This paper presents how Artificial Intelligence (AI) / Machine Learning (ML) technology uses unsupervised genetics algorithms in Exploration, Drilling Operations, Field Appraisal, Development and multiple 3D seismic volumes comparisons to minimize geological risk and uncertainty resulting in increased capital efficiency. We will present a high level overview of why this technology was invented and how it works. We will show you how you can use it to significantly reduce the time to achieve your organizational goals while reducing geotechnical risk and uncertainty and optimize the cycle time from Lead to Production. Outputs include a comprehensive analysis of your entire 3D Seismic Data Volume to identify and high grade, quality leads and prospects with high resource potential in the near, medium and long term. This approach will allow an evaluation of the field geological risk (reservoir distribution, trap, seal, source, hydrocarbon migration pathway from source into reservoir) and initial possible hydrocarbon content/type evaluation (e.g. DHI evaluation) without disrupting your current workflow. The results will quickly delineate possible structural and stratigraphic targets. This will also provide the Production Asset with additional support in their appraisal and development drilling programmes. Optimally place horizontal wells and injectors / offtakes in Improved Oil Recovery/Enhanced Oil Recovery (IOR / EOR) projects in areas of the field having the highest reservoir continuity to optimize the cycle time from concept to production. The case studies and examples presented will demonstrate how the technology and approach serve to increase the probability of success leading to increased capital efficiency and profitability.
{"title":"Artificial Intelligence AI / Machine Learning ML Drives Increased Capital Efficiency and Minimizes Geological Risk in E&P Operations","authors":"A. Aming","doi":"10.2118/200978-ms","DOIUrl":"https://doi.org/10.2118/200978-ms","url":null,"abstract":"\u0000 This paper presents how Artificial Intelligence (AI) / Machine Learning (ML) technology uses unsupervised genetics algorithms in Exploration, Drilling Operations, Field Appraisal, Development and multiple 3D seismic volumes comparisons to minimize geological risk and uncertainty resulting in increased capital efficiency. We will present a high level overview of why this technology was invented and how it works. We will show you how you can use it to significantly reduce the time to achieve your organizational goals while reducing geotechnical risk and uncertainty and optimize the cycle time from Lead to Production. Outputs include a comprehensive analysis of your entire 3D Seismic Data Volume to identify and high grade, quality leads and prospects with high resource potential in the near, medium and long term. This approach will allow an evaluation of the field geological risk (reservoir distