Cesar Orta, Mohanad Al Faqih, Bader Al Gharibi, Mohammed Al Shabibi, Ali El Khouly, Ya. I. Matin, Ayoub Hadj-moussa, M. Saleh
Drilling with a gas cap over the Natih formation in Oman often results in excessive flat time. Using the current dynamic fill equipment to deal with kick and loss scenarios leads to extensive nonproductive time on the rig. Managed pressure drilling (MPD) is a well-established drilling technology, and diverse variants exist to suit different requirements. All those variants use the rotating control device (RCD) as a common piece of equipment, but their procedures are different. The pressurized mud-cap drilling (PMCD) technique in the Natih formation replaces the need for traditional dynamic filling technology. The PMCD application enhances the drilling and completion processes by reducing flat time when total downhole losses are experienced. This paper elaborates on PMCD as a proven drilling technique in total loss scenarios when drilling with it for the first time in the Natih formation in Oman. It describes the PMCD process, the associated equipment, and the results of the inaugural application in the Qalah field.
{"title":"First Oman Implementation of Pressurized Mud-Cap Drilling Improves Drilling Efficiency and Sustainability","authors":"Cesar Orta, Mohanad Al Faqih, Bader Al Gharibi, Mohammed Al Shabibi, Ali El Khouly, Ya. I. Matin, Ayoub Hadj-moussa, M. Saleh","doi":"10.2118/204682-ms","DOIUrl":"https://doi.org/10.2118/204682-ms","url":null,"abstract":"\u0000 Drilling with a gas cap over the Natih formation in Oman often results in excessive flat time. Using the current dynamic fill equipment to deal with kick and loss scenarios leads to extensive nonproductive time on the rig. Managed pressure drilling (MPD) is a well-established drilling technology, and diverse variants exist to suit different requirements. All those variants use the rotating control device (RCD) as a common piece of equipment, but their procedures are different. The pressurized mud-cap drilling (PMCD) technique in the Natih formation replaces the need for traditional dynamic filling technology. The PMCD application enhances the drilling and completion processes by reducing flat time when total downhole losses are experienced.\u0000 This paper elaborates on PMCD as a proven drilling technique in total loss scenarios when drilling with it for the first time in the Natih formation in Oman. It describes the PMCD process, the associated equipment, and the results of the inaugural application in the Qalah field.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"5 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89203198","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}
This paper presents an unparalleled engineering assessment conducted to evaluate the feasibility of pre-investing in O2 enrichment technology, with the purpose of increasing the processing capacities of conventional air-based sulfur recovery units (SRUs). Ultimately, the goal is to minimize the overall number of required SRUs for a greenfield gas plant and, consequently, capture a significant cost-avoidance opportunity. The technology review revealed that a high-level O2 enrichment can double the processing capacity of air-based SRU, depending on the H2S content in acid gas. As H2S mole fraction in feed increases, the debottlenecking capability increases. For the project under assessment, the processing capacity of air-based SRUs showed a maximum increase of 80%. On the contrary, operating with high O2 levels, will elevate SRU reaction furnace temperature, and mandates installing high-intensity burners, along with special control and ESD functions, to manage potential risk and ensure safe operation. Additionally, the liquid handling section of SRUs (condensers, collection vessels, degassing vessels, sulfur storage tanks) should be enlarged to accommodate more sulfur production. Typically, the enriched oxygen can be supplied from air separation units (ASUs), which entails significant capital cost. Apart from these special design considerations, there are several advantages for adopting this technology. Oxygen enrichment removes significant nitrogen volumes, which reduces loads on Claus, tail gas treatment, and thermal oxidizer units. Hence, lower capital cost for new plants is acquired due to equipment size reduction. In addition, higher HP steam production and less fuel gas consumption are achieved. Conventionally, O2 enrichment technology is employed in the initial design stage or used to retrofit operating SRUs facilities. However, it is unique to consider O2 enrichment-design requirements as part of new air-based SRUs design for phased program development. The objective is to enable smooth transition to fully O2 enrichment operated SRUs at a later phase of the project without the need for any design modification. This exceptional pre-investment strategy has resulted into reducing the required number of SRUs at phase II from eight to five units; and accordingly, a significant cost avoidance was captured.
