In 2014, an R&D project was intitiated to develop an innovative technological solution to improve the performance and reliability of Deepwater Gulf of Mexico assets. The objective was to increase the life expectancy of Miocene and Lower Tertiary water injection (WI) wells, several of which had suffered a severe loss of injectivity within only a few years of completion. Before scoping out the project, an internal study was conducted to compile and analyse the available data. The root problem was identified as an accumulation of formation solids inside the lower completion; principally fine matrix sand that had been pulled in from the reservoir. These formation solids are normally stationary during steady injection, but can be mobilized during shut-ins (maintenance, pump problems, environmental conditions, etc.) due to powerful transient flow effects such as back-flow, cross-flow and even water-hammer. Eventually, enough solid fill can accumulate inside the lower completion as to diminish the injection rates. At this point the operator must consider some very expensive options such as to sidetrack or re-drill a new injector well. The obvious solution to this problem was to find a way to prevent the fine material from getting inside the completion. The challenge was to do so while sustaining high injection rates, with no loss of injection pressure or requirement for additional horsepower. Therefore, the goal of the project was to find a practical, efficient method of stopping the formation material from entering the lower completion during a shut-in cycle. To achieve this, a new flow control device (FCD) and completion system was developed with intrinsic non-return valves (NRV) that are designed to prevent any back-flow or cross-flow during the shut-ins. Also, depending on well conditions, the system will minimize the damaging effects of water-hammer: rapid, high-amplitude pressure cycles that can occur during a sudden stoppage of flow.
{"title":"Field Trial Results for New Sand Control Technology for Water Injectors","authors":"S. Fipke, J. E. Charles, Annabel Green","doi":"10.2118/192840-MS","DOIUrl":"https://doi.org/10.2118/192840-MS","url":null,"abstract":"\u0000 In 2014, an R&D project was intitiated to develop an innovative technological solution to improve the performance and reliability of Deepwater Gulf of Mexico assets. The objective was to increase the life expectancy of Miocene and Lower Tertiary water injection (WI) wells, several of which had suffered a severe loss of injectivity within only a few years of completion.\u0000 Before scoping out the project, an internal study was conducted to compile and analyse the available data. The root problem was identified as an accumulation of formation solids inside the lower completion; principally fine matrix sand that had been pulled in from the reservoir. These formation solids are normally stationary during steady injection, but can be mobilized during shut-ins (maintenance, pump problems, environmental conditions, etc.) due to powerful transient flow effects such as back-flow, cross-flow and even water-hammer. Eventually, enough solid fill can accumulate inside the lower completion as to diminish the injection rates. At this point the operator must consider some very expensive options such as to sidetrack or re-drill a new injector well.\u0000 The obvious solution to this problem was to find a way to prevent the fine material from getting inside the completion. The challenge was to do so while sustaining high injection rates, with no loss of injection pressure or requirement for additional horsepower. Therefore, the goal of the project was to find a practical, efficient method of stopping the formation material from entering the lower completion during a shut-in cycle. To achieve this, a new flow control device (FCD) and completion system was developed with intrinsic non-return valves (NRV) that are designed to prevent any back-flow or cross-flow during the shut-ins. Also, depending on well conditions, the system will minimize the damaging effects of water-hammer: rapid, high-amplitude pressure cycles that can occur during a sudden stoppage of flow.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"94 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72802172","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}
One of the most secure storage sites for CO2 injection is in depleted gas reservoirs. To ensure that the CO2 is trapped securely and will not escape to the surface, storage in such formations must be study carefully prior to injection in such formations. After the injection, the injected CO2 will undergo several trapping mechanisms; namely: hydrodynamic, solubility and mineral trapping. The extend of geochemical reactions involved depend on the composition of the injected fluid introduced in the aquifer, the composition of the initial minerals assemblage and the aquifer brine. In this paper, the importance of biological/microbial mechanisms towards the impact on the storage capacity was studied using reactive transport modelling. The results obtained shows that the presence of microbial compound such as organic matter contributes to the enhancement of mineral precipitation, resulting in secure long-term storage.
