Wuroud Al-Fadhli, R. Kurma, D. Kovyazin, Y. Muhammad
The case study describes a modeling and simulation study of an inverted ESP completion to address three fundamental objectives. A) Increasing the ultimate oil recovery in the massive sands of Cretaceous age in Greater Burgan field by managing water production B) Mitigating the rapid water coning conditions in this high permeable water drive reservoir and C) Designing an optimal operating strategy with Downhole Water Sink (DWS) to control water production and manage well performance. A 2×2km sector was carved out from the full field geological model with 12 wells including the study well. The study well was producing at high water cut at the time of the study. All static properties were updated, and the model was history matched for production, pressure and saturation. Several sensitivity runs were performed, and prediction scenarios were run for 5 years to observe well production behavior in time. The well model was setup with an inverted ESP between straddle packers to produce water from below OWC and inject into bottom reservoir with a production string above to produce from the oil zone. This setting ensured a reverse oil cone being generated from below OWC in the reservoir under production. The aquifer model was finite in size enabling bottom water influx. Simulation results showed that implementation of DWS technology made the water production reduced by 18% during five years with an increase in oil production of nearly 25% in the study well. To maintain continuous well offtake rate, a range of water rates to be produced and injected to bottom reservoir have been studied. Several iterative runs were made to investigate the best completion interval and injection & production rates. The profiles of oil water interface near well bore indicated good reduction in the cone height as compared to normal completion. The results also showed significant improvement in oil recovery within the drainage radius of the well from the simulations. Simulation results provided good understanding of the saturation change near well bore area under different production rates. Prediction runs were made for sustainable oil production under natural flowing condition and the conditions to switch over to production under artificial lift. Production of thin layers of remaining oil from within high permeable massive Burgan middle sands has been a high concern due to very high water cuts because of coning. The study results have provided encouraging option with DWS technique to improve recovery from the reservoir.
{"title":"Modeling and Simulation to Produce Thin Layers of Remaining Oil Using Downhole Water Sink Technique for Improved Oil Recovery. A Case Study in Greater Burgan Field.","authors":"Wuroud Al-Fadhli, R. Kurma, D. Kovyazin, Y. Muhammad","doi":"10.2118/194839-MS","DOIUrl":"https://doi.org/10.2118/194839-MS","url":null,"abstract":"\u0000 The case study describes a modeling and simulation study of an inverted ESP completion to address three fundamental objectives. A) Increasing the ultimate oil recovery in the massive sands of Cretaceous age in Greater Burgan field by managing water production B) Mitigating the rapid water coning conditions in this high permeable water drive reservoir and C) Designing an optimal operating strategy with Downhole Water Sink (DWS) to control water production and manage well performance. A 2×2km sector was carved out from the full field geological model with 12 wells including the study well. The study well was producing at high water cut at the time of the study. All static properties were updated, and the model was history matched for production, pressure and saturation. Several sensitivity runs were performed, and prediction scenarios were run for 5 years to observe well production behavior in time. The well model was setup with an inverted ESP between straddle packers to produce water from below OWC and inject into bottom reservoir with a production string above to produce from the oil zone. This setting ensured a reverse oil cone being generated from below OWC in the reservoir under production. The aquifer model was finite in size enabling bottom water influx. Simulation results showed that implementation of DWS technology made the water production reduced by 18% during five years with an increase in oil production of nearly 25% in the study well. To maintain continuous well offtake rate, a range of water rates to be produced and injected to bottom reservoir have been studied. Several iterative runs were made to investigate the best completion interval and injection & production rates. The profiles of oil water interface near well bore indicated good reduction in the cone height as compared to normal completion. The results also showed significant improvement in oil recovery within the drainage radius of the well from the simulations. Simulation results provided good understanding of the saturation change near well bore area under different production rates. Prediction runs were made for sustainable oil production under natural flowing condition and the conditions to switch over to production under artificial lift. Production of thin layers of remaining oil from within high permeable massive Burgan middle sands has been a high concern due to very high water cuts because of coning. The study results have provided encouraging option with DWS technique to improve recovery from the reservoir.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86162491","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 success of resource shale development has drawn much attention to develop new technologies to economize the extensive fracturing treatments required to make commercial wells. While a single planar hydraulic fracture is the objective in conventional wells, generating a complex fracturing network is commonly the goal when fracturing unconventional wells. Therefore, in shale formations, it is required to establish connectivity to natural fractures and beddings to generate large Stimulated Reservoir Volume (SRV). Two main staged fracturing techniques have been implemented to complete horizontal wells drilled in the challenging unconventional reservoirs: plug-and-perf and sliding sleeves. This paper presents a technique for effective fracture stimulation, including hydrajetting for fracture initiation, then continuous injection for fracture propagation. Hydrajetting is used to place singular or dual miniholes of approximately 2-in. ID and 2 ft penetration depth to bypass the near wellbore stress field and focus the energy on generating SRV at a distance away from the disturbed near wellbore stress field (due to drilling effects). The procedure involves two steps: hydrajetting at a given depth using coiled tubing equipped with a gravity-oriented jetting tool, and then fracturing by pumping through both the annulus and the jetting tool. Large miniholes offer minimizing the energy loss created by conventional perforations, avoiding tortuous path generation, minimizing possibilities for near wellbore screen-out, and generating complex fracture networks. This paper discusses the unique mechanics of the new procedure aimed at creating large SRV in shale formations. The new technique is fairly easy to implement and the beneficial impact could be substantial. The technique and resulting benefits in fracture stimulation of shale reservoirs will be presented.
