M. Isbell, Austin Groover, Blakley Farrow, D. Hasler
An operator and rig contractor have been implementing drilling operations automation (DOA) pursuing well design and drilling operational execution improvements in terms of safety, quality, delivery, and cost (SQDC). Today, drilling automation enables tighter process control of operations and well design stakeholders are beginning to fully understand and anticipate its value. DOA requires applying a process control approach and defining well construction processes at a very detailed level. This process control approach is proposed as a method to study and improve work steps and integrate them into overall operational activities. Optimizing, much less controlling, a drilling system is a difficult task with a multitude of variables to manage. The process of automating operations may be one of the best tools to reduce the number of unknown variables and better deliver consistent SQDC results. Automation case studies such as a downhole Weight on Bit (WOB) drilling system, a directional drilling advisory system, a sliding system for conventional steerable mud motors, and an integrated tubular running system are described to highlight the role of automation in assisting operators and contractors to efficiently manage and improve the well construction process. Process automation requires improvements in foundational systems, tools, and data quality to support operational performance. The most significant finding is how automated systems enable operations to be practically managed at a detailed level by drilling personnel, engineers, and other stakeholders. After practices and systems are proven and automated, they can be scaled and managed over an entire rig fleet. This will ultimately enable today's well construction and drilling system related risks to be mitigated and managed, leading to further SQDC rewards with more efficient well designs. The operator and rig contractor will share perspectives for realizing value and opportunity through applying DOA. Experience shows DOA-influenced standardized operations can result in eliminating steps that are no longer needed. Automation enables changes to well design that are just beginning to be understood and anticipated by drilling teams. The challenge will be linking these opportunities to pursue new capabilities supporting well design improvement. This will be the true benefit from automating drilling operations.
{"title":"What Drilling Automation can Teach us about Drilling Wells","authors":"M. Isbell, Austin Groover, Blakley Farrow, D. Hasler","doi":"10.2118/195818-ms","DOIUrl":"https://doi.org/10.2118/195818-ms","url":null,"abstract":"\u0000 An operator and rig contractor have been implementing drilling operations automation (DOA) pursuing well design and drilling operational execution improvements in terms of safety, quality, delivery, and cost (SQDC). Today, drilling automation enables tighter process control of operations and well design stakeholders are beginning to fully understand and anticipate its value.\u0000 DOA requires applying a process control approach and defining well construction processes at a very detailed level. This process control approach is proposed as a method to study and improve work steps and integrate them into overall operational activities. Optimizing, much less controlling, a drilling system is a difficult task with a multitude of variables to manage. The process of automating operations may be one of the best tools to reduce the number of unknown variables and better deliver consistent SQDC results.\u0000 Automation case studies such as a downhole Weight on Bit (WOB) drilling system, a directional drilling advisory system, a sliding system for conventional steerable mud motors, and an integrated tubular running system are described to highlight the role of automation in assisting operators and contractors to efficiently manage and improve the well construction process. Process automation requires improvements in foundational systems, tools, and data quality to support operational performance. The most significant finding is how automated systems enable operations to be practically managed at a detailed level by drilling personnel, engineers, and other stakeholders. After practices and systems are proven and automated, they can be scaled and managed over an entire rig fleet. This will ultimately enable today's well construction and drilling system related risks to be mitigated and managed, leading to further SQDC rewards with more efficient well designs.\u0000 The operator and rig contractor will share perspectives for realizing value and opportunity through applying DOA. Experience shows DOA-influenced standardized operations can result in eliminating steps that are no longer needed. Automation enables changes to well design that are just beginning to be understood and anticipated by drilling teams. The challenge will be linking these opportunities to pursue new capabilities supporting well design improvement. This will be the true benefit from automating drilling operations.","PeriodicalId":10909,"journal":{"name":"Day 2 Tue, October 01, 2019","volume":"62 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87354661","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. F. A. H. Khan, M. Abid, A. Fareed, Z. Javed, M. N. Khan, Shariq Hashmi
Technical evaluation and subsequently devising an appraisal and development strategy of a structural cum stratigraphic reservoir based on a discovery well only is always challenging. The reservoir under discussion was discovered as a structurally bounded trap and the appraisal wells were drilled on NW-SE direction along with the main bounding fault based on this understanding. However, presence of hydrocarbon below the spill point, anomalous sand thickness, lateral facies and reservoir quality variations observed in few of the wells indicated stratigraphic component in the field. Further complexity was added when the deepest tested gas was assigned on the structural map which showed extension of the hydrocarbon play outside the block boundary where the area was under different operating company that later drilled multiple wells near the block boundary. Therefore, it was critical to estimate correct initial gas in-place and percentage distribution of hydrocarbon across the lease boundaries. Figure 1 Well location map for the studied field The objective of this paper is to present workflow that integrates multiple dataset to understand the field's hydrocarbon filling mechanism. Detailed geophysical and Petrophysical work has been carried out, which includes building of sequence stratigraphic framework, preparation of seismic attribute maps, understanding of the depositional setting for all the individual sand units encountered in all the wells, rock quality assessment (core and log methods with integration of capillary pressure curves), free water level (FWL) assessment, permeability modelling using machine learning approach (NN), pore throat radius estimation to relate hydrocarbon filling mechanism and saturation-height function modelling to build