{"title":"A Study on the Effect of Biological Processes on Trapping Mechanisms and Storage Capacity for High Temperature Depleted Gas Field","authors":"Sharidah Mohd Amin","doi":"10.2118/193262-ms","DOIUrl":"https://doi.org/10.2118/193262-ms","url":null,"abstract":"\u0000 One of the most secure storage sites for CO2 injection is in depleted gas reservoirs. To ensure that the CO2 is trapped securely and will not escape to the surface, storage in such formations must be study carefully prior to injection in such formations. After the injection, the injected CO2 will undergo several trapping mechanisms; namely: hydrodynamic, solubility and mineral trapping. The extend of geochemical reactions involved depend on the composition of the injected fluid introduced in the aquifer, the composition of the initial minerals assemblage and the aquifer brine. In this paper, the importance of biological/microbial mechanisms towards the impact on the storage capacity was studied using reactive transport modelling. The results obtained shows that the presence of microbial compound such as organic matter contributes to the enhancement of mineral precipitation, resulting in secure long-term storage.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"6 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86697158","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}
Despite emerging technology in the areas of unconventional forecasting, recovery factors are merely a fraction of its conventional counterparts. Unconventional reservoirs are characterized by their ultra-low permeability. It is to be noted that traditional decline curve analysis (DCA) is not best suited to forecast unconventional reservoirs. This is due, in part to a variety of reasons the most important being lengthy transition zones from transient flow to boundary-dominated flow which is highlighted in this paper via the usage of diagnostic plots. The objective of this paper is to compare the production performance of volatile oil reservoirs, generated from a commercial compositional simulator, by using simple decline models used in the industry. Fluids with different initial gas to oil ratio (GOR), due to different fluid composition, was simulated for a period of 30 years. Oil rate was forecasted by assuming different lengths of available production history. We present the application of diagnostic plots to identify different flow regime. The results from our study showed that the duration of linear flow period and the transition from linear to boundary dominated flow varies drastically based on the initial fluid composition. With respect to the decline curve analysis performed, a hybrid decline curve model was used to model different sections of the production profile. Since we are analyzing volatile oil reservoirs, the biggest challenge in performing traditional DCA is the effect of multi-phase flow behavior. So, use of hybrid decline model results in a better production forecasting compared to a single decline curve. With the advent of the shale boom, many oil and gas producers struggle to forecast unconventional reservoirs effectively. We believe that this paper serves to further elucidate the theory and application behind the concept of unconventional forecasting.
{"title":"Forecasting Unconventional Volatile Oil Reservoirs Using Compositional Reservoir Simulation and Hybrid Decline Curve Models","authors":"John Xavier, A. Khanal, John W. Lee","doi":"10.2118/193024-MS","DOIUrl":"https://doi.org/10.2118/193024-MS","url":null,"abstract":"\u0000 Despite emerging technology in the areas of unconventional forecasting, recovery factors are merely a fraction of its conventional counterparts. Unconventional reservoirs are characterized by their ultra-low permeability. It is to be noted that traditional decline curve analysis (DCA) is not best suited to forecast unconventional reservoirs. This is due, in part to a variety of reasons the most important being lengthy transition zones from transient flow to boundary-dominated flow which is highlighted in this paper via the usage of diagnostic plots.\u0000 The objective of this paper is to compare the production performance of volatile oil reservoirs, generated from a commercial compositional simulator, by using simple decline models used in the industry. Fluids with different initial gas to oil ratio (GOR), due to different fluid composition, was simulated for a period of 30 years. Oil rate was forecasted by assuming different lengths of available production history. We present the application of diagnostic plots to identify different flow regime. The results from our study showed that the duration of linear flow period and the transition from linear to boundary dominated flow varies drastically based on the initial fluid composition. With respect to the decline curve analysis performed, a hybrid decline curve model was used to model different sections of the production profile. Since we are analyzing volatile oil reservoirs, the biggest challenge in performing traditional DCA is the effect of multi-phase flow behavior. So, use of hybrid decline model results in a better production forecasting compared to a single decline curve.