مقالات مربوط به EOR&IOR
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SPE-113269
SPE-113269
SPE-113269
Effective EOR Decision Strategies With Limited Data: Field Cases Demonstration
Summary
Enhanced-oil-recovery (EOR) evaluations focused on asset acquisition or rejuvenation involve a combination of complex decisions using different data sources. EOR projects traditionally have been associated with high capital and operational expenditures (CAPEX and OPEX, respectively) as well as high financial risk, which tend to limit the number of EOR projects launched. We propose a workflow for EOR evaluations that accounts for different volumes and quality of information. This flexible workflow has been applied successfully to oil-property evaluations and EOR-feasibility studies in many oil reservoirs. The method associated with the workflow relies on traditional (e.g., look-up tables, x-y correlations) and more-advanced (data mining for analog-reservoir search and geology indicators) screening methods, emphasizing identification of analogs to support decision making. The screening phase is combined with analytical or simplified numerical simulations to estimate full-field performance with reservoir-data-driven segmentation procedures. This paper illustrates the EOR decision-making workflow by use of field case examples from Asia, Canada, Mexico, South America, and the United States. The assets evaluated include reservoir types ranging from oil sands to condensate reservoirs. Different stages of development and information availability are discussed. Results show the advantage of a flexible decision-making workflow that can be adapted to the volume and quality of information by formulating the correct decision problem and concentrating on projects and/or properties with the highest expected economic merit. An interesting aspect of this approach is the combination of geologic and engineering data, minimizing experts' bias and combining technical and financial figures of merit. The proposed method has proved useful to screen and evaluate projects/properties very rapidly, identifying when upside potential exists.
Summary
Enhanced-oil-recovery (EOR) evaluations focused on asset acquisition or rejuvenation involve a combination of complex decisions using different data sources. EOR projects traditionally have been associated with high capital and operational expenditures (CAPEX and OPEX, respectively) as well as high financial risk, which tend to limit the number of EOR projects launched. We propose a workflow for EOR evaluations that accounts for different volumes and quality of information. This flexible workflow has been applied successfully to oil-property evaluations and EOR-feasibility studies in many oil reservoirs. The method associated with the workflow relies on traditional (e.g., look-up tables, x-y correlations) and more-advanced (data mining for analog-reservoir search and geology indicators) screening methods, emphasizing identification of analogs to support decision making. The screening phase is combined with analytical or simplified numerical simulations to estimate full-field performance with reservoir-data-driven segmentation procedures. This paper illustrates the EOR decision-making workflow by use of field case examples from Asia, Canada, Mexico, South America, and the United States. The assets evaluated include reservoir types ranging from oil sands to condensate reservoirs. Different stages of development and information availability are discussed. Results show the advantage of a flexible decision-making workflow that can be adapted to the volume and quality of information by formulating the correct decision problem and concentrating on projects and/or properties with the highest expected economic merit. An interesting aspect of this approach is the combination of geologic and engineering data, minimizing experts' bias and combining technical and financial figures of merit. The proposed method has proved useful to screen and evaluate projects/properties very rapidly, identifying when upside potential exists.
SPE-109682
SPE-109682
SPE-109682
Key Aspects of Project Design for Polymer Flooding
Abstract
After a pilot site meets the screening qualifications for polymer flooding, the injection measures and the injection formula are key points when designing a polymer flood. This paper places special emphasis on some new design factors that were found to be important during extensive experience during polymer flooding. These factors include (1) recognizing when profile modification is needed before polymer injection and when zone isolation is of value during polymer injection, (2) establishing the optimum polymer formulations, injection rates, and individual well production allocations, and (3) time-dependent variation of the molecular weight of the polymer used in the injected slugs.
At Daqing, polymers with molecular weights from 12 to 38 million Daltons were designed and supplied to meet the requirements for different reservoir geological conditions. The optimum polymer injection volume varied around 0.7 pore volume (PV),1 depending on the water cut in the different flooding units. The average polymer concentration was designed about 1,000 mg/L, but for an individual injection station, it could be much more.2,3 The injection rate should be less than 0.2 PV/yr, depending on well spacing. Additionally, the project design should follow certain rules when allocating the injection rate and production rate for individual wells.
Introduction
Many elements have long been recognized as important during the design of a polymer flood.4-12 This paper spells out some of those elements using examples from the Daqing oilfield. Critical reservoir factors that traditionally receive consideration are the reservoir lithology, stratigraphy, important heterogeneities (such as fractures), distribution of remaining oil, well pattern, and well distance. Critical polymer properties include cost-effectiveness (e.g., cost per unit of viscosity), resistance to degradation (mechanical or shear, oxidative, thermal, microbial), tolerance of reservoir salinity and hardness, retention by rock, inaccessible pore volume, permeability dependence of performance, rheology, and compatibility with other chemicals that might be used. Issues long recognized as important for polymer bank design include bank size (volume), polymer concentration and salinity (affecting bank viscosity and mobility), and whether (and how) to grade polymer concentrations in the chase water.
