large-scale benefits at low oil prices is under heated discussion.For this reason，post-project evaluation has been carried out for some implemented projects，and the key to reasonable evaluation results is the cost value. According to the cost level in the starting year of evaluation，the relationship between cost elements and development indicators is established to recalculate the historical cost of the projects. Then，in light of the development law，future cost is predicted to reconstruct the life cycle cost of the projects. On this basis，a post-project evaluation method for chemical flooding projects is proposed for some chemical flooding projects that have been implemented. Results show that chemical flooding projects can get very good economic benefits at low oil prices，and the cost per ton of oil is 10%-20% lower than that of water flooding units with the same water cut. In addition，when the oil price is 40 $/bbl，the economic limit on oil increment per ton of polymer for chemical flooding projects is about 15 t/t. The chemical flooding resources that meet this requirement in Shengli Oilfield have great potential，and chemical flooding at low oil prices still has great prospects of promotion. Further analysis indicates that the fluctuation in oil prices has little impact on the benefits of chemical flooding projects，and their benefits can be significantly improved by optimizing the dosage of reagents and extending their peak periods of working.
2021, 28(3):104-110.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.03.013
Abstract:
The difference in seepage resistance of each layer and interlayer resistance in a multilayer reservoir can directly characterize interlayer interference and its changes during development. However，the present formulas for calculating seepage resistance are featured by complicated computation or low accuracy. On the basis of the Buckley-Leverett theory，a novel calculation method of two-phase（oil-water）seepage resistance is given in this paper for the one-dimensional water flooding process，and its accuracy is verified. According to this method，the calculation process of the interlayer resistance difference during water flooding of a multilayer reservoir is further proposed，which can predict and analyze the changes in the interlayer interference during development. The results demonstrate that the values of seepage resistance calculated by our method agree well with the results of numerical simulation，with the relative error less than 12%. The variation of seepage resistance presents the stages of linear，gradual，and nearly gentle decrease，corresponding to the periods of water-free oil production，medium-high water cut，and ultra-high water cut. The interlayer resistance difference during the water flooding process of the multilayer reservoir reaches a peak after the high-permeability layer enters the period of ultra-high water cut，which can serve as a transition point for adjustment measures. The increase in the permeability difference could rapidly enlarge interlayer interference. Therefore，early control measures are essential for multilayer heterogeneous reservoirs.
The difference in seepage resistance of each layer and interlayer resistance in a multilayer reservoir can directly characterize interlayer interference and its changes during development. However，the present formulas for calculating seepage resistance are featured by complicated computation or low accuracy. On the basis of the Buckley-Leverett theory，a novel calculation method of two-phase（oil-water）seepage resistance is given in this paper for the one-dimensional water flooding process，and its accuracy is verified. According to this method，the calculation process of the interlayer resistance difference during water flooding of a multilayer reservoir is further proposed，which can predict and analyze the changes in the interlayer interference during development. The results demonstrate that the values of seepage resistance calculated by our method agree well with the results of numerical simulation，with the relative error less than 12%. The variation of seepage resistance presents the stages of linear，gradual，and nearly gentle decrease，corresponding to the periods of water-free oil production，medium-high water cut，and ultra-high water cut. The interlayer resistance difference during the water flooding process of the multilayer reservoir reaches a peak after the high-permeability layer enters the period of ultra-high water cut，which can serve as a transition point for adjustment measures. The increase in the permeability difference could rapidly enlarge interlayer interference. Therefore，early control measures are essential for multilayer heterogeneous reservoirs.
2021, 28(3):111-118.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.03.014
Abstract:
To systematically research the flow law of supercritical steam in the wellbore and accurately calculate the heat transfer characteristics and thermal loss during the flow，we construct mathematical model to calculate the heat loss during supercritical steam flow in the vertical wellbore based on the principles of mass conservation，momentum conservation and energy conservation. The model comprehensively considers the physicochemical properties of supercritical steam and its heat transfer law during flow. Finally，a series of calculations are completed for the sensitivity analysis of parameters. The results demonstrate that the pressure of supercritical steam in the wellbore grows while the temperature decreases with a rise in well depth. When the steam injection rate reaches 12 t/h，the temperature along the wellbore reduces slightly and then rises at a well depth of 3 000 m. However，when the steam injection rate is 8 t/h，the temperature，after decreasing first，begins to increase at a well depth of about 850 m and then declines at about 2 300 m. At higher initial temperature of steam injection，the temperature drops faster while the pressure rises more swiftly along the wellbore. At a well depth of 1 000 m，the temperature drop is only 0.45% at the steam injection temperature of 400 ℃，while it is 5.17% at 450 ℃. In addition，during supercritical steam flow，phase transition will be observed at the over low steam injection rate or the over large wellbore depth. The depth of phase transition is about 1 000 m at the steam injection rate of 2 t/h，while it is about 2 150 m at 4 t/h.