\u0000 With the advent of the shale boom, many oil and gas producers struggle to forecast unconventional reservoirs effectively. We believe that this paper serves to further elucidate the theory and application behind the concept of unconventional forecasting.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"4 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87776420","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 Hoban and Baqaa Members are located between the glacial to early post-glacial Sarah Formation (Ordovician) and the Qalibah Formation (Silurian). They have been distinguished as separate stratigraphic units in few outcrops of northern Saudi Arabia based on palynological analyses, graptolites, shell fragments, and their predominantly shallow marine depositional environments. There has been long debate over whether the Hoban and Baqaa Members should be attributed to other upper Sarah Formations or the lower Qalibah Formation. This debate fundamentally concerns the location of the Silurian-Ordovician sequence boundary, which developed globally, in central Arabia. Detailed sedimentological and stratigraphical data of the latest Ordovician to earliest Silurian interval were available from the subsurface. Therefore, the main aim of this project is to provide a detailed sedimentological model for the Hoban and Baqaa Members, both in outcrop-reservoir analogues and in the subsurface. This includes a sequence stratigraphic correlation between outcrops and wells, and general depositional environment maps. The resulting model provides an improved understanding of depositional changes as well as relative and eustatic sea-level changes across the Ordovician-Silurian boundary in Arabia. The study is based on 16 outcrop sections in three different regions of northwestern and northeastern Saudi Arabia (Tabuk, Tayma, and east of Hail) and 26 shallow and deep well cores. Outcrops and the well are enclosed in a total area of about 340 by 100 km. The Hoban Member has a thickness between 0-40 m (typically 23 m) and consists of two units, which represent the final stages of glaciation. Sediment deformation, internal brecciation, and angular Sarah clasts are widespread. The Baqaa Member, which has a thickness of 15-40 m (typically 31 m), unconformably overlies the Hoban Member and consists of two to three shallowing-upward cycles (high-frequency sequences). Each cycle consists of a basal transgressive part (proximal offshore) and a regressive part (lower to upper shoreface or foreshore, respectively). The top of each cycle is formed by closely stacked submarine hardgrounds (transgressive surface at the base) with ample bioturbation and shell horizons. Hot shales of the Qusaiba Member (Qalibah Formation) conformably cover the hardground of the upper Baqaa shallowing-upward cycle. Palynological data indicates that both the Hoban and Baqaa are late Ordovician in age, while the Qusaiba shales are lower Silurian. The Hoban Member represents stages of final glacial advance and local sediment mass transport in a peri-glacial environment. The Baqaa Member represents post-glacial flooding with prograding beach and shoreface systems. During peak transgression, intermittent open marine conditions existed. Long-term fully marine conditions were only established in the lowermost Qusaiba Member. From a process-oriented perspective, the Hoban Member constitutes the uppermost m
{"title":"Late Hirnantian Clastic Depositional Systems Using Sequence Stratigraphy and Chronostratigraphy","authors":"S. Al-Shahrani, R. Zühlke","doi":"10.2118/193044-MS","DOIUrl":"https://doi.org/10.2118/193044-MS","url":null,"abstract":"\u0000 The Hoban and Baqaa Members are located between the glacial to early post-glacial Sarah Formation (Ordovician) and the Qalibah Formation (Silurian). They have been distinguished as separate stratigraphic units in few outcrops of northern Saudi Arabia based on palynological analyses, graptolites, shell fragments, and their predominantly shallow marine depositional environments. There has been long debate over whether the Hoban and Baqaa Members should be attributed to other upper Sarah Formations or the lower Qalibah Formation. This debate fundamentally concerns the location of the Silurian-Ordovician sequence boundary, which developed globally, in central Arabia. Detailed sedimentological and stratigraphical data of the latest Ordovician to earliest Silurian interval were available from the subsurface. Therefore, the main aim of this project is to provide a detailed sedimentological model for the Hoban and Baqaa Members, both in outcrop-reservoir analogues and in the subsurface. This includes a sequence stratigraphic correlation between outcrops and wells, and general depositional environment maps. The resulting model provides an improved understanding of depositional changes as well as relative and eustatic sea-level changes across the Ordovician-Silurian boundary in Arabia.