Sachit Saumya, S. Sarkar, Juli Singh, Ajit Kumar, G. Agarwal, Isha Khambra, Jitesh Vij, Bhaswati Das, P. Shedde, C. Majumdar, S. Pabla
Drilling is carried out in the very early stage of the well and it is critical for ensuring smooth execution of every aspect of well construction such as faster drilling, better hole cleaning, superior logging, running casing efficiently, maintaining wellbore integrity and achieving economic production. This paper will demonstrate the significance of best drilling practices to achieve good wellbore geometry, which has a profound effect on total well construction and production time and cost and sometimes even determine the success of the well. Poor wellbore geometry, because of improper choice of drilling system i.e. mud motor or rotatory steerable, is generally related to the washed out and/or spiraled wellbore. Washed out hole is recognized by using calipers, however, the hole spiraling is difficult to detect at the early stage of the well. In spiraled holes, it becomes virtually impossible to get a good cementing job done. The poor cementing conditions behind the casing are identified using ultra-sonic images or high amplitudes values of CBL/VDL. These channels behind casing are, a clear threat to production and life cycle of the well. It is widely assumed that the squeeze jobs are an option to improve cement behind casing, however, it does not hold true in case of a spiral borehole. This paper compares the wells, drilled with different drilling system and their impact on the wellbore geometry. It also exhibits the aftermath effects on wellbore construction, well integrity and production.
{"title":"Impact of Drilling Practices on Well Integrity and Production: An Analysis and Assessment","authors":"Sachit Saumya, S. Sarkar, Juli Singh, Ajit Kumar, G. Agarwal, Isha Khambra, Jitesh Vij, Bhaswati Das, P. Shedde, C. Majumdar, S. Pabla","doi":"10.2118/193208-MS","DOIUrl":"https://doi.org/10.2118/193208-MS","url":null,"abstract":"\u0000 Drilling is carried out in the very early stage of the well and it is critical for ensuring smooth execution of every aspect of well construction such as faster drilling, better hole cleaning, superior logging, running casing efficiently, maintaining wellbore integrity and achieving economic production. This paper will demonstrate the significance of best drilling practices to achieve good wellbore geometry, which has a profound effect on total well construction and production time and cost and sometimes even determine the success of the well.\u0000 Poor wellbore geometry, because of improper choice of drilling system i.e. mud motor or rotatory steerable, is generally related to the washed out and/or spiraled wellbore. Washed out hole is recognized by using calipers, however, the hole spiraling is difficult to detect at the early stage of the well. In spiraled holes, it becomes virtually impossible to get a good cementing job done. The poor cementing conditions behind the casing are identified using ultra-sonic images or high amplitudes values of CBL/VDL. These channels behind casing are, a clear threat to production and life cycle of the well. It is widely assumed that the squeeze jobs are an option to improve cement behind casing, however, it does not hold true in case of a spiral borehole. This paper compares the wells, drilled with different drilling system and their impact on the wellbore geometry. It also exhibits the aftermath effects on wellbore construction, well integrity and production.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"20 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88074582","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}
Arwa Al-Harrasi, R. Al-Mjeni, A. Al-Yaarubi, Fathiya R Al-Battashi, Ahmed Al-Jabri
This paper reviews the petrophysical evaluation of a major oil field in the South of the Sultanate of Oman. The current recovery factor is 15% with over 400 vertical and horizontal well penetrations. The reservoir is in the shaly-sand Mahwis formation. This reservoir is characterized by high porosity, averaging around 30pu, and permeabilities between 200 to 2000mD. The hydrocarbon is of variable viscosity ranging from 250 to 2000 cP closer to water contact. The formation water is of low salinity around 5000ppm NaCl. The mineralogy is composed of quartz, feldspars and clays that include large proportion of smectite. Smectite has the highest cation exchange capacity–CEC-among all clay types. The varying distribution of smectite in the field led to a varied resistivity response across the reservoir. Consequently, the resistivity-based saturation models overestimated water saturation in some parts of the field. That coupled with historical production has led to ambiguity in the current saturation distribution of the reservoir. A petrophysical workflow is devised to overcome saturation ambiguity and provide essential information for current infill and future field developments. The evaluation utilizes modern logging tools including elemental spectroscopy, dielectric dispersion and multi-dimensional NMR. The Spectroscopy data is useful in determining representative mineralogical composition. The results of this analysis is verified against side-wall-core samples. The mineralogy data is used as an input into a multi-mineral-volumetric-solver to compute accurate porosity and matrix dielectric permittivity. Subsequently, these are used as inputs into dielectric dispersion analysis that outputs total water and hydrocarbon volumes at the tool’s depth of investigation. The integration of NMR and dielectric logs help to partition measured T2 distribution into hydrocarbon, bound and free fluids. This information is then used to determine formation saturation and in-situ oil viscosity. Additionally, Carbon-Oxygen data, which outputs resistivity-independent saturation was acquired after setting the casing and allowing sufficient time for mud filtrate to dissipate. The comparison of saturation from the analysis behind casing and shallow reading tools (i.e NMR and dielectric) allowed to determine intervals with mobile hydrocarbon and accurately determine the onset of the transition zone. The study presented a methodology to accurately separate NMR signals of the heavy oil, bound and free fluids. Subsequently, these datasets were used as inputs into proven correlations to estimate saturation and in-situ oil viscosity. The results were in good agreement with laboratory data performed on core samples acquired in the same well. In addition, the integration of the elemental capture spectroscopy and dielectric permittivity logs resulted in a good quantitative estimate of the hydrocarbon saturation. The result of this study contributed to delineating sections of the