consistent 1D water saturation model. Comprehensive dataset has been acquired to evaluate the potential of the field that covers 3D seismic for the entire field, biostratigraphic analysis for seven (7) well, conventional logs in twelve (12) wells and advance measurements like Elemental Capture Spectroscopy and high-resolution resistivity images in five (5) wells. Core analysis data also acquired in five (5) different wells including routine core analysis, capillary pressure measurements using high pressure mercury injections, pore throat radius, relative permeability measurements (Centrifuge), formation resistivity factor measurements and sedimentological analysis (XRD & thin section) to overcome the challenges and defining the uncertainty associated with initial gas in-place. Sequence based boundaries were defined to correlate individual sand bodies using the core data, image logs, elastic logs, seismic transacts and attribute maps for understanding the depositional setting. Lat-er these correlations were used to build a consistent petrophysical model including VCL estimation from Gamma/Neutron-Density/Sonic Density methods which was validated with ECS/XRD data. Porosity model was
{"title":"Petrophysical Modelling of Structure-Cum-Stratigraphic Play for Improved Reservoir Potential, an Integrated Field Study of L. Goru Sands, Pakistan","authors":"M. F. A. H. Khan, M. Abid, A. Fareed, Z. Javed, M. N. Khan, Shariq Hashmi","doi":"10.2118/196066-ms","DOIUrl":"https://doi.org/10.2118/196066-ms","url":null,"abstract":"\u0000 Technical evaluation and subsequently devising an appraisal and development strategy of a structural cum stratigraphic reservoir based on a discovery well only is always challenging. The reservoir under discussion was discovered as a structurally bounded trap and the appraisal wells were drilled on NW-SE direction along with the main bounding fault based on this understanding. However, presence of hydrocarbon below the spill point, anomalous sand thickness, lateral facies and reservoir quality variations observed in few of the wells indicated stratigraphic component in the field. Further complexity was added when the deepest tested gas was assigned on the structural map which showed extension of the hydrocarbon play outside the block boundary where the area was under different operating company that later drilled multiple wells near the block boundary. Therefore, it was critical to estimate correct initial gas in-place and percentage distribution of hydrocarbon across the lease boundaries.\u0000 Figure 1 Well location map for the studied field\u0000 \u0000 \u0000 The objective of this paper is to present workflow that integrates multiple dataset to understand the field's hydrocarbon filling mechanism. Detailed geophysical and Petrophysical work has been carried out, which includes building of sequence stratigraphic framework, preparation of seismic attribute maps, understanding of the depositional setting for all the individual sand units encountered in all the wells, rock quality assessment (core and log methods with integration of capillary pressure curves), free water level (FWL) assessment, permeability modelling using machine learning approach (NN), pore throat radius estimation to relate hydrocarbon filling mechanism and saturation-height function modelling to build consistent 1D water saturation model.\u0000 \u0000 \u0000 \u0000 Comprehensive dataset has been acquired to evaluate the potential of the field that covers 3D seismic for the entire field, biostratigraphic analysis for seven (7) well, conventional logs in twelve (12) wells and advance measurements like Elemental Capture Spectroscopy and high-resolution resistivity images in five (5) wells. Core analysis data also acquired in five (5) different wells including routine core analysis, capillary pressure measurements using high pressure mercury injections, pore throat radius, relative permeability measurements (Centrifuge), formation resistivity factor measurements and sedimentological analysis (XRD & thin section) to overcome the challenges and defining the uncertainty associated with initial gas in-place.\u0000 \u0000 \u0000 \u0000 Sequence based boundaries were defined to correlate individual sand bodies using the core data, image logs, elastic logs, seismic transacts and attribute maps for understanding the depositional setting. Lat-er these correlations were used to build a consistent petrophysical model including VCL estimation from Gamma/Neutron-Density/Sonic Density methods which was validated with ECS/XRD data. Porosity model was ","PeriodicalId":10909,"journal":{"name":"Day 2 Tue, October 01, 2019","volume":"4 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75993054","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}
Plugs for hydraulic fracturing generally are pumped into horizontal wellbores. Initially, the goal was to get the plugs to depth without careful consideration of the amount of water used in the pumping. As the industry has grown, a better understanding of pump-down methods and techniques has resulted in a realization that these pumping inefficiencies should be improved. When completing a horizontal well using the plug-and-perf technique, water is required to push the bottom hole assembly (BHA), containing a frac plug, to the target depth. With over one million frac plugs having been pumped in North America, large data sets are available to quantify the pump-down efficiency of these operations. This past information, along with a working model of how pump down works, can be used to promote improvements in pump-down efficiency, reducing water usage and rig time. The efficiency of the pump-down operation can be calculated based on pump time, displacement volume, and the actual volume of fluid pumped. This type of information can be recorded during operations. The pump-down efficiencies can be calculated as a percentage of actual versus calculated volumes pumped and is often expressed as a relational number, such as how much fluid is needed per 100 feet of casing. These numbers can be used as a metric for the amount of water and time required to move the plug to its desired location. Over 10,000 frac plug pump downs from diverse North American regions were analyzed to attain a baseline for efficiency during frac plug pump down operations. The force, pressure, and fluid velocity effects acting on the BHA during pump down were analyzed to understand how to better quantify methods and designs that increase or decrease efficiency. Finally, procedures were mapped out on the operational units used in pump down to understand the potential impacts on efficiency. The result is a guide on gauging pump-down efficiency of past operations while understanding methods to increase these efficiencies in the future. This framework can be used to view how a frac plug is pumped downhole while understanding the relationships that control its efficiency. This model can be used to evaluate past operations as well as design for future operations to increase overall efficiencies and decrease water usage and time on location.
