In order to select highly productive and enriched areas of high rank coalbed methane reservoirs, based on hydrologic geology as one of the main factors controlling coalbed methane （CBM） reservoir formations, the eff...In order to select highly productive and enriched areas of high rank coalbed methane reservoirs, based on hydrologic geology as one of the main factors controlling coalbed methane （CBM） reservoir formations, the effect of hydrodynamic forces controlling CBM reservoir formations was studied by a physical simulation experiment in which we used CBM reservoir simulation facilities. The hydrodynamic conditions of high coal rank reservoirs in the Qinshui basin were analyzed. Our experiment shows the following results： under strong hydrodynamic alternating action, 6C~ of coalbed methane reservoir changed from the start at -2.95% ~ -3.66%, and the lightening process occurred in phases; the CI-I4 volume reduced from 96.35% to 12.42%; the CO2 vo- lume decreased from 0.75% in sample 1 to 0.68% in sample 2, then rose to 1.13% in sample 3; the N2 volume changed from 2.9% in sample 1 to 86.45% in sample 3. On one hand, these changes show the complexity of CBM reservoir formation; on the other hand, they indicate that strong hydrodynamic actions have an unfavorable impact on CBM reservoir formation. It was found that the gas volume and hydrodynamic intensity were negatively correlated and low hydrodynamic flow conditions might result in highly productive and enriched areas of high rank CBM.展开更多
Dimensional analysis and numerical simulations were carried out to research prediction method of breakthrough time of horizontal wells in bottom water reservoir. Four dimensionless independent variables and dimensionl...Dimensional analysis and numerical simulations were carried out to research prediction method of breakthrough time of horizontal wells in bottom water reservoir. Four dimensionless independent variables and dimensionless time were derived from 10 influencing factors of the problem by using dimensional analysis. Simulations of horizontal well in reservoir with bottom water were run to find the prediction correlation. A general and concise functional relationship for predicting breakthrough time was established based on simulation results and theoretical analysis. The breakthrough time of one conceptual model predicted by the correlation is very close to the result by Eclipse with less than 2% error. The practical breakthrough time of one well in Helder oilfield is 10 d, and the predicted results by the method is 11.2 d, which is more accurate than the analytical result. Case study indicates that the method could predict breakthrough time of horizontal well under different reservoir conditions accurately. For its university and ease of use, the method is suitable for quick prediction of breakthrough time.展开更多
The Bakken formation has become a prominent oil resource for south-east Saskatchewan, especially with the advent of horizontal well technology and new hydraulic fracturing methods. As more wells are drilled, there is ...The Bakken formation has become a prominent oil resource for south-east Saskatchewan, especially with the advent of horizontal well technology and new hydraulic fracturing methods. As more wells are drilled, there is a desire to determine whether there is potential for improved oil recovery and to evaluate the economic feasibility. This paper evaluates the benefit of implementing waterflooding, CO2 injection or WAG （water-alternating-gas） recovery methods for improved oil recovery of the Bakken formation. A simulation model resembling the study area was built using CMG-GEM （computer modeling group-generalized equation of state model） reservoir simulation package and a history match of the primary recovery data available was performed. Based on the simulation results, it was concluded that waterflooding had a significant influence on the oil recovery factor, although COz provided the highest increase in crude oil recovery, The capital expenditure for surface facilities and cost of injected fluid was the most economically viable for implementation of waterflooding. The WAG injection simulation results were similar to CO2 injection, except that reservoir pressure was able to be better maintained. Given that high-quality source water is available, waterflooding is the most economically feasible choice according to the simulation results obtained from this study.展开更多
Cooperative inversion for petroleum reservoir characterization produces an Earth model that fits all available geological, geophysical and reservoir production data to within acceptable error criteria. The mathematica...Cooperative inversion for petroleum reservoir characterization produces an Earth model that fits all available geological, geophysical and reservoir production data to within acceptable error criteria. The mathematical formulation for the inversion requires an appropriate modeling description of both seismic wave propagation and reservoir fluid flow. The inversion requires the minimization of an objective function which is the weighted sum of model misfits for both geophysical and production data. While the complete automation of cooperative inversion may be unrealistic or intractable, geophysical data can provide useful information for enhancing heavy oil production. A methodology is given to demonstrate possible cooperative inversion application in heavy oil reservoirs.展开更多