\u0000 The study is based on 16 outcrop sections in three different regions of northwestern and northeastern Saudi Arabia (Tabuk, Tayma, and east of Hail) and 26 shallow and deep well cores. Outcrops and the well are enclosed in a total area of about 340 by 100 km. The Hoban Member has a thickness between 0-40 m (typically 23 m) and consists of two units, which represent the final stages of glaciation. Sediment deformation, internal brecciation, and angular Sarah clasts are widespread. The Baqaa Member, which has a thickness of 15-40 m (typically 31 m), unconformably overlies the Hoban Member and consists of two to three shallowing-upward cycles (high-frequency sequences). Each cycle consists of a basal transgressive part (proximal offshore) and a regressive part (lower to upper shoreface or foreshore, respectively). The top of each cycle is formed by closely stacked submarine hardgrounds (transgressive surface at the base) with ample bioturbation and shell horizons. Hot shales of the Qusaiba Member (Qalibah Formation) conformably cover the hardground of the upper Baqaa shallowing-upward cycle. Palynological data indicates that both the Hoban and Baqaa are late Ordovician in age, while the Qusaiba shales are lower Silurian.\u0000 The Hoban Member represents stages of final glacial advance and local sediment mass transport in a peri-glacial environment. The Baqaa Member represents post-glacial flooding with prograding beach and shoreface systems. During peak transgression, intermittent open marine conditions existed. Long-term fully marine conditions were only established in the lowermost Qusaiba Member. From a process-oriented perspective, the Hoban Member constitutes the uppermost m","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"28 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79897982","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}
Wafa Shizawi, R. Zadjali, M. Riyami, L. Bellmann, Haitham Yahya'Ei
A thermal steam project has been successfully implemented in a Petroleum Development Oman (PDO) field in the South of Oman. The steam flood developed the crest of the field and incremental oil recovery from formation A has been obtained. Based on this success expansion of the steam flood in the field is planned. The southern extension will encounter the same formation A as developed at the crest. The northern extension, however, will contain two new formations (B and C). For these two new formations limited field data on sand production is available, and a sand prediction evaluation for both cold & thermal production conditions is required. Additional to that, the field development strategy requires that the oil producers will be re-completed after steam breakthrough and a flexible placement of the pump above/below the perforations at different phases of the steam flood. Successful implementation of conformance control in wells with sand control has a significant impact on the oil recovery and thus economics of the project. This paper focuses on formation B. The assessment of the likelihood of sand production and the requirement of sand control was based on a combination of a) actual field data such as sand production, well performance & completion data; and b) a sand production model for the different production conditions (hot and cold) utilizing rock-mechanical data. The sand evaluation study demonstrated that there is a risk of catastrophic sand failure under both cold and hot operation conditions and thus a completion with thermally compliant sand control and conformance control is required for this formation. Core sieve analysis data were used to determine the Particle Size Distribution (PSD), which was used to select the sand control type and screen slot width. A standalone wire wrap screen has been selected for sand control in formation B. A completion that combines a standalone wire wrap screen, with the provision of conformance control by isolating perforation intervals, with placement of a 4.5" tubing pump below the (isolated) sand screen is challenging to design. Multiple completion types have been evaluated and a new type of technology for PDO of sand control with an isolation sleeve is proposed to meet the requirements of the field development plan. It is expected that this new design with flexible recompletion of the sand control system will have a large impact on the oil recovery.