{"title":"Frac Plug Pump Down Efficiencies and Techniques","authors":"Z. Walton, M. Nichols, M. Fripp","doi":"10.2118/196210-ms","DOIUrl":"https://doi.org/10.2118/196210-ms","url":null,"abstract":"Plugs for hydraulic fracturing generally are pumped into horizontal wellbores. Initially, the goal was to get the plugs to depth without careful consideration of the amount of water used in the pumping. As the industry has grown, a better understanding of pump-down methods and techniques has resulted in a realization that these pumping inefficiencies should be improved. When completing a horizontal well using the plug-and-perf technique, water is required to push the bottom hole assembly (BHA), containing a frac plug, to the target depth. With over one million frac plugs having been pumped in North America, large data sets are available to quantify the pump-down efficiency of these operations. This past information, along with a working model of how pump down works, can be used to promote improvements in pump-down efficiency, reducing water usage and rig time. The efficiency of the pump-down operation can be calculated based on pump time, displacement volume, and the actual volume of fluid pumped. This type of information can be recorded during operations. The pump-down efficiencies can be calculated as a percentage of actual versus calculated volumes pumped and is often expressed as a relational number, such as how much fluid is needed per 100 feet of casing. These numbers can be used as a metric for the amount of water and time required to move the plug to its desired location. Over 10,000 frac plug pump downs from diverse North American regions were analyzed to attain a baseline for efficiency during frac plug pump down operations. The force, pressure, and fluid velocity effects acting on the BHA during pump down were analyzed to understand how to better quantify methods and designs that increase or decrease efficiency. Finally, procedures were mapped out on the operational units used in pump down to understand the potential impacts on efficiency. The result is a guide on gauging pump-down efficiency of past operations while understanding methods to increase these efficiencies in the future. This framework can be used to view how a frac plug is pumped downhole while understanding the relationships that control its efficiency. This model can be used to evaluate past operations as well as design for future operations to increase overall efficiencies and decrease water usage and time on location.","PeriodicalId":10909,"journal":{"name":"Day 2 Tue, October 01, 2019","volume":"6 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79025904","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}
Reliability of subsurface assessment for different field development scenarios depends on how effective the uncertainty in production forecast is quantified. Currently there is a body of work in the literature on different methods to quantify the uncertainty in production forecast. The objective of this paper is to revisit and compare these probabilistic uncertainty quantification techniques through their applications to assisted history matching of a deep-water offshore waterflood field. The paper will address the benefits, limitations, and the best criteria for applicability of each technique. Three probabilistic history matching techniques commonly practiced in the industry are discussed. These are Design-of-Experiment (DoE) with rejection sampling from proxy, Ensemble Smoother (ES) and Genetic Algorithm (GA). The model used for this study is an offshore waterflood field in Gulf-of-Mexico. Posterior distributions of global subsurface uncertainties (e.g. regional pore volume and oil-water contact) were estimated using each technique conditioned to the injection and production data. The three probabilistic history matching techniques were applied to a deep-water field with 13 years of production history. The first 8 years of production data was used for the history matching and estimate of the posterior distribution of uncertainty in geologic parameters. While the convergence behavior and shape of the posterior distributions were different, consistent posterior means were obtained from Bayesian workflows such as DoE or ES. In contrast, the application of GA showed differences in posterior distribution of geological uncertainty parameters, especially those that had small sensitivity to the production data. We then conducted production forecast by including infill wells and evaluated the production performance using sample means of posterior geologic uncertainty parameters. The robustness of the solution was examined by performing history matching multiple times using different initial sample points (e.g. random seed). This confirmed that heuristic optimization techniques such as GA were unstable since parameter setup for the optimizer had a large impact on uncertainty characterization and production performance. This study shows the guideline to obtain the stable solution from the history matching techniques used for different conditions such as number of simulation model realizations and uncertainty parameters, and number of datapoints (e.g. maturity of the reservoir development). These guidelines will greatly help the decision-making process in selection of best development options.
{"title":"Methods for Probabilistic Uncertainty Quantification with Reliable Subsurface Assessment and Robust Decision-Making","authors":"Shusei Tanaka, K. Dehghani, Wang Zhenzhen","doi":"10.2118/195837-ms","DOIUrl":"https://doi.org/10.2118/195837-ms","url":null,"abstract":"\u0000 Reliability of subsurface assessment for different field development scenarios depends on how effective the uncertainty in production forecast is quantified. Currently there is a body of work in the literature on different methods to quantify the uncertainty in production forecast. The objective of this paper is to revisit and compare these probabilistic uncertainty quantification techniques through their applications to assisted history matching of a deep-water offshore waterflood field. The paper will address the benefits, limitations, and the best criteria for applicability of each technique.\u0000 Three probabilistic history matching techniques commonly practiced in the industry are discussed. These are Design-of-Experiment (DoE) with rejection sampling from proxy, Ensemble Smoother (ES) and Genetic Algorithm (GA). The model used for this study is an offshore waterflood field in Gulf-of-Mexico. Posterior distributions of global subsurface uncertainties (e.g. regional pore volume and oil-water contact) were estimated using each technique conditioned to the injection and production data.\u0000 The three probabilistic history matching techniques were applied to a deep-water field with 13 years of production history. The first 8 years of production data was used for the history matching and estimate of the posterior distribution of uncertainty in geologic parameters. While the convergence behavior and shape of the posterior distributions were different, consistent posterior means were obtained from Bayesian workflows such as DoE or ES. In contrast, the application of GA showed differences in posterior distribution of geological uncertainty parameters, especially those that had small sensitivity to the production data. We then conducted production forecast by including infill wells and evaluated the production performance using sample means of posterior geologic uncertainty parameters. The robustness of the solution was examined by performing history matching multiple times using different initial sample points (e.g. random seed). This confirmed that heuristic optimization techniques such as GA were unstable since parameter setup for the optimizer had a large impact on uncertainty characterization and production performance.\u0000 This study shows the guideline to obtain the stable solution from the history matching techniques used for different conditions such as number of simulation model realizations and uncertainty parameters, and number of datapoints (e.g. maturity of the reservoir development). These guidelines will greatly help the decision-making process in selection of best development options.","PeriodicalId":10909,"journal":{"name":"Day 2 Tue, October 01, 2019","volume":"215 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79594737","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}