{"title":"Revisiting Petrophysical and Fluid Characteristics of a Mature Smectite-Rich Shally Sand Reservoir for EOR Screening in the Sultanate of Oman","authors":"Arwa Al-Harrasi, R. Al-Mjeni, A. Al-Yaarubi, Fathiya R Al-Battashi, Ahmed Al-Jabri","doi":"10.2118/193051-MS","DOIUrl":"https://doi.org/10.2118/193051-MS","url":null,"abstract":"\u0000 This paper reviews the petrophysical evaluation of a major oil field in the South of the Sultanate of Oman. The current recovery factor is 15% with over 400 vertical and horizontal well penetrations. The reservoir is in the shaly-sand Mahwis formation. This reservoir is characterized by high porosity, averaging around 30pu, and permeabilities between 200 to 2000mD. The hydrocarbon is of variable viscosity ranging from 250 to 2000 cP closer to water contact. The formation water is of low salinity around 5000ppm NaCl. The mineralogy is composed of quartz, feldspars and clays that include large proportion of smectite. Smectite has the highest cation exchange capacity–CEC-among all clay types. The varying distribution of smectite in the field led to a varied resistivity response across the reservoir. Consequently, the resistivity-based saturation models overestimated water saturation in some parts of the field. That coupled with historical production has led to ambiguity in the current saturation distribution of the reservoir.\u0000 A petrophysical workflow is devised to overcome saturation ambiguity and provide essential information for current infill and future field developments. The evaluation utilizes modern logging tools including elemental spectroscopy, dielectric dispersion and multi-dimensional NMR. The Spectroscopy data is useful in determining representative mineralogical composition. The results of this analysis is verified against side-wall-core samples. The mineralogy data is used as an input into a multi-mineral-volumetric-solver to compute accurate porosity and matrix dielectric permittivity. Subsequently, these are used as inputs into dielectric dispersion analysis that outputs total water and hydrocarbon volumes at the tool’s depth of investigation. The integration of NMR and dielectric logs help to partition measured T2 distribution into hydrocarbon, bound and free fluids. This information is then used to determine formation saturation and in-situ oil viscosity. Additionally, Carbon-Oxygen data, which outputs resistivity-independent saturation was acquired after setting the casing and allowing sufficient time for mud filtrate to dissipate. The comparison of saturation from the analysis behind casing and shallow reading tools (i.e NMR and dielectric) allowed to determine intervals with mobile hydrocarbon and accurately determine the onset of the transition zone.\u0000 The study presented a methodology to accurately separate NMR signals of the heavy oil, bound and free fluids. Subsequently, these datasets were used as inputs into proven correlations to estimate saturation and in-situ oil viscosity. The results were in good agreement with laboratory data performed on core samples acquired in the same well. In addition, the integration of the elemental capture spectroscopy and dielectric permittivity logs resulted in a good quantitative estimate of the hydrocarbon saturation. The result of this study contributed to delineating sections of the ","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88671238","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}
Muhammad Navaid Khan, Ahmed Khaleefa Al Neaimi, Abdullah Al Qamzi, Shabbeer Ali Yusaf, Yasushi Shimizu, A. Asghar, T. F. Menchaca
Operational efficiency improvement is a fundamental requirement and the continuous effort to achieve it is the inevitable need for any organization that targets profitable throughput in today's volatile market. Based on a study for a group of North American oilfields, in a typical mature oilfield, on an average 6% to 10% production deferments are caused by the process inefficiencies. Organizations continuously look for cost effective technologies that can facilitate implementing systematic operating procedures to maximize value of available resources and to provide a controlled environment for executing defined activities efficiently. Business process management (BPM) is a technique that brings in a governance mechanism to the efficient execution of processes. It uses various methods to discover, model, analyze, measure, improve, optimize, and automate business process to generate and track improvement actions. A typical project implementation involves a holistic review of the existing processes, identifications of the bottlenecks, mapping of the stakeholders and developing definitions for efficient corrective actions that enable closing system gaps. Early engagement with the stakeholders and an insightful management of change (MOC) are the key requisites of assuring the successful process roll out. Despite many industries, such as, medical and financial institutions, human capital management firms and logistics tracking system providers, have exploited the use of BPM and workflow automation to enhance their operation management capabilities, oil and gas industry still lags behind in capitalizing the benefits of this useful combination. This paper demonstrates the stepwise approach of implementing effective strategies, methods, and techniques to model and roll out collaborative solutions to help multi-disciplinary teams to execute business processes efficiently and consistently, whilst ensuring adherence to standards and agreed guidelines for maximizing efficiency and profitability. A real implementation case is presented, where a complex integrated production management and optimization system is managed leveraging workflow automation and BPM that has resulted in significant efficiency gain.