{"title":"Hydrajet-Based Fracturing Treatment in Unconventional Wells","authors":"J. B. Surjaatmadja","doi":"10.2118/195142-MS","DOIUrl":"https://doi.org/10.2118/195142-MS","url":null,"abstract":"\u0000 The success of resource shale development has drawn much attention to develop new technologies to economize the extensive fracturing treatments required to make commercial wells. While a single planar hydraulic fracture is the objective in conventional wells, generating a complex fracturing network is commonly the goal when fracturing unconventional wells. Therefore, in shale formations, it is required to establish connectivity to natural fractures and beddings to generate large Stimulated Reservoir Volume (SRV). Two main staged fracturing techniques have been implemented to complete horizontal wells drilled in the challenging unconventional reservoirs: plug-and-perf and sliding sleeves. This paper presents a technique for effective fracture stimulation, including hydrajetting for fracture initiation, then continuous injection for fracture propagation.\u0000 Hydrajetting is used to place singular or dual miniholes of approximately 2-in. ID and 2 ft penetration depth to bypass the near wellbore stress field and focus the energy on generating SRV at a distance away from the disturbed near wellbore stress field (due to drilling effects). The procedure involves two steps: hydrajetting at a given depth using coiled tubing equipped with a gravity-oriented jetting tool, and then fracturing by pumping through both the annulus and the jetting tool. Large miniholes offer minimizing the energy loss created by conventional perforations, avoiding tortuous path generation, minimizing possibilities for near wellbore screen-out, and generating complex fracture networks.\u0000 This paper discusses the unique mechanics of the new procedure aimed at creating large SRV in shale formations. The new technique is fairly easy to implement and the beneficial impact could be substantial. The technique and resulting benefits in fracture stimulation of shale reservoirs will be presented.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86292019","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}
Baraa Al-Shammari, Nitin L. Rane, Shareefa Mulla Ali, Aala Ahmad Sultan, S. A. Sabea, Meqdad Al-Naqi, M. Pandey, F. L. Solaeche
The Kuwait Integrated Digital Field project for Gathering-Center 01 (KwIDF GC-01) at Burgan Field acquires real-time data from wells and processing facilities as input for its production-surveillance program. Live data from the field is fed into an integrated production model for analyzing and optimizing pump performance. An automated workflow process generates alarms for critical well and facility parameters to identify wells with potential scaling issues. KwIDF workflows are integrated with updated well models to visualize the effect of scale build up on the wellhead performance and thereby assist in quantifying the associated production losses caused by scale deposition. A sensitivity analysis is also performed to identify current and optimal pump operating conditions and prioritize scale cleaning jobs. The exception-based surveillance of key real-time parameters for wells utilizing electrical submersible pumps (ESPs) in Burgan field has significantly improved diagnostics of scale deposition at wellhead chokes and flowlines. Automated workflows calibrate an integrated production model in real-time, which enables engineers to run a quick analysis of current pump operating conditions and make a proactive plan of action. The application of real-time data and automated models has aided the operator's production team in making informed and timely decisions that enable them to run pumps at optimal operating conditions, with the result that they are able to sustain well production at target levels. This paper describes an innovative approach to applying real-time data and integrated models in an automated workflow process for enhancing capabilities to diagnose scale deposition in the surface flow network. Examples are presented to demonstrate the application of integrated technology for identifying scaling at wellhead chokes and flowlines and prioritizing a scale removal program for optimizing pump performance.