As exploration for oil and gas continues, it becomes necessary to produce from deeper formations, have low permeability, and higher temperature. Unconventional shale formations utilize slickwater fracturing fluids due to the shale’s unique geomechanical properties. On the other hand, conventional formations require crosslinked fracturing fluids to properly enhance productivity. Guar and its derivatives have a history of success in crosslinked hydraulic fracturing fluids. However, they require higher polymer loading to withstand higher temperature environments. This leads to an increase in mixing time and additive requirements. Most importantly, due to the high polymer loading, they do not break completely and generate residual polymer fragments that can plug the formation and reduce fracture conductivity significantly. In this work, a new hybrid dual polymer hydraulic fracturing fluid is developed. The fluid consists of a guar derivative and a polyacrylamide-based synthetic polymer. Compared to conventional fracturing fluids, this new system is easily hydrated, requires fewer additives, can be mixed on the fly, and is capable of maintaining excellent rheological performance at low polymer loadings. The polymer mixture solutions were prepared at a total polymer concentration of 20 to 40 lb/1,000 gal and at a volume ratio of 2:1, 1:1, and 1:2. The fluids were crosslinked with a metallic crosslinker and broken with an oxidizer at 300°F. Testing focused on crosslinker to polymer ratio analysis to effectively lower loading while maintaining sufficient performance to carry proppant at this temperature. HP/HT rheometer was used to measure viscosity, storage modulus, and fluid breaking performance. HP/HT aging cell and HP/HT see-through cell were utilized for proppant settling. FTIR, Cryo-SEM and HP/HT rheometer were also utilized to understand the interaction. Results indicate that the dual polymer fracturing fluid is able to generate stable viscosity at 300°F and 100 s-1. Results show that the dual polymer fracturing fluid can generate higher viscosity compared to the individual polymer fracturing fluid. Also, properly understanding and tuning the crosslinker to polymer ratio generates excellent performance at 20 lb/1,000 gal. The two polymers form an improved crosslinking network that enhances proppant carrying properties. It also demonstrates a clean and controlled break performance with an oxidizer. Extensive experiments were pursued to evaluate the new dual polymer system for the first time. This system exhibits a positive interaction between polysaccharide and polyacrylamide families and generates excellent rheological properties. The major benefit of using a mixed polymer system is to reduce polymer loading. Lower loading is highly desirable because it reduces material cost, eases field operation and potentially lowers damage to the fracture face, proppant pack, and formation.
{"title":"Dual-Polymer Fracturing Fluids Provide Major Advantages Over Traditional Fluids","authors":"Tariq Almubarak","doi":"10.2118/199765-stu","DOIUrl":"https://doi.org/10.2118/199765-stu","url":null,"abstract":"\u0000 As exploration for oil and gas continues, it becomes necessary to produce from deeper formations, have low permeability, and higher temperature. Unconventional shale formations utilize slickwater fracturing fluids due to the shale’s unique geomechanical properties. On the other hand, conventional formations require crosslinked fracturing fluids to properly enhance productivity.\u0000 Guar and its derivatives have a history of success in crosslinked hydraulic fracturing fluids. However, they require higher polymer loading to withstand higher temperature environments. This leads to an increase in mixing time and additive requirements. Most importantly, due to the high polymer loading, they do not break completely and generate residual polymer fragments that can plug the formation and reduce fracture conductivity significantly.\u0000 In this work, a new hybrid dual polymer hydraulic fracturing fluid is developed. The fluid consists of a guar derivative and a polyacrylamide-based synthetic polymer. Compared to conventional fracturing fluids, this new system is easily hydrated, requires fewer additives, can be mixed on the fly, and is capable of maintaining excellent rheological performance at low polymer loadings.\u0000 The polymer mixture solutions were prepared at a total polymer concentration of 20 to 40 lb/1,000 gal and at a volume ratio of 2:1, 1:1, and 1:2. The fluids were crosslinked with a metallic crosslinker and broken with an oxidizer at 300°F. Testing focused on crosslinker to polymer ratio analysis to effectively lower loading while maintaining sufficient performance to carry proppant at this temperature. HP/HT rheometer was used to measure viscosity, storage modulus, and fluid breaking performance. HP/HT aging cell and HP/HT see-through cell were utilized for proppant settling. FTIR, Cryo-SEM and HP/HT rheometer were also utilized to understand the interaction.\u0000 Results indicate that the dual polymer fracturing fluid is able to generate stable viscosity at 300°F and 100 s-1. Results show that the dual polymer fracturing fluid can generate higher viscosity compared to the individual polymer fracturing fluid. Also, properly understanding and tuning the crosslinker to polymer ratio generates excellent performance at 20 lb/1,000 gal. The two polymers form an improved crosslinking network that enhances proppant carrying properties. It also demonstrates a clean and controlled break performance with an oxidizer.\u0000 Extensive experiments were pursued to evaluate the new dual polymer system for the first time. This system exhibits a positive interaction between polysaccharide and polyacrylamide families and generates excellent rheological properties. The major benefit of using a mixed polymer system is to reduce polymer loading. Lower loading is highly desirable because it reduces material cost, eases field operation and potentially lowers damage to the fracture face, proppant pack, and formation.","PeriodicalId":10909,"journal":{"name":"Day 2 Tue, October 01, 2019","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88634529","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}
Dai Zong, L. Hailong, Fangli Tang, D. Luo, Wang Yahui, Y. Zhenghe
