Fabian Iwere - Academia.edu (original) (raw)
Papers by Fabian Iwere
Proceedings of SPE Annual Technical Conference and Exhibition, Sep 1, 2004
All Days, Feb 10, 2002
As a part of an integrated improved oil recovery project, it was required to evaluate asphaltene ... more As a part of an integrated improved oil recovery project, it was required to evaluate asphaltene formation arising from contacting nitrogen gas with the reservoir fluid. This paper discusses the experimental work associated with the asphaltene evaluation. The subject reservoir was known to have operational problems due to asphaltene precipitation during primary production. Hence, laboratory experiments using the transmittance of an optimized laser light in the near infrared (NIR) wavelength (~1600 nm) were used to first define the pressure-temperature regions of asphaltene instability of the reservoir fluid. Subsequently, several light transmittance experiments were conducted to evaluate the asphaltene instability regions by contacting various molar concentrations (5, 10, & 20%) of nitrogen gas with the reservoir fluid. Also, measurements were conducted to quantify the bulk precipitation of asphaltene with various molar concentrations of nitrogen. Results indicated that nitrogen gas aggravated the asphaltene instability, and also, increased the bulk precipitation amount with increasing concentrations of nitrogen gas in the reservoir fluid. The aggravated asphaltene instability could potentially nullify any expected benefits of improved oil recovery with nitrogen injection as pressure maintenance.
All Days, Dec 10, 2012
The Burgan Minagish reservoir in the Greater Burgan Field is one of several reservoirs producing ... more The Burgan Minagish reservoir in the Greater Burgan Field is one of several reservoirs producing from the Minagish formation in Kuwait and the Divided Zone. The reservoir has been produced intermittently since the 1960s under natural depletion. A powered water-flood is currently being planned. The pressure performance of the reservoir has proved hard to explain without invoking communication with other reservoirs. Such communication could be either with other reservoirs through the regional aquifer of through faults to other reservoirs in the Greater Burgan field. Recent pressures are close to the bubble point.A coarse simulation model of the nearby fields and the regional aquifer was constructed based on data from the fields and regional geological understanding. This model could be history matched to allow all regional pressure data to be broadly matched, a result which supports the view that communication is through the regional aquifer. Using this model to predict future pressure performance suggested that injecting at rates that exceeded voidage replacement by about 50 Mbd could keep reservoir pressure above bubble point. It was recognized that the process of history matching performance was non-unique. This is a particular concern in the context of this study because the model inputs that were varied in the history matching process included aquifer data that was very poorly constrained. To address this problem multiple history matched models were created using an assisted history matching tool. Using prediction results from the range of models has increased our confidence that a modest degree of over-injection can help maintain reservoir pressure.This paper demonstrates the utility of computer assisted history match tools in allowing an assessment of uncertainty in a case where non-uniqueness was a particular problem. It also emphasizes the importance of understanding aquifer communication when relatively closely spaced fields are being developed.
All Days, Mar 24, 2009
Conceptual models are used to solve specific problems in selected sectors of reservoirs; study pr... more Conceptual models are used to solve specific problems in selected sectors of reservoirs; study production mechanisms; understand behavior of a particular process in a reservoir system, and assess impacts of changing input parameters during reservoir modeling. They are tools of choice for assessing risks, evaluating "worst-case" scenarios, validating analyst's intuition, and to support informed decision making. Our objective is to demonstrate via two case studies how conceptual numerical models were used to shorten the time required to make reservoir management decisions. The first case study involves making a decision, either to develop or sell an oil property. Target formation is sandstone saturated with heavy oil (12°API gravity) which is overlain by a gas cap. Conceptual numerical simulation models provided answers to two questions: What is the impact of gas production from the gas cap on the underlying heavy oil zone? Can gas production from up-structure wells meet field deliverability requirements? Second case study uses conceptual models to optimize well placement and support infill drilling. Infill well placement posed a challenge because thickness of target formation is not well known, and oil zone is bounded on top by a massive impermeable shale boundary, and by oil-water contact (OWC) located about 20-40 feet below. Conceptual models answered the following questions: What type of well to drill–vertical or horizontal? What is the impact of horizontal well's vertical placement (offset distance from OWC) on oil recovery and water breakthrough times? What is the optimum horizontal well lateral length and its impact on oil recovery? This paper describes modeling methodology, major observations and conclusions. We discuss the benefits and lessons learned from the case studies and demonstrate that successful application of conceptual models requires identifying key well/reservoir performance drivers and assessing their impacts on the reservoir management decisions.