{"title":"Using Real-Time Data and Integrated Models to Diagnose Scale Problems and Improve Pump Performance","authors":"Baraa Al-Shammari, Nitin L. Rane, Shareefa Mulla Ali, Aala Ahmad Sultan, S. A. Sabea, Meqdad Al-Naqi, M. Pandey, F. L. Solaeche","doi":"10.2118/194847-MS","DOIUrl":"https://doi.org/10.2118/194847-MS","url":null,"abstract":"\u0000 The Kuwait Integrated Digital Field project for Gathering-Center 01 (KwIDF GC-01) at Burgan Field acquires real-time data from wells and processing facilities as input for its production-surveillance program. Live data from the field is fed into an integrated production model for analyzing and optimizing pump performance. An automated workflow process generates alarms for critical well and facility parameters to identify wells with potential scaling issues. KwIDF workflows are integrated with updated well models to visualize the effect of scale build up on the wellhead performance and thereby assist in quantifying the associated production losses caused by scale deposition. A sensitivity analysis is also performed to identify current and optimal pump operating conditions and prioritize scale cleaning jobs.\u0000 The exception-based surveillance of key real-time parameters for wells utilizing electrical submersible pumps (ESPs) in Burgan field has significantly improved diagnostics of scale deposition at wellhead chokes and flowlines. Automated workflows calibrate an integrated production model in real-time, which enables engineers to run a quick analysis of current pump operating conditions and make a proactive plan of action. The application of real-time data and automated models has aided the operator's production team in making informed and timely decisions that enable them to run pumps at optimal operating conditions, with the result that they are able to sustain well production at target levels.\u0000 This paper describes an innovative approach to applying real-time data and integrated models in an automated workflow process for enhancing capabilities to diagnose scale deposition in the surface flow network. Examples are presented to demonstrate the application of integrated technology for identifying scaling at wellhead chokes and flowlines and prioritizing a scale removal program for optimizing pump performance.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86097858","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}
Sarah Al-Shuaib, Haifa Al-Bader, Y. Al-salali, Waleed Ahmad Abdel Hameed, H. Ahmad, S. Al-Dousari
Comprehensive and fully-integrated analyses were performed on the first discovery in Zubair formation of lower Cretaceous age at Bahrah field in North Kuwait with objective of assessing HC potential, well performance, reservoir characteristics and verify connectivity between reservoir flow units. Based on petro-physical evaluation of OHL, bottom-hole samples, and RDT pressure points two flow units within Zubair reservoir were identified. The OHL showed that these two zones are separated by thin shale strikes additionally; the resistivity against the upper zone showed possibility of being water. Therefore, it was decided to test the two reservoir units separately. Subsequently, after two successful production tests, analyses of well production performance including Nodal Analysis, PVT, RDT and PTA were carried out for both zones in order to assess reserve potential, obtain essential reservoir rock & fluid characteristics and verify vertical connectivity. Remarkable oil discovery was made in Zubair reservoir of Bahrah field with substantial addition of proven reserves and commercial production potential, which will definitely support achieving the strategic production target. In order to verify long-term production sustainability, Extended Well Testing (EWT) was conducted. The results showed that this reservoir is capable to produce Hydrocarbon in a sustainable manner. Production Performance, PVT, RDT, PTA and Nodal analysis results showed that the two tested zones in Zubair reservoir are interconnected with same fluid characteristics and it can be considered as one reservoir even though the open-hole logs responses showing that they could be different reservoirs. This paper will present detailed comprehensive engineering and geological analyses of first Zubair oil discovery in Bahrah Field at North Kuwait. All available structural, petrophysical, PVT and production information were used to develop static model by Petrel-RE and subsequently, detailed data acquisition, appraisal drilling and conceptual field development plans have been established.