To systematically research the flow law of supercritical steam in the wellbore and accurately calculate the heat transfer characteristics and thermal loss during the flow，we construct mathematical model to calculate the heat loss during supercritical steam flow in the vertical wellbore based on the principles of mass conservation，momentum conservation and energy conservation. The model comprehensively considers the physicochemical properties of supercritical steam and its heat transfer law during flow. Finally，a series of calculations are completed for the sensitivity analysis of parameters. The results demonstrate that the pressure of supercritical steam in the wellbore grows while the temperature decreases with a rise in well depth. When the steam injection rate reaches 12 t/h，the temperature along the wellbore reduces slightly and then rises at a well depth of 3 000 m. However，when the steam injection rate is 8 t/h，the temperature，after decreasing first，begins to increase at a well depth of about 850 m and then declines at about 2 300 m. At higher initial temperature of steam injection，the temperature drops faster while the pressure rises more swiftly along the wellbore. At a well depth of 1 000 m，the temperature drop is only 0.45% at the steam injection temperature of 400 ℃，while it is 5.17% at 450 ℃. In addition，during supercritical steam flow，phase transition will be observed at the over low steam injection rate or the over large wellbore depth. The depth of phase transition is about 1 000 m at the steam injection rate of 2 t/h，while it is about 2 150 m at 4 t/h.
2021, 28(3):119-125.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.03.015
Abstract:
To avoid uneven vertical displacement of CO2 flooding in beach-bar sandstone reservoirs with extra-low permeability，we analyze the influence of reservoir permeability，crude oil viscosity，oil saturation，and oil layer thickness on layer combination by the numerical simulation. The orthogonal test method is used to determine their degrees of influence in descending order：crude oil viscosity，oil saturation，reservoir permeability，and oil layer thickness. Through formula derivation and numerical simulation of reservoirs，comprehensive effective fluidity that involves oil saturation，crude oil viscosity，and reservoir permeability，as well as starting pressure gradient and fracturing，is proposed to characterize layer combination. The limits of comprehensive effective fluidity under various injection-production pressure differences are determined with the numerical simulation technology for reservoirs. As the injection-production pressure difference increases，the limit gradually decreases. According to the comprehensive effective fluidity of each oil layer，the K-means clustering algorithm is used for the automatic division of layer combination. The research results are applied to the Es4 in Block Gao89 of Zhenglizhuang Oilfield，showing that the recovery is raised by 2.25% when the layers are divided into three schemes.
To avoid uneven vertical displacement of CO2 flooding in beach-bar sandstone reservoirs with extra-low permeability，we analyze the influence of reservoir permeability，crude oil viscosity，oil saturation，and oil layer thickness on layer combination by the numerical simulation. The orthogonal test method is used to determine their degrees of influence in descending order：crude oil viscosity，oil saturation，reservoir permeability，and oil layer thickness. Through formula derivation and numerical simulation of reservoirs，comprehensive effective fluidity that involves oil saturation，crude oil viscosity，and reservoir permeability，as well as starting pressure gradient and fracturing，is proposed to characterize layer combination. The limits of comprehensive effective fluidity under various injection-production pressure differences are determined with the numerical simulation technology for reservoirs. As the injection-production pressure difference increases，the limit gradually decreases. According to the comprehensive effective fluidity of each oil layer，the K-means clustering algorithm is used for the automatic division of layer combination. The research results are applied to the Es4 in Block Gao89 of Zhenglizhuang Oilfield，showing that the recovery is raised by 2.25% when the layers are divided into three schemes.
2021, 28(3):126-133.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.03.016
Abstract:
Based on the statistics and processing of injected gas composition，reservoir temperature，crude oil composition，critical temperature of injected gas，and minimum miscible pressure of 35 CO2 flooding reservoirs at home and abroad，a new GPR-DE model integrating Gaussian process regression（GPR）and differential evolution algorithm（DE）is proposed for predicting the minimum miscibility pressure of a CO2-crude oil system. The accuracy of the GPR-DE model is evaluated with regard to statistical errors and graphical errors. The model results are verified by experimental data and sensitivity analysis and compared with the prediction results of existing models. The results demonstrate that，compared with other models，the GPR-DE model has higher accuracy and wider applicability，with the average absolute relative error of only 2.060% and the standard deviation of only 0.053 2. The GPR-DE model can predict the minimum miscibility pressure of the CO2-crude oil system and other gas and crude oil systems.