All Days, Oct 5, 2003
The results of a reservoir performance evaluation of a giant mature heavy oil field are presented... more The results of a reservoir performance evaluation of a giant mature heavy oil field are presented here. This field began production in 1927. By 2002, cumulative production had surpassed half a billion barrels of low-gravity oil from Miocene sandstone formations produced under natural depletion, water and gas injection, and cyclic steam injection from more than 400 wells. As a result, several interdependent flow models including black-oil full-field, thermal single-well, and thermal large-sector models were built for field analysis and optimization. The long and complex production history, as well as the various recovery mechanisms, presented a number of challenges in constructing and calibrating the models to past historical performance. The optimization work was done in the following three stages. First, a coarse-grid black-oil model was constructed to study the field performance prior to steam injection, following the successful geological modeling phase of this project (presented in Márquez et al., 20011). The second stage involved single-well and sector-model thermal simulation analysis. The thermal models were used to match the field historical pressure and production data over the natural depletion, water injection and cyclic steam injection periods. Third, we investigated the field performance under different development scenarios. Optimization results with the singlewell thermal models were incorporated into the sector models, which were used for processing runs to examine infill drilling; recompletion of active wells; waterflooding; huff ‘n’ puff steam injection; steam drive; and horizontal well drilling. The project resulted in the identification of more than 100 infill or recompletion candidates, and an estimated three million barrels of oil (MMBO) of additional recovery during the first 2 years of this project. As a result there were significant performance improvements and more are anticipated through the implementation of the field development strategies recommended here. The modeling approach led to significant time savings and provided an effective reservoir management tool for future field development.
American Association of Petroleum Geologists eBooks, 2011
The Pinedale anticline is a large natural gas field in the Greater Green River Basin of Wyoming, ... more The Pinedale anticline is a large natural gas field in the Greater Green River Basin of Wyoming, located north of the giant Jonah field. Gas production is from overpressured fluvial channel sandstones of the Upper Cretaceous Mesaverde and Lance formations and the lower Tertiary “unnamed Tertiary” formation. To date, most studies have focused on the regional geology and potential hydrocarbon economics. This chapter discusses an integrated approach for reservoir modeling to reduce uncertainty in this tight-gas field development. In this study, fluvial facies were defined using wireline logs. Object-based modeling was used to integrate well-log facies, object dimension, channel sinuosity, and orientation in building the three-dimensional facies model. The facies model was then used to guide petrophysical property modeling. Dependencies between rock properties were modeled using a geostatistical method. The final model honors the fluvial depositional characteristics and dependencies between the rock properties and was used for better uncertainty management in reservoir simulation and performance forecasting.
SPE Enhanced Oil Recovery Symposium, 1986
Summary Steam injection into fractured carbonates has been examined in the laboratory and with a ... more Summary Steam injection into fractured carbonates has been examined in the laboratory and with a fully implicit reservoir simulator. These studies showed that significant oil can be recovered from matrix elements when hot water or steam is injected into fractures. Heat is rapidly replenished to fractures and heat conduction into the matrix plays a major role in matrix heating with a resulting increase in the rate of oil release. At steam temperatures carbonates decompose to produce a significant amount of CO2 which further enhances the recovery rate. Carbonate disks were flooded in the laboratory with hot water and steam. Oil recovery from competent as well as fractured disks increased as injection temperature increased. Oil recovery from fractured disks approached 30% 0IP at 200°F even though pressure differentials were small. In other experiments, CO2 con-centration in effluent gas was determined. One mole of CO2 was produced for each mole of H2O injected at steam temperatures. Reservoir simulations were accomplished using two kinds of porosity/permeability grid blocks. Fracture grid blocks were continuous from injection to production wells and accounted for less than 0.5% of the total reservoir volume. Oil recovery and water/oil ratios were dependent on matrix grid block size, steam Injection rate, initial saturations and distributions, and CO2 generation. Oil recovery increased with in creasing steam injection rates, however, water/oil ratios were high. These results show that there is an optimum steam injection rate for a specified reservoir volume and matrix grid block size. The rate of heat conduction from fracture to matrix is the controlling factor.