{"title":"Integrated G&G and Engineering Assessment of a Remarkable Cretaceous Discovery in Bahrah Field at North Kuwait","authors":"Sarah Al-Shuaib, Haifa Al-Bader, Y. Al-salali, Waleed Ahmad Abdel Hameed, H. Ahmad, S. Al-Dousari","doi":"10.2118/194750-MS","DOIUrl":"https://doi.org/10.2118/194750-MS","url":null,"abstract":"\u0000 Comprehensive and fully-integrated analyses were performed on the first discovery in Zubair formation of lower Cretaceous age at Bahrah field in North Kuwait with objective of assessing HC potential, well performance, reservoir characteristics and verify connectivity between reservoir flow units.\u0000 Based on petro-physical evaluation of OHL, bottom-hole samples, and RDT pressure points two flow units within Zubair reservoir were identified. The OHL showed that these two zones are separated by thin shale strikes additionally; the resistivity against the upper zone showed possibility of being water. Therefore, it was decided to test the two reservoir units separately.\u0000 Subsequently, after two successful production tests, analyses of well production performance including Nodal Analysis, PVT, RDT and PTA were carried out for both zones in order to assess reserve potential, obtain essential reservoir rock & fluid characteristics and verify vertical connectivity.\u0000 Remarkable oil discovery was made in Zubair reservoir of Bahrah field with substantial addition of proven reserves and commercial production potential, which will definitely support achieving the strategic production target. In order to verify long-term production sustainability, Extended Well Testing (EWT) was conducted. The results showed that this reservoir is capable to produce Hydrocarbon in a sustainable manner. Production Performance, PVT, RDT, PTA and Nodal analysis results showed that the two tested zones in Zubair reservoir are interconnected with same fluid characteristics and it can be considered as one reservoir even though the open-hole logs responses showing that they could be different reservoirs.\u0000 This paper will present detailed comprehensive engineering and geological analyses of first Zubair oil discovery in Bahrah Field at North Kuwait. All available structural, petrophysical, PVT and production information were used to develop static model by Petrel-RE and subsequently, detailed data acquisition, appraisal drilling and conceptual field development plans have been established.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83912152","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 objective of this work is to characterize the porosity distribution and the types of carbonate facies in the Mishrif reservoir in the West Qurna/1 Oil Field using seismic inversion results, well log data, rock physics model and core data analysis. Identification of the pore system and the spatial distribution of lithology are keys for constructing Mishrif reservoir model, which have a great impact on the development of the most prolific reservoir in the field Mishrif reservoir. Seismic inversion process is transforming of seismic response into a quantitative elastic properties of the reservoir rocks. It enables the modeling of porosity and lithology distribution in 3D space away from well control. In order to achieve the aim of the work, a step wise approach will be taken. First of all, the vertical distribution of porosity based on well log data and its relationship with elastic properties was undertaken. A model-based seismic inversion guided by rock physic analysis modeling was applied across the high resolution 3-D seismic data, and integrated with core data for validating at Mishrif intervals. The porosity volume was then generated over the entire West Qurna/1 field based on the linear-regression analysis. The interpretation of seismically derived characterization in the Mishrif reservoir observed a different lateral distribution of acoustic impedance. The results were correlated with computed acoustic impedance log and core analysis data to classify lithofacies of the Mishrif interval. The resulting porosity volume was validated with well log data where good consistency was indicated. By slicing through the porosity volume, it shows a high porosity in many carbonate features with low acoustic impedance which reflect a good reservoir quality (grainstone tidal channel or the accumulation of corals and mounds facies). This observation implied that Mishrif zones displayed a wide range of porosity and lithology fluctuations due to the impact of depositional environment. The workflow provided insight into the porosity distribution and quantification of its influence on dynamic reservoir behavior. The estimation of the porosity based on seismic data, can increase the reliability of reservoir characteristics through providing a more detailed of porosity distribution in interwell regions. Overall, this study will ultimately lead to improve the development plan of wells in terms of production performance, and economic value of the West Qurna/1 oil field and similar heterogeneous carbonate reservoirs.