{"title":"Innovation of Sand Management and Conformance Control Design in a Steam Flood in the South of the Sultanate of Oman","authors":"Wafa Shizawi, R. Zadjali, M. Riyami, L. Bellmann, Haitham Yahya'Ei","doi":"10.2118/192921-MS","DOIUrl":"https://doi.org/10.2118/192921-MS","url":null,"abstract":"\u0000 A thermal steam project has been successfully implemented in a Petroleum Development Oman (PDO) field in the South of Oman. The steam flood developed the crest of the field and incremental oil recovery from formation A has been obtained. Based on this success expansion of the steam flood in the field is planned. The southern extension will encounter the same formation A as developed at the crest. The northern extension, however, will contain two new formations (B and C).\u0000 For these two new formations limited field data on sand production is available, and a sand prediction evaluation for both cold & thermal production conditions is required. Additional to that, the field development strategy requires that the oil producers will be re-completed after steam breakthrough and a flexible placement of the pump above/below the perforations at different phases of the steam flood. Successful implementation of conformance control in wells with sand control has a significant impact on the oil recovery and thus economics of the project.\u0000 This paper focuses on formation B. The assessment of the likelihood of sand production and the requirement of sand control was based on a combination of a) actual field data such as sand production, well performance & completion data; and b) a sand production model for the different production conditions (hot and cold) utilizing rock-mechanical data. The sand evaluation study demonstrated that there is a risk of catastrophic sand failure under both cold and hot operation conditions and thus a completion with thermally compliant sand control and conformance control is required for this formation.\u0000 Core sieve analysis data were used to determine the Particle Size Distribution (PSD), which was used to select the sand control type and screen slot width. A standalone wire wrap screen has been selected for sand control in formation B.\u0000 A completion that combines a standalone wire wrap screen, with the provision of conformance control by isolating perforation intervals, with placement of a 4.5\" tubing pump below the (isolated) sand screen is challenging to design. Multiple completion types have been evaluated and a new type of technology for PDO of sand control with an isolation sleeve is proposed to meet the requirements of the field development plan. It is expected that this new design with flexible recompletion of the sand control system will have a large impact on the oil recovery.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"52 3","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91496557","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}
Hanan F. Al-Saeed, S. Duncan, Jassim Al-Kanderi, D. Negut, Cathy Martin, W. Nowry
The Kuwait Oil Company's (KOC) Sabriyah field, located in North Kuwait, produces oil and condensate from the Jurassic Najmah formation in a structurally complex setting. In 2017, Kuwait Oil Company reprocessed their 50 square km, three-component 3D seismic survey originally shot in 2010, to include shear wave splitting analysis and diffraction imaging. This project was undertaken not only to seismically image the structures better but to also better define faults and fractures and their positioning in the Najmah.Also in order to determine maxium and minimum stress directions and correlate with the known geological areas of maximum stress from previous core work. This work will help the Engineers to determine best orientation directions for drilling programs to add value. One of the purposes of this project was to help answer the disconnect between the actual well logs,geology and the conventional seismic interpretation when tied to the well on crestal part of the anticline. The other main purpose was to see if we could help engineers place vertical and horizontal wells in optimal positions through the use of P-P,P-S, and diffraction imaging geophysical methods we were able to come up with a comprehensive look at the fractures and faulting of the Najmah as well as match with current drilling results.
{"title":"Integration of P-P,P-S, and Diffraction Imaging Brings Geophysics, Geology and Engineering Together-A Case Study of the KOC Sabriyah Field","authors":"Hanan F. Al-Saeed, S. Duncan, Jassim Al-Kanderi, D. Negut, Cathy Martin, W. Nowry","doi":"10.2118/193013-MS","DOIUrl":"https://doi.org/10.2118/193013-MS","url":null,"abstract":"\u0000 The Kuwait Oil Company's (KOC) Sabriyah field, located in North Kuwait, produces oil and condensate from the Jurassic Najmah formation in a structurally complex setting. In 2017, Kuwait Oil Company reprocessed their 50 square km, three-component 3D seismic survey originally shot in 2010, to include shear wave splitting analysis and diffraction imaging. This project was undertaken not only to seismically image the structures better but to also better define faults and fractures and their positioning in the Najmah.Also in order to determine maxium and minimum stress directions and correlate with the known geological areas of maximum stress from previous core work. This work will help the Engineers to determine best orientation directions for drilling programs to add value.\u0000 One of the purposes of this project was to help answer the disconnect between the actual well logs,geology and the conventional seismic interpretation when tied to the well on crestal part of the anticline. The other main purpose was to see if we could help engineers place vertical and horizontal wells in optimal positions through the use of P-P,P-S, and diffraction imaging geophysical methods we were able to come up with a comprehensive look at the fractures and faulting of the Najmah as well as match with current drilling results.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"53 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87030564","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}
BP is a joint venture partner in GUPCO, which operates in the Gulf of Suez, Egypt. The asset is over 50 years old and has a large operational foot print. This includes 3 onshore process facilities handling over 450,000 barrels of fluid per day from over 100 offshore structures and 200 pipelines. The field is supported by gas lift and water injection from two onshore facilities. The asset presents a challenge from an integrity perspective, namely corrosion and production chemistry threats. These are managed through an inspection program and anomaly management process. This case study presents how our asset integrity is managed and forward plan for improvement. The important relationship with the risk management process is highlighted.