All Days, 2002
Several factors, including the oil composition, reservoir pressure and temperature, and the prope... more Several factors, including the oil composition, reservoir pressure and temperature, and the properties of asphaltene, influence asphaltene precipitation from reservoir oil. Asphaltene starts to precipitate and plug the reservoir pore space under certain reservoir conditions, reducing flow capacity of the wells and the amount of recoverable oil. It is necessary to understand the mechanism of asphaltene precipitation and the resulting effects on well performance in order to build a representative forecasting model for reservoir management. The goal of this study is to model the effects of asphaltene precipitation on fluid flow and oil production from the vuggy, fractured reservoirs of the Taratunich Field. Asphaltene precipitation has presented serious problems in the development of this field, which is located in the Bay of Campeche, Mexico. Asphaltene deposition has been reported both at the tubings and surface facilities. Special laboratory fluid and core studies and analysis of th...
All Days, 2002
Three porosity types, matrix, vugs and fractures, are usually present in naturally fractured, vug... more Three porosity types, matrix, vugs and fractures, are usually present in naturally fractured, vuggy carbonate reservoirs. The vugs are generally considered connected either to the matrix or to the fractures in numerical simulation. One of the challenges of modeling these reservoirs is the partitioning of the porosities into two components since dual porosity reservoir simulators can only handle two rock components, namely matrix system and fracture system. The goal of this study is to characterize the vugs in these systems, and to determine the pore volume compressibility for the simulation of vuggy, naturally fractured reservoirs. Sequential laboratory experiments were designed and conducted to determine the amount of secondary porosity in the core samples. A combination of capillary pressure (centrifuge and mercury injection experiments) and NMR experiments was used to determine the vug or secondary porosity of the samples from pore size and T2 (relaxation time) distributions. The...
Proceedings of SPE International Petroleum Conference in Mexico, 2004
This paper presents the challenges of constructing adequate static and flow models of a field fro... more This paper presents the challenges of constructing adequate static and flow models of a field from disparate data sets, and the workflow methodologies adopted for integrating, reconciling, and extrapolating available data from multiple disciplines. This study uses a data set of about 300 wells penetrating a 2500-meter thick section of fractured and vuggy carbonates. A 30-year production history was used to calibrate the model; the main recovery mechanism of the complex is rock and fluid expansion, combined with a weak aquifer. A reservoir simulation study was constructed to investigate the field behavior under natural depletion, water injection and gas injection, and to provide technical foundation supporting investments in future development projects. The static model comprises of a three-dimensional structural model, a matrix property model, and a fracture property model. There was no 3-D seismic. The complex system of normal and reverse faults dividing the structure into 70 fault blocks was created from well picks. The matrix property model was derived from limited routine and special cores, and vug analysis. The fracture property model was obtained by integrating fracture indicator logs, including DSI, image logs, conventional logs of different vintages, with fault orientation from structural conditioning, core analysis, PTA, well production and static pressure histories. The complex structure, long production history and the various recovery mechanisms posed additional challenges in constructing and calibrating the flow models to historical performances. The fluid properties for the thick reservoir sections were derived using limited available fluid samples, and verified by history matching reservoir pressure and gas-oil ratio, which declined over time until secondary gas cap encroachment. The different vintage and accuracies of the pressure and rate measurement devices were also considered in evaluating the history match quality.
