The Experts below are selected from a list of 144 Experts worldwide ranked by ideXlab platform
S. Kord - One of the best experts on this subject based on the ideXlab platform.
-
Pore-scale numerical modeling of relative permeability curves for CO_2–oil fluid system with an application in immiscible CO_2 flooding
Journal of Petroleum Exploration and Production Technology, 2017Co-Authors: S. Mahmoudi, O. Mohammadzadeh, A. Hashemi, S. KordAbstract:CO_2 injection is considered as one of the proven EOR methods and is being widely used nowadays in many EOR projects all over the globe. The process of in situ displacement of oil with CO_2 Gas is implemented in both miscible and immiscible modes of operation. In some oil reservoirs, CO_2 miscibility will not be attained due to fluid composition characteristics as well as in situ pressure and temperature conditions. Laboratory determination of Gas–oil relative permeability curves is usually performed with air, nitrogen, or helium Gases, and the results are then implemented for both natural depletion processes (especially in reservoirs with “solution Gas” or “Gas Cap” Drive mechanisms) and Gas injection processes. For the Gas injection processes, it is therefore necessary to find out how selection of the Gas phase would affect the relative permeability curves when the intention of developing the curves is to use them for immiscible CO_2 displacement. In this study, a reservoir simulator was first used to quantitatively analyze the effect of variation in relative permeability data (due to the use of different Gas phases) on production performance of a reservoir. Then, computational analysis was performed on changes in relative permeability curves upon using different Gas phases with the aid of pore-scale modeling using statistical methods. To predict Gas–oil relative permeability curves, a Shan–Chen-type multi-component multiphase Lattice Boltzmann pore-scale model for two-phase flow in a 2D porous medium was developed. Fully periodic and “full-way” bounce-back boundary conditions were applied in the model to get infinite domain of fluid with nonslip solid nodes. Incorporation of an external body force was performed by Guo scheme, and the influence of pore structure and Capillary number on relative permeability curves was also studied for CO_2–oil as well as N_2–oil fluid pairs. The modeled relative permeability curves were then compared with experimental results for both these fluid pairs.
-
Pore-scale numerical modeling of relative permeability curves for CO2–oil fluid system with an application in immiscible CO2 flooding
Journal of Petroleum Exploration and Production Technology, 2016Co-Authors: S. Mahmoudi, O. Mohammadzadeh, A. Hashemi, S. KordAbstract:CO2 injection is considered as one of the proven EOR methods and is being widely used nowadays in many EOR projects all over the globe. The process of in situ displacement of oil with CO2 Gas is implemented in both miscible and immiscible modes of operation. In some oil reservoirs, CO2 miscibility will not be attained due to fluid composition characteristics as well as in situ pressure and temperature conditions. Laboratory determination of Gas–oil relative permeability curves is usually performed with air, nitrogen, or helium Gases, and the results are then implemented for both natural depletion processes (especially in reservoirs with “solution Gas” or “Gas Cap” Drive mechanisms) and Gas injection processes. For the Gas injection processes, it is therefore necessary to find out how selection of the Gas phase would affect the relative permeability curves when the intention of developing the curves is to use them for immiscible CO2 displacement. In this study, a reservoir simulator was first used to quantitatively analyze the effect of variation in relative permeability data (due to the use of different Gas phases) on production performance of a reservoir. Then, computational analysis was performed on changes in relative permeability curves upon using different Gas phases with the aid of pore-scale modeling using statistical methods. To predict Gas–oil relative permeability curves, a Shan–Chen-type multi-component multiphase Lattice Boltzmann pore-scale model for two-phase flow in a 2D porous medium was developed. Fully periodic and “full-way” bounce-back boundary conditions were applied in the model to get infinite domain of fluid with nonslip solid nodes. Incorporation of an external body force was performed by Guo scheme, and the influence of pore structure and Capillary number on relative permeability curves was also studied for CO2–oil as well as N2–oil fluid pairs. The modeled relative permeability curves were then compared with experimental results for both these fluid pairs.
