P. Weijermans, P. Huibregtse, R. Arts, T. Benedictus, M. D. Jong, Wouter Hazebelt, V. Vernain-Perriot, Michiel Van der Most
The E17a-A gas field, located offshore The Netherlands in the Southern North Sea, started production in 2009 from Upper Carboniferous sandstones, initially from three wells. Since early production history of the field, the p/z plot extrapolation has consistently shown an apparent Gas Initially In Place (GIIP) which was more than 50% higher than the volumetric GIIP mapped. The origin of the pressure support (e.g. aquifer support, much higher GIIP than mapped) and overall behavior of the field were poorly understood. An integrated modeling study was carried out to better understand the dynamics of this complex field, evaluate infill potential and optimize recovery. An initial history matching attempt with a simulation model based on a legacy static model highlighted the limitations of existing interpretations in terms of in-place volumes and connectivity. The structural interpretation of the field was revisited and a novel facies modeling methodology was developed. 3D training images, constructed from reservoir analogue and outcrop data integrated with deterministic reservoir body mapping, allowed successful application of Multi Point Statistics techniques to generate plausible reservoir body geometry, dimensions and connectivity. Following a series of static-dynamic iterations, a satisfying history match was achieved which matches observed reservoir pressure data, flowing wellhead pressure data, water influx trends in the wells and RFT pressure profiles of two more recent production wells. The new facies modeling methodology, using outcrop analogue data as deterministic input, and a revised seismic interpretation were key improvements to the static model. Apart from resolving the magnitude of GIIP and aquifer pressure support, the reservoir characterization and simulation study provided valuable insights into the overall dynamics of the field – e.g. crossflows between compartments, water encroachment patterns and vertical communication. Based on the model a promising infill target was identified at an up-dip location in the west of the field which looked favorable in terms of increasing production and optimizing recovery. At the time of writing, the new well has just been drilled. Preliminary logging results of the well will be briefly discussed and compared to pre-drill predictions based on the results of the integrated reservoir characterization and simulation study. The new facies modeling methodology presented is in principle applicable to a number of Carboniferous gas fields in the Southern North Sea. Application of this method can lead to improved understanding and optimized recovery. In addition, this case study demonstrates how truly integrated reservoir characterization and simulation can lead to a revision of an existing view of a field, improve understanding and unlock hidden potential.
{"title":"Integrated Reservoir Characterization and Simulation to Optimize Recovery from a Mature Carboniferous North Sea Gas Field with Water Influx","authors":"P. Weijermans, P. Huibregtse, R. Arts, T. Benedictus, M. D. Jong, Wouter Hazebelt, V. Vernain-Perriot, Michiel Van der Most","doi":"10.2118/196730-ms","DOIUrl":"https://doi.org/10.2118/196730-ms","url":null,"abstract":"\u0000 The E17a-A gas field, located offshore The Netherlands in the Southern North Sea, started production in 2009 from Upper Carboniferous sandstones, initially from three wells. Since early production history of the field, the p/z plot extrapolation has consistently shown an apparent Gas Initially In Place (GIIP) which was more than 50% higher than the volumetric GIIP mapped. The origin of the pressure support (e.g. aquifer support, much higher GIIP than mapped) and overall behavior of the field were poorly understood.\u0000 An integrated modeling study was carried out to better understand the dynamics of this complex field, evaluate infill potential and optimize recovery. An initial history matching attempt with a simulation model based on a legacy static model highlighted the limitations of existing interpretations in terms of in-place volumes and connectivity. The structural interpretation of the field was revisited and a novel facies modeling methodology was developed. 3D training images, constructed from reservoir analogue and outcrop data integrated with deterministic reservoir body mapping, allowed successful application of Multi Point Statistics techniques to generate plausible reservoir body geometry, dimensions and connectivity.