The results of a reservoir performance evaluation of a giant mature heavy oil field are presented... more The results of a reservoir performance evaluation of a giant mature heavy oil field are presented here. This field began production in 1927. By 2002, cumulative production had surpassed half a billion barrels of low-gravity oil from Miocene sandstone formations produced under natural depletion, water and gas injection, and cyclic steam injection from more than 400 wells. As a result, several interdependent flow models including black-oil full-field, thermal single-well, and thermal large-sector models were built for field analysis and optimization. The long and complex production history, as well as the various recovery mechanisms, presented a number of challenges in constructing and calibrating the models to past historical performance. The optimization work was done in the following three stages. First, a coarse-grid black-oil model was constructed to study the field performance prior to steam injection, following the successful geological modeling phase of this project (presented in Márquez et al., 2001 1). The second stage involved single-well and sector-model thermal simulation analysis. The thermal models were used to match the field historical pressure and production data over the natural depletion, water injection and cyclic steam injection periods.T hird, we investigated the field performance under different development scenarios. Optimization results with the single-well thermal models were incorporated into the sector models, which were used for processing runs to examine infill drilling; recompletion of active wells; waterflooding; huff ‘n’puff steam injection; steam drive; and horizontal well drilling. The project resulted in the identification of more than 100 infill or recompletion candidates, and an estimated three million barrels of oil (MMBO)of additional recovery during the first 2 years of this project. As a result there were significant performance improvements and more are anticipated through the implementation of the field development strategies recommendedhere. The modeling approach led to significant time savings and provided an effective reservoir management tool for future field development. Introduction Schlumberger Data and Consulting Services (DCS), in Denver, Colorado, initiated a project for preparing the numerical 3D predictive model of theLL-04 Miocene reservoirs in Lake Maracaibo. The objectives of the reservoir performance evaluation were toprovide Petróleos de Venezuela, S.A. (PDVSA), the Venezuelan state-owned national oil company, with an updated geologic model that could be used to select new drilling and workover candidatesprovide PDVSA with a dynamic flow model that could be used as a tool to improve ultimate recovery from a number of operating strategies, and to monitor the field performancemake recommendations that would help PDVSA maximize production, maximize oil recovery, and to determine the best operating strategy for the field. This paper describes the reservoir simulation part of the reservoir characterization and simulation project. The Reservoir The LL-04 field is located on the northeast side of Lake Maracaibo along the Bolivar Coast of Venezuela (Fig. 1). This was one of the first fields discovered in Lake Maracaibo with production dating back to 1927. Production is from shallow (2000 to 3000 ft) unconsolidated sands in the Miocene La Rosa, Lower Laguna and Lower Lagunillas formations. Because production from the field is from highly unconsolidated sands, very limited core was available. Complicating the reservoir performance is the subsidence that has occurred. This has been accounted for by using very high rock compressibility in the simulation model.
The Pinedale anticline is a large natural gas field in the Greater Green River Basin of Wyoming, ... more The Pinedale anticline is a large natural gas field in the Greater Green River Basin of Wyoming, located north of the giant Jonah field. Gas production is from overpressured fluvial channel sandstones of the Upper Cretaceous Mesaverde and Lance formations and the lower Tertiary “unnamed Tertiary” formation. To date, most studies have focused on the regional geology and potential hydrocarbon economics. This chapter discusses an integrated approach for reservoir modeling to reduce uncertainty in this tight-gas field development. In this study, fluvial facies were defined using wireline logs. Object-based modeling was used to integrate well-log facies, object dimension, channel sinuosity, and orientation in building the three-dimensional facies model. The facies model was then used to guide petrophysical property modeling. Dependencies between rock properties were modeled using a geostatistical method. The final model honors the fluvial depositional characteristics and dependencies between the rock properties and was used for better uncertainty management in reservoir simulation and performance forecasting.
Copyright 2009, Society of Petroleum Engineers This paper was prepared for presentation at the 20... more Copyright 2009, Society of Petroleum Engineers This paper was prepared for presentation at the 2009 SPE Rocky Mountain Petroleum Technology Conference held in Denver, Colorado, USA, 1416 April 2009. This paper was selected for presentation by an SPE ...
Proceedings of SPE Annual Technical Conference and Exhibition, 2005
SPE Americas Unconventional Resources Conference, 2012
SPE Rocky Mountain Petroleum Technology Conference, 2009
Copyright 2009, Society of Petroleum Engineers This paper was prepared for presentation at the 20... more Copyright 2009, Society of Petroleum Engineers This paper was prepared for presentation at the 2009 SPE Rocky Mountain Petroleum Technology Conference held in Denver, Colorado, USA, 1416 April 2009. This paper was selected for presentation by an SPE ...
Proceedings of Eastern Regional Meeting, 2007
... One set developed parallel to the direction of maximum shortening with an ESE – WNW strike an... more ... One set developed parallel to the direction of maximum shortening with an ESE – WNW strike and a sub vertical dip. ... The updip well performed better than the down-dip well although its producing GOR was increasing throughout the run. ...
SPE Hydraulic Fracturing Technology Conference, 2012
Abstract In field development programs where large variations in reservoir and completion paramet... more Abstract In field development programs where large variations in reservoir and completion parameters exist, the evaluation of reservoir performance to determine the optimal completion strategy can be a challenging task. This paper presents findings from a recent ...