{"title":"Faster and Profitable Production Optimization Decisions through Workflow Automation and Business Process Management - A Unique Concept","authors":"Muhammad Navaid Khan, Ahmed Khaleefa Al Neaimi, Abdullah Al Qamzi, Shabbeer Ali Yusaf, Yasushi Shimizu, A. Asghar, T. F. Menchaca","doi":"10.2118/193343-MS","DOIUrl":"https://doi.org/10.2118/193343-MS","url":null,"abstract":"\u0000 Operational efficiency improvement is a fundamental requirement and the continuous effort to achieve it is the inevitable need for any organization that targets profitable throughput in today's volatile market. Based on a study for a group of North American oilfields, in a typical mature oilfield, on an average 6% to 10% production deferments are caused by the process inefficiencies. Organizations continuously look for cost effective technologies that can facilitate implementing systematic operating procedures to maximize value of available resources and to provide a controlled environment for executing defined activities efficiently.\u0000 Business process management (BPM) is a technique that brings in a governance mechanism to the efficient execution of processes. It uses various methods to discover, model, analyze, measure, improve, optimize, and automate business process to generate and track improvement actions. A typical project implementation involves a holistic review of the existing processes, identifications of the bottlenecks, mapping of the stakeholders and developing definitions for efficient corrective actions that enable closing system gaps. Early engagement with the stakeholders and an insightful management of change (MOC) are the key requisites of assuring the successful process roll out.\u0000 Despite many industries, such as, medical and financial institutions, human capital management firms and logistics tracking system providers, have exploited the use of BPM and workflow automation to enhance their operation management capabilities, oil and gas industry still lags behind in capitalizing the benefits of this useful combination. This paper demonstrates the stepwise approach of implementing effective strategies, methods, and techniques to model and roll out collaborative solutions to help multi-disciplinary teams to execute business processes efficiently and consistently, whilst ensuring adherence to standards and agreed guidelines for maximizing efficiency and profitability. A real implementation case is presented, where a complex integrated production management and optimization system is managed leveraging workflow automation and BPM that has resulted in significant efficiency gain.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"13 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83536931","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}
Faisal Al Jenaibi, M. Giddins, Adelis Valero, Samad Ali, Y. Saeed, A. Amtereg, A. Bajwa
Simulating a high-resolution multimillion cell model brings many benefits, by enabling reservoir engineers to use the best grid size for accurate representation of water and gas movement in the reservoir, essential for advanced field management, Enhanced Oil Recovery or complex well design studies. To improve the characterization of a giant heterogeneous carbonate reservoir and enhance the quality of field development plans, new high-resolution static and dynamic models have been used to study one of the largest oil fields in Abu Dhabi. A detailed static model of over 50 million grid cells was constructed, using a unique water saturation modeling approach, without upscaling to a dynamic simulation, using hysteresis for both relative permeability and capillary pressure. The reservoir has over 50 years of history, with hundreds of vertical and horizontal wells. Large volumes of data from well logs, cores and other measurements were used to populate the static model, define dynamic rock types and match well log water saturation and water capillary pressure profiles. The concept of wettability change with depth was introduced, with an oil-wet system at the crest, graduating to a water-wet system near the thin transition zone. A geological resolution grid was used for reservoir simulation studies, after testing input data consistency and stable behavior. A stability test was performed by running the simulation with no wells for 50 years after equilibration and showed no movable fluids. This verified the consistency of the reservoir static properties, rock types, water saturation, relative permeability and fluid model. A history matched case was developed with over 850 wells using the same fine grid, to meet the objective of completing each simulation run within one day. After history matching, a compositional simulation model was built, to investigate the impact of grid resolution on future production forecasts. This is the largest dynamic model built by the company and demonstrates the benefits of rigorous attention to the quality of the static data, while using modern simulation workflows to avoid compromising the detailed model by upscaling. The methodologies presented in this paper will be adopted as best practices for future similar projects.