{"title":"Smart SRUs Pre-Investment Utilizing Oxygen Enrichment Technology","authors":"W. Alhazmi, Maher Alabdullatif","doi":"10.2118/204756-ms","DOIUrl":"https://doi.org/10.2118/204756-ms","url":null,"abstract":"\u0000 This paper presents an unparalleled engineering assessment conducted to evaluate the feasibility of pre-investing in O2 enrichment technology, with the purpose of increasing the processing capacities of conventional air-based sulfur recovery units (SRUs). Ultimately, the goal is to minimize the overall number of required SRUs for a greenfield gas plant and, consequently, capture a significant cost-avoidance opportunity.\u0000 The technology review revealed that a high-level O2 enrichment can double the processing capacity of air-based SRU, depending on the H2S content in acid gas. As H2S mole fraction in feed increases, the debottlenecking capability increases. For the project under assessment, the processing capacity of air-based SRUs showed a maximum increase of 80%. On the contrary, operating with high O2 levels, will elevate SRU reaction furnace temperature, and mandates installing high-intensity burners, along with special control and ESD functions, to manage potential risk and ensure safe operation. Additionally, the liquid handling section of SRUs (condensers, collection vessels, degassing vessels, sulfur storage tanks) should be enlarged to accommodate more sulfur production. Typically, the enriched oxygen can be supplied from air separation units (ASUs), which entails significant capital cost.\u0000 Apart from these special design considerations, there are several advantages for adopting this technology. Oxygen enrichment removes significant nitrogen volumes, which reduces loads on Claus, tail gas treatment, and thermal oxidizer units. Hence, lower capital cost for new plants is acquired due to equipment size reduction. In addition, higher HP steam production and less fuel gas consumption are achieved. Conventionally, O2 enrichment technology is employed in the initial design stage or used to retrofit operating SRUs facilities. However, it is unique to consider O2 enrichment-design requirements as part of new air-based SRUs design for phased program development. The objective is to enable smooth transition to fully O2 enrichment operated SRUs at a later phase of the project without the need for any design modification. This exceptional pre-investment strategy has resulted into reducing the required number of SRUs at phase II from eight to five units; and accordingly, a significant cost avoidance was captured.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"136 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76440542","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}
Mohd Ghazali Abd Karim, W. Hidayat, Alzahrani Abdulelah
The objective of this paper is to investigate the effects of interfacial tension dependent relative permeability (Kr_IFT) on oil displacement and recovery under different gas injection compositions utilizing a compositional simulation model. Oil production under miscible gas injection will result in variations of interfacial tension (IFT) due to changes in oil and gas compositions and other reservoir properties, such as pressure and temperature. Laboratory experiments show that changes in IFT will affect the two-phase relative permeability curve (Kr), especially for oil-gas system. Using a single relative permeability curve during the process from immiscible to miscible conditions will result in inaccurate gas mobility against water, which may lead to poor estimation of sweep efficiency and oil recovery. A synthetic sector compositional model was built to evaluate the effects of this phenomenon. Several simulation cases were investigated over different gas injection compositions (lean, rich and CO2), fluid properties and reservoir characterizations to demonstrate the impact of these parameters. Simulation model results show that the application of Kr_IFT on gas injection simulation modelling has captured different displacement behavior to provide better estimation of oil recovery and identify any upside potential.
{"title":"The Effects of Interfacial Tension Dependent Relative Permeability on Sweep Efficiency and Oil Recovery Under Different Gas Injection Composition","authors":"Mohd Ghazali Abd Karim, W. Hidayat, Alzahrani Abdulelah","doi":"10.2118/204651-ms","DOIUrl":"https://doi.org/10.2118/204651-ms","url":null,"abstract":"\u0000 The objective of this paper is to investigate the effects of interfacial tension dependent relative permeability (Kr_IFT) on oil displacement and recovery under different gas injection compositions utilizing a compositional simulation model. Oil production under miscible gas injection will result in variations of interfacial tension (IFT) due to changes in oil and gas compositions and other reservoir properties, such as pressure and temperature. Laboratory experiments show that changes in IFT will affect the two-phase relative permeability curve (Kr), especially for oil-gas system. Using a single relative permeability curve during the process from immiscible to miscible conditions will result in inaccurate gas mobility against water, which may lead to poor estimation of sweep efficiency and oil recovery. A synthetic sector compositional model was built to evaluate the effects of this phenomenon. Several simulation cases were investigated over different gas injection compositions (lean, rich and CO2), fluid properties and reservoir characterizations to demonstrate the impact of these parameters. Simulation model results show that the application of Kr_IFT on gas injection simulation modelling has captured different displacement behavior to provide better estimation of oil recovery and identify any upside potential.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"61 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74488867","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}
Natural gas liquid (NGL) production facilities, typically, utilize turbo-expander-brake compressor (TE) to generate cold for C2+ separation from the natural gas by isentropic expansion of feed stream and use energy absorbed by expansion to compress residue gas. Experience shows that during operational phase TE can exposed to operation outside of design window that may lead to machine integrity loss and consequent impact on production. At the same time, there is a lack of performance indicators that help operator to monitor operating window of the machine and proactively identify performance deterioration. For instance, TE brake compressor side is always equipped with anti-surge protection system, including surge deviation alarms and trip. However, there is often gap in monitoring deviation from stonewall region. At the same time, in some of the designs (2×50% machines) likelihood of running brake compressor in stonewall is high during one machine trip or train start-up, turndown operating modes. Also, typical compressor performance monitoring systems does not have enough dynamic parameters that may indicate machine process process performance deterioration proactively (real-time calculation of actual polytrophic efficiency, absorbed power etc.) and help operator to take action before catastrophic failure occurs. In addition, typical compressor monitoring systems are based on assumed composition and fixed compressibility factor and do not reflect actual compositions variations that may affect machine performance monitoring. To overcome issues highlighted above, Hawiyah NGL (HNGL) team has developed computerized monitoring and advisory system to monitor the performance of turbo-expander-brake compressor, proactively, identify potentially unsafe conditions or performance deterioration and advice operators on taking necessary actions to avoid unscheduled deferment of production. Computerized performance monitoring system has been implemented in HNGL DCS (Yokogawa) and utilized by control room operators on day-to-day basis. Real-time calculation, analysis and outputs produced by performance monitoring system allow operator to understand how current operating condition are far from danger zone. Proactive deviation alarms and guide messages produce by the system in case of deviation help operators to control machine from entering unsafe region. Actual polytrophic efficiency, adsorbed power calculations provide machine condition status and allow identifying long-term performance deterioration trends.