A new method of digital core construction and analysis for unconsolidated sandstone is presented in this paper to solve the problem for friable cores. Results are compared with conventional experimental techniques and routine digital core construction methods. The new method procedures: Firstly, rocks are full-closure cored from unconsolidated formation and frozen; multi-scale (meter/millimeter/micron) CT scanning for core samples with original formation fluids, and the core heterogeneity has been analyzed. Then, skeleton and pore space of samples are segmented with the watershed algorithm. Finally, pore network model is extracted with maximum sphere method. After building the digital core, petrophysical parameters and fluid flowing characteristic are simulated. Compared with conventional experimental method, samples preparation is convenient under lower requirements of the size and shape. Without cleaning, the distortion of experimental parameters are avoided due to damages to the original pore structure of friable core samples, especially for unconsolidated samples. Compared with conventional digital core construction, the focused scanning mode is used for micron scanning, without catching the smaller samples. The new method not only simplifies the preparation of conventional core analysis that reduces the difficulty of sample preparation of unconsolidated sandstone natural core, but also guarantees the quality of core analysis data. The new method is successfully applied and results are compared in field of South China Sea. The results from different methods with consolidated samples analysis, such as porosity, permeability and parameters of relative permeability, show the relative errors are less than 10%. The results from unconsolidated samples analysis with conventional experimental method show obvious errors: permeability of some samples are more than 15 Darcy, the relative permeability curve is obviously not consistent with the actual field performance. While results from unconsolidated samples analysis with the new method show good agreement with actual field performance. This method can accurately test the petrophysical parameters of unconsolidated sandstone, reduce the experimental errors caused by conventional methods and shorten the experimental schedule. It could be applied to core analysis of similar formation.
{"title":"A New Method of Digital Core Construction and Analysis for Unconsolidated Sandstone","authors":"Dai Zong, L. Hailong, Fangli Tang, D. Luo, Wang Yahui, Y. Zhenghe","doi":"10.2118/196200-ms","DOIUrl":"https://doi.org/10.2118/196200-ms","url":null,"abstract":"\u0000 A new method of digital core construction and analysis for unconsolidated sandstone is presented in this paper to solve the problem for friable cores. Results are compared with conventional experimental techniques and routine digital core construction methods.\u0000 The new method procedures: Firstly, rocks are full-closure cored from unconsolidated formation and frozen; multi-scale (meter/millimeter/micron) CT scanning for core samples with original formation fluids, and the core heterogeneity has been analyzed. Then, skeleton and pore space of samples are segmented with the watershed algorithm. Finally, pore network model is extracted with maximum sphere method. After building the digital core, petrophysical parameters and fluid flowing characteristic are simulated.\u0000 Compared with conventional experimental method, samples preparation is convenient under lower requirements of the size and shape. Without cleaning, the distortion of experimental parameters are avoided due to damages to the original pore structure of friable core samples, especially for unconsolidated samples. Compared with conventional digital core construction, the focused scanning mode is used for micron scanning, without catching the smaller samples. The new method not only simplifies the preparation of conventional core analysis that reduces the difficulty of sample preparation of unconsolidated sandstone natural core, but also guarantees the quality of core analysis data.\u0000 The new method is successfully applied and results are compared in field of South China Sea. The results from different methods with consolidated samples analysis, such as porosity, permeability and parameters of relative permeability, show the relative errors are less than 10%. The results from unconsolidated samples analysis with conventional experimental method show obvious errors: permeability of some samples are more than 15 Darcy, the relative permeability curve is obviously not consistent with the actual field performance. While results from unconsolidated samples analysis with the new method show good agreement with actual field performance.\u0000 This method can accurately test the petrophysical parameters of unconsolidated sandstone, reduce the experimental errors caused by conventional methods and shorten the experimental schedule. It could be applied to core analysis of similar formation.","PeriodicalId":10909,"journal":{"name":"Day 2 Tue, October 01, 2019","volume":"25 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88738584","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}
Polymer rheological behavior in an Enhanced Oil Recovery (EOR) project is one of the critical factors to determine whether the polymer injection would be effective to increase the oil production in a field. Due to complications on the measurement of this parameter and its variation within the reservoir, the challenge of understanding viscosity behavior relies on lab and field tests that become key factors to solve this issue. This study was conducted during an injectivity test for an EOR project in Los Perales field (Santa Cruz, Argentina) in three wells with different operational and subsurface conditions, and tests were performed twice a day for 30 days each in order to obtain sufficient time span of data. From lab rheology tests performed at reservoir conditions, where the main objective was to analyze viscosity changes through time, two different tendencies were observed: one that affects in early times and another that becomes preeminent at late times. With these results, a describing equation was developed to predict viscosity evolution over time. The equation consists of three terms including thermal variation, chemical degradation and the final viscosity towards which the polymer tends. Although the equation properly describes both lab and field polymer solution, there is a considerable difference, especially when the effects mentioned become preponderant. This difference is attributed to both the water used for the mixture and the possible impurities that may be incorporated during the maturation or transfer of the polymer. Since most of the data used was obtained from field tests, this emphasizes the appliance of the equation on the field. Impurities turn out to be crucial, specially oxygen (O2) and hydrogen sulfide (H2S) combined. Their presence highly impacts the asymptotic viscosity, so a correlation between H2S content and final viscosity was also developed. Finally, an analysis of the temperature influence on the viscosity was conducted. A correlation between the final viscosity and temperature was found and used to incorporate temperature variations in the predictions and therefore to relate measurements performed at different conditions. The primary advantage of this study is that the equation and correlations enable the prediction of the polymer solution viscosity at any time. This allows the estimation of actual polymer viscosity in the reservoir from a routine measurement at any temperature and impurities content. The versatility of this equation is what makes it novel and useful in an industry going towards EOR projects.