{"title":"Improved Carbonate Reservoir Characterization: A Case Study from a Supergiant Field in Southern of Iraq","authors":"A. Al-Ali, K. Stephen, Asghar Shams","doi":"10.2118/194934-MS","DOIUrl":"https://doi.org/10.2118/194934-MS","url":null,"abstract":"\u0000 The objective of this work is to characterize the porosity distribution and the types of carbonate facies in the Mishrif reservoir in the West Qurna/1 Oil Field using seismic inversion results, well log data, rock physics model and core data analysis. Identification of the pore system and the spatial distribution of lithology are keys for constructing Mishrif reservoir model, which have a great impact on the development of the most prolific reservoir in the field Mishrif reservoir.\u0000 Seismic inversion process is transforming of seismic response into a quantitative elastic properties of the reservoir rocks. It enables the modeling of porosity and lithology distribution in 3D space away from well control. In order to achieve the aim of the work, a step wise approach will be taken. First of all, the vertical distribution of porosity based on well log data and its relationship with elastic properties was undertaken. A model-based seismic inversion guided by rock physic analysis modeling was applied across the high resolution 3-D seismic data, and integrated with core data for validating at Mishrif intervals. The porosity volume was then generated over the entire West Qurna/1 field based on the linear-regression analysis.\u0000 The interpretation of seismically derived characterization in the Mishrif reservoir observed a different lateral distribution of acoustic impedance. The results were correlated with computed acoustic impedance log and core analysis data to classify lithofacies of the Mishrif interval. The resulting porosity volume was validated with well log data where good consistency was indicated. By slicing through the porosity volume, it shows a high porosity in many carbonate features with low acoustic impedance which reflect a good reservoir quality (grainstone tidal channel or the accumulation of corals and mounds facies). This observation implied that Mishrif zones displayed a wide range of porosity and lithology fluctuations due to the impact of depositional environment.\u0000 The workflow provided insight into the porosity distribution and quantification of its influence on dynamic reservoir behavior. The estimation of the porosity based on seismic data, can increase the reliability of reservoir characteristics through providing a more detailed of porosity distribution in interwell regions. Overall, this study will ultimately lead to improve the development plan of wells in terms of production performance, and economic value of the West Qurna/1 oil field and similar heterogeneous carbonate reservoirs.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91486071","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
When water is injected into an oil reservoir, estimates of fluid transmissibility from the respective log-log plots show substantial differences between magnitudes out of injection and falloff models. This observation appears to be anomalous when compared to the cases of producing wells where there are no marked differences in transmissibility estimated from drawdown and buildup models. This study investigates the reason behind the differences in fluid transmissibility estimated from injection and falloff models. We have developed high-resolution, numerical models to illustrate differences in log-log plots observed in the injection and falloff periods. To explain the anomalous behavior, we have reviewed the fundamental principle of superposition which is particularly applicable in production wells. However, we have found that the principle of superposition falls apart while applying during injection periods due to a lack of static equilibrium of the transmissibility distribution around the injection wells. In contrast, the principle of superposition is still applicable during the falloff period following a period of water injection. As a result, differences in injection and falloff models appear on the log-log plots. The requirement of linearity on the part of the principle of superposition breaks down due to changing transmissibility in the vicinity of the injection wells during the injection periods. This invalidates the method of estimating the fluid transmissibility during the injection periods. But during the falloff periods, the transmissibility distribution in the reservoir gets back to its equilibrium condition. Hence the estimates of the mobility from the models during the falloff periods on the log-log plot are valid as demonstrated with isothermal and non-isothermal cases. This study is to show how it is misleading in estimating the mobility from injection-pressure data contrary to conventional wisdom. With this knowledge, reservoir engineers will be able to steer clear of the trap of wrongful analysis of transient-pressure data.
{"title":"An Investigation into Apparent Differences Between Injection Transmissibility and Falloff Transmissibility in Oil Reservoirs Subject to Water Injection","authors":"N. Rahman, Omar H Obathani","doi":"10.2118/195123-MS","DOIUrl":"https://doi.org/10.2118/195123-MS","url":null,"abstract":"\u0000 When water is injected into an oil reservoir, estimates of fluid transmissibility from the respective log-log plots show substantial differences between magnitudes out of injection and falloff models. This observation appears to be anomalous when compared to the cases of producing wells where there are no marked differences in transmissibility estimated from drawdown and buildup models. This study investigates the reason behind the differences in fluid transmissibility estimated from injection and falloff models.\u0000 We have developed high-resolution, numerical models to illustrate differences in log-log plots observed in the injection and falloff periods. To explain the anomalous behavior, we have reviewed the fundamental principle of superposition which is particularly applicable in production wells. However, we have found that the principle of superposition falls apart while applying during injection periods due to a lack of static equilibrium of the transmissibility distribution around the injection wells. In contrast, the principle of superposition is still applicable during the falloff period following a period of water injection. As a result, differences in injection and falloff models appear on the log-log plots.\u0000 The requirement of linearity on the part of the principle of superposition breaks down due to changing transmissibility in the vicinity of the injection wells during the injection periods. This invalidates the method of estimating the fluid transmissibility during the injection periods. But during the falloff periods, the transmissibility distribution in the reservoir gets back to its equilibrium condition. Hence the estimates of the mobility from the models during the falloff periods on the log-log plot are valid as demonstrated with isothermal and non-isothermal cases.\u0000 This study is to show how it is misleading in estimating the mobility from injection-pressure data contrary to conventional wisdom. With this knowledge, reservoir engineers will be able to steer clear of the trap of wrongful analysis of transient-pressure data.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88818720","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}