Based on the statistics and processing of injected gas composition，reservoir temperature，crude oil composition，critical temperature of injected gas，and minimum miscible pressure of 35 CO2 flooding reservoirs at home and abroad，a new GPR-DE model integrating Gaussian process regression（GPR）and differential evolution algorithm（DE）is proposed for predicting the minimum miscibility pressure of a CO2-crude oil system. The accuracy of the GPR-DE model is evaluated with regard to statistical errors and graphical errors. The model results are verified by experimental data and sensitivity analysis and compared with the prediction results of existing models. The results demonstrate that，compared with other models，the GPR-DE model has higher accuracy and wider applicability，with the average absolute relative error of only 2.060% and the standard deviation of only 0.053 2. The GPR-DE model can predict the minimum miscibility pressure of the CO2-crude oil system and other gas and crude oil systems.
2021, 28(3):134-141.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.03.017
Abstract:
By investigating the application effect and practical experience of CO2 huff and puff projects，we analyzed the reservoir characteristics suitable for CO2 huff and puff from nine parameters in four categories，namely geological features，reservoir characteristics，fluid properties，and development characteristics. According to the laboratory experiments，the expansion coefficient of crude oil in the CO2-injected formation in Block JL exhibits such an evident increase and the elastic energy of the formation could be well supplemented，which means the formation is the suitable for CO2 huff and puff. Meanwhile，the surfactant CRS-1080 can effectively reduce the interfacial tension between fluids and increase CO2 swept volume，thus improving the effect of CO2 huff and puff. Combined with well selection conditions and laboratory experiments，Well X1 in Block JL was selected to carry out the pilot test of CO2-chemical composite huff and puff，after which the reservoir energy was effectively supplemented and the production decline trend of near wells was restrained. The test showed that this technology has certain applicability to this block.
By investigating the application effect and practical experience of CO2 huff and puff projects，we analyzed the reservoir characteristics suitable for CO2 huff and puff from nine parameters in four categories，namely geological features，reservoir characteristics，fluid properties，and development characteristics. According to the laboratory experiments，the expansion coefficient of crude oil in the CO2-injected formation in Block JL exhibits such an evident increase and the elastic energy of the formation could be well supplemented，which means the formation is the suitable for CO2 huff and puff. Meanwhile，the surfactant CRS-1080 can effectively reduce the interfacial tension between fluids and increase CO2 swept volume，thus improving the effect of CO2 huff and puff. Combined with well selection conditions and laboratory experiments，Well X1 in Block JL was selected to carry out the pilot test of CO2-chemical composite huff and puff，after which the reservoir energy was effectively supplemented and the production decline trend of near wells was restrained. The test showed that this technology has certain applicability to this block.
2021, 28(3):142-146.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.03.018
Abstract:
The space and load-bearing capacity of offshore platforms are limited，and the dissolution time of hydrophobically associating polymers is long. The polymer-graded forced stretching device greatly shortens the dissolution time of those polymers and reduces the footprint of the dispensing system. To further optimize the polymer dispensing system and reduce its footprint，we designed a high-gravity instant dissolving device. Through laboratory experiments，the influence of filler pore sizes，the high-gravity factor，and packing ring combinations on polymer dissolution time was studied，and the optimal polymer dissolution conditions were determined. The research results reveal the high-gravity instant dissolving device can considerably shorten the polymer dissolution time. The basic dissolution time of AP-P4 was cut by 56.25%，from 80 min to 35 min，with the mixing temperature of 45 ℃，the mixing concentration of 5 000 mg/L，the packing ring combination inside the device of 300 μm/100 μm，and the high-gravity factor of 1 307.
The space and load-bearing capacity of offshore platforms are limited，and the dissolution time of hydrophobically associating polymers is long. The polymer-graded forced stretching device greatly shortens the dissolution time of those polymers and reduces the footprint of the dispensing system. To further optimize the polymer dispensing system and reduce its footprint，we designed a high-gravity instant dissolving device. Through laboratory experiments，the influence of filler pore sizes，the high-gravity factor，and packing ring combinations on polymer dissolution time was studied，and the optimal polymer dissolution conditions were determined. The research results reveal the high-gravity instant dissolving device can considerably shorten the polymer dissolution time. The basic dissolution time of AP-P4 was cut by 56.25%，from 80 min to 35 min，with the mixing temperature of 45 ℃，the mixing concentration of 5 000 mg/L，the packing ring combination inside the device of 300 μm/100 μm，and the high-gravity factor of 1 307.
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