\u0000 Following a series of static-dynamic iterations, a satisfying history match was achieved which matches observed reservoir pressure data, flowing wellhead pressure data, water influx trends in the wells and RFT pressure profiles of two more recent production wells. The new facies modeling methodology, using outcrop analogue data as deterministic input, and a revised seismic interpretation were key improvements to the static model. Apart from resolving the magnitude of GIIP and aquifer pressure support, the reservoir characterization and simulation study provided valuable insights into the overall dynamics of the field – e.g. crossflows between compartments, water encroachment patterns and vertical communication. Based on the model a promising infill target was identified at an up-dip location in the west of the field which looked favorable in terms of increasing production and optimizing recovery. At the time of writing, the new well has just been drilled. Preliminary logging results of the well will be briefly discussed and compared to pre-drill predictions based on the results of the integrated reservoir characterization and simulation study.\u0000 The new facies modeling methodology presented is in principle applicable to a number of Carboniferous gas fields in the Southern North Sea. Application of this method can lead to improved understanding and optimized recovery. In addition, this case study demonstrates how truly integrated reservoir characterization and simulation can lead to a revision of an existing view of a field, improve understanding and unlock hidden potential.","PeriodicalId":11098,"journal":{"name":"Day 2 Wed, September 18, 2019","volume":"139 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79872799","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
E. BinAbadat, H. Bu-Hindi, Omar Al-Farisi, Atul Kumar, Kamel Zahaf, L. Ibrahim, Yaxin Liu, C. Darous, L. Barillas
Reservoir Rock Typing and saturation modeling need a two-sided methodology. One side is the geological side of the rock types to populate properties within geological concepts. The other side is addressing reservoir flow and dynamic initialization with capillary pressure. The difficulty is to comply with both aspects especially in carbonates reservoirs with complex diagenesis and migration history. The objective of this paper is to describe the methodology and the results obtained in a complex carbonate reservoir. The approach is initiated from the sedimentological description from cores and complemented with microfacies from thin sections. The core-based rock types use the dominant rock fabrics, as well as the cementation and dissolution diagenetic processes. The groups are limited to similar pore throat size distribution and porosity-permeability relationships to stay compatible with property modeling at a later stage. At log-scale, the rock typing has a focus on the estimation of permeability using the most appropriate logs available in all wells. Those logs are porosity, mineral volumes, normalized saturation in invaded zone (Sxo), macro-porosity from borehole image or Nuclear Magnetic Resonance (NMR), NMR T2 log mean relaxation, and rigidity from sonic logs. A specific calculation to identify the presence of tar is also included to assess the permeability better and further interpret the saturation history. The MICP data defined the saturation height functions, according to the modality of the pore throat size. The log derived saturation, and the SHFs are used to identify Free Water Level (FWL) positions and interpret the migration history. The rock typing classification is well connected with the geological aspects of the reservoirs since it originates from the sedimentological description and the diagenetic processes. We identified a total of 21 rock types across all the formations of interest. We associated rock types with depositional environments ranging from supra-tidal to open marine that controls both the original rock fabrics and the diagenetic processes. The rock typing classification is also appropriate to model permeability and saturation since core petrophysical measurements were in use during the classification. The permeability estimation from logs uses multivariate regressions that have proven to be sensitive to permeability after a Principal Component Analysis per zones and per lithologies. The difference between the core permeability and the permeability derived from logs stays within one-fold of standard deviation as compared to the initial 3-fold range of porosity-permeability. We assigned the rock types with three Saturation Height Function (SHF) classes; (unimodal-dolomite, unimodal- limestone & Multimodal-Limestone). The log derived water saturation (Sw) from logs and SHF shows acceptable agreement. The reservoir rock typing and saturation modeling methodology described in this paper are considerate of honoring g