{"title":"A Case Study from a 53 Year Old Asset - The Importance of Integrity and Risk Management for a Mature Asset","authors":"A. Jadoon","doi":"10.2118/193271-MS","DOIUrl":"https://doi.org/10.2118/193271-MS","url":null,"abstract":"\u0000 BP is a joint venture partner in GUPCO, which operates in the Gulf of Suez, Egypt. The asset is over 50 years old and has a large operational foot print. This includes 3 onshore process facilities handling over 450,000 barrels of fluid per day from over 100 offshore structures and 200 pipelines. The field is supported by gas lift and water injection from two onshore facilities.\u0000 The asset presents a challenge from an integrity perspective, namely corrosion and production chemistry threats. These are managed through an inspection program and anomaly management process.\u0000 This case study presents how our asset integrity is managed and forward plan for improvement. The important relationship with the risk management process is highlighted.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"31 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77368793","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}
T. J. Ahmad, Weichang Li, Robert W. Adams, M. Deffenbaugh, M. Arsalan
Reliable flow measurement at the surface is critical for production optimization and reservoir management. Commercial water-cut and three phase flow meters have limitations in accuracy over the range of multiphase flow conditions. They require frequent calibration, and have high capital and operational cost. This paper describes an ultrasonic tomography based measurement of water hold-up, and presents preliminary flow loop and field test results. This ultrasonic system has the potential to overcome certain limitations of existing metering solutions.
{"title":"Ultrasound Tomography Based Two-Phase Composition Measurement","authors":"T. J. Ahmad, Weichang Li, Robert W. Adams, M. Deffenbaugh, M. Arsalan","doi":"10.2118/193317-MS","DOIUrl":"https://doi.org/10.2118/193317-MS","url":null,"abstract":"\u0000 Reliable flow measurement at the surface is critical for production optimization and reservoir management. Commercial water-cut and three phase flow meters have limitations in accuracy over the range of multiphase flow conditions. They require frequent calibration, and have high capital and operational cost. This paper describes an ultrasonic tomography based measurement of water hold-up, and presents preliminary flow loop and field test results. This ultrasonic system has the potential to overcome certain limitations of existing metering solutions.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"30 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81813816","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}
Abdul Naser Abdulla Al Mulla Al Shehhi, Alauddin Mohamed Abou Draz, T. N. Mahboob, P. Agnihotri
Since 2014, ADNOC Onshore has utilized the potential of hoists and commissioned its operational significance, which allowed saving in rig time (4 – 6 rig years per year over 5 years business plan period) and generating a cost saving opportunity. During this period we have faced many challenges and complications mainly during fishing operations which result in unsuccessful retrieval of the completion. Other factors and challenges that are commonly faced which require hoist intervention include: Old wells melted or corroded fish (Tubing + Casing)Reservoir Thammama Zone B wells (High water cut)Pushing the corroded fishComplete plug & abandonPartial plug & abandon required for future side trackWait on conventional rig arrival for intervention Main challenge we faced during our business development phase is losing number of oil producing wells due to fishing complications, therefore the hoist rig is not capable to drill or sidetrack such wells. This will result in delaying requirements to restore production and meet the field quota objective since the wells should be scheduled to conventional Rig intervention. In order to optimize the hoists capability and performance to overcome this issue, we have to optimize based on priority and cost-effective selection criteria which will support to save the rig time & cost. Various advantages of hoists applications experienced in the last 2 years in ADCO include: Running scraperCorrosion and Cement Bond LogsFaster rig move.Work-over well repairs for single completion (well-kill, pulling old completion and running new completion)Well preparation for re-entry and sidetrack plug back to top of 7'’ linerESP work-over. Pulled old ESP pumpsFishing and milling operationsRun 7 "tie back liners.Plug and abandon wells partially or fully Abandonment (inactive string).Spotting and squeezing cement plugs and squeeze off old perforations, changing THS and X-mass tree.Cure Sustainable Annulus Pressure (SAP)Pressure test casingRun completion & special completion such as gas lift mandrels This paper presents methods of optimizing application of hoist in Abu Dhabi onshore fields by modifying enhanced well selection criteria based on the operation experiment and avoid production loss to sustain our field development plan. This implemented strategy benefit the optimization of number of workover wells which will increase in next five years scenarios, which in turn is expected to utilize rig cost savings. In addition, the new selection criteria will create "fit for purpose" solution to overcome these challenges of existing workover wells with less time and complication