{"title":"Multimillion Cell Dynamic Model for High Resolution Studies of a Carbonate Reservoir, Part-1","authors":"Faisal Al Jenaibi, M. Giddins, Adelis Valero, Samad Ali, Y. Saeed, A. Amtereg, A. Bajwa","doi":"10.2118/192984-MS","DOIUrl":"https://doi.org/10.2118/192984-MS","url":null,"abstract":"\u0000 Simulating a high-resolution multimillion cell model brings many benefits, by enabling reservoir engineers to use the best grid size for accurate representation of water and gas movement in the reservoir, essential for advanced field management, Enhanced Oil Recovery or complex well design studies.\u0000 To improve the characterization of a giant heterogeneous carbonate reservoir and enhance the quality of field development plans, new high-resolution static and dynamic models have been used to study one of the largest oil fields in Abu Dhabi. A detailed static model of over 50 million grid cells was constructed, using a unique water saturation modeling approach, without upscaling to a dynamic simulation, using hysteresis for both relative permeability and capillary pressure.\u0000 The reservoir has over 50 years of history, with hundreds of vertical and horizontal wells. Large volumes of data from well logs, cores and other measurements were used to populate the static model, define dynamic rock types and match well log water saturation and water capillary pressure profiles. The concept of wettability change with depth was introduced, with an oil-wet system at the crest, graduating to a water-wet system near the thin transition zone. A geological resolution grid was used for reservoir simulation studies, after testing input data consistency and stable behavior.\u0000 A stability test was performed by running the simulation with no wells for 50 years after equilibration and showed no movable fluids. This verified the consistency of the reservoir static properties, rock types, water saturation, relative permeability and fluid model. A history matched case was developed with over 850 wells using the same fine grid, to meet the objective of completing each simulation run within one day. After history matching, a compositional simulation model was built, to investigate the impact of grid resolution on future production forecasts.\u0000 This is the largest dynamic model built by the company and demonstrates the benefits of rigorous attention to the quality of the static data, while using modern simulation workflows to avoid compromising the detailed model by upscaling. The methodologies presented in this paper will be adopted as best practices for future similar projects.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"293 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76483978","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}
Wells in the South Ratqa field often fill with sand. Ultra low bottom-hole pressure did not allow efficient sand cleanouts in several wells. Despite using massive amounts of nitrogen during clean out, and largest available CT size (2.375") to ensure enough annular velocity; severe fluid losses occurred into the formation, which resulted in decreased well production post clean outs, moreover handling energized returns has always been a logistic and safety hazard Recently, concentric coiled tubing (CCT) technology was employed for the first time in Kuwait and five wells were identified as viable fill cleanout candidates for which traditional cleanout methods had proved inefficient at best and many times unsuccessful. The system uses concentric coiled tubing and a special vacuum tool designed to apply a localized drawdown, which would deliver the sand particles through the Coiled Tubing / Coiled tubing annulus to surface. Returns were handled using H2S resistant lines into a desander. A carefully engineered cleanout program enabled removal of more than 12 MT of sand from four vertical wells, and also identified the formation damage in a horizontal wellbore. The identification of wellbore damage revealed the best intervention to cure the damage and eliminated speculative remedies that sometimes increased the damage done to reservoir. Additionally, the layout of well plots was designed in a very congested way to maximize output but made it impractical to have return pits, requiring mobile tanks to handle returns, while the energized nature of returns in conventional nitrogen jobs are dangerous to handle in a closed tank environment. CCT eliminated that hazard as the returns are not energized. The campaign has pushed the boundaries of the coiled tubing interventions in Kuwait and has unlocked several wellbore cleanout opportunities using the CCT technology
{"title":"Novel Technology of Concentric Coiled Tubing Enhances Ultra-Low Pressure Reservoir Wellbore Cleanouts in Kuwait","authors":"M. Almatar, F. Alshammari, Naser Bader Alhouti","doi":"10.2118/193341-MS","DOIUrl":"https://doi.org/10.2118/193341-MS","url":null,"abstract":"\u0000 Wells in the South Ratqa field often fill with sand. Ultra low bottom-hole pressure did not allow efficient sand cleanouts in several wells. Despite using massive amounts of nitrogen during clean out, and largest available CT size (2.375\") to ensure enough annular velocity; severe fluid losses occurred into the formation, which resulted in decreased well production post clean outs, moreover handling energized returns has always been a logistic and safety hazard\u0000 Recently, concentric coiled tubing (CCT) technology was employed for the first time in Kuwait and five wells were identified as viable fill cleanout candidates for which traditional cleanout methods had proved inefficient at best and many times unsuccessful. The system uses concentric coiled tubing and a special vacuum tool designed to apply a localized drawdown, which would deliver the sand particles through the Coiled Tubing / Coiled tubing annulus to surface. Returns were handled using H2S resistant lines into a desander.\u0000 A carefully engineered cleanout program enabled removal of more than 12 MT of sand from four vertical wells, and also identified the formation damage in a horizontal wellbore. The identification of wellbore damage revealed the best intervention to cure the damage and eliminated speculative remedies that sometimes increased the damage done to reservoir. Additionally, the layout of well plots was designed in a very congested way to maximize output but made it impractical to have return pits, requiring mobile tanks to handle returns, while the energized nature of returns in conventional nitrogen jobs are dangerous to handle in a closed tank environment. CCT eliminated that hazard as the returns are not energized.\u0000 The campaign has pushed the boundaries of the coiled tubing interventions in Kuwait and has unlocked several wellbore cleanout opportunities using the CCT technology","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"162 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77047170","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}