Proceedings of SPE Annual Technical Conference and Exhibition, Sep 1, 2004
All Days, Feb 10, 2002
As a part of an integrated improved oil recovery project, it was required to evaluate asphaltene ... more As a part of an integrated improved oil recovery project, it was required to evaluate asphaltene formation arising from contacting nitrogen gas with the reservoir fluid. This paper discusses the experimental work associated with the asphaltene evaluation. The subject reservoir was known to have operational problems due to asphaltene precipitation during primary production. Hence, laboratory experiments using the transmittance of an optimized laser light in the near infrared (NIR) wavelength (~1600 nm) were used to first define the pressure-temperature regions of asphaltene instability of the reservoir fluid. Subsequently, several light transmittance experiments were conducted to evaluate the asphaltene instability regions by contacting various molar concentrations (5, 10, & 20%) of nitrogen gas with the reservoir fluid. Also, measurements were conducted to quantify the bulk precipitation of asphaltene with various molar concentrations of nitrogen. Results indicated that nitrogen gas aggravated the asphaltene instability, and also, increased the bulk precipitation amount with increasing concentrations of nitrogen gas in the reservoir fluid. The aggravated asphaltene instability could potentially nullify any expected benefits of improved oil recovery with nitrogen injection as pressure maintenance.
All Days, Dec 10, 2012
The Burgan Minagish reservoir in the Greater Burgan Field is one of several reservoirs producing ... more The Burgan Minagish reservoir in the Greater Burgan Field is one of several reservoirs producing from the Minagish formation in Kuwait and the Divided Zone. The reservoir has been produced intermittently since the 1960s under natural depletion. A powered water-flood is currently being planned. The pressure performance of the reservoir has proved hard to explain without invoking communication with other reservoirs. Such communication could be either with other reservoirs through the regional aquifer of through faults to other reservoirs in the Greater Burgan field. Recent pressures are close to the bubble point.A coarse simulation model of the nearby fields and the regional aquifer was constructed based on data from the fields and regional geological understanding. This model could be history matched to allow all regional pressure data to be broadly matched, a result which supports the view that communication is through the regional aquifer. Using this model to predict future pressure performance suggested that injecting at rates that exceeded voidage replacement by about 50 Mbd could keep reservoir pressure above bubble point. It was recognized that the process of history matching performance was non-unique. This is a particular concern in the context of this study because the model inputs that were varied in the history matching process included aquifer data that was very poorly constrained. To address this problem multiple history matched models were created using an assisted history matching tool. Using prediction results from the range of models has increased our confidence that a modest degree of over-injection can help maintain reservoir pressure.This paper demonstrates the utility of computer assisted history match tools in allowing an assessment of uncertainty in a case where non-uniqueness was a particular problem. It also emphasizes the importance of understanding aquifer communication when relatively closely spaced fields are being developed.
All Days, Mar 24, 2009
Conceptual models are used to solve specific problems in selected sectors of reservoirs; study pr... more Conceptual models are used to solve specific problems in selected sectors of reservoirs; study production mechanisms; understand behavior of a particular process in a reservoir system, and assess impacts of changing input parameters during reservoir modeling. They are tools of choice for assessing risks, evaluating "worst-case" scenarios, validating analyst's intuition, and to support informed decision making. Our objective is to demonstrate via two case studies how conceptual numerical models were used to shorten the time required to make reservoir management decisions. The first case study involves making a decision, either to develop or sell an oil property. Target formation is sandstone saturated with heavy oil (12°API gravity) which is overlain by a gas cap. Conceptual numerical simulation models provided answers to two questions: What is the impact of gas production from the gas cap on the underlying heavy oil zone? Can gas production from up-structure wells meet field deliverability requirements? Second case study uses conceptual models to optimize well placement and support infill drilling. Infill well placement posed a challenge because thickness of target formation is not well known, and oil zone is bounded on top by a massive impermeable shale boundary, and by oil-water contact (OWC) located about 20-40 feet below. Conceptual models answered the following questions: What type of well to drill–vertical or horizontal? What is the impact of horizontal well's vertical placement (offset distance from OWC) on oil recovery and water breakthrough times? What is the optimum horizontal well lateral length and its impact on oil recovery? This paper describes modeling methodology, major observations and conclusions. We discuss the benefits and lessons learned from the case studies and demonstrate that successful application of conceptual models requires identifying key well/reservoir performance drivers and assessing their impacts on the reservoir management decisions.