Marco Tulio De Carvalho Ferraz - One of the best experts on this subject based on the ideXlab platform.
-
Analise do comportamento de reservatorios submetidos a segregação gravitacional usando pseudo-funções
2014Co-Authors: Marco Tulio De Carvalho FerrazAbstract:Resumo: O objetivo deste trabalho é a análise do comportamento de um reservatório de gás em solução, submetido ao mecanismo de segregação gravitacional, durante a fase de recuperação primária. O sistema físico contempla a análise bidimensional de um reservatório cilíndrico, com o poço no centro, produzindo da porção inferior do mesmo. Foi analisado o fluxo de óleo e gás na presença de água conata imóvel. Efeitos Capilares são desprezados e efeitos gravitacionais são considerados. O fluido pode ser descrito pelo modelo Beta. Resultados são gerados por um simulador comercial totalmente impléito. Essencialmente, este estudo é uma analogia dos trabalhos de Serra, Chen e Poston e Lima, com maior enfoque nos aspectos de segregação gravitacional. Aspectos do comportamento de reservatórios submetidos à segregação gravitacional, são mostrados, com análise acerca de alguns parâmetros que a controlam. Dentro de algumas limitações, o uso de pseudo-funções nas equações de fluxo multifásico, leva a formas lineares, análoGas à solução do líquido de baixa compressibilidade e propriedades constantes. Fazendo uso destas definições e hipóteses acopladas às curvas tipo de Fetkovich, comparações são feitas quando da obtenção de parâmetros do reservatório, para as análises com e sem o uso das pseudo-funções. Os resultados obtidos mostram que o uso das pseudo-funções reduzem bastante as não linear idades presentes nas equações de fluxo multifásicoAbstract: The main purpose of this work is to study the behavior of a solution - Gas reservoir under a Gas-Cap Drive during natural depletion. The physical system consists of a two-dimensional cylindrical reservoir, with a well at the center, producing from its lower portion. We consider the flow of oi! and Gas in the presence of gravitacional effects. Capillary effects are negleted. Thé fluid behavior can be described by the Black-Oil model (13 - model). Results are generated from a commercial multipurpose reservoir simulator. Essentially, this work is similar the ones developed by Serra, Chen and Poston and Lima, but with more emphasys to gravity segregation in two-dimensional flow. Aspects of the behavior of reservoirs under gravity segregation are shown, with some analysis of the parameters which control the mecanism.Under certain conditions the use of pseudo-functions in the multiphase flow equations, give linear aspects similar to the solution of low compressibility liquid. Using these approaches and definitions and the type curve of Fetkovich, comparisions are made to obtaining reservoirs parameters, with and without the use of pseudo- function
-
Analise do comportamento de reservatorios submetidos a segregação gravitacional usando pseudo-funções
Universidade Estadual de Campinas. Faculdade de Engenharia Mecânica e Instituto de Geociências, 1991Co-Authors: Marco Tulio De Carvalho FerrazAbstract:O objetivo deste trabalho é a análise do comportamento de um reservatório de gás em solução, submetido ao mecanismo de segregação gravitacional, durante a fase de recuperação primária. O sistema físico contempla a análise bidimensional de um reservatório cilíndrico, com o poço no centro, produzindo da porção inferior do mesmo. Foi analisado o fluxo de óleo e gás na presença de água conata imóvel. Efeitos Capilares são desprezados e efeitos gravitacionais são considerados. O fluido pode ser descrito pelo modelo Beta. Resultados são gerados por um simulador comercial totalmente impléito. Essencialmente, este estudo é uma analogia