{"title":"Complex Carbonate Rock Typing and Saturation Modeling with Highly-Coupled Geological Description and Petrophysical Properties","authors":"E. BinAbadat, H. Bu-Hindi, Omar Al-Farisi, Atul Kumar, Kamel Zahaf, L. Ibrahim, Yaxin Liu, C. Darous, L. Barillas","doi":"10.2118/196677-ms","DOIUrl":"https://doi.org/10.2118/196677-ms","url":null,"abstract":"\u0000 Reservoir Rock Typing and saturation modeling need a two-sided methodology. One side is the geological side of the rock types to populate properties within geological concepts. The other side is addressing reservoir flow and dynamic initialization with capillary pressure. The difficulty is to comply with both aspects especially in carbonates reservoirs with complex diagenesis and migration history. The objective of this paper is to describe the methodology and the results obtained in a complex carbonate reservoir.\u0000 The approach is initiated from the sedimentological description from cores and complemented with microfacies from thin sections. The core-based rock types use the dominant rock fabrics, as well as the cementation and dissolution diagenetic processes. The groups are limited to similar pore throat size distribution and porosity-permeability relationships to stay compatible with property modeling at a later stage.\u0000 At log-scale, the rock typing has a focus on the estimation of permeability using the most appropriate logs available in all wells. Those logs are porosity, mineral volumes, normalized saturation in invaded zone (Sxo), macro-porosity from borehole image or Nuclear Magnetic Resonance (NMR), NMR T2 log mean relaxation, and rigidity from sonic logs. A specific calculation to identify the presence of tar is also included to assess the permeability better and further interpret the saturation history. The MICP data defined the saturation height functions, according to the modality of the pore throat size. The log derived saturation, and the SHFs are used to identify Free Water Level (FWL) positions and interpret the migration history.\u0000 The rock typing classification is well connected with the geological aspects of the reservoirs since it originates from the sedimentological description and the diagenetic processes. We identified a total of 21 rock types across all the formations of interest. We associated rock types with depositional environments ranging from supra-tidal to open marine that controls both the original rock fabrics and the diagenetic processes. The rock typing classification is also appropriate to model permeability and saturation since core petrophysical measurements were in use during the classification. The permeability estimation from logs uses multivariate regressions that have proven to be sensitive to permeability after a Principal Component Analysis per zones and per lithologies. The difference between the core permeability and the permeability derived from logs stays within one-fold of standard deviation as compared to the initial 3-fold range of porosity-permeability. We assigned the rock types with three Saturation Height Function (SHF) classes; (unimodal-dolomite, unimodal- limestone & Multimodal-Limestone). The log derived water saturation (Sw) from logs and SHF shows acceptable agreement.\u0000 The reservoir rock typing and saturation modeling methodology described in this paper are considerate of honoring g","PeriodicalId":11098,"journal":{"name":"Day 2 Wed, September 18, 2019","volume":"23 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91137902","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. Bagir, B. Andhika, Ivan Zhia Ming Wu, Rio Wijaya, Sakti Lail Nasution, Lee Chung Yee
Numerous carbonate reservoir discoveries were made in Indonesia (Soeparjadi et al. 1975), including the Berai Formation, which consists of high heterogeneity and low porosity characteristics. To optimize production on a field-scale basis, developing an effective stimulation program is necessary to maximize the asset’s output. This integrated study demonstrates the multidiscipline approach of well stimulation and reservoir characterization for designing successful acid-fracturing stages. Understanding reservoir characteristics helps during selection of the effective fracturing design and staging plan for application. The process involves multiple cycles—from formation evaluation (e.g., geomechanics analysis, design of an effective fracturing method, and production forecasting) through the economic impact to the operator. During the early phase of this integrated study, the uncertainties of all static and dynamic parameters (i.e., geological complexity, rock physics, and stress profile) were considered for fracturing design. Production performances from multiple fracturing stimulation scenarios were then modeled and compared to select the plan that optimizes production for the Berai Formation. Results demonstrated an effective multidiscipline approach toward a comprehensive strategy to meet the ultimate objective in optimizing production. This project leveraged formation evaluation and fracturing design to deliver integrated solutions from exploration to accurate production forecast. The well stimulations were performed by carefully selecting fluid characteristics based on geological-petrophysical properties, pressure, and stress profiles within the area. Results yielded excellent production gains—for the best case, up to 50% with an average of 40% in comparison with initial production by using an acid that provides optimum fracture geometry and permeability. This opportunity demonstrated the importance of understanding formation behavior and the parameters that aid the selection of an appropriate fracturing design for a low porosity/permeability carbonate reservoir.