{"title":"Polymer Viscosity: Understanding of Changes Through Time in the Reservoir and a Way to Predict Them","authors":"Katz Marquez, E. Roman","doi":"10.2118/199779-stu","DOIUrl":"https://doi.org/10.2118/199779-stu","url":null,"abstract":"\u0000 Polymer rheological behavior in an Enhanced Oil Recovery (EOR) project is one of the critical factors to determine whether the polymer injection would be effective to increase the oil production in a field. Due to complications on the measurement of this parameter and its variation within the reservoir, the challenge of understanding viscosity behavior relies on lab and field tests that become key factors to solve this issue.\u0000 This study was conducted during an injectivity test for an EOR project in Los Perales field (Santa Cruz, Argentina) in three wells with different operational and subsurface conditions, and tests were performed twice a day for 30 days each in order to obtain sufficient time span of data.\u0000 From lab rheology tests performed at reservoir conditions, where the main objective was to analyze viscosity changes through time, two different tendencies were observed: one that affects in early times and another that becomes preeminent at late times. With these results, a describing equation was developed to predict viscosity evolution over time. The equation consists of three terms including thermal variation, chemical degradation and the final viscosity towards which the polymer tends.\u0000 Although the equation properly describes both lab and field polymer solution, there is a considerable difference, especially when the effects mentioned become preponderant. This difference is attributed to both the water used for the mixture and the possible impurities that may be incorporated during the maturation or transfer of the polymer. Since most of the data used was obtained from field tests, this emphasizes the appliance of the equation on the field.\u0000 Impurities turn out to be crucial, specially oxygen (O2) and hydrogen sulfide (H2S) combined. Their presence highly impacts the asymptotic viscosity, so a correlation between H2S content and final viscosity was also developed.\u0000 Finally, an analysis of the temperature influence on the viscosity was conducted. A correlation between the final viscosity and temperature was found and used to incorporate temperature variations in the predictions and therefore to relate measurements performed at different conditions.\u0000 The primary advantage of this study is that the equation and correlations enable the prediction of the polymer solution viscosity at any time. This allows the estimation of actual polymer viscosity in the reservoir from a routine measurement at any temperature and impurities content. The versatility of this equation is what makes it novel and useful in an industry going towards EOR projects.","PeriodicalId":10909,"journal":{"name":"Day 2 Tue, October 01, 2019","volume":"27 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81190392","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}
When wells producing up casing in the Marcellus Shale dip into the slug flow regime, their production begins to drop off significantly. In some instances, wells that begin slugging dramatically can defer the majority of the production that they were delivering just months before slugging, resulting in significant loss in present value. To remedy this complication, engineers can install tubing in these wells to help lift fluids through the vertical section. Because slugging causes large fluctuations in production, most slugging is identified and addressed only after a production engineer notices these fluctuations. This can be months after the decrease in production rate. To challenge this reactive approach to identifying wells ready for tubing installation, I created a workflow—implemented with software—to create a tubing installation schedule which requires little time or effort by the production engineer. While it is unlikely this program can be replicated exactly, the logic I used to create the program can certainly be adopted and applied elsewhere. I used Coleman's model for critical rate to determine quantitatively when a given well is likely to begin to slug. Critical rate is defined as the minimum gas rate needed to maintain steady flow up a well to the surface. When the gas rate in a well dips below this critical rate, the well will dip into the slug flow regime. Bottomhole pressure (BHP) is a necessary input for the critical rate calculation. Because BHP data is not readily available for wells producing up casing, I had to create an alternative approach to determining BHP. After investigation, I determined that using data from different combinations of water-gas ratio (WGR), wellhead pressure (WHP), and gas rate allowed me to create a correlation to approximate the BHP of any given well on any given producing day. The resulting correlation could be incorporated in my workflow and—after combined with other input data—my software could determine, with sufficient accuracy, the critical rate of any given well on any given producing day. An engineer can use my software to create a graph displaying both critical rate and gas rate with time for every well in a data set. Engineers can summarize the pertinent information from those plots in a data table which can assist them with creating a tubing installation schedule. This workflow will help engineers to determine more readily whether any of their wells are on the verge of slugging, allowing them to be more proactive in installing tubing on their wells and preventing costly deferred production.