{"title":"Compressor Computerized Performance Monitoring System CPMS","authors":"Vadim Goryachikh, Fahad Alghamdi, Abdulrahman Takrouni","doi":"10.2118/204582-ms","DOIUrl":"https://doi.org/10.2118/204582-ms","url":null,"abstract":"\u0000 \u0000 \u0000 Natural gas liquid (NGL) production facilities, typically, utilize turbo-expander-brake compressor (TE) to generate cold for C2+ separation from the natural gas by isentropic expansion of feed stream and use energy absorbed by expansion to compress residue gas.\u0000 Experience shows that during operational phase TE can exposed to operation outside of design window that may lead to machine integrity loss and consequent impact on production. At the same time, there is a lack of performance indicators that help operator to monitor operating window of the machine and proactively identify performance deterioration.\u0000 For instance, TE brake compressor side is always equipped with anti-surge protection system, including surge deviation alarms and trip. However, there is often gap in monitoring deviation from stonewall region. At the same time, in some of the designs (2×50% machines) likelihood of running brake compressor in stonewall is high during one machine trip or train start-up, turndown operating modes.\u0000 Also, typical compressor performance monitoring systems does not have enough dynamic parameters that may indicate machine process process performance deterioration proactively (real-time calculation of actual polytrophic efficiency, absorbed power etc.) and help operator to take action before catastrophic failure occurs.\u0000 In addition, typical compressor monitoring systems are based on assumed composition and fixed compressibility factor and do not reflect actual compositions variations that may affect machine performance monitoring.\u0000 To overcome issues highlighted above, Hawiyah NGL (HNGL) team has developed computerized monitoring and advisory system to monitor the performance of turbo-expander-brake compressor, proactively, identify potentially unsafe conditions or performance deterioration and advice operators on taking necessary actions to avoid unscheduled deferment of production.\u0000 Computerized performance monitoring system has been implemented in HNGL DCS (Yokogawa) and utilized by control room operators on day-to-day basis.\u0000 Real-time calculation, analysis and outputs produced by performance monitoring system allow operator to understand how current operating condition are far from danger zone. Proactive deviation alarms and guide messages produce by the system in case of deviation help operators to control machine from entering unsafe region. Actual polytrophic efficiency, adsorbed power calculations provide machine condition status and allow identifying long-term performance deterioration trends.\u0000","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"267 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75157988","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}
Nadir Husein, E. Malyavko, Igor Novikov, A. Drobot, A. Buyanov, E. Potapova, Vishwajit Upadhye
Currently, it is hard to imagine oil field development management without various surveys, involving resource optimisation for more economical reserves recovery. In this context, the application of new technologies aimed at diagnostics of the state of producing wells opens up multiple opportunities to identify the causes of premature water flooding and reduction in oil production, clarify the geology of the developed deposit, and obtain other useful information in a cost-efficient manner. For several decades now, well logging has been the source of information for field operators on the producing reservoir performance and the composition of fluid flowing across the reservoir through target intervals. However, in the course of time, the industry tends to seek advanced technologies and alternative production logging techniques for well performance diagnostics. Marker-based production logging is just one of the techniques employed to obtain additional data that can be extremely important for prompt decision-making in case of any complicating factors. At the same time, such information requires proper processing and interpretation. The information on how various factors impact the production profile helps develop a set of measures to adjust the oil flow into the well. In this regard, the task above offers a promising outlook for improving the development system efficiency using selective reservoir stimulation, as far as unconventional reservoirs and hard-to-recover reserves are concerned. Therefore, the upstream industry puts a strong focus on further research in this area today.