Additive Manufacturing (AM) is a set of technologies that has historically found fertile applications in the aerospace and healthcare industries, while adoption in the oil and gas (O&G) sector has progressed slowly. Nonetheless, AM is reaching maturity in this industry as well, allowing for significant innovation. This paper describes how AM has been integrated within the value chain of a major oilfield supplier, highlighting specific peculiarities for each of its business segments. "Fullstream" activities of the oilfield supplier cover the entire O&G value chain, from the exploration of reservoirs and production (upstream) to the transportation and storage of hydrocarbons (midstream), as well as refining and industrial power processing (downstream). AM technologies in this company were originally deployed for rapid prototyping, but they have matured as strategic manufacturing pillars to address the maintenance of equipment of all industry segments within the company. Several manufacturing methods within the AM landscape can be deployed, depending on the technical requirements of the components and the environment in which they operate. O&G equipment end users face several challenges when dealing with spare parts management, such as performance, total cost of ownership, procurement time, inventory levels and obsolescence. From an OEM standpoint, serving a wide fleet with a variety of products and their different versions (with an unpredictable and unstable demand) is challenging. AM is the tool that enables a new way to serve such an installed fleet. The company has already experimented with several applications regarding obsolete spare parts re-introduction through AM, gaining strong benefits (50% +) in terms of cost and procurement time reduction. Consequently, it is important to continue adopting AM to deliver faster outcomes for the customer at first. This, in turn, fosters the development of sound knowledge and references that can then be used to develop further solutions and value propositions for the customers.
{"title":"Metal 3D Printing Applications in the Oil & Gas Industry","authors":"Madison Burns, C. Wangenheim","doi":"10.2118/194787-MS","DOIUrl":"https://doi.org/10.2118/194787-MS","url":null,"abstract":"\u0000 Additive Manufacturing (AM) is a set of technologies that has historically found fertile applications in the aerospace and healthcare industries, while adoption in the oil and gas (O&G) sector has progressed slowly. Nonetheless, AM is reaching maturity in this industry as well, allowing for significant innovation. This paper describes how AM has been integrated within the value chain of a major oilfield supplier, highlighting specific peculiarities for each of its business segments. \"Fullstream\" activities of the oilfield supplier cover the entire O&G value chain, from the exploration of reservoirs and production (upstream) to the transportation and storage of hydrocarbons (midstream), as well as refining and industrial power processing (downstream). AM technologies in this company were originally deployed for rapid prototyping, but they have matured as strategic manufacturing pillars to address the maintenance of equipment of all industry segments within the company. Several manufacturing methods within the AM landscape can be deployed, depending on the technical requirements of the components and the environment in which they operate. O&G equipment end users face several challenges when dealing with spare parts management, such as performance, total cost of ownership, procurement time, inventory levels and obsolescence. From an OEM standpoint, serving a wide fleet with a variety of products and their different versions (with an unpredictable and unstable demand) is challenging. AM is the tool that enables a new way to serve such an installed fleet. The company has already experimented with several applications regarding obsolete spare parts re-introduction through AM, gaining strong benefits (50% +) in terms of cost and procurement time reduction. Consequently, it is important to continue adopting AM to deliver faster outcomes for the customer at first. This, in turn, fosters the development of sound knowledge and references that can then be used to develop further solutions and value propositions for the customers.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84609695","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}
Hydraulic fracturing is being used globally to unlock hydrocarbon resources in unconventional reservoirs. However, the efficient utilization of resources in most treatment designs is debatable. A study of hydraulic fracturing treatments in 56 vertical and horizontal wells representing 1,151 treated stages in the Wolfcamp and Spraberry formations of the Permian Basin in West Texas was conducted in this paper. Intrinsic treatment strategies and operational methodologies used by the well operators were evaluated with the objective of extracting and deducing insights into criteria that characterize operational virtuosity, efficiency and inefficiency. Treatments of vertical wells were studied with 25 wells in both formations, in the Midland basin. 18 wells were studied in Spraberry horizontal well treatments, while horizontal Wolfcamp treatments were studied with 13 wells in the Delaware basin. Well completion records, treatment reports and well files were reviewed for treatment parameters on each well. The study concentrated on indices like, proppants types and amount; fluid types and volumes pumped; treatment rates and pressures; productivity and treatment cost. Empirical and statistical analysis using correlations and analysis of variance were then conducted and used to identify the best practices that actively and positively increased production rates and decreased production costs in each of these formations and well types. The Spraberry is very fine-grained sandstone, siltstone and carbonates with interbedded shales in the studied area. The Delaware Wolfcamp is a complex formation with carbonates, mostly limestone, and interbedded organic rich mudstones in varying proportions. Results show that the use of 20/40 white as a proppant is not economical, in both formations either in vertical or horizontal wells, because of the huge increase in treatment costs. Use of 100 mesh and 40/70 white proppant in both formations was amenable to better production rate. Results show that usage of crosslinked gel increases treatment costs drastically. Slickwater was found to improve production rates, although huge volumes were needed for large proppant amounts. The use of HCl acid as spearhead in formations with high carbonate content like the Wolfcamp was found to improve treatment results. Increasing the number of stages increases treatment cost, but increasing the perforated intervals correlates positively with production rate.