dos trabalhos de Serra, Chen e Poston e Lima, com maior enfoque nos aspectos de segregação gravitacional. Aspectos do comportamento de reservatórios submetidos à segregação gravitacional, são mostrados, com análise acerca de alguns parâmetros que a controlam. Dentro de algumas limitações, o uso de pseudo-funções nas equações de fluxo multifásico, leva a formas lineares, análoGas à solução do líquido de baixa compressibilidade e propriedades constantes. Fazendo uso destas definições e hipóteses acopladas às curvas tipo de Fetkovich, comparações são feitas quando da obtenção de parâmetros do reservatório, para as análises com e sem o uso das pseudo-funções. Os resultados obtidos mostram que o uso das pseudo-funções reduzem bastante as não linear idades presentes nas equações de fluxo multifásicoThe main purpose of this work is to study the behavior of a solution - Gas reservoir under a Gas-Cap Drive during natural depletion. The physical system consists of a two-dimensional cylindrical reservoir, with a well at the center, producing from its lower portion. We consider the flow of oi! and Gas in the presence of gravitacional effects. Capillary effects are negleted. Thé fluid behavior can be described by the Black-Oil model (13 - model). Results are generated from a commercial multipurpose reservoir simulator. Essentially, this work is similar the ones developed by Serra, Chen and Poston and Lima, but with more emphasys to gravity segregation in two-dimensional flow. Aspects of the behavior of reservoirs under gravity segregation are shown, with some analysis of the parameters which control the mecanism.Under certain conditions the use of pseudo-functions in the multiphase flow equations, give linear aspects similar to the solution of low compressibility liquid. Using these approaches and definitions and the type curve of Fetkovich, comparisions are made to obtaining reservoirs parameters, with and without the use of pseudo- function
Wu You - One of the best experts on this subject based on the ideXlab platform.
-
discussion on the problem in Gas Cap Drive development of shuangtaizi oil Gas reservoir
Journal of Xi'an Petroleum Institute, 2001Co-Authors: Wu YouAbstract:Shuangtaizi reservoir in Liaohe Oilfield is a typical Gas Cap sandstone reservoir. Development scheme of Gas Cap Drive was taken in 1980. In the initial stage of development, the effectiveness of oil production is ideal. But in the middle-later stage, the result became rapidly bad. The author analyses the causes of the problem in detail. It is held that it is resulted from increasing production pressure difference from 1984 and increasing wells in pattern many times after 1985. The increases of the pressure difference and the wells in pattern lead to the interconnection and interference among wells. The interconnection and interference make a lof of Gas Cap Gas produced but oil output reduced.
-
Discussion on the Problem in Gas Cap Drive Development of Shuangtaizi Oil/Gas Reservoir
Journal of Xi'an Petroleum Institute, 2001Co-Authors: Wu YouAbstract:Shuangtaizi reservoir in Liaohe Oilfield is a typical Gas Cap sandstone reservoir. Development scheme of Gas Cap Drive was taken in 1980. In the initial stage of development, the effectiveness of oil production is ideal. But in the middle-later stage, the result became rapidly bad. The author analyses the causes of the problem in detail. It is held that it is resulted from increasing production pressure difference from 1984 and increasing wells in pattern many times after 1985. The increases of the pressure difference and the wells in pattern lead to the interconnection and interference among wells. The interconnection and interference make a lof of Gas Cap Gas produced but oil output reduced.