A best practice for PVT modeling and reliability analysis had been developed in order to characterize complex giant oil reservoir fluid model, oil in place assessment and to optimize full field development and management plan for EOR studies. This study builds on previous studies done by various parties but includes recent data and revised objectives. The primary objectives are: (1) to develop understanding of fluid properties across the reservoir and the influence of separator conditions on formation volume factor. (2) to generate PVT models for the reservoir’s units, accounting for lateral and vertical variations in properties and including the ability to predict the performance of gas injection schemes 3) to estimate the potential for asphaltene precipitation and recommend further work to improve the reliability of the reservoir simulation model. The study is divided into three phases: (1) Review of previous work and conduct Data QC of PVT data. (2) Establish lateral and areal PVT property trends and EoS fluid model. (3) Historical separator conditions issues, reserves and oil in place volumes. The undertaken review of the previous EOS modeling studies had resulted in very different fluid models, each tailored slightly to focus on the specific priorities of the different studies. In this study, the understanding of the fluid properties and their distribution within the reservoir has been achieved by: Using a thorough QC process which rejected unsuitable sample dataIdentifying C6+ mass content as the reliable indicator of the fluid compositionGenerating lateral and cross-section fluid property plots to identify regional differencesGenerating C6+ mass content versus depth plots to define compositional gradients and property trends. Besides, analysis of the later MDT samples did not appear to have been used in identifying fluid property trends in any of the previous reviews. However, after Data QC, 18 PVT samples and reports were chosen to determine the compositional trends, 16 to determine property trends and 2 were identified for development of the EoS fluid model. Therefore, vertical and lateral fluid property gradients have been identified consistent with the reservoir structural and stratigraphy model. The initial GORs in the layer-cake South/Central regions fall between Rsi= 816 scf/bbl at the top (7551 ft TVDss) down to Rsi=582 scf/bbl near the OWC (8245 ft TVDss). A similar trend is observed in the northern clinoform region, but 106.6 ft deeper. None of the earlier PVT studies had identified lateral trends within this complex reservoir. The main uncertainty in the fluid description is a lack of data below 7950 ft TVDss.
{"title":"A Thorough Investigation of PVT Data and Fluid Model for Giant Onshore Field, Hidden Lateral Trends Identified","authors":"S. Meziani, S. Tahir, Tayba Al Hashemi","doi":"10.2118/193154-MS","DOIUrl":"https://doi.org/10.2118/193154-MS","url":null,"abstract":"\u0000 A best practice for PVT modeling and reliability analysis had been developed in order to characterize complex giant oil reservoir fluid model, oil in place assessment and to optimize full field development and management plan for EOR studies. This study builds on previous studies done by various parties but includes recent data and revised objectives. The primary objectives are: (1) to develop understanding of fluid properties across the reservoir and the influence of separator conditions on formation volume factor. (2) to generate PVT models for the reservoir’s units, accounting for lateral and vertical variations in properties and including the ability to predict the performance of gas injection schemes 3) to estimate the potential for asphaltene precipitation and recommend further work to improve the reliability of the reservoir simulation model. The study is divided into three phases: (1) Review of previous work and conduct Data QC of PVT data. (2) Establish lateral and areal PVT property trends and EoS fluid model. (3) Historical separator conditions issues, reserves and oil in place volumes.\u0000 The undertaken review of the previous EOS modeling studies had resulted in very different fluid models, each tailored slightly to focus on the specific priorities of the different studies.\u0000 In this study, the understanding of the fluid properties and their distribution within the reservoir has been achieved by: Using a thorough QC process which rejected unsuitable sample dataIdentifying C6+ mass content as the reliable indicator of the fluid compositionGenerating lateral and cross-section fluid property plots to identify regional differencesGenerating C6+ mass content versus depth plots to define compositional gradients and property trends.\u0000 Besides, analysis of the later MDT samples did not appear to have been used in identifying fluid property trends in any of the previous reviews. However, after Data QC, 18 PVT samples and reports were chosen to determine the compositional trends, 16 to determine property trends and 2 were identified for development of the EoS fluid model.\u0000 Therefore, vertical and lateral fluid property gradients have been identified consistent with the reservoir structural and stratigraphy model. The initial GORs in the layer-cake South/Central regions fall between Rsi= 816 scf/bbl at the top (7551 ft TVDss) down to Rsi=582 scf/bbl near the OWC (8245 ft TVDss). A similar trend is observed in the northern clinoform region, but 106.6 ft deeper. None of the earlier PVT studies had identified lateral trends within this complex reservoir. The main uncertainty in the fluid description is a lack of data below 7950 ft TVDss.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74373104","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}
R. V. Rachapudi, S. Alshehhi, Omar Saadwai, Gokhan Ayidinoglu, C. Dodan, M. Khaled, Fernando Quintero, Saber Mubarak, A. R. Gali, Samy Mohammed, Brume Ikogho