{"title":"Hydraulic Fracturing Treatments in the Permian Basin: Distillation of Best Practices in the Spraberry and Wolfcamp Formations","authors":"A. Othman, Abiodun Matthew Amao","doi":"10.2118/194931-MS","DOIUrl":"https://doi.org/10.2118/194931-MS","url":null,"abstract":"\u0000 Hydraulic fracturing is being used globally to unlock hydrocarbon resources in unconventional reservoirs. However, the efficient utilization of resources in most treatment designs is debatable. A study of hydraulic fracturing treatments in 56 vertical and horizontal wells representing 1,151 treated stages in the Wolfcamp and Spraberry formations of the Permian Basin in West Texas was conducted in this paper. Intrinsic treatment strategies and operational methodologies used by the well operators were evaluated with the objective of extracting and deducing insights into criteria that characterize operational virtuosity, efficiency and inefficiency.\u0000 Treatments of vertical wells were studied with 25 wells in both formations, in the Midland basin. 18 wells were studied in Spraberry horizontal well treatments, while horizontal Wolfcamp treatments were studied with 13 wells in the Delaware basin. Well completion records, treatment reports and well files were reviewed for treatment parameters on each well. The study concentrated on indices like, proppants types and amount; fluid types and volumes pumped; treatment rates and pressures; productivity and treatment cost. Empirical and statistical analysis using correlations and analysis of variance were then conducted and used to identify the best practices that actively and positively increased production rates and decreased production costs in each of these formations and well types.\u0000 The Spraberry is very fine-grained sandstone, siltstone and carbonates with interbedded shales in the studied area. The Delaware Wolfcamp is a complex formation with carbonates, mostly limestone, and interbedded organic rich mudstones in varying proportions. Results show that the use of 20/40 white as a proppant is not economical, in both formations either in vertical or horizontal wells, because of the huge increase in treatment costs. Use of 100 mesh and 40/70 white proppant in both formations was amenable to better production rate. Results show that usage of crosslinked gel increases treatment costs drastically. Slickwater was found to improve production rates, although huge volumes were needed for large proppant amounts. The use of HCl acid as spearhead in formations with high carbonate content like the Wolfcamp was found to improve treatment results. Increasing the number of stages increases treatment cost, but increasing the perforated intervals correlates positively with production rate.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89774832","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}
Data Analytics is an emerging area that involves using advanced statistical and machine learning algorithms to discover information & relationsips present in different types of data. The work described in this paper illustrates the application of machine learning techniques to an Oilfield Advanced Process Control (APC) project involving deployment of APC at a large onshore conventional oilfield in Saudi Aramco. APC implementation enables better control and optimization of the production from hundreds of oilwells. APC rollout at the large oilfield involved APC deployment on 300+ oil wells. Using conventional APC implementation methodology, the rollout would be very difficult to manage and would have taken about 3 man years which was not practical. Use of innovative data analytics techniques was essential to ensuring the timely deployment of such a large scale APC project. A machine learning algorithm used to cluster similarly behaving wells, enabled significant (80%) reduction in the engineering effort and operator involvement in developing the models for each well. This allowed the implementation to be completed one year in advance thus realizing the APC benefits earlier than planned.