All Days, Oct 5, 2003
The results of a reservoir performance evaluation of a giant mature heavy oil field are presented... more The results of a reservoir performance evaluation of a giant mature heavy oil field are presented here. This field began production in 1927. By 2002, cumulative production had surpassed half a billion barrels of low-gravity oil from Miocene sandstone formations produced under natural depletion, water and gas injection, and cyclic steam injection from more than 400 wells. As a result, several interdependent flow models including black-oil full-field, thermal single-well, and thermal large-sector models were built for field analysis and optimization. The long and complex production history, as well as the various recovery mechanisms, presented a number of challenges in constructing and calibrating the models to past historical performance. The optimization work was done in the following three stages. First, a coarse-grid black-oil model was constructed to study the field performance prior to steam injection, following the successful geological modeling phase of this project (presented in Márquez et al., 20011). The second stage involved single-well and sector-model thermal simulation analysis. The thermal models were used to match the field historical pressure and production data over the natural depletion, water injection and cyclic steam injection periods. Third, we investigated the field performance under different development scenarios. Optimization results with the singlewell thermal models were incorporated into the sector models, which were used for processing runs to examine infill drilling; recompletion of active wells; waterflooding; huff ‘n’ puff steam injection; steam drive; and horizontal well drilling. The project resulted in the identification of more than 100 infill or recompletion candidates, and an estimated three million barrels of oil (MMBO) of additional recovery during the first 2 years of this project. As a result there were significant performance improvements and more are anticipated through the implementation of the field development strategies recommended here. The modeling approach led to significant time savings and provided an effective reservoir management tool for future field development.
American Association of Petroleum Geologists eBooks, 2011
The Pinedale anticline is a large natural gas field in the Greater Green River Basin of Wyoming, ... more The Pinedale anticline is a large natural gas field in the Greater Green River Basin of Wyoming, located north of the giant Jonah field. Gas production is from overpressured fluvial channel sandstones of the Upper Cretaceous Mesaverde and Lance formations and the lower Tertiary “unnamed Tertiary” formation. To date, most studies have focused on the regional geology and potential hydrocarbon economics. This chapter discusses an integrated approach for reservoir modeling to reduce uncertainty in this tight-gas field development. In this study, fluvial facies were defined using wireline logs. Object-based modeling was used to integrate well-log facies, object dimension, channel sinuosity, and orientation in building the three-dimensional facies model. The facies model was then used to guide petrophysical property modeling. Dependencies between rock properties were modeled using a geostatistical method. The final model honors the fluvial depositional characteristics and dependencies between the rock properties and was used for better uncertainty management in reservoir simulation and performance forecasting.
SPE Enhanced Oil Recovery Symposium, 1986
Summary Steam injection into fractured carbonates has been examined in the laboratory and with a ... more Summary Steam injection into fractured carbonates has been examined in the laboratory and with a fully implicit reservoir simulator. These studies showed that significant oil can be recovered from matrix elements when hot water or steam is injected into fractures. Heat is rapidly replenished to fractures and heat conduction into the matrix plays a major role in matrix heating with a resulting increase in the rate of oil release. At steam temperatures carbonates decompose to produce a significant amount of CO2 which further enhances the recovery rate. Carbonate disks were flooded in the laboratory with hot water and steam. Oil recovery from competent as well as fractured disks increased as injection temperature increased. Oil recovery from fractured disks approached 30% 0IP at 200°F even though pressure differentials were small. In other experiments, CO2 con-centration in effluent gas was determined. One mole of CO2 was produced for each mole of H2O injected at steam temperatures. Reservoir simulations were accomplished using two kinds of porosity/permeability grid blocks. Fracture grid blocks were continuous from injection to production wells and accounted for less than 0.5% of the total reservoir volume. Oil recovery and water/oil ratios were dependent on matrix grid block size, steam Injection rate, initial saturations and distributions, and CO2 generation. Oil recovery increased with in creasing steam injection rates, however, water/oil ratios were high. These results show that there is an optimum steam injection rate for a specified reservoir volume and matrix grid block size. The rate of heat conduction from fracture to matrix is the controlling factor.