Effective reservoir management is critical to the success of water flood developments. Continuous monitoring of downhole parameters such as pressure, temperature and flow profile in water injector wells is vital in order to optimize the water-flood sweep efficiency and to avoid early water breakthrough in nearby oil producer wells. The target field has three stacked tight carbonate reservoirs with low reservoir energy and as such is being developed with water injection scheme from day one. As such, effective monitoring of downhole injection parameters is important from an early stage. A common industry practice to monitor these parameters is to install Permanent Downhole Gauge (PDHG) and Distributed Temperature Sensing (DTS) system. Recently, a new smart Hybrid Technology has been developed to measure the downhole data at surface. This paper describes the successful application of this hybrid technology in a green onshore oil field development. Details are presented about the well bore segmentation design of the DTS system, the hybrid cable installation and the operational challenges with the hookup to the wellhead control system. The paper also presents the data acquired during commissioning job, and interpretation of the temperature data which was used to generate the injection profile along the wellbore. Finally, a strategy for future implementation of the DTS system is discussed. Overall, this technology showcases the application of the smart hybrid completion for real-time monitoring of the water injection profile, including the pressure and rates along with injection volume per segment in the horizontal section. Real-time data from the hybrid technology has been integrated to digital oil field implementation to enhance the real time decision making to optimize the injection rates and to allow the operator to implement the decisions without any delay. This technology optimized the cables requirement and maximized the utilization of cable for multi-application environment to support acquiring Pressure, DTS and DAS data to generate real time injection profile.
{"title":"Smart Hybrid Technology for Water Injector Wells: Installation, Commissioning and Data Interpretation Challenges - Case Study from a Middle Eastern Field","authors":"R. V. Rachapudi, S. Alshehhi, Omar Saadwai, Gokhan Ayidinoglu, C. Dodan, M. Khaled, Fernando Quintero, Saber Mubarak, A. R. Gali, Samy Mohammed, Brume Ikogho","doi":"10.2118/192816-MS","DOIUrl":"https://doi.org/10.2118/192816-MS","url":null,"abstract":"\u0000 Effective reservoir management is critical to the success of water flood developments. Continuous monitoring of downhole parameters such as pressure, temperature and flow profile in water injector wells is vital in order to optimize the water-flood sweep efficiency and to avoid early water breakthrough in nearby oil producer wells. The target field has three stacked tight carbonate reservoirs with low reservoir energy and as such is being developed with water injection scheme from day one. As such, effective monitoring of downhole injection parameters is important from an early stage.\u0000 A common industry practice to monitor these parameters is to install Permanent Downhole Gauge (PDHG) and Distributed Temperature Sensing (DTS) system. Recently, a new smart Hybrid Technology has been developed to measure the downhole data at surface. This paper describes the successful application of this hybrid technology in a green onshore oil field development. Details are presented about the well bore segmentation design of the DTS system, the hybrid cable installation and the operational challenges with the hookup to the wellhead control system. The paper also presents the data acquired during commissioning job, and interpretation of the temperature data which was used to generate the injection profile along the wellbore. Finally, a strategy for future implementation of the DTS system is discussed.\u0000 Overall, this technology showcases the application of the smart hybrid completion for real-time monitoring of the water injection profile, including the pressure and rates along with injection volume per segment in the horizontal section. Real-time data from the hybrid technology has been integrated to digital oil field implementation to enhance the real time decision making to optimize the injection rates and to allow the operator to implement the decisions without any delay. This technology optimized the cables requirement and maximized the utilization of cable for multi-application environment to support acquiring Pressure, DTS and DAS data to generate real time injection profile.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79385858","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. Al-Awadi, B. Al-Ajmi, Akash Ranjan, Yousef Al-Enezi
The objective of this paper is to describe the production enhancement by the application of Propellant stimulation perforation during testing. During testing of a very tight carbonate reservoir (5% average porosity) the well productivity before and after propellant stimulation was studied for it's effectiveness. Propellant stimulation is achieved by burning the propellant material chemically and generating the gas by combustion. Gases generate a peak pressure that exceeds the fracture gradient of formation. High pressure gases injects at extremely high rates for a few milliseconds, resulting in creating micro fractures in the reservoir near the wellbore area which may result in good reservoir connectivity. Based on the subsurface information from offset wells, a vertical exploratory well drilled to delineate the potential of the target reservoir. Three sets of intervals were perforated in the target carbonate reservoir, in underbalanced condition and all intervals were tested together with Drill Stem Test (DST) tools. Matrix stimulation carried out using emulsified acid. During cleanup period, the flowing pressure continuously declined and finally only gas return was observed at surface. Flow period lasted for 30 hours. Production logging results showed that only the top perforation interval was contributing to the well flow. After detailed review of PLT results and open hole logs the middle perforations was selected for the propellant stimulation. Well was filled with 2% KCL brine and the middle section was stimulated thru’ tubing using 15ft. of 2″ propellant stimulation tool on wireline. Matrix stimulation repeated with diverter and emulsified acid for all the perforated interval. Flowed the well for cleanup followed by rate measurement for 15 hours showed improved flowing pressure and increased liquid rate. Second production logging results showed that both the top and middle perforation interval is contributing to the total flow. Middle perforation contributing to flow after use of matrix propellant stimulation. Propellant stimulation was successfully applied in tight carbonate reservoir. The production logs recorded pre & post of the propellant stimulation clearly indicates gain in oil production rate & improvement of flowing pressure in tight carbonate reservoir. During Shut-in survey, no cross flow was observed between the perforations and no flow behind casing. The data acquired using production logging will provide procedures for testing new exploration wells in similar reservoirs. Propellant stimulation is economical and enhances the effectiveness of standard acid stimulation in carbonate reservoirs. Propellant stimulation executed in tight carbonate reservoir of exploration well in State of Kuwait was remarkable success. This mechanism will aid to produce oil from the tight carbonate reservoirs.