At the end of 2006, oil production from polymer flooding at the Daqing Oilfield was more than 10 million tons (63 million barrels) per year (sustained for 5 years). This paper describes the design procedures that led to favorable incremental oil production and reduced water production during 12 years of successful polymer flooding in the Daqing Oil Field.
1 Zone Management before Polymer Flooding
1.1 Profile Modification before Polymer Injection
Under some circumstances, use of gel treatments or other types of “profile modification” methods may be of value before implementation of a polymer or chemical flood.13 If fractures cause severe channeling, gel treatments can greatly enhance reservoir sweep if applied before injection of large volumes of expensive polymer or surfactant formulations.14 Also, if one or more high permeability stratum are watered out, there may be considerable value in applying profile modification methods before starting the EOR project.
For some Daqing wells with layers with no crossflow, numerical simulation demonstrated that oil recovery can be enhanced 2-4 % original oil in place (OOIP) with profile modification before polymer injection.15 (10-12% OOIP was the typical EOR due to polymer flooding alone.) As expected, the benefits from profile modification decrease if it is implemented toward the middle or end of polymer injection
Abstract
After a pilot site meets the screening qualifications for polymer flooding, the injection measures and the injection formula are key points when designing a polymer flood. This paper places special emphasis on some new design factors that were found to be important during extensive experience during polymer flooding. These factors include (1) recognizing when profile modification is needed before polymer injection and when zone isolation is of value during polymer injection, (2) establishing the optimum polymer formulations, injection rates, and individual well production allocations, and (3) time-dependent variation of the molecular weight of the polymer used in the injected slugs.
At Daqing, polymers with molecular weights from 12 to 38 million Daltons were designed and supplied to meet the requirements for different reservoir geological conditions. The optimum polymer injection volume varied around 0.7 pore volume (PV),1 depending on the water cut in the different flooding units. The average polymer concentration was designed about 1,000 mg/L, but for an individual injection station, it could be much more.2,3 The injection rate should be less than 0.2 PV/yr, depending on well spacing. Additionally, the project design should follow certain rules when allocating the injection rate and production rate for individual wells.
Introduction
Many elements have long been recognized as important during the design of a polymer flood.4-12 This paper spells out some of those elements using examples from the Daqing oilfield. Critical reservoir factors that traditionally receive consideration are the reservoir lithology, stratigraphy, important heterogeneities (such as fractures), distribution of remaining oil, well pattern, and well distance. Critical polymer properties include cost-effectiveness (e.g., cost per unit of viscosity), resistance to degradation (mechanical or shear, oxidative, thermal, microbial), tolerance of reservoir salinity and hardness, retention by rock, inaccessible pore volume, permeability dependence of performance, rheology, and compatibility with other chemicals that might be used. Issues long recognized as important for polymer bank design include bank size (volume), polymer concentration and salinity (affecting bank viscosity and mobility), and whether (and how) to grade polymer concentrations in the chase water.
At the end of 2006, oil production from polymer flooding at the Daqing Oilfield was more than 10 million tons (63 million barrels) per year (sustained for 5 years). This paper describes the design procedures that led to favorable incremental oil production and reduced water production during 12 years of successful polymer flooding in the Daqing Oil Field.
1 Zone Management before Polymer Flooding
1.1 Profile Modification before Polymer Injection
Under some circumstances, use of gel treatments or other types of “profile modification” methods may be of value before implementation of a polymer or chemical flood.13 If fractures cause severe channeling, gel treatments can greatly enhance reservoir sweep if applied before injection of large volumes of expensive polymer or surfactant formulations.14 Also, if one or more high permeability stratum are watered out, there may be considerable value in applying profile modification methods before starting the EOR project.
For some Daqing wells with layers with no crossflow, numerical simulation demonstrated that oil recovery can be enhanced 2-4 % original oil in place (OOIP) with profile modification before polymer injection.15 (10-12% OOIP was the typical EOR due to polymer flooding alone.) As expected, the benefits from profile modification decrease if it is implemented toward the middle or end of polymer injection
Stability of Displacement Fronts in WAG Operations
Abstract
This paper presents an analytical and numerical study of the stability of gas-oil-water displacement fronts in two and three spatial dimensions. The flow equations are simplified by averaging in the dip-normal direction assuming vertical equilibrium to give analytical expressions for three-phase pseudo relative permeabilities and capillary pressures for a stratified reservoir.