印度尼西亚发现了许多碳酸盐岩储层(Soeparjadi et al. 1975)，包括具有高非均质性和低孔隙度特征的Berai组。为了在油田规模的基础上优化生产，必须制定有效的增产方案，以最大限度地提高资产的产量。该综合研究展示了油井增产和储层表征的多学科方法，以设计成功的酸压裂阶段。了解储层特征有助于选择有效的压裂设计和分级方案。该过程涉及多个循环，从地层评估(例如地质力学分析、有效压裂方法的设计和产量预测)到对作业者的经济影响。在这项综合研究的早期阶段，所有静态和动态参数(即地质复杂性、岩石物理和应力剖面)的不确定性都被考虑到压裂设计中。然后对多种压裂增产方案的生产性能进行建模和比较，以选择Berai地层的最佳生产方案。结果表明，为了实现优化生产的最终目标，采用了一种有效的多学科综合策略。该项目利用地层评价和压裂设计，提供了从勘探到准确产量预测的综合解决方案。根据该地区的地质岩石物理性质、压力和应力剖面，仔细选择流体特征，进行增产作业。结果表明，通过使用具有最佳裂缝形状和渗透率的酸，与初始产量相比，产量提高了50%，平均提高了40%。这个机会证明了了解地层行为和参数的重要性，这些参数有助于为低孔隙度/渗透率的碳酸盐岩油藏选择合适的压裂设计。
{"title":"Increased Production by Leveraging a Multidiscipline Approach for Fracturing a Complex Carbonate Reservoir","authors":"M. Bagir, B. Andhika, Ivan Zhia Ming Wu, Rio Wijaya, Sakti Lail Nasution, Lee Chung Yee","doi":"10.2118/196725-ms","DOIUrl":"https://doi.org/10.2118/196725-ms","url":null,"abstract":"\u0000 Numerous carbonate reservoir discoveries were made in Indonesia (Soeparjadi et al. 1975), including the Berai Formation, which consists of high heterogeneity and low porosity characteristics. To optimize production on a field-scale basis, developing an effective stimulation program is necessary to maximize the asset’s output. This integrated study demonstrates the multidiscipline approach of well stimulation and reservoir characterization for designing successful acid-fracturing stages. Understanding reservoir characteristics helps during selection of the effective fracturing design and staging plan for application.\u0000 The process involves multiple cycles—from formation evaluation (e.g., geomechanics analysis, design of an effective fracturing method, and production forecasting) through the economic impact to the operator. During the early phase of this integrated study, the uncertainties of all static and dynamic parameters (i.e., geological complexity, rock physics, and stress profile) were considered for fracturing design. Production performances from multiple fracturing stimulation scenarios were then modeled and compared to select the plan that optimizes production for the Berai Formation.\u0000 Results demonstrated an effective multidiscipline approach toward a comprehensive strategy to meet the ultimate objective in optimizing production. This project leveraged formation evaluation and fracturing design to deliver integrated solutions from exploration to accurate production forecast. The well stimulations were performed by carefully selecting fluid characteristics based on geological-petrophysical properties, pressure, and stress profiles within the area. Results yielded excellent production gains—for the best case, up to 50% with an average of 40% in comparison with initial production by using an acid that provides optimum fracture geometry and permeability.\u0000 This opportunity demonstrated the importance of understanding formation behavior and the parameters that aid the selection of an appropriate fracturing design for a low porosity/permeability carbonate reservoir.","PeriodicalId":11098,"journal":{"name":"Day 2 Wed, September 18, 2019","volume":"23 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82143612","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Aaesha Al-Keebali, M. Yaslam, Ahmed Amro, Shehadeh Masalmaeh
As part of enhanced oil recovery (EOR) strategic objectives to boost oil recovery towards 70% aspiration and demonstrate EOR as an attractive viable option for environmental Carbon Capture, Utilization and Storage (CCUS) applications, various conventional and novel EOR technologies and applications are being screened and studied to ensure meeting mandated objectives. Accordingly, number of EOR pilots and projects have grown substantially over recent years to ensure derisking the full field expansion uncertainties and challenges, especially in such carbonate reservoirs with harsh conditions of temperature (~ 250 F) and salinity (~ 200,000 ppm). Detailed screening study and performance review assessment have been conducted, in which gas and chemical based EOR technologies were identified for targeted reservoirs. The candidate reservoirs have a long history of EOR projects focusing on miscible hydrocarbon gas (HC) as early as 1996, which has supported oil production meeting forecast demand. On the other hand, as part of environmental driven strategy for CCUS and EOR applications, CO2 technology has been successfully