Convection-dispersion of fluids flowing through porous media is an important phenomenon in immiscible and miscible displacement in hydrocarbon reservoirs. Exact calculation of this problem leads to perform more robust...Convection-dispersion of fluids flowing through porous media is an important phenomenon in immiscible and miscible displacement in hydrocarbon reservoirs. Exact calculation of this problem leads to perform more robust reservoir simulation and reliable prediction. There are various techniques that have been proposed to solve convection-dispersion equation. To check the validity of these techniques, the convection-dispersion equation was solved numerically using a series of well known numerical techniques. Such techniques that employed in this study include method of line, explicit, implicit, Crank-Nicolson and Barakat-Clark. Several cases were considered as input, and convection-dispersion equation was solved using the aforementioned techniques. Moreover the error analysis was also carried out based on the comparison of numerical and analytical results. Finally it was observed that method of line and explicit methods are not capable of simulating the convection-dispersion equation for wide range of input parameters. The Barakat-Clark method was also failed to predict accurate results and in some cases it had large deviation from analytical solution. On the other hand, the simulation results of implicit and Crank-Nicolson have more qualitative and quantitative agreement with those obtained by the analytical solutions.展开更多
After analyzing many studies of fluid flow theory of multi-porous media in low and extra-low permeability reservoirs and the numerical simulation of non-Darcy flow, we found that a negative flow rate occurs in the exi...After analyzing many studies of fluid flow theory of multi-porous media in low and extra-low permeability reservoirs and the numerical simulation of non-Darcy flow, we found that a negative flow rate occurs in the existing non-Darcy flow equation, which is unreasonable. We believe that the existing equation can only be considered as a discriminant to judging Darcy flow or non-Darcy flow, and cannot be taken as a fluid flow governing equation of multi-porous media. Our analysis of the experimental results shows that the threshold pressure gradient(TPG) of low and extra-low permeability reservoirs is excessively high, and does not conform to fluid flow through multi-porous media in the actual reservoir situation. Therefore, we present a reasonable TPG ranging from 0.006 to 0.04 MPa/m at the well depth of 1500 m and oil drainage distance of 500 m. The results of our study also indicate that the non-Darcy flow phenomenon will disappear when the TPG reaches a certain value. In addition, the TPG or non-Darcy flow in low and extra-low permeability reservoirs does not need to be considered in the productivity prediction and reservoir numerical simulation. At present, the black oil model or dual-porous media is suitable for simulating low and extra-low permeability reservoirs.展开更多
We study a class of preconditioners to solve large-scale linear systems arising from fully implicit reservoir simulation. These methods are discussed in the framework of the auxiliary space preconditioning method for ...We study a class of preconditioners to solve large-scale linear systems arising from fully implicit reservoir simulation. These methods are discussed in the framework of the auxiliary space preconditioning method for generality. Unlike in the case of classical algebraic preconditioning methods, we take several analytical and physical considerations into account. In addition, we choose appropriate auxiliary problems to design the robust solvers herein. More importantly, our methods are user-friendly and general enough to be easily ported to existing petroleum reservoir simulators. We test the efficiency and robustness of the proposed method by applying them to a couple of benchmark problems and real-world reservoir problems. The numerical results show that our methods are both efficient and robust for large reservoir models.展开更多
The worldwide proven recoverable reserves of conventional oil are less than the amount of the heavy oil.Owing to weakly consolidated formation,sand production is an important problem encountered during oil production ...The worldwide proven recoverable reserves of conventional oil are less than the amount of the heavy oil.Owing to weakly consolidated formation,sand production is an important problem encountered during oil production in heavy oil reservoirs,for which frac-pack technique is one of the most common treatments.Hence,how to obtain the optimal fracture geometry is the key to increasing well production and preventing sand.Due to the faultiness that current optimization of the fracture geometry only depends on well productivity,fracture-flow fraction was used to describe the contribution of the fracture collecting and conducting fluids from the reservoir.The higher the fracture-flow fraction,the more likely bilinear flow pattern occurs,thus leading to smaller flow resistance and better results in oil productivity and sand prevention.A reservoir numerical simulation model was established to simulate the long-term production dynamic of a fractured well in rectangular drainage areas.In order to reach the aim of increasing productivity meanwhile preventing sand,a new method based on Unified Fracture Design was developed to optimize the fracture geometry.For a specific reservoir and a certain amount of proppant injected to the target layer,there exits an optimal dimensionless fracture conductivity which corresponds to the maximum fracture-flow fraction,accordingly we can get the optimal fracture geometry.The formulas of the optimal fracture geometry were presented on square drainage area conditions,which are very convenient to apply.Equivalent Proppant Number was used to eliminate the impact of aspect ratios of rectangular drainage area,then,the same method to optimize the fracture geometry as mentioned for square drainage areas could be adopted too.展开更多