{"title":"Recovery Improvement Using Geological, Technical and Operational Factors of Field Development That Influence the Character of Inflow Profiles in Horizontal Laterals","authors":"Nadir Husein, E. Malyavko, Igor Novikov, A. Drobot, A. Buyanov, E. Potapova, Vishwajit Upadhye","doi":"10.2118/204798-ms","DOIUrl":"https://doi.org/10.2118/204798-ms","url":null,"abstract":"\u0000 Currently, it is hard to imagine oil field development management without various surveys, involving resource optimisation for more economical reserves recovery. In this context, the application of new technologies aimed at diagnostics of the state of producing wells opens up multiple opportunities to identify the causes of premature water flooding and reduction in oil production, clarify the geology of the developed deposit, and obtain other useful information in a cost-efficient manner.\u0000 For several decades now, well logging has been the source of information for field operators on the producing reservoir performance and the composition of fluid flowing across the reservoir through target intervals. However, in the course of time, the industry tends to seek advanced technologies and alternative production logging techniques for well performance diagnostics. Marker-based production logging is just one of the techniques employed to obtain additional data that can be extremely important for prompt decision-making in case of any complicating factors. At the same time, such information requires proper processing and interpretation.\u0000 The information on how various factors impact the production profile helps develop a set of measures to adjust the oil flow into the well. In this regard, the task above offers a promising outlook for improving the development system efficiency using selective reservoir stimulation, as far as unconventional reservoirs and hard-to-recover reserves are concerned. Therefore, the upstream industry puts a strong focus on further research in this area today.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"8 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74272484","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}
Stimulations in early horizontal wells in most shale plays are characterized by few and widely spaced perforation clusters, and low amounts of injected fracturing fluid and proppant. Low recovery from these wells has motivated refracturing although outcomes have been interpreted to range from successful to minimal impact based on operator specific evaluations. To tailor available technologies and improve quantification of upsides, there is need for mapping the spatial distribution of remaining resources and developing simpler but reliable analytical techniques. In this study, hydraulic fractures were assumed to be planar in a matrix with low porosity and ultra-low permeability. Consideration of natural fractures and their interaction with stimulation fluids led to addition of distributed fracture networks adjacent to the planar hydraulic fractures to define the composite fracture corridors. A sector model with the aforementioned architecture was used in reservoir simulation to investigate induced temporal and spatial drainage. These findings were used to explain the efficacy of widely used refracturing techniques and how post-refracturing reservoir response can be analyzed. Results from reservoir simulation showed remaining reserves were in the matrix between earlier placed hydraulic fractures aligned along initial perforation clusters, and beyond tips of hydraulic fractures. Upside from refracs could come from creation of new fractures in the matrix between earlier placed fractures and extension of tips of early fractures into virgin matrix. Assessment of these scenarios found the former to be optimal although depletion and existing perforations would limit the stimulation efficiency of new perforations. The second scenario would require large volumes of fracturing fluid to re-initiate fracture propagation. Yet this could trigger interference with offsets or affect drilling and stimulation of planned wells in adjacent acreage. For treatment efficiency, re-casing horizontal wells with competent liners and use of coiled tubing with straddle packers appears a better solution for bypassing old perforations. For the near wellbore and far field, re-stimulating new perforations at low injection rates could allow extension of fractures in virgin matrix surrounded by depleted strata. Real-time surveillance would be essential for mapping flow paths of refracturing fluid. For assessment of refracturing, actual and simulated flow exhibited persistent linear flow (PLF) that could be matched by Arps hyperbolic equation with a b value of 2. Incorporation of a novel fracture geometry factor (FGF) yielded an Arps-based equation that was tested on North American shale refracturing cases that often use post-treatment peak rate and wellhead pressure as measures of success. This study identified factors hindering the success of refracturing and proposed a modified Arps hyperbolic equation to analyze refracturing production data.