A similarity transform results in a set of two coupled, ordinary differential equations and a simple technique is presented to identify the traveling-wave solution when certain conditions are met, and the shape of the front is calculated. The technique is based on an analysis of initial and boundary conditions and is verified by numerical simulation.
Dietz's classical stability theory for two-phase displacement fronts has recently been extended to layered reservoirs. To our knowledge, the present paper is the first to treat three-phase flow. It is shown that stable water-oil-gas fronts occur only for a limited number of the injection gas-water ratio, if at all.
Introduction
Gravity-segregated multiphase flow takes place in reservoirs with high vertical permeability and large distances between wells, a situation relevant for many North Sea reservoirs. Two-phase, gravity-segregated flow theory has been discussed in books and several papers and may be looked upon as fairly matured. The extension to three-phase flow is, however, still not developed even though there are important practical applications, e.g., water-alternate-gas injection.
There exist two approaches to two-phase gravity-segregated flow in the literature. Dietz and Ekrann considered the stability of the boundary between the two phases. Others have used averaging of the flow equations in the dip-normal direction and have introduced pseudo-functions.
In this paper we follow the the second approach and apply pseudo relative permeabilities and pseudo capillary pressures to allow two-dimensional flow in a cross-section to be modeled by a set of equations in one dimension. The solutions of the traveling-wave type entail conditions for stability of displacement fronts and the possibility of high vertical sweep efficiency.
The traveling-wave solution for gravity-segregated flow was introduced by Martin and expanded upon by Ingsoy et al. First, the problem is reduced from two to one dimension by pseudofunctions and then solved by the method of Rijhik et at. The works of Martin and Ingsoy et al. bridge the pseudofunction approach of Coats et al. with the front-shape calculation of Dietz and Ekrann.
Gravity Segregated Three-Phase Flow
In this section we derive pseudofunctions to model 2D reservoir flow by iD equations. The results may also be directly applied to describe 3D reservoir flow by 2D equations.
With capillary effects neglected, three-phase flow of immiscible, incompressible fluids in two dimensions is in general described by the following set of equations for each phase i,
Abstract
This paper presents an analytical and numerical study of the stability of gas-oil-water displacement fronts in two and three spatial dimensions. The flow equations are simplified by averaging in the dip-normal direction assuming vertical equilibrium to give analytical expressions for three-phase pseudo relative permeabilities and capillary pressures for a stratified reservoir.
A similarity transform results in a set of two coupled, ordinary differential equations and a simple technique is presented to identify the traveling-wave solution when certain conditions are met, and the shape of the front is calculated. The technique is based on an analysis of initial and boundary conditions and is verified by numerical simulation.
Dietz's classical stability theory for two-phase displacement fronts has recently been extended to layered reservoirs. To our knowledge, the present paper is the first to treat three-phase flow. It is shown that stable water-oil-gas fronts occur only for a limited number of the injection gas-water ratio, if at all.
Introduction
Gravity-segregated multiphase flow takes place in reservoirs with high vertical permeability and large distances between wells, a situation relevant for many North Sea reservoirs. Two-phase, gravity-segregated flow theory has been discussed in books and several papers and may be looked upon as fairly matured. The extension to three-phase flow is, however, still not developed even though there are important practical applications, e.g., water-alternate-gas injection.
There exist two approaches to two-phase gravity-segregated flow in the literature. Dietz and Ekrann considered the stability of the boundary between the two phases. Others have used averaging of the flow equations in the dip-normal direction and have introduced pseudo-functions.
In this paper we follow the the second approach and apply pseudo relative permeabilities and pseudo capillary pressures to allow two-dimensional flow in a cross-section to be modeled by a set of equations in one dimension. The solutions of the traveling-wave type entail conditions for stability of displacement fronts and the possibility of high vertical sweep efficiency.
The traveling-wave solution for gravity-segregated flow was introduced by Martin and expanded upon by Ingsoy et al. First, the problem is reduced from two to one dimension by pseudofunctions and then solved by the method of Rijhik et at. The works of Martin and Ingsoy et al. bridge the pseudofunction approach of Coats et al. with the front-shape calculation of Dietz and Ekrann.
Gravity Segregated Three-Phase Flow
In this section we derive pseudofunctions to model 2D reservoir flow by iD equations. The results may also be directly applied to describe 3D reservoir flow by 2D equations.