基金Project 2002CB211705 supported by the National Basic Research Program of China
文摘In order to select highly productive and enriched areas of high rank coalbed methane reservoirs, based on hydrologic geology as one of the main factors controlling coalbed methane （CBM） reservoir formations, the effect of hydrodynamic forces controlling CBM reservoir formations was studied by a physical simulation experiment in which we used CBM reservoir simulation facilities. The hydrodynamic conditions of high coal rank reservoirs in the Qinshui basin were analyzed. Our experiment shows the following results： under strong hydrodynamic alternating action, 6C~ of coalbed methane reservoir changed from the start at -2.95% ~ -3.66%, and the lightening process occurred in phases; the CI-I4 volume reduced from 96.35% to 12.42%; the CO2 vo- lume decreased from 0.75% in sample 1 to 0.68% in sample 2, then rose to 1.13% in sample 3; the N2 volume changed from 2.9% in sample 1 to 86.45% in sample 3. On one hand, these changes show the complexity of CBM reservoir formation; on the other hand, they indicate that strong hydrodynamic actions have an unfavorable impact on CBM reservoir formation. It was found that the gas volume and hydrodynamic intensity were negatively correlated and low hydrodynamic flow conditions might result in highly productive and enriched areas of high rank CBM.
基金Project(2011ZX05009-004)supported by the National Science and Technology Major Projects of China
文摘Dimensional analysis and numerical simulations were carried out to research prediction method of breakthrough time of horizontal wells in bottom water reservoir. Four dimensionless independent variables and dimensionless time were derived from 10 influencing factors of the problem by using dimensional analysis. Simulations of horizontal well in reservoir with bottom water were run to find the prediction correlation. A general and concise functional relationship for predicting breakthrough time was established based on simulation results and theoretical analysis. The breakthrough time of one conceptual model predicted by the correlation is very close to the result by Eclipse with less than 2% error. The practical breakthrough time of one well in Helder oilfield is 10 d, and the predicted results by the method is 11.2 d, which is more accurate than the analytical result. Case study indicates that the method could predict breakthrough time of horizontal well under different reservoir conditions accurately. For its university and ease of use, the method is suitable for quick prediction of breakthrough time.
文摘The Bakken formation has become a prominent oil resource for south-east Saskatchewan, especially with the advent of horizontal well technology and new hydraulic fracturing methods. As more wells are drilled, there is a desire to determine whether there is potential for improved oil recovery and to evaluate the economic feasibility. This paper evaluates the benefit of implementing waterflooding, CO2 injection or WAG （water-alternating-gas） recovery methods for improved oil recovery of the Bakken formation. A simulation model resembling the study area was built using CMG-GEM （computer modeling group-generalized equation of state model） reservoir simulation package and a history match of the primary recovery data available was performed. Based on the simulation results, it was concluded that waterflooding had a significant influence on the oil recovery factor, although COz provided the highest increase in crude oil recovery, The capital expenditure for surface facilities and cost of injected fluid was the most economically viable for implementation of waterflooding. The WAG injection simulation results were similar to CO2 injection, except that reservoir pressure was able to be better maintained. Given that high-quality source water is available, waterflooding is the most economically feasible choice according to the simulation results obtained from this study.
文摘Cooperative inversion for petroleum reservoir characterization produces an Earth model that fits all available geological, geophysical and reservoir production data to within acceptable error criteria. The mathematical formulation for the inversion requires an appropriate modeling description of both seismic wave propagation and reservoir fluid flow. The inversion requires the minimization of an objective function which is the weighted sum of model misfits for both geophysical and production data. While the complete automation of cooperative inversion may be unrealistic or intractable, geophysical data can provide useful information for enhancing heavy oil production. A methodology is given to demonstrate possible cooperative inversion application in heavy oil reservoirs.