{"title":"Impediments to Refracturing Success in Shale Reservoirs","authors":"Clay Kurison","doi":"10.2118/204799-ms","DOIUrl":"https://doi.org/10.2118/204799-ms","url":null,"abstract":"\u0000 Stimulations in early horizontal wells in most shale plays are characterized by few and widely spaced perforation clusters, and low amounts of injected fracturing fluid and proppant. Low recovery from these wells has motivated refracturing although outcomes have been interpreted to range from successful to minimal impact based on operator specific evaluations. To tailor available technologies and improve quantification of upsides, there is need for mapping the spatial distribution of remaining resources and developing simpler but reliable analytical techniques. In this study, hydraulic fractures were assumed to be planar in a matrix with low porosity and ultra-low permeability. Consideration of natural fractures and their interaction with stimulation fluids led to addition of distributed fracture networks adjacent to the planar hydraulic fractures to define the composite fracture corridors. A sector model with the aforementioned architecture was used in reservoir simulation to investigate induced temporal and spatial drainage. These findings were used to explain the efficacy of widely used refracturing techniques and how post-refracturing reservoir response can be analyzed. Results from reservoir simulation showed remaining reserves were in the matrix between earlier placed hydraulic fractures aligned along initial perforation clusters, and beyond tips of hydraulic fractures. Upside from refracs could come from creation of new fractures in the matrix between earlier placed fractures and extension of tips of early fractures into virgin matrix. Assessment of these scenarios found the former to be optimal although depletion and existing perforations would limit the stimulation efficiency of new perforations. The second scenario would require large volumes of fracturing fluid to re-initiate fracture propagation. Yet this could trigger interference with offsets or affect drilling and stimulation of planned wells in adjacent acreage. For treatment efficiency, re-casing horizontal wells with competent liners and use of coiled tubing with straddle packers appears a better solution for bypassing old perforations. For the near wellbore and far field, re-stimulating new perforations at low injection rates could allow extension of fractures in virgin matrix surrounded by depleted strata. Real-time surveillance would be essential for mapping flow paths of refracturing fluid. For assessment of refracturing, actual and simulated flow exhibited persistent linear flow (PLF) that could be matched by Arps hyperbolic equation with a b value of 2. Incorporation of a novel fracture geometry factor (FGF) yielded an Arps-based equation that was tested on North American shale refracturing cases that often use post-treatment peak rate and wellhead pressure as measures of success. This study identified factors hindering the success of refracturing and proposed a modified Arps hyperbolic equation to analyze refracturing production data.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"37 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86831916","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. Alsheikh, C. Gooneratne, A. Magana-Mora, Mohamad Ibrahim, Mike Affleck, W. Contreras, G. Zhan, M. A. Jamea, Isa Al Umairin, Ahmed Zaghary, M. Ayachi, Ahmed Galal Abdel-Kader, Shehab Ahmed, G. Makowski, Hitesh Kapoor
This study focuses on the design and infrastructure development of Internet-of-Things (IoT) edge platforms on drilling rigs and the testing of pilot IoT-Edge Computer Vision Systems (ECVS) for the optimization of drilling processes. The pilot technology presented in this study, Well Control Space Out System (WC-SOS), reduces the risks associated with hydrocarbon release during drilling by significantly increasing the success and time response for shut-in a well. Current shut-in methods that require manual steps are prone to errors and may take minutes to perform, which is enough time for an irreversible escalation in the well control incident. Consequently, the WC-SOS enables the drilling rig crew to shut-in a well in seconds. The IoT-ECVS deployed for the WC-SOS can be seamlessly expanded to analyze drillstring dynamics and drilling fluid cuttings/solids/flow analysis at the shale shakers in real-time. When IoT-ECVSs communicate with each other, their value is multiplied, which makes interoperability essential for maximizing benefits in drilling operations.
{"title":"Internet of Things IoT Edge Computer Vision Systems on Drilling Rigs","authors":"M. Alsheikh, C. Gooneratne, A. Magana-Mora, Mohamad Ibrahim, Mike Affleck, W. Contreras, G. Zhan, M. A. Jamea, Isa Al Umairin, Ahmed Zaghary, M. Ayachi, Ahmed Galal Abdel-Kader, Shehab Ahmed, G. Makowski, Hitesh Kapoor","doi":"10.2118/204757-ms","DOIUrl":"https://doi.org/10.2118/204757-ms","url":null,"abstract":"\u0000 This study focuses on the design and infrastructure development of Internet-of-Things (IoT) edge platforms on drilling rigs and the testing of pilot IoT-Edge Computer Vision Systems (ECVS) for the optimization of drilling processes. The pilot technology presented in this study, Well Control Space Out System (WC-SOS), reduces the risks associated with hydrocarbon release during drilling by significantly increasing the success and time response for shut-in a well. Current shut-in methods that require manual steps are prone to errors and may take minutes to perform, which is enough time for an irreversible escalation in the well control incident. Consequently, the WC-SOS enables the drilling rig crew to shut-in a well in seconds. The IoT-ECVS deployed for the WC-SOS can be seamlessly expanded to analyze drillstring dynamics and drilling fluid cuttings/solids/flow analysis at the shale shakers in real-time. When IoT-ECVSs communicate with each other, their value is multiplied, which makes interoperability essential for maximizing benefits in drilling operations.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"39 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84375251","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}