{"title":"Machine Learning in Oil & Gas Industry: A Novel Application of Clustering for Oilfield Advanced Process Control","authors":"Kalpesh M Patel, R. Patwardhan","doi":"10.2118/194827-MS","DOIUrl":"https://doi.org/10.2118/194827-MS","url":null,"abstract":"\u0000 Data Analytics is an emerging area that involves using advanced statistical and machine learning algorithms to discover information & relationsips present in different types of data. The work described in this paper illustrates the application of machine learning techniques to an Oilfield Advanced Process Control (APC) project involving deployment of APC at a large onshore conventional oilfield in Saudi Aramco. APC implementation enables better control and optimization of the production from hundreds of oilwells.\u0000 APC rollout at the large oilfield involved APC deployment on 300+ oil wells. Using conventional APC implementation methodology, the rollout would be very difficult to manage and would have taken about 3 man years which was not practical. Use of innovative data analytics techniques was essential to ensuring the timely deployment of such a large scale APC project. A machine learning algorithm used to cluster similarly behaving wells, enabled significant (80%) reduction in the engineering effort and operator involvement in developing the models for each well. This allowed the implementation to be completed one year in advance thus realizing the APC benefits earlier than planned.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89231535","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 Bahrain Field is characterized by large lateral and vertical variations in fluid properties, with oil gravity ranging between −9 and 80 °API. The lower API crudes are encountered mostly on the structural flanks and within the upper reservoir units, while the highest API crudes are condensates from deeper formations such as Hith and Arab. The deepest reservoir is the gas-bearing Khuff. It has 50 °API condensate and forms a separate fluid type from the rest of the Bahrain Field. The objective of this paper is to derive a single compositional predictor for the entire range of crude gravities. Excluded from this unified model are bitumens from Aruma and Khuff condensates, which are compositionally different. One outcome of this study was to predict the reservoir fluid as a function of well test Gas Oil Ratio (GOR) and API gravity by mathematical recombination of averaged data from abundant well tests across the Bahrain Field. A strong trend of methane fraction in the reservoir fluid versus saturation pressure has been observed, and thus it has been possible to construct the recombined reservoir fluid and then predict saturation pressures, Formation Volume Fraction (FVF), and viscosity. This fluid model was used to initialize compositional models for gas plant evaluations, miscible flood evaluations, and to determine the maximum GOR at which saturation pressure equals reservoir pressure. Another outcome of the unified fluid model was to construct a reservoir fluid composition given a target saturation pressure and API. This information is used to construct representative fluids for laboratory synthesis of crudes and gas for live oil experiments. As part of the process, a number of quality checks were constructed to determine if the fluid encountered is in range of historic produced crudes (e.g. contamination by air or lift gas) and enable construction of fluids for reservoir simulation.
{"title":"Unified Field Compositional Fluid Model for the Bahrain Field","authors":"A. Al-Muftah","doi":"10.2118/194699-MS","DOIUrl":"https://doi.org/10.2118/194699-MS","url":null,"abstract":"\u0000 The Bahrain Field is characterized by large lateral and vertical variations in fluid properties, with oil gravity ranging between −9 and 80 °API. The lower API crudes are encountered mostly on the structural flanks and within the upper reservoir units, while the highest API crudes are condensates from deeper formations such as Hith and Arab. The deepest reservoir is the gas-bearing Khuff. It has 50 °API condensate and forms a separate fluid type from the rest of the Bahrain Field.\u0000 The objective of this paper is to derive a single compositional predictor for the entire range of crude gravities. Excluded from this unified model are bitumens from Aruma and Khuff condensates, which are compositionally different. One outcome of this study was to predict the reservoir fluid as a function of well test Gas Oil Ratio (GOR) and API gravity by mathematical recombination of averaged data from abundant well tests across the Bahrain Field. A strong trend of methane fraction in the reservoir fluid versus saturation pressure has been observed, and thus it has been possible to construct the recombined reservoir fluid and then predict saturation pressures, Formation Volume Fraction (FVF), and viscosity. This fluid model was used to initialize compositional models for gas plant evaluations, miscible flood evaluations, and to determine the maximum GOR at which saturation pressure equals reservoir pressure. Another outcome of the unified fluid model was to construct a reservoir fluid composition given a target saturation pressure and API. This information is used to construct representative fluids for laboratory synthesis of crudes and gas for live oil experiments.\u0000 As part of the process, a number of quality checks were constructed to determine if the fluid encountered is in range of historic produced crudes (e.g. contamination by air or lift gas) and enable construction of fluids for reservoir simulation.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73507373","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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