{"title":"Production Enhancement in Tight Carbonate Reservoir with Propellant Stimulation Technique: Case Study in the State of Kuwait","authors":"M. Al-Awadi, B. Al-Ajmi, Akash Ranjan, Yousef Al-Enezi","doi":"10.2118/192979-MS","DOIUrl":"https://doi.org/10.2118/192979-MS","url":null,"abstract":"\u0000 \u0000 \u0000 The objective of this paper is to describe the production enhancement by the application of Propellant stimulation perforation during testing. During testing of a very tight carbonate reservoir (5% average porosity) the well productivity before and after propellant stimulation was studied for it's effectiveness.\u0000 \u0000 \u0000 \u0000 Propellant stimulation is achieved by burning the propellant material chemically and generating the gas by combustion. Gases generate a peak pressure that exceeds the fracture gradient of formation. High pressure gases injects at extremely high rates for a few milliseconds, resulting in creating micro fractures in the reservoir near the wellbore area which may result in good reservoir connectivity.\u0000 Based on the subsurface information from offset wells, a vertical exploratory well drilled to delineate the potential of the target reservoir. Three sets of intervals were perforated in the target carbonate reservoir, in underbalanced condition and all intervals were tested together with Drill Stem Test (DST) tools. Matrix stimulation carried out using emulsified acid. During cleanup period, the flowing pressure continuously declined and finally only gas return was observed at surface. Flow period lasted for 30 hours. Production logging results showed that only the top perforation interval was contributing to the well flow.\u0000 After detailed review of PLT results and open hole logs the middle perforations was selected for the propellant stimulation. Well was filled with 2% KCL brine and the middle section was stimulated thru’ tubing using 15ft. of 2″ propellant stimulation tool on wireline. Matrix stimulation repeated with diverter and emulsified acid for all the perforated interval.\u0000 Flowed the well for cleanup followed by rate measurement for 15 hours showed improved flowing pressure and increased liquid rate. Second production logging results showed that both the top and middle perforation interval is contributing to the total flow. Middle perforation contributing to flow after use of matrix propellant stimulation.\u0000 \u0000 \u0000 \u0000 Propellant stimulation was successfully applied in tight carbonate reservoir. The production logs recorded pre & post of the propellant stimulation clearly indicates gain in oil production rate & improvement of flowing pressure in tight carbonate reservoir. During Shut-in survey, no cross flow was observed between the perforations and no flow behind casing. The data acquired using production logging will provide procedures for testing new exploration wells in similar reservoirs. Propellant stimulation is economical and enhances the effectiveness of standard acid stimulation in carbonate reservoirs.\u0000 \u0000 \u0000 \u0000 Propellant stimulation executed in tight carbonate reservoir of exploration well in State of Kuwait was remarkable success. This mechanism will aid to produce oil from the tight carbonate reservoirs.\u0000","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"62 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72782923","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 paper is to communicate operational and engineering process enhancement and cost saving initiatives in advanced well completions. The initiatives were identified following a detailed review of industrywide advanced completion best practices standardized over the past decade. Several operational and engineering best practices involving inflow control valves (ICVs), inflow control devices (ICDs), zonal isolation (mechanical and swell packers), multistage fracturing (MSF) and sand control technologies were examined. In addition, downhole pressure relief requirements were also considered to introduce new ways of enhancing well integrity by preventing casing corrosion. A standard research and development methodology was utilized for this review. The methodology was based on collecting and documenting industrywide actual operational and engineering challenges in advanced well completion deployments for both oil and gas fields. These challenges resulted in either lost time at the rig site, necessitated workovers, or rigless operations. Examples of such challenges include extreme frictional forces during ICD deployments, repetitive solids removal practices prior to running ICVs, coiled tubing milling requirements for MSF, wash pipe deployments for downhole sand screen circulation, and calcium carbonate scale deposition in sand screens. The research also encompass a literature review for identifying further advanced completion challenges across the industry. The review resulted in identifying several areas of potential improvement. As a result, multiple engineering and operational process enhancement initiatives were recommended. This includes the utilization of centralizers to reduce frictional forces in ICD deployments. Also, the application of isolation valves to eliminate wash pipe requirements in screens or ICDs. Moreover, running downhole annular relief check valves to preserve tubular integrity by eliminating casing-to-casing annular (CCA) pressure communication and utilization of mono-bore ball seat technology to eliminate milling in MSF. Finally, the utilization of sacrificial completion accessories to improve ICV cleanup practices and save rig time in addition to several other relevant initiatives across the industry. In summary, the paper provides a deep dive into several technical advanced completion challenges across the industry. Also, several new initiatives are proposed with the objective of achieving significant cost savings. It is intended for these initiatives to be adopted as new advanced completion best practices. Not only to yield significant cost savings, but also to supplement the existing best practices body of literature in the areas of ICVs, ICDs, zonal isolation, MSF, well integrity and sand control technology.