Stratigraphic correlation is crucial for reservoir characterization; therefore, it requires more advanced methods and techniques to reduce the stratigraphic correlation uncertainty, especially when variation in lateral facies is high. The studied formations from bottom to top consist of fluvial to marginal marine X Formation, shallow marine Y Formation, and fluvial distributary channels to estuarine Z Formation. Spectral gamma-ray logs give additional consistent information on lithological composition that can support identification of boundary between formations within the stratigraphic framework. Wells with a full section of Y Formation, core, palynology, and spectral gamma-ray were selected as key wells. The top and base of the Y Formation were picked using conventional logs refined by a thorium/potassium (Th/K) ratio log and cross plot with core and palynology data as validations. The internal Y Formation markers were also picked with the aid of the Th/K cross plots. The top picking criteria from the key wells was implemented to the rest of the wells across the field with consistency. The uniform low Th/K ratio log (<3.5) across the Y Formation indicates illite as the dominant clay type, confirmed by X-ray diffraction (XRD) data with an average of more than 80%. The character is consistent with the interpreted depositional environment. This character makes the Y Formation stand out from the overlying Z and the underlying X formations. The change from X to Y Formation is defined by the decrease of the Th/K ratio log, from high kaolinite content to illite dominated environment. Inversely, the top of the Y Formation (base of Z) is indicated by the increase of the Th/K ratio log moving from shallow marine Y Formation to the fluvial-influenced Z Formation. The Th/K cross plot indicates different clusters amongst the studied formations and the internal Y zonation. The X Formation is located in the high Th and low K area where kaolinite is predominant, related to fluvial environment. The case is similar for the Z Formation but with more influence of mixed-clay type. The Y Formation shows clear clustering along the mixed-clay and illite window. Internal Y zonation displays, from bottom to top, an increasing K value within the clusters. This method provides a semi-quantitative interpretation to define the studied formations boundaries and the Y Formation internal zonation. This study has increased the consistency of the studied formations’ stratigraphic and structural framework. This consistency has, in turn, fine-tuned the structural framework and aided field development through better geosteering and lateral well placements. These results are a valuable starting point to refine and extend the work to other areas.
{"title":"Enhancing Stratigraphic Framework Consistency Using Spectral Gamma-Ray Data","authors":"R. Nugraha, Oliver Esteva Tumbarinu","doi":"10.2118/204836-ms","DOIUrl":"https://doi.org/10.2118/204836-ms","url":null,"abstract":"\u0000 Stratigraphic correlation is crucial for reservoir characterization; therefore, it requires more advanced methods and techniques to reduce the stratigraphic correlation uncertainty, especially when variation in lateral facies is high. The studied formations from bottom to top consist of fluvial to marginal marine X Formation, shallow marine Y Formation, and fluvial distributary channels to estuarine Z Formation. Spectral gamma-ray logs give additional consistent information on lithological composition that can support identification of boundary between formations within the stratigraphic framework.\u0000 Wells with a full section of Y Formation, core, palynology, and spectral gamma-ray were selected as key wells. The top and base of the Y Formation were picked using conventional logs refined by a thorium/potassium (Th/K) ratio log and cross plot with core and palynology data as validations. The internal Y Formation markers were also picked with the aid of the Th/K cross plots. The top picking criteria from the key wells was implemented to the rest of the wells across the field with consistency.\u0000 The uniform low Th/K ratio log (<3.5) across the Y Formation indicates illite as the dominant clay type, confirmed by X-ray diffraction (XRD) data with an average of more than 80%. The character is consistent with the interpreted depositional environment. This character makes the Y Formation stand out from the overlying Z and the underlying X formations. The change from X to Y Formation is defined by the decrease of the Th/K ratio log, from high kaolinite content to illite dominated environment. Inversely, the top of the Y Formation (base of Z) is indicated by the increase of the Th/K ratio log moving from shallow marine Y Formation to the fluvial-influenced Z Formation. The Th/K cross plot indicates different clusters amongst the studied formations and the internal Y zonation. The X Formation is located in the high Th and low K area where kaolinite is predominant, related to fluvial environment. The case is similar for the Z Formation but with more influence of mixed-clay type. The Y Formation shows clear clustering along the mixed-clay and illite window. Internal Y zonation displays, from bottom to top, an increasing K value within the clusters. This method provides a semi-quantitative interpretation to define the studied formations boundaries and the Y Formation internal zonation.\u0000 This study has increased the consistency of the studied formations’ stratigraphic and structural framework. This consistency has, in turn, fine-tuned the structural framework and aided field development through better geosteering and lateral well placements. These results are a valuable starting point to refine and extend the work to other areas.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"73 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90086107","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}