progressing as EOR business case full-integrated cycle from pilot to field expansion during 2009-2016. In 2016, Al Reyadah has been launched as a unique commercial- scale CCUS facility in the region, that captures 800,000 tonnes of CO2 annually from Emirate Steel Industries and injects it into oilfields to boost crude recovery. Furthermore, novel EOR technologies have been screened and identified with significant potential added value, that includes SIMGAP, SIWAP, Surfactant, Polymer and others, which are currently under modeling and design phase for implementation within upcoming few years to boost recovery factor towards 70% aspiration. Development and piloting of latest technologies are among the main enablers to ensure fit-for purpose applications, proper planning and optimum design for ultimately maximum revenue economically. This paper presents a big-picture overview of EOR technologies with the focus on some cases, challenges and opportunities for super giant carbonate reservoirs.
{"title":"EOR Technologies and Applications Towards 70% Recovery Factor Aspiration in Giant Carbonate Middle East Reservoirs","authors":"Aaesha Al-Keebali, M. Yaslam, Ahmed Amro, Shehadeh Masalmaeh","doi":"10.2118/196693-ms","DOIUrl":"https://doi.org/10.2118/196693-ms","url":null,"abstract":"\u0000 As part of enhanced oil recovery (EOR) strategic objectives to boost oil recovery towards 70% aspiration and demonstrate EOR as an attractive viable option for environmental Carbon Capture, Utilization and Storage (CCUS) applications, various conventional and novel EOR technologies and applications are being screened and studied to ensure meeting mandated objectives. Accordingly, number of EOR pilots and projects have grown substantially over recent years to ensure derisking the full field expansion uncertainties and challenges, especially in such carbonate reservoirs with harsh conditions of temperature (~ 250 F) and salinity (~ 200,000 ppm).\u0000 Detailed screening study and performance review assessment have been conducted, in which gas and chemical based EOR technologies were identified for targeted reservoirs. The candidate reservoirs have a long history of EOR projects focusing on miscible hydrocarbon gas (HC) as early as 1996, which has supported oil production meeting forecast demand. On the other hand, as part of environmental driven strategy for CCUS and EOR applications, CO2 technology has been successfully progressing as EOR business case full-integrated cycle from pilot to field expansion during 2009-2016. In 2016, Al Reyadah has been launched as a unique commercial- scale CCUS facility in the region, that captures 800,000 tonnes of CO2 annually from Emirate Steel Industries and injects it into oilfields to boost crude recovery.\u0000 Furthermore, novel EOR technologies have been screened and identified with significant potential added value, that includes SIMGAP, SIWAP, Surfactant, Polymer and others, which are currently under modeling and design phase for implementation within upcoming few years to boost recovery factor towards 70% aspiration.\u0000 Development and piloting of latest technologies are among the main enablers to ensure fit-for purpose applications, proper planning and optimum design for ultimately maximum revenue economically. This paper presents a big-picture overview of EOR technologies with the focus on some cases, challenges and opportunities for super giant carbonate reservoirs.","PeriodicalId":11098,"journal":{"name":"Day 2 Wed, September 18, 2019","volume":"11 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74978543","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. Z. Usop, Alister Albert Suggust, A. M. Razali, Dzulfahmi Zamzuri, M. Khalil, M. Hatta, Aizuddin Khalid, Muhammad Hasan Azhari, Delwistiel Jamel, Diana Ting Yeong Ye, Muhammad Abdulhadi, M. Z. A. Pon