{"title":"Commissioning Advanced Hoist Technologies to Mitigate Challenges Associated with Selective Workover Wells - A Revolutionary Approach","authors":"Abdul Naser Abdulla Al Mulla Al Shehhi, Alauddin Mohamed Abou Draz, T. N. Mahboob, P. Agnihotri","doi":"10.2118/193159-MS","DOIUrl":"https://doi.org/10.2118/193159-MS","url":null,"abstract":"\u0000 Since 2014, ADNOC Onshore has utilized the potential of hoists and commissioned its operational significance, which allowed saving in rig time (4 – 6 rig years per year over 5 years business plan period) and generating a cost saving opportunity.\u0000 During this period we have faced many challenges and complications mainly during fishing operations which result in unsuccessful retrieval of the completion. Other factors and challenges that are commonly faced which require hoist intervention include: Old wells melted or corroded fish (Tubing + Casing)Reservoir Thammama Zone B wells (High water cut)Pushing the corroded fishComplete plug & abandonPartial plug & abandon required for future side trackWait on conventional rig arrival for intervention\u0000 Main challenge we faced during our business development phase is losing number of oil producing wells due to fishing complications, therefore the hoist rig is not capable to drill or sidetrack such wells. This will result in delaying requirements to restore production and meet the field quota objective since the wells should be scheduled to conventional Rig intervention. In order to optimize the hoists capability and performance to overcome this issue, we have to optimize based on priority and cost-effective selection criteria which will support to save the rig time & cost.\u0000 Various advantages of hoists applications experienced in the last 2 years in ADCO include: Running scraperCorrosion and Cement Bond LogsFaster rig move.Work-over well repairs for single completion (well-kill, pulling old completion and running new completion)Well preparation for re-entry and sidetrack plug back to top of 7'’ linerESP work-over. Pulled old ESP pumpsFishing and milling operationsRun 7 \"tie back liners.Plug and abandon wells partially or fully Abandonment (inactive string).Spotting and squeezing cement plugs and squeeze off old perforations, changing THS and X-mass tree.Cure Sustainable Annulus Pressure (SAP)Pressure test casingRun completion & special completion such as gas lift mandrels\u0000 This paper presents methods of optimizing application of hoist in Abu Dhabi onshore fields by modifying enhanced well selection criteria based on the operation experiment and avoid production loss to sustain our field development plan. This implemented strategy benefit the optimization of number of workover wells which will increase in next five years scenarios, which in turn is expected to utilize rig cost savings. In addition, the new selection criteria will create \"fit for purpose\" solution to overcome these challenges of existing workover wells with less time and complication","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"6 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82500217","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}
During the hydraulic fracturing process, the created rough fracture surface and fracturing fluids with high viscosity greatly challenge proppants placement in the thin aperture of fractures. Thus, it is essential to detailly investigate the effect of surface roughness on the proppant distribution. In addition, the multiphase flow in the rough nanoscale microfractures in the variety of orientations have not been cleared. Taking all of these into consideration; rock grain geometries, packing mechanisms, the presence of clay content, and in-situ stress field will be affected and will affect the presence of the microcracks, and consequently control the permeability and porosity of the sedimentary rock. In the failed rock after fracturing work, a processed zone where the pre-existing natural fractures get activated, and induced microcracks including intergranular and intragranular grain boundaries are brought to connect to the main fracture. Hence, the rock grain and pore size distributions at fracture processed zone are altered. This, in turn, controls the fluid transport in the rocks. Our novel approach incorporates the image analysis software (ImageJ) by organizing desired image processing codes to study the critical features of the post-fracturing core sample, including main fracture roughness, mechanical rock properties, crack density, grain, and pore size distributions. Tennessee sandstone was undergone the hydraulic fracturing test