Several studies have shown that rock-fluid interactions in tight rocks are influenced by the natural wettability behavior of the various pore systems. Studying the water/oil displacement on a smaller scale using core plug imbibition and monitoring with NMR is very insightful in evaluating wettability and distinguishing pore modes and rock types based on their fluid affinity. Extending learnings from plug-scale imbibition process to reservoir production behavior requires understanding of the underlying compositional and/or textural parameters controlling the wettability. This paper presents a systematic study of spontaneous imbibition of oil and water in core plugs procured from several tight and organic-rich reservoirs with varying mineral composition and organic content. The experiment comprised three identical core plugs from the same depth undergoing multiple fluid imbibition cycles with one plug starting in produced brine, the second one in produced crude and the last one in decane. Sample weights were continuously monitored and when stable, a sample which was in brine was moved to crude and the one in crude was moved to brine. This process was repeated for four cycles so that samples that started in brine finally ended up in crude and those that started in crude ended up in brine. The saturation changes and rock-fluid interaction in different fluid types were monitored using a 12 MHz NMR spectrometer. The 12 MHz NMR allowed very accurate partitioning of the oil-filled and water-filled porosity in these tight rocks, which was essential for the wettability analysis. The rate and extent of saturation changes varied significantly from sample to sample. The comparison between the companion plugs imbibing either higher amounts of oil or water revealed the fluid affinity of each sample. We computed the ratio of the net incremental fluid fraction to the total porosity to represent the dominant pore wetting system for rock samples at a given depth. We measured organic content and mineralogy of the samples and analyzed the matrix effect on wettability. We analyzed the post-imbibition NMR relaxation times (T1,T2) of individual fluid types and integrated with matrix properties to evaluate oil and water mobilities. We found predicted fluid mobilities to be consistent with the observed production from wells drilled in the different reservoirs and rock types. We observed most samples attain 100% fluid saturation within two to four cycles and almost all the samples at a given depth took up very similar water volumes irrespective of whether the companion plugs started in brine or crude. The process highlighted that water-wet pores governed the final water saturation, which was strongly correlated with total clay. The amount of organic content and carbonate minerals influenced the oil uptake and its relative mobility. For samples that started in decane, decane was imbibed faster and caused samples to attain higher oil saturation than samples that started
{"title":"Evaluate Wettability and Production Potential of Tight Reservoirs Through Spontaneous Imbibition Using Time-Lapse NMR and Other Measurements","authors":"M. Ali, Safdar Ali, A. Mathur, William Von Gonten","doi":"10.2118/204709-ms","DOIUrl":"https://doi.org/10.2118/204709-ms","url":null,"abstract":"\u0000 Several studies have shown that rock-fluid interactions in tight rocks are influenced by the natural wettability behavior of the various pore systems. Studying the water/oil displacement on a smaller scale using core plug imbibition and monitoring with NMR is very insightful in evaluating wettability and distinguishing pore modes and rock types based on their fluid affinity. Extending learnings from plug-scale imbibition process to reservoir production behavior requires understanding of the underlying compositional and/or textural parameters controlling the wettability.\u0000 This paper presents a systematic study of spontaneous imbibition of oil and water in core plugs procured from several tight and organic-rich reservoirs with varying mineral composition and organic content. The experiment comprised three identical core plugs from the same depth undergoing multiple fluid imbibition cycles with one plug starting in produced brine, the second one in produced crude and the last one in decane. Sample weights were continuously monitored and when stable, a sample which was in brine was moved to crude and the one in crude was moved to brine. This process was repeated for four cycles so that samples that started in brine finally ended up in crude and those that started in crude ended up in brine. The saturation changes and rock-fluid interaction in different fluid types were monitored using a 12 MHz NMR spectrometer. The 12 MHz NMR allowed very accurate partitioning of the oil-filled and water-filled porosity in these tight rocks, which was essential for the wettability analysis.\u0000 The rate and extent of saturation changes varied significantly from sample to sample. The comparison between the companion plugs imbibing either higher amounts of oil or water revealed the fluid affinity of each sample. We computed the ratio of the net incremental fluid fraction to the total porosity to represent the dominant pore wetting system for rock samples at a given depth. We measured organic content and mineralogy of the samples and analyzed the matrix effect on wettability. We analyzed the post-imbibition NMR relaxation times (T1,T2) of individual fluid types and integrated with matrix properties to evaluate oil and water mobilities. We found predicted fluid mobilities to be consistent with the observed production from wells drilled in the different reservoirs and rock types.\u0000 We observed most samples attain 100% fluid saturation within two to four cycles and almost all the samples at a given depth took up very similar water volumes irrespective of whether the companion plugs started in brine or crude. The process highlighted that water-wet pores governed the final water saturation, which was strongly correlated with total clay. The amount of organic content and carbonate minerals influenced the oil uptake and its relative mobility. For samples that started in decane, decane was imbibed faster and caused samples to attain higher oil saturation than samples that started","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"10 1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84020190","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}