With capillary effects neglected, three-phase flow of immiscible, incompressible fluids in two dimensions is in general described by the following set of equations for each phase i,
Wave Structure in WAG Recovery
Abstract
For immiscible three-phase flow, potentially three-quarters of the oil recovered through a WAG process can be caused by a non-Buckley-Leverett "transitional" shock wave. This nonclassical kind of wave is common in three-phase flow. In this paper, we show how transitional waves arise in WAG flow and how they can be calculated by semi-analytic methods, which are helpful in the design of effective WAG recovery strategies.
Abstract
For immiscible three-phase flow, potentially three-quarters of the oil recovered through a WAG process can be caused by a non-Buckley-Leverett "transitional" shock wave. This nonclassical kind of wave is common in three-phase flow. In this paper, we show how transitional waves arise in WAG flow and how they can be calculated by semi-analytic methods, which are helpful in the design of effective WAG recovery strategies.
Pore-to-Field Scale Modeling of WAG
Abstract
The paper describes an integrated pore-to-field scale modeling method of multiphase flow in porous media. Although the method is general, we demonstrate its power and versatility by modeling a WAG process in the Etive formation in a North Sea oil field. The method aims at capturing the relevant flow physics at different scales. Pore scale physics (μm-scale) is accounted for through predictive pore scale modeling of relative permeability and capillary pressure. The computed rock curves (cm-scale) are used to populate detailed geological models with a plausible spatial distribution of constitutive relations. Effective flow properties at the heterogeneous facies scale (m-scale) are determined by a steady state upscaling technique. Finally, the effective flow properties are implemented in a field scale (km-scale) simulation model. The simulation results show that the effective flow properties describe the reservoir WAG performance fairly accurately without any adjustment through history matching.
Introduction
Hydrocarbon reservoirs are generally heterogeneous and display spatial variability in their geometric and hydraulic properties on all length scales. In recent years, the petroleum industry has emphasized and made significant progress in describing detailed heterogeneities in the reservoir and incorporating these heterogeneities in the flow calculations1-3. For single phase properties - porosity and permeability - geological models that incorporate spatial in-homogeneity down to the scale of centimeters are now routinely generated for large hydrocarbon reservoirs.
Just like single phase properties, multiphase properties will vary considerably throughout the reservoir depending on the local pore structure, interactions between the fluids, and rock-fluid interactions. However, the description of the spatial variability of multiphase flow properties is not nearly as detailed as that for single phase properties. Measurements of multiphase flow properties, such as relative permeability and capillary pressure, are much more scarce and there is no easy way to account for variations of these properties in the field, due to different pore structures and/or wettability trends. Typically, a single set of constitutive relations is assumed and applied to the whole field or to a few major rock types. This is almost invariably incorrect. Furthermore, the constitutive relations themselves often come from empirical correlations of dubious quality or from measurements on core samples that may only be representative for a very small portion of the reservoir.
Pore scale modeling offers exciting possibilities of bridging the gap between detailed descriptions of the variability of single phase properties and the lack thereof for multiphase flow properties. Recent advances in pore scale modeling have shown that a realistic characterization of the pore structure can be used to produce a model that accurately predicts both single and multiphase flow properties4-14, at least for diagentically simple rocks. If predictive pore scale modeling is verified for a diverse range of reservoir rocks, it can become a very useful reservoir characterization tool which can be used to populate fine scale geological models with a realistic spatial distribution of constitutive relations derived from pore scale modeling.
It is well established that small-scale heterogeneities can have a significant impact on flow and oil recovery2,15,16. However, small-scale heterogeneities cannot be directly incorporated in field-scale simulation models because of limitations in computer speed. Therefore, the average effects of small-scale heterogeneities in large-scale numerical grids must be accounted for through upscaling. There are two key components in upscaling: up-gridding and averaging. The former focuses on preserving the geological features of the fine grid model and will not be discussed here. The latter focuses on computing effective properties that can accurately capture the flow behavior in the detailed model. For single phase flow, a variety of averaging techniques have been developed. These range from simple statistical estimates to detailed numerical simulations
A Simulation Study of Chemically Enhanced Water Alternating Gas (CWAG) Injection
Abstract
Water alternating gas (WAG) injection has been a popular method for commercial gas injection projects worldwide. The injection of water and gas alternatively offers better mobility control of gas and hence, improves the volumetric sweep efficiency. Although the WAG process is conceptually sound, its field incremental recovery is disappointing as it rarely exceeds 5 to 10 % OOIP. Apart from operational problems, the WAG mechanism suffers from inherent challenges such as water blocking, gravity segregation, mobility control in high viscosity oil, decreased oil relative permeability, and decreased gas injectivity.