文摘Convection-dispersion of fluids flowing through porous media is an important phenomenon in immiscible and miscible displacement in hydrocarbon reservoirs. Exact calculation of this problem leads to perform more robust reservoir simulation and reliable prediction. There are various techniques that have been proposed to solve convection-dispersion equation. To check the validity of these techniques, the convection-dispersion equation was solved numerically using a series of well known numerical techniques. Such techniques that employed in this study include method of line, explicit, implicit, Crank-Nicolson and Barakat-Clark. Several cases were considered as input, and convection-dispersion equation was solved using the aforementioned techniques. Moreover the error analysis was also carried out based on the comparison of numerical and analytical results. Finally it was observed that method of line and explicit methods are not capable of simulating the convection-dispersion equation for wide range of input parameters. The Barakat-Clark method was also failed to predict accurate results and in some cases it had large deviation from analytical solution. On the other hand, the simulation results of implicit and Crank-Nicolson have more qualitative and quantitative agreement with those obtained by the analytical solutions.
基金sponsored by National Key Project of Science and Technology of the Ministry of Science and Technology(MOST)(Grant No.2011ZX05043-002)
文摘After analyzing many studies of fluid flow theory of multi-porous media in low and extra-low permeability reservoirs and the numerical simulation of non-Darcy flow, we found that a negative flow rate occurs in the existing non-Darcy flow equation, which is unreasonable. We believe that the existing equation can only be considered as a discriminant to judging Darcy flow or non-Darcy flow, and cannot be taken as a fluid flow governing equation of multi-porous media. Our analysis of the experimental results shows that the threshold pressure gradient(TPG) of low and extra-low permeability reservoirs is excessively high, and does not conform to fluid flow through multi-porous media in the actual reservoir situation. Therefore, we present a reasonable TPG ranging from 0.006 to 0.04 MPa/m at the well depth of 1500 m and oil drainage distance of 500 m. The results of our study also indicate that the non-Darcy flow phenomenon will disappear when the TPG reaches a certain value. In addition, the TPG or non-Darcy flow in low and extra-low permeability reservoirs does not need to be considered in the productivity prediction and reservoir numerical simulation. At present, the black oil model or dual-porous media is suitable for simulating low and extra-low permeability reservoirs.
基金supported by Petro-China Joint Research Funding(Grant No.12HT1050002654)National Science Foundation of USA(Grant No.DMS-1217142)+1 种基金the Dean’s Startup FundAcademy of Mathematics and System Sciences and the State High Tech Development Plan of China(863 Program)(GrantNo.2012AA01A309)
文摘We study a class of preconditioners to solve large-scale linear systems arising from fully implicit reservoir simulation. These methods are discussed in the framework of the auxiliary space preconditioning method for generality. Unlike in the case of classical algebraic preconditioning methods, we take several analytical and physical considerations into account. In addition, we choose appropriate auxiliary problems to design the robust solvers herein. More importantly, our methods are user-friendly and general enough to be easily ported to existing petroleum reservoir simulators. We test the efficiency and robustness of the proposed method by applying them to a couple of benchmark problems and real-world reservoir problems. The numerical results show that our methods are both efficient and robust for large reservoir models.
基金supported by the National Science and Technology Major Projects of China (Grant No. 2008ZX05024-03-003-004)
文摘The worldwide proven recoverable reserves of conventional oil are less than the amount of the heavy oil.Owing to weakly consolidated formation,sand production is an important problem encountered during oil production in heavy oil reservoirs,for which frac-pack technique is one of the most common treatments.Hence,how to obtain the optimal fracture geometry is the key to increasing well production and preventing sand.Due to the faultiness that current optimization of the fracture geometry only depends on well productivity,fracture-flow fraction was used to describe the contribution of the fracture collecting and conducting fluids from the reservoir.The higher the fracture-flow fraction,the more likely bilinear flow pattern occurs,thus leading to smaller flow resistance and better results in oil productivity and sand prevention.A reservoir numerical simulation model was established to simulate the long-term production dynamic of a fractured well in rectangular drainage areas.In order to reach the aim of increasing productivity meanwhile preventing sand,a new method based on Unified Fracture Design was developed to optimize the fracture geometry.For a specific reservoir and a certain amount of proppant injected to the target layer,there exits an optimal dimensionless fracture conductivity which corresponds to the maximum fracture-flow fraction,accordingly we can get the optimal fracture geometry.The formulas of the optimal fracture geometry were presented on square drainage area conditions,which are very convenient to apply.Equivalent Proppant Number was used to eliminate the impact of aspect ratios of rectangular drainage area,then,the same method to optimize the fracture geometry as mentioned for square drainage areas could be adopted too.