The narrow density window in deep-water environment brought great challenges to well drilling and completion by causing well control issues. Managed Pressure Cementing (MPC) is a new technology developed from Manage Pressure Drilling (MPD), which can precisely control the annular fluid pressure profile. Accurate calculation of wellbore temperature and pressure is the key to MPC. This paper focus on coupled models of temperature and pressure for MPC in deep-water region. The well cementing process can be divided into two stages: fluid displacement stage and cement setting stage, which displays different characteristics. During the cementing displacement stage, the cement is in a flowable slurry state and is circulated into the annulus. During this process, the rheology of fluids if effected by temperature in wellbore. On basis of the fluid rheology model, a coupled model of temperature and pressure in wellbore is established considering the transient flow characteristics during cementing displacement stage. During cement setting stage, the cement slurry stops flowing and the significant cement hydration reaction starts. A large amount of hydration heat and obvious pressure reduction can be observed. On basis of the cement hydration kinetics model, a coupled model of temperature and pressure in wellbore during cementing setting stage is established. Based on the models established in this paper, a series of numerical simulations are conducted using a deep-water well. Simulation results show that neglecting the complicated interactions between temperature and pressure can cause a big error. During the cementing displacement stage, higher temperature in the deep part of wellbore reduces the fluid viscosity, which leads to a smaller friction. On the contrary, larger friction is observed near seabed as a result of the low temperature in deep-water environment. The pressure in wellbore changes frequently due to the coexistence of multiple fluids in wellbore. Therefore, a frequent control of annular fluid pressure is required using the MPC technology. During the cement setting stage, an obvious temperature increase is observed as a result of cement hydration heat. The pressure decreases with the depending of cement hydration. An addition back pressure at wellhead has to be added using the MPC technology. The transient temperature and pressure have impact on the rate of cement hydration in turn. Cement in the deep part of wellbore have a faster rate of cement hydration. The low temperature at mudline slows the cement hydration process. Considering the complicated interactions between temperature, pressure, cement hydration and fluid rheology, coupled models between temperature and pressure based on hydration kinetics during well cementing in deep-water region is established in the manuscript. The new model established in this paper plays an important role in the MPC technology.
{"title":"A Coupled Model of Temperature and Pressure for Managed Pressure Cementing in Deep-Water Region","authors":"Xuerui Wang, Feng Hao, Baojiang Sun, Zhiyuan Wang","doi":"10.2118/204621-ms","DOIUrl":"https://doi.org/10.2118/204621-ms","url":null,"abstract":"\u0000 The narrow density window in deep-water environment brought great challenges to well drilling and completion by causing well control issues. Managed Pressure Cementing (MPC) is a new technology developed from Manage Pressure Drilling (MPD), which can precisely control the annular fluid pressure profile. Accurate calculation of wellbore temperature and pressure is the key to MPC. This paper focus on coupled models of temperature and pressure for MPC in deep-water region.\u0000 The well cementing process can be divided into two stages: fluid displacement stage and cement setting stage, which displays different characteristics. During the cementing displacement stage, the cement is in a flowable slurry state and is circulated into the annulus. During this process, the rheology of fluids if effected by temperature in wellbore. On basis of the fluid rheology model, a coupled model of temperature and pressure in wellbore is established considering the transient flow characteristics during cementing displacement stage. During cement setting stage, the cement slurry stops flowing and the significant cement hydration reaction starts. A large amount of hydration heat and obvious pressure reduction can be observed. On basis of the cement hydration kinetics model, a coupled model of temperature and pressure in wellbore during cementing setting stage is established.\u0000 Based on the models established in this paper, a series of numerical simulations are conducted using a deep-water well. Simulation results show that neglecting the complicated interactions between temperature and pressure can cause a big error. During the cementing displacement stage, higher temperature in the deep part of wellbore reduces the fluid viscosity, which leads to a smaller friction. On the contrary, larger friction is observed near seabed as a result of the low temperature in deep-water environment. The pressure in wellbore changes frequently due to the coexistence of multiple fluids in wellbore. Therefore, a frequent control of annular fluid pressure is required using the MPC technology. During the cement setting stage, an obvious temperature increase is observed as a result of cement hydration heat. The pressure decreases with the depending of cement hydration. An addition back pressure at wellhead has to be added using the MPC technology. The transient temperature and pressure have impact on the rate of cement hydration in turn. Cement in the deep part of wellbore have a faster rate of cement hydration. The low temperature at mudline slows the cement hydration process.\u0000 Considering the complicated interactions between temperature, pressure, cement hydration and fluid rheology, coupled models between temperature and pressure based on hydration kinetics during well cementing in deep-water region is established in the manuscript. The new model established in this paper plays an important role in the MPC technology.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88320294","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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