Reservoir G-4, a depleted reservoir in field B had been producing from 1992 to 2015 with a recovery factor of 30% before the production was stopped due to low reservoir pressure. Due to the huge inplace volume. A secondary recovery screening was conducted and gas injection was identified as the most suitable solution to revive G-4 reservoir due to its low cost impact of 0.4 Mil. USD whilst managing to deliver the same results as other solutions (i.e. Water injection & Water Dumpflood). The project had utilized existing facilities in field B including a gas compressor. The project required only minor surface modification to re-route gas into the tubing of injection well BG-03. From simulation results, a continuous injection of 5 MMscf/d will increase the reservoir pressure by 150 psia in 9 months, with incremental potential reserves of atleast 5.0 MMstb from the benefitter wells, BG-02 & as well as incoming infill wells BG-14 & BG-15. It is also envisaged that with future development of additional infill wells, the recovery factor will be increased up to 60%. In term of gas management, field B is able to deliver additional 15 MMscf/d post petroleum operation reduction (i.e. Fuel Gas, Instrument Gas & Gas lift). With the initiation of gas injection, the project had managed to utilize and optimize 33% of additional gas production for reservoir rejuvenation purposes. The paper provides valuable insight into the case study and lesson learned of maximizing oil recovery through gas injection with minimal cost incurred. The approach is highly recommended to maximize oil recovery especially in mature fields with similar reservoir conditions and production facilities.
{"title":"Rejuvenating a Depleted Reservoir by Capitalizing Existing Facilities for Secondary Recovery in a Brownfield: A Case Study in Offshore Field","authors":"M. Z. Usop, Alister Albert Suggust, A. M. Razali, Dzulfahmi Zamzuri, M. Khalil, M. Hatta, Aizuddin Khalid, Muhammad Hasan Azhari, Delwistiel Jamel, Diana Ting Yeong Ye, Muhammad Abdulhadi, M. Z. A. Pon","doi":"10.2118/196703-ms","DOIUrl":"https://doi.org/10.2118/196703-ms","url":null,"abstract":"\u0000 Reservoir G-4, a depleted reservoir in field B had been producing from 1992 to 2015 with a recovery factor of 30% before the production was stopped due to low reservoir pressure. Due to the huge inplace volume. A secondary recovery screening was conducted and gas injection was identified as the most suitable solution to revive G-4 reservoir due to its low cost impact of 0.4 Mil. USD whilst managing to deliver the same results as other solutions (i.e. Water injection & Water Dumpflood).\u0000 The project had utilized existing facilities in field B including a gas compressor. The project required only minor surface modification to re-route gas into the tubing of injection well BG-03. From simulation results, a continuous injection of 5 MMscf/d will increase the reservoir pressure by 150 psia in 9 months, with incremental potential reserves of atleast 5.0 MMstb from the benefitter wells, BG-02 & as well as incoming infill wells BG-14 & BG-15. It is also envisaged that with future development of additional infill wells, the recovery factor will be increased up to 60%.\u0000 In term of gas management, field B is able to deliver additional 15 MMscf/d post petroleum operation reduction (i.e. Fuel Gas, Instrument Gas & Gas lift). With the initiation of gas injection, the project had managed to utilize and optimize 33% of additional gas production for reservoir rejuvenation purposes.\u0000 The paper provides valuable insight into the case study and lesson learned of maximizing oil recovery through gas injection with minimal cost incurred. The approach is highly recommended to maximize oil recovery especially in mature fields with similar reservoir conditions and production facilities.","PeriodicalId":11098,"journal":{"name":"Day 2 Wed, September 18, 2019","volume":"88 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73910255","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Micromodels are commonly utilized to investigate the fundamentals of multiphase displacements and oil mobilization. Definitely, the utility of micromodels has been well demonstrated in the literature. Yet, while the generic workflows are mutual, there is no standard protocol. Therefore, the primary objective of this work was to develop reliable protocols for micromodel experimentations. These protocols are developed within the context of investigating flow-rate effects on oil trapping and recovery, which represents a supplementary objective. The presented experimental work utilized a high pressure and high temperature setup. A metalloid pattern with a pore-volume of 0.08 mL constitutes the porous-media micromodel. The model is positioned vertically, which permits investigation of gravity effects. Displacement