S. Mahmoudi - One of the best experts on this subject based on the ideXlab platform.
-
Pore-scale numerical modeling of relative permeability curves for CO_2–oil fluid system with an application in immiscible CO_2 flooding
Journal of Petroleum Exploration and Production Technology, 2017Co-Authors: S. Mahmoudi, O. Mohammadzadeh, A. Hashemi, S. KordAbstract:CO_2 injection is considered as one of the proven EOR methods and is being widely used nowadays in many EOR projects all over the globe. The process of in situ displacement of oil with CO_2 Gas is implemented in both miscible and immiscible modes of operation. In some oil reservoirs, CO_2 miscibility will not be attained due to fluid composition characteristics as well as in situ pressure and temperature conditions. Laboratory determination of Gas–oil relative permeability curves is usually performed with air, nitrogen, or helium Gases, and the results are then implemented for both natural depletion processes (especially in reservoirs with “solution Gas” or “Gas Cap” Drive mechanisms) and Gas injection processes. For the Gas injection processes, it is therefore necessary to find out how selection of the Gas phase would affect the relative permeability curves when the intention of developing the curves is to use them for immiscible CO_2 displacement. In this study, a reservoir simulator was first used to quantitatively analyze the effect of variation in relative permeability data (due to the use of different Gas phases) on production performance of a reservoir. Then, computational analysis was performed on changes in relative permeability curves upon using different Gas phases with the aid of pore-scale modeling using statistical methods. To predict Gas–oil relative permeability curves, a Shan–Chen-type multi-component multiphase Lattice Boltzmann pore-scale model for two-phase flow in a 2D porous medium was developed. Fully periodic and “full-way” bounce-back boundary conditions were applied in the model to get infinite domain of fluid with nonslip solid nodes. Incorporation of an external body force was performed by Guo scheme, and the influence of pore structure and Capillary number on relative permeability curves was also studied for CO_2–oil as well as N_2–oil fluid pairs. The modeled relative permeability curves were then compared with experimental results for both these fluid pairs.
-
Pore-scale numerical modeling of relative permeability curves for CO2–oil fluid system with an application in immiscible CO2 flooding
Journal of Petroleum Exploration and Production Technology, 2016Co-Authors: S. Mahmoudi, O. Mohammadzadeh, A. Hashemi, S. KordAbstract:CO2 injection is considered as one of the proven EOR methods and is being widely used nowadays in many EOR projects all over the globe. The process of in situ displacement of oil with CO2 Gas is implemented in both miscible and immiscible modes of operation. In some oil reservoirs, CO2 miscibility will not be attained due to fluid composition characteristics as well as in situ pressure and temperature conditions. Laboratory determination of Gas–oil relative permeability curves is usually performed with air, nitrogen, or helium Gases, and the results are then implemented for both natural depletion processes (especially in reservoirs with “solution Gas” or “Gas Cap” Drive mechanisms) and Gas injection processes. For the Gas injection processes, it is therefore necessary to find out how selection of the Gas phase would affect the relative permeability curves when the intention of developing the curves is to use them for immiscible CO2 displacement. In this study, a reservoir simulator was first used to quantitatively analyze the effect of variation in relative permeability data (due to the use of different Gas phases) on production performance of a reservoir. Then, computational analysis was performed on changes in relative permeability curves upon using different Gas phases with the aid of pore-scale modeling using statistical methods. To predict Gas–oil relative permeability curves, a Shan–Chen-type multi-component multiphase Lattice Boltzmann pore-scale model for two-phase flow in a 2D porous medium was developed. Fully periodic and “full-way” bounce-back boundary conditions were applied in the model to get infinite domain of fluid with nonslip solid nodes. Incorporation of an external body force was performed by Guo scheme, and the influence of pore structure and Capillary number on relative permeability curves was also studied for CO2–oil as well as N2–oil fluid pairs. The modeled relative permeability curves were then compared with experimental results for both these fluid pairs.
W. J. Lee - One of the best experts on this subject based on the ideXlab platform.
-
A Bayesian Integration of Volumetric and Material Balance Analyses to Quantify Uncertainty in Original Hydrocarbons in Place
Petroleum Science and Technology, 2012Co-Authors: C. Ogele, Ahmed Daoud, Duane A. Mcvay, W. J. LeeAbstract:Abstract The authors use a Bayesian formulation to integrate volumetric and material balance analyses. Specifically, they apply Bayes's rule to the Havlena and Odeh material balance equation to estimate original oil in place, N, and relative Gas-Cap size, m, for a Gas-Cap Drive oil reservoir. The authors consider uncertainty and correlation in the volumetric estimates of N and m, as well as uncertainty in the pressure data. They then quantify uncertainty in the estimates of N and m resulting from the combined volumetric and material balance analyses. By combining the analyses, each reduces the uncertainty of the other, resulting in more accurate in-place estimates than from the separate analyses.