and polished on a cross-section perpendicular to the main fracture. This cross-section was recorded by the high-resolution SEM images after ion-milling. Corresponding grain size and pore size distributions are studied at each representative location with respect to its distance to the main fracture to probe alterations of the fracturing process from the core sample original state. The results of grain size and pore size distributions are compared. The discussions of their alterations mechanisms and their effects on the rock porosity and permeability are analyzed. We find that the roughness presence of fractures strongly increases conduits open to fluid flow. In addition, our developed image processing code perfectly captured the rock grains with the promising precision. Further, we are able to observe the grain size deduction due to the incremental intragranular grain boundaries while intergranular grain boundaries are still majorities outside the fracture processed zone (FPZ). Grain size renders a lognormal distribution at each representative location and coincides with the permeability distribution of most reservoir rocks. Grain size averages also match the literature values with reasonable uncertainties (20%). The pore size distribution and its average value vary spatially. Results from this study kindle the insights of the heterogeneity of the fractured formation with proper petrophysics parameters quantitatively. We also found that the aspect ratio from 2D image analysis does not reflect the significance in
{"title":"Quantification of Fracture Roughness and its Effects on the Grain and Pore Size Distribution of the Fractured Rock Using Image Analysis Technique","authors":"Yiwen Gong, Ilham El-monier","doi":"10.2118/193134-MS","DOIUrl":"https://doi.org/10.2118/193134-MS","url":null,"abstract":"\u0000 During the hydraulic fracturing process, the created rough fracture surface and fracturing fluids with high viscosity greatly challenge proppants placement in the thin aperture of fractures. Thus, it is essential to detailly investigate the effect of surface roughness on the proppant distribution. In addition, the multiphase flow in the rough nanoscale microfractures in the variety of orientations have not been cleared. Taking all of these into consideration; rock grain geometries, packing mechanisms, the presence of clay content, and in-situ stress field will be affected and will affect the presence of the microcracks, and consequently control the permeability and porosity of the sedimentary rock. In the failed rock after fracturing work, a processed zone where the pre-existing natural fractures get activated, and induced microcracks including intergranular and intragranular grain boundaries are brought to connect to the main fracture. Hence, the rock grain and pore size distributions at fracture processed zone are altered. This, in turn, controls the fluid transport in the rocks.\u0000 Our novel approach incorporates the image analysis software (ImageJ) by organizing desired image processing codes to study the critical features of the post-fracturing core sample, including main fracture roughness, mechanical rock properties, crack density, grain, and pore size distributions. Tennessee sandstone was undergone the hydraulic fracturing test and polished on a cross-section perpendicular to the main fracture. This cross-section was recorded by the high-resolution SEM images after ion-milling. Corresponding grain size and pore size distributions are studied at each representative location with respect to its distance to the main fracture to probe alterations of the fracturing process from the core sample original state. The results of grain size and pore size distributions are compared. The discussions of their alterations mechanisms and their effects on the rock porosity and permeability are analyzed.\u0000 We find that the roughness presence of fractures strongly increases conduits open to fluid flow. In addition, our developed image processing code perfectly captured the rock grains with the promising precision. Further, we are able to observe the grain size deduction due to the incremental intragranular grain boundaries while intergranular grain boundaries are still majorities outside the fracture processed zone (FPZ). Grain size renders a lognormal distribution at each representative location and coincides with the permeability distribution of most reservoir rocks. Grain size averages also match the literature values with reasonable uncertainties (20%). The pore size distribution and its average value vary spatially. Results from this study kindle the insights of the heterogeneity of the fractured formation with proper petrophysics parameters quantitatively. We also found that the aspect ratio from 2D image analysis does not reflect the significance in ","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"79 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83910742","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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