experiments were performed to establish the image processing workflow. Those experiments were performed at different injection rates for fixed volumes starting from 10 mL up to 50 mL. All experiments were replicated to assess the associated uncertainties. Initial conditions were established via drainage of connate brine by dead crude oil followed by imbibition of injection brine. The performed experiments established a preferred workflow for image processing that includes in order: thresholding, despeckling, and binary conversion. Thresholding limits were found to be dependent on the camera including its position and focal length. The final binary images can be used for oil recovery estimation based on areal analyses. High rate experiments demonstrated better repeatability. Prolonged injection helped reduce variations in recovery estimates between replicates. At the investigated macroscopic scale and in light of associated uncertainties, recovery was found to be negligibly dependent on injection rate up to a critical flow-rate of around 1 mL/min above which recovery increases with higher injection rates. A trend that is consistent with capillary desaturation. This paper demonstrates the procedure to establish a micromodel image processing protocol. It also illustrates the possible uncertainties associated with recovery estimates obtained from such images. Finally, key observations and recommendations with respect to the significance of high throughput and replications were uncovered.
{"title":"Recovery Estimates from Micromodel Experiments: Processing, Uncertainty, and Rate-dependence","authors":"Z. Kaidar, A. AlSofi, Amer Al-Anazi","doi":"10.2118/196623-ms","DOIUrl":"https://doi.org/10.2118/196623-ms","url":null,"abstract":"\u0000 Micromodels are commonly utilized to investigate the fundamentals of multiphase displacements and oil mobilization. Definitely, the utility of micromodels has been well demonstrated in the literature. Yet, while the generic workflows are mutual, there is no standard protocol. Therefore, the primary objective of this work was to develop reliable protocols for micromodel experimentations. These protocols are developed within the context of investigating flow-rate effects on oil trapping and recovery, which represents a supplementary objective.\u0000 The presented experimental work utilized a high pressure and high temperature setup. A metalloid pattern with a pore-volume of 0.08 mL constitutes the porous-media micromodel. The model is positioned vertically, which permits investigation of gravity effects. Displacement experiments were performed to establish the image processing workflow. Those experiments were performed at different injection rates for fixed volumes starting from 10 mL up to 50 mL. All experiments were replicated to assess the associated uncertainties. Initial conditions were established via drainage of connate brine by dead crude oil followed by imbibition of injection brine.\u0000 The performed experiments established a preferred workflow for image processing that includes in order: thresholding, despeckling, and binary conversion. Thresholding limits were found to be dependent on the camera including its position and focal length. The final binary images can be used for oil recovery estimation based on areal analyses. High rate experiments demonstrated better repeatability. Prolonged injection helped reduce variations in recovery estimates between replicates. At the investigated macroscopic scale and in light of associated uncertainties, recovery was found to be negligibly dependent on injection rate up to a critical flow-rate of around 1 mL/min above which recovery increases with higher injection rates. A trend that is consistent with capillary desaturation.\u0000 This paper demonstrates the procedure to establish a micromodel image processing protocol. It also illustrates the possible uncertainties associated with recovery estimates obtained from such images. Finally, key observations and recommendations with respect to the significance of high throughput and replications were uncovered.","PeriodicalId":11098,"journal":{"name":"Day 2 Wed, September 18, 2019","volume":"156 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80111573","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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