-
Integration of Volumetric and Material Balance Analyses Using a Bayesian Framework to Estimate OHIP and Quantify Uncertainty
All Days, 2006Co-Authors: C. Ogele, Ahmed Daoud, Duane A. Mcvay, W. J. LeeAbstract:ABSTRACT Estimating original hydrocarbons in place (OHIP) in a reservoir is fundamentally important in estimating reserves and potential profitability. Two traditional methods for estimating OHIP are volumetric and material balance methods. Probabilistic estimates of OHIP are commonly generated prior to significant production from a reservoir by combining volumetric analysis with Monte Carlo methods. Material balance is routinely used to analyze reservoir performance and estimate OHIP. Although material balance has uncertainties due to errors in pressure and other parameters, probabilistic estimates are seldom generated. In this paper we use a Bayesian formulation to integrate volumetric and material balance analyses and to quantify uncertainty in the combined OHIP estimates. Specifically, we apply Bayes' rule to the Havlena and Odeh material balance equation to estimate original oil in place, N, and relative Gas-Cap size, m, for a Gas-Cap Drive oil reservoir. We consider uncertainty and correlation in the volumetric estimates of N and m (reflected in the prior probability distribution), as well as uncertainty in the pressure data (reflected in the likelihood distribution). Approximation of the covariance of the posterior distribution allows quantification of uncertainty in the estimates of N and m resulting from the combined volumetric and material balance analyses. Our investigations show that material balance data reduce the uncertainty in the volumetric estimate, and the volumetric data reduce the considerable non-uniqueness of the material balance solution, resulting in more accurate OHIP estimates than from the separate analyses. One of the advantages over reservoir simulation is that, with the smaller number of parameters in this approach, we can easily sample the entire posterior distribution, resulting in more complete quantification of uncertainty. INTRODUCTION The estimation of original hydrocarbons in place (OHIP) in a reservoir is one of the oldest and, still, most important problems in reservoir engineering. Estimating OHIP in a reservoir is fundamentally important in estimating reserves and potential profitability. We have long known that our estimates of OHIP possess uncertainty due to scarcity of data and data inaccuracies.[1–3] Quantifying the uncertainties in OHIP estimates can improve reservoir development and investment decision-making for individual reservoirs and can lead to improved portfolio performance.[4] The general question we address in this paper is: Given reservoir data available, how do we best estimate OHIP and how do we quantify the uncertainty inherent in this estimate? Two traditional methods for estimating OHIP are volumetric and material balance methods.[5,6] Volumetric methods are based on static reservoir properties, such as porosity, net thickness and initial saturation distributions. Since they can be applied prior to production from the reservoir, volumetric methods are often the only source of OHIP values available in making the large investment decisions required early in the life of a reservoir. Given the often large uncertainty due to paucity of well data early in the reservoir life, it is common to quantify the uncertainty of volumetric estimates of OHIP using statistical methods such as Confidence Interval[7] and Monte Carlo analysis.[8,9] Material balance is routinely used to analyze reservoir performance data and estimate OHIP. The material balance method requires pressure and production data and, thus, can be applied only after the reservoir has produced for a significant period of time. The advantages of material balance methods arewe can determine Drive mechanism in addition to OHIP,no geological model is required, andwe can solve for OHIP (and sometimes other parameters) directly from performance data. Primary sources of uncertainty in material balance analyses are incomplete or inaccurate production data and inaccuracies in determining an accurate average pressure trend, particularly in low-permeability or heterogeneous reservoirs. Although these uncertainties have been long recognized, material balance methods are often considered more accurate than volumetric methods, since they are based on observed performance data. It is not common practice to formally quantify the uncertainty in material balance estimates of OHIP, although there have been some attempts.[10–13]