All Days, 2002
Several factors, including the oil composition, reservoir pressure and temperature, and the prope... more Several factors, including the oil composition, reservoir pressure and temperature, and the properties of asphaltene, influence asphaltene precipitation from reservoir oil. Asphaltene starts to precipitate and plug the reservoir pore space under certain reservoir conditions, reducing flow capacity of the wells and the amount of recoverable oil. It is necessary to understand the mechanism of asphaltene precipitation and the resulting effects on well performance in order to build a representative forecasting model for reservoir management. The goal of this study is to model the effects of asphaltene precipitation on fluid flow and oil production from the vuggy, fractured reservoirs of the Taratunich Field. Asphaltene precipitation has presented serious problems in the development of this field, which is located in the Bay of Campeche, Mexico. Asphaltene deposition has been reported both at the tubings and surface facilities. Special laboratory fluid and core studies and analysis of th...
All Days, 2002
Three porosity types, matrix, vugs and fractures, are usually present in naturally fractured, vug... more Three porosity types, matrix, vugs and fractures, are usually present in naturally fractured, vuggy carbonate reservoirs. The vugs are generally considered connected either to the matrix or to the fractures in numerical simulation. One of the challenges of modeling these reservoirs is the partitioning of the porosities into two components since dual porosity reservoir simulators can only handle two rock components, namely matrix system and fracture system. The goal of this study is to characterize the vugs in these systems, and to determine the pore volume compressibility for the simulation of vuggy, naturally fractured reservoirs. Sequential laboratory experiments were designed and conducted to determine the amount of secondary porosity in the core samples. A combination of capillary pressure (centrifuge and mercury injection experiments) and NMR experiments was used to determine the vug or secondary porosity of the samples from pore size and T2 (relaxation time) distributions. The...
Proceedings of SPE International Petroleum Conference in Mexico, 2004
This paper presents the challenges of constructing adequate static and flow models of a field fro... more This paper presents the challenges of constructing adequate static and flow models of a field from disparate data sets, and the workflow methodologies adopted for integrating, reconciling, and extrapolating available data from multiple disciplines. This study uses a data set of about 300 wells penetrating a 2500-meter thick section of fractured and vuggy carbonates. A 30-year production history was used to calibrate the model; the main recovery mechanism of the complex is rock and fluid expansion, combined with a weak aquifer. A reservoir simulation study was constructed to investigate the field behavior under natural depletion, water injection and gas injection, and to provide technical foundation supporting investments in future development projects. The static model comprises of a three-dimensional structural model, a matrix property model, and a fracture property model. There was no 3-D seismic. The complex system of normal and reverse faults dividing the structure into 70 fault blocks was created from well picks. The matrix property model was derived from limited routine and special cores, and vug analysis. The fracture property model was obtained by integrating fracture indicator logs, including DSI, image logs, conventional logs of different vintages, with fault orientation from structural conditioning, core analysis, PTA, well production and static pressure histories. The complex structure, long production history and the various recovery mechanisms posed additional challenges in constructing and calibrating the flow models to historical performances. The fluid properties for the thick reservoir sections were derived using limited available fluid samples, and verified by history matching reservoir pressure and gas-oil ratio, which declined over time until secondary gas cap encroachment. The different vintage and accuracies of the pressure and rate measurement devices were also considered in evaluating the history match quality.