This paper addresses the aforementioned problems and proposes a new combination method, named as the chemically enhanced water alternating gas (CWAG), to improve the efficiency of WAG process. The unique feature of this new method is that it uses alkaline, surfactant, and polymer as a chemical slug which will be injected during WAG process to reduce the interfacial tension (IFT) and improve the mobility ratio. In a CWAG process, a chemical slug is chased by water, preceded by gas slug and followed by alternate CO2 and water slug or chemical slug injects after one cycle of gas and water slug. Essentially CWAG involves a combination of chemical flooding and immiscible carbon dioxide (CO2) injections. These mechanisms are IFT reduction, reducing water blocking effect, mobility control, oil viscosity reduction due to the CO2 dissolution and oil swelling.
CMG's STARS was used to study the performance of the new method using some of the data found in the literature. It is a chemical flood simulator that can simulate all aspects of chemical flooding, and it can also handle immiscible CO2 injection features by considering K-value partitioning. The sensitivity analysis shows that the new method gives a better recovery when compared to conventional WAG. This study shows the potential of CWAG to enhance oil recovery.
Introduction
Enhanced oil recovery (EOR) refers to a variety of processes to increase the amount of oil extracted from a reservoir after primary and secondary recoveries, typically by injecting liquid chemicals (e.g., surfactant) or gas (e.g., nitrogen, carbon dioxide) or the use of thermal energy. The injected fluids compliment the natural energy of the reservoir or interact with the reservoir rock/oil system to create favorable conditions for oil recovery (Green and Willhite 1998). The concept of EOR has gained popularity as the global demand for supply of oil has increased. It is generally known that about two-thirds of original oil in place (OOIP) remains unrecovered after primary and secondary recovery (pressure maintenance, water flooding). The remaining oil exists as trapped, immobile oil droplets due to high capillary forces between water and oil droplets. Hence, EOR methods are key factors to extend and maximize production from existing oil and gas fields. The economic potential of providing new methods for increased and enhanced oil recovery is significant. It therefore represents a subject of great interest as it provides a means to optimize production and resource management.
Abstract
Water alternating gas (WAG) injection has been a popular method for commercial gas injection projects worldwide. The injection of water and gas alternatively offers better mobility control of gas and hence, improves the volumetric sweep efficiency. Although the WAG process is conceptually sound, its field incremental recovery is disappointing as it rarely exceeds 5 to 10 % OOIP. Apart from operational problems, the WAG mechanism suffers from inherent challenges such as water blocking, gravity segregation, mobility control in high viscosity oil, decreased oil relative permeability, and decreased gas injectivity.
This paper addresses the aforementioned problems and proposes a new combination method, named as the chemically enhanced water alternating gas (CWAG), to improve the efficiency of WAG process. The unique feature of this new method is that it uses alkaline, surfactant, and polymer as a chemical slug which will be injected during WAG process to reduce the interfacial tension (IFT) and improve the mobility ratio. In a CWAG process, a chemical slug is chased by water, preceded by gas slug and followed by alternate CO2 and water slug or chemical slug injects after one cycle of gas and water slug. Essentially CWAG involves a combination of chemical flooding and immiscible carbon dioxide (CO2) injections. These mechanisms are IFT reduction, reducing water blocking effect, mobility control, oil viscosity reduction due to the CO2 dissolution and oil swelling.
CMG's STARS was used to study the performance of the new method using some of the data found in the literature. It is a chemical flood simulator that can simulate all aspects of chemical flooding, and it can also handle immiscible CO2 injection features by considering K-value partitioning. The sensitivity analysis shows that the new method gives a better recovery when compared to conventional WAG. This study shows the potential of CWAG to enhance oil recovery.
Introduction
Enhanced oil recovery (EOR) refers to a variety of processes to increase the amount of oil extracted from a reservoir after primary and secondary recoveries, typically by injecting liquid chemicals (e.g., surfactant) or gas (e.g., nitrogen, carbon dioxide) or the use of thermal energy. The injected fluids compliment the natural energy of the reservoir or interact with the reservoir rock/oil system to create favorable conditions for oil recovery (Green and Willhite 1998). The concept of EOR has gained popularity as the global demand for supply of oil has increased. It is generally known that about two-thirds of original oil in place (OOIP) remains unrecovered after primary and secondary recovery (pressure maintenance, water flooding). The remaining oil exists as trapped, immobile oil droplets due to high capillary forces between water and oil droplets. Hence, EOR methods are key factors to extend and maximize production from existing oil and gas fields. The economic potential of providing new methods for increased and enhanced oil recovery is significant. It therefore represents a subject of great interest as it provides a means to optimize production and resource management.
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