{"title":"Proactive Approach Minimizes Production Losses Due to Slug Flow","authors":"S. Carrie","doi":"10.2118/199782-stu","DOIUrl":"https://doi.org/10.2118/199782-stu","url":null,"abstract":"\u0000 When wells producing up casing in the Marcellus Shale dip into the slug flow regime, their production begins to drop off significantly. In some instances, wells that begin slugging dramatically can defer the majority of the production that they were delivering just months before slugging, resulting in significant loss in present value. To remedy this complication, engineers can install tubing in these wells to help lift fluids through the vertical section. Because slugging causes large fluctuations in production, most slugging is identified and addressed only after a production engineer notices these fluctuations. This can be months after the decrease in production rate.\u0000 To challenge this reactive approach to identifying wells ready for tubing installation, I created a workflow—implemented with software—to create a tubing installation schedule which requires little time or effort by the production engineer. While it is unlikely this program can be replicated exactly, the logic I used to create the program can certainly be adopted and applied elsewhere.\u0000 I used Coleman's model for critical rate to determine quantitatively when a given well is likely to begin to slug. Critical rate is defined as the minimum gas rate needed to maintain steady flow up a well to the surface. When the gas rate in a well dips below this critical rate, the well will dip into the slug flow regime. Bottomhole pressure (BHP) is a necessary input for the critical rate calculation. Because BHP data is not readily available for wells producing up casing, I had to create an alternative approach to determining BHP. After investigation, I determined that using data from different combinations of water-gas ratio (WGR), wellhead pressure (WHP), and gas rate allowed me to create a correlation to approximate the BHP of any given well on any given producing day. The resulting correlation could be incorporated in my workflow and—after combined with other input data—my software could determine, with sufficient accuracy, the critical rate of any given well on any given producing day.\u0000 An engineer can use my software to create a graph displaying both critical rate and gas rate with time for every well in a data set. Engineers can summarize the pertinent information from those plots in a data table which can assist them with creating a tubing installation schedule. This workflow will help engineers to determine more readily whether any of their wells are on the verge of slugging, allowing them to be more proactive in installing tubing on their wells and preventing costly deferred production.","PeriodicalId":10909,"journal":{"name":"Day 2 Tue, October 01, 2019","volume":"12 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90134470","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}
Yingchun Zhang, W. Xu, Jingyun Zou, Z. Jing, L. Fang, Jun Liu
In complex clastic reservoirs, deviation often exists in oil saturation derived from logging interpretation due to the borehole conditions and log quality. Especially in thin-sand reservoirs, oil saturation is generally lower than actual results because of boundary effect. An innovative approach of saturation height function coupled with rocktype is provided to improve the accuracy of saturation prediction in well logs and spatial distribution. The model results are compared with log derived results. The new approach is based on the routine and special core analysis of over 100 core samples from the complex clastic reservoir in the north of Albert Basin in Uganda. Discrete rocktypes (DRT) are determined by flow zone index and pore throat radius which indicate the fluid flows. After converting the capillary pressure (Pc) data to reservoir conditions, Lambda curve fitting (Sw = A * PcB + C) is used to fit each capillary pressure curve. Then, a robust relationship between the fitting coefficients (A, B, C) and rock properties (i.e. porosity and permeability) is expressed as a nonlinear function for each DRT. Combined with the height above free water level, a water saturation (Sw) model is constructed by SHF within DRT model. Using the porosity and permeability obtainedfrom routine core analysis, FZI and pore throat radius are calculated (e.g., by Winland function). Five different rocktypes (DRT1-5) are defined in the delta sand reservoir in the north of Albert Basin with distinct pore textures. The distinguishment is in accordance with the shape of capillary pressure curve, that is, the flow capability increases from DRT1 to DRT5. A strong correlation between Pc and Sw processed by Lambda curve is acquired for each core sample. Meanwhile, 3 coefficients A, B and C can be obtained in Lambda formula. By nonlinear regression, coherent relation between each factor and reservoir properties (porosity and permeability) for each DRT are obtained. Height above the free water level is estimated by geometrical modeling on the oil water contact. The Sw model is constructed by the new SHF function coupled with DRT model. It showed that the water saturation derived from SHF is highly consistent with log derived results and NMR results. Moreover, it provides more precise results in thinner sands and in spatial distribution. Based on the identified different rocktype, a new SHF derived from capillary pressure data is utilized to establish the relationship between saturation, the height above the free water level and rock properties. The approach can significantly improve the accuracy of saturation prediction of thin reservoir and reasonably depict the spatial distribution characteristics of saturation. Furthermore, the approach will provide a more precise result in hydrocarbon volume calculation and numerical simulation.
在复杂碎屑岩储层中，由于井眼条件和测井质量的影响，测井解释含油饱和度往往存在偏差。特别是在薄砂油藏中，由于边界效应的影响，含油饱和度普遍低于实际结果。提出了一种结合岩石类型的饱和高度函数的创新方法，提高了测井曲线和空间分布的饱和度预测精度。将模型结果与对数推导结果进行了比较。新方法是基于对乌干达阿尔伯特盆地北部复杂碎屑储层100多个岩心样本的常规和特殊岩心分析。离散岩石类型(DRT)由指示流体流动的流区指数和孔喉半径决定。将毛管压力(Pc)数据转换为储层条件后，采用Lambda曲线拟合(Sw = A * PcB + C)拟合各毛管压力曲线。然后，拟合系数(a, B, C)与岩石性质(即孔隙度和渗透率)之间的鲁棒关系被表示为每个DRT的非线性函数。结合自由水位以上高度，利用DRT模型中的SHF构造了含水饱和度(Sw)模型。利用常规岩心分析得到的孔隙度和渗透率，计算FZI和孔喉半径(如采用Winland函数)。阿尔伯特盆地北部三角洲砂岩储层划分出5种不同的岩石类型(DRT1-5)，孔隙结构各异。这种区别与毛管压力曲线的形状一致，即从DRT1到DRT5，流动能力增加。对每个岩心样品进行Lambda曲线处理，得到了Pc与Sw之间较强的相关性。同时在Lambda公式中可以得到3个系数A、B、C。通过非线性回归，得到各因素与各DRT储层物性(孔隙度和渗透率)之间的相干关系。通过油水接触面的几何建模来估计自由水位以上的高度。该模型由新的SHF函数与DRT模型耦合而成。结果表明，深水场计算的含水饱和度与测井结果和核磁共振结果高度一致。此外，在较薄的砂层和空间分布上，它提供了更精确的结果。在确定不同岩石类型的基础上，利用毛管压力数据推导出新的SHF，建立了饱和度、自由水位以上高度与岩石性质之间的关系。该方法可显著提高薄层储层饱和度预测的精度，合理刻画储层饱和度的空间分布特征。此外，该方法将为油气体积计算和数值模拟提供更精确的结果。