The results of a reservoir performance evaluation of a giant mature heavy oil field are presented... more The results of a reservoir performance evaluation of a giant mature heavy oil field are presented here. This field began production in 1927. By 2002, cumulative production had surpassed half a billion barrels of low-gravity oil from Miocene sandstone formations produced under natural depletion, water and gas injection, and cyclic steam injection from more than 400 wells. As a result, several interdependent flow models including black-oil full-field, thermal single-well, and thermal large-sector models were built for field analysis and optimization. The long and complex production history, as well as the various recovery mechanisms, presented a number of challenges in constructing and calibrating the models to past historical performance. The optimization work was done in the following three stages. First, a coarse-grid black-oil model was constructed to study the field performance prior to steam injection, following the successful geological modeling phase of this project (presented in Márquez et al., 2001 1). The second stage involved single-well and sector-model thermal simulation analysis. The thermal models were used to match the field historical pressure and production data over the natural depletion, water injection and cyclic steam injection periods.T hird, we investigated the field performance under different development scenarios. Optimization results with the single-well thermal models were incorporated into the sector models, which were used for processing runs to examine infill drilling; recompletion of active wells; waterflooding; huff ‘n’puff steam injection; steam drive; and horizontal well drilling. The project resulted in the identification of more than 100 infill or recompletion candidates, and an estimated three million barrels of oil (MMBO)of additional recovery during the first 2 years of this project. As a result there were significant performance improvements and more are anticipated through the implementation of the field development strategies recommendedhere. The modeling approach led to significant time savings and provided an effective reservoir management tool for future field development. Introduction Schlumberger Data and Consulting Services (DCS), in Denver, Colorado, initiated a project for preparing the numerical 3D predictive model of theLL-04 Miocene reservoirs in Lake Maracaibo. The objectives of the reservoir performance evaluation were toprovide Petróleos de Venezuela, S.A. (PDVSA), the Venezuelan state-owned national oil company, with an updated geologic model that could be used to select new drilling and workover candidatesprovide PDVSA with a dynamic flow model that could be used as a tool to improve ultimate recovery from a number of operating strategies, and to monitor the field performancemake recommendations that would help PDVSA maximize production, maximize oil recovery, and to determine the best operating strategy for the field. This paper describes the reservoir simulation part of the reservoir characterization and simulation project. The Reservoir The LL-04 field is located on the northeast side of Lake Maracaibo along the Bolivar Coast of Venezuela (Fig. 1). This was one of the first fields discovered in Lake Maracaibo with production dating back to 1927. Production is from shallow (2000 to 3000 ft) unconsolidated sands in the Miocene La Rosa, Lower Laguna and Lower Lagunillas formations. Because production from the field is from highly unconsolidated sands, very limited core was available. Complicating the reservoir performance is the subsidence that has occurred. This has been accounted for by using very high rock compressibility in the simulation model.
The Pinedale anticline is a large natural gas field in the Greater Green River Basin of Wyoming, ... more The Pinedale anticline is a large natural gas field in the Greater Green River Basin of Wyoming, located north of the giant Jonah field. Gas production is from overpressured fluvial channel sandstones of the Upper Cretaceous Mesaverde and Lance formations and the lower Tertiary “unnamed Tertiary” formation. To date, most studies have focused on the regional geology and potential hydrocarbon economics. This chapter discusses an integrated approach for reservoir modeling to reduce uncertainty in this tight-gas field development. In this study, fluvial facies were defined using wireline logs. Object-based modeling was used to integrate well-log facies, object dimension, channel sinuosity, and orientation in building the three-dimensional facies model. The facies model was then used to guide petrophysical property modeling. Dependencies between rock properties were modeled using a geostatistical method. The final model honors the fluvial depositional characteristics and dependencies between the rock properties and was used for better uncertainty management in reservoir simulation and performance forecasting.
Copyright 2009, Society of Petroleum Engineers This paper was prepared for presentation at the 20... more Copyright 2009, Society of Petroleum Engineers This paper was prepared for presentation at the 2009 SPE Rocky Mountain Petroleum Technology Conference held in Denver, Colorado, USA, 1416 April 2009. This paper was selected for presentation by an SPE ...
Proceedings of SPE Annual Technical Conference and Exhibition, 2005
SPE Americas Unconventional Resources Conference, 2012
SPE Rocky Mountain Petroleum Technology Conference, 2009
Copyright 2009, Society of Petroleum Engineers This paper was prepared for presentation at the 20... more Copyright 2009, Society of Petroleum Engineers This paper was prepared for presentation at the 2009 SPE Rocky Mountain Petroleum Technology Conference held in Denver, Colorado, USA, 1416 April 2009. This paper was selected for presentation by an SPE ...
Proceedings of Eastern Regional Meeting, 2007
... One set developed parallel to the direction of maximum shortening with an ESE – WNW strike an... more ... One set developed parallel to the direction of maximum shortening with an ESE – WNW strike and a sub vertical dip. ... The updip well performed better than the down-dip well although its producing GOR was increasing throughout the run. ...
SPE Hydraulic Fracturing Technology Conference, 2012
Abstract In field development programs where large variations in reservoir and completion paramet... more Abstract In field development programs where large variations in reservoir and completion parameters exist, the evaluation of reservoir performance to determine the optimal completion strategy can be a challenging task. This paper presents findings from a recent ...