{"title":"A Review of Industry-Wide Advanced Completion Best Practices","authors":"M. Al-Rabeh, K. R. Al-Noaimi, J. Brown","doi":"10.2118/193112-MS","DOIUrl":"https://doi.org/10.2118/193112-MS","url":null,"abstract":"\u0000 The objective of this paper is to communicate operational and engineering process enhancement and cost saving initiatives in advanced well completions. The initiatives were identified following a detailed review of industrywide advanced completion best practices standardized over the past decade. Several operational and engineering best practices involving inflow control valves (ICVs), inflow control devices (ICDs), zonal isolation (mechanical and swell packers), multistage fracturing (MSF) and sand control technologies were examined. In addition, downhole pressure relief requirements were also considered to introduce new ways of enhancing well integrity by preventing casing corrosion.\u0000 A standard research and development methodology was utilized for this review. The methodology was based on collecting and documenting industrywide actual operational and engineering challenges in advanced well completion deployments for both oil and gas fields. These challenges resulted in either lost time at the rig site, necessitated workovers, or rigless operations. Examples of such challenges include extreme frictional forces during ICD deployments, repetitive solids removal practices prior to running ICVs, coiled tubing milling requirements for MSF, wash pipe deployments for downhole sand screen circulation, and calcium carbonate scale deposition in sand screens. The research also encompass a literature review for identifying further advanced completion challenges across the industry.\u0000 The review resulted in identifying several areas of potential improvement. As a result, multiple engineering and operational process enhancement initiatives were recommended. This includes the utilization of centralizers to reduce frictional forces in ICD deployments. Also, the application of isolation valves to eliminate wash pipe requirements in screens or ICDs. Moreover, running downhole annular relief check valves to preserve tubular integrity by eliminating casing-to-casing annular (CCA) pressure communication and utilization of mono-bore ball seat technology to eliminate milling in MSF. Finally, the utilization of sacrificial completion accessories to improve ICV cleanup practices and save rig time in addition to several other relevant initiatives across the industry.\u0000 In summary, the paper provides a deep dive into several technical advanced completion challenges across the industry. Also, several new initiatives are proposed with the objective of achieving significant cost savings. It is intended for these initiatives to be adopted as new advanced completion best practices. Not only to yield significant cost savings, but also to supplement the existing best practices body of literature in the areas of ICVs, ICDs, zonal isolation, MSF, well integrity and sand control technology.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"97 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75035718","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}
Elkin Arroyo Negrete, J. Rodiguez, S. Goryachev, N. Belova, Ahmed Yahya Al Blooshi, M. Basioni
History matching (HM) is a mandatory step for any reservoir simulation study. Without a proper history match, a reservoir simulation model may lose credibility, or even worse, may lead to erroneous conclusions. HM is typically approached by reservoir enginners (RE) using a trial and error method, but there is a new, more advanced methodology known as computer assisted or automatic automatic history matching. Although assisted HM technology is well developed, its acceptance in the RE community has been slow. This paper aims to explain the concepts in a simple manner and suggest practical tips to make it easier for a practitioner to use automatic HM technology properly.
{"title":"Automatic History Matching Theory, Implementation, and Field Applications","authors":"Elkin Arroyo Negrete, J. Rodiguez, S. Goryachev, N. Belova, Ahmed Yahya Al Blooshi, M. Basioni","doi":"10.2118/193018-MS","DOIUrl":"https://doi.org/10.2118/193018-MS","url":null,"abstract":"\u0000 History matching (HM) is a mandatory step for any reservoir simulation study. Without a proper history match, a reservoir simulation model may lose credibility, or even worse, may lead to erroneous conclusions. HM is typically approached by reservoir enginners (RE) using a trial and error method, but there is a new, more advanced methodology known as computer assisted or automatic automatic history matching. Although assisted HM technology is well developed, its acceptance in the RE community has been slow. This paper aims to explain the concepts in a simple manner and suggest practical tips to make it easier for a practitioner to use automatic HM technology properly.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74331644","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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