{"title":"Saturation Height Function Coupled with Rocktype in Complex Clastic Reservoir in the North of Albert Basin, Uganda","authors":"Yingchun Zhang, W. Xu, Jingyun Zou, Z. Jing, L. Fang, Jun Liu","doi":"10.2118/195853-ms","DOIUrl":"https://doi.org/10.2118/195853-ms","url":null,"abstract":"\u0000 In complex clastic reservoirs, deviation often exists in oil saturation derived from logging interpretation due to the borehole conditions and log quality. Especially in thin-sand reservoirs, oil saturation is generally lower than actual results because of boundary effect. An innovative approach of saturation height function coupled with rocktype is provided to improve the accuracy of saturation prediction in well logs and spatial distribution. The model results are compared with log derived results.\u0000 The new approach is based on the routine and special core analysis of over 100 core samples from the complex clastic reservoir in the north of Albert Basin in Uganda. Discrete rocktypes (DRT) are determined by flow zone index and pore throat radius which indicate the fluid flows. After converting the capillary pressure (Pc) data to reservoir conditions, Lambda curve fitting (Sw = A * PcB + C) is used to fit each capillary pressure curve. Then, a robust relationship between the fitting coefficients (A, B, C) and rock properties (i.e. porosity and permeability) is expressed as a nonlinear function for each DRT. Combined with the height above free water level, a water saturation (Sw) model is constructed by SHF within DRT model.\u0000 Using the porosity and permeability obtainedfrom routine core analysis, FZI and pore throat radius are calculated (e.g., by Winland function). Five different rocktypes (DRT1-5) are defined in the delta sand reservoir in the north of Albert Basin with distinct pore textures. The distinguishment is in accordance with the shape of capillary pressure curve, that is, the flow capability increases from DRT1 to DRT5. A strong correlation between Pc and Sw processed by Lambda curve is acquired for each core sample. Meanwhile, 3 coefficients A, B and C can be obtained in Lambda formula. By nonlinear regression, coherent relation between each factor and reservoir properties (porosity and permeability) for each DRT are obtained. Height above the free water level is estimated by geometrical modeling on the oil water contact. The Sw model is constructed by the new SHF function coupled with DRT model. It showed that the water saturation derived from SHF is highly consistent with log derived results and NMR results. Moreover, it provides more precise results in thinner sands and in spatial distribution.\u0000 Based on the identified different rocktype, a new SHF derived from capillary pressure data is utilized to establish the relationship between saturation, the height above the free water level and rock properties. The approach can significantly improve the accuracy of saturation prediction of thin reservoir and reasonably depict the spatial distribution characteristics of saturation. Furthermore, the approach will provide a more precise result in hydrocarbon volume calculation and numerical simulation.","PeriodicalId":10909,"journal":{"name":"Day 2 Tue, October 01, 2019","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90261825","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}
Substantial computational time is typically a bottleneck for coupled flow-geomechanics simulation in realistic problems despite increasing importance in reservoir geomechanics. This paper presents a new, rapid, coupled flow-geomechanics simulator using the Fast Marching Method (FMM-Geo). The simulator incorporates Diffusive Time-of-Flight (DTOF), which represents the arrival time of the propagating pressure front, as a 1-D spatial coordinate to transform original multi-dimensional model into equivalent 1-D model. DTOF can be obtained by efficiently solving the Eikonal equation using the Fast Marching Method (FMM). FMM-Geo is verified for 2-D models against a benchmark simulator and has achieved order-of-magnitude faster computation while it preserved reasonable accuracy. Finally, the simulator is applied to an assisted history matching example using surface subsidence data to illustrate its computational efficiency and applicability.
尽管油藏地质力学在实际问题中越来越重要，但大量的计算时间通常是流体-地质力学耦合模拟的瓶颈。本文提出了一种基于快速推进法(FMM-Geo)的新型、快速、耦合流动-地质力学模拟器。仿真器将表示传播压力锋到达时间的扩散飞行时间(diffusion time -of- flight, DTOF)作为一维空间坐标，将原来的多维模型转化为等效的一维模型。利用快速推进法(FMM)求解Eikonal方程，可以得到dof。FMM-Geo在二维模型上进行了基准模拟器验证，在保持合理精度的同时，计算速度提高了数量级。最后，以地面沉降数据辅助历史匹配为例，说明了该仿真器的计算效率和适用性。
{"title":"Rapid Coupled Flow and Geomechanics Simulation using the Fast Marching Method","authors":"K. Terada","doi":"10.2118/199785-stu","DOIUrl":"https://doi.org/10.2118/199785-stu","url":null,"abstract":"\u0000 Substantial computational time is typically a bottleneck for coupled flow-geomechanics simulation in realistic problems despite increasing importance in reservoir geomechanics. This paper presents a new, rapid, coupled flow-geomechanics simulator using the Fast Marching Method (FMM-Geo). The simulator incorporates Diffusive Time-of-Flight (DTOF), which represents the arrival time of the propagating pressure front, as a 1-D spatial coordinate to transform original multi-dimensional model into equivalent 1-D model. DTOF can be obtained by efficiently solving the Eikonal equation using the Fast Marching Method (FMM). FMM-Geo is verified for 2-D models against a benchmark simulator and has achieved order-of-magnitude faster computation while it preserved reasonable accuracy. Finally, the simulator is applied to an assisted history matching example using surface subsidence data to illustrate its computational efficiency and applicability.","PeriodicalId":10909,"journal":{"name":"Day 2 Tue, October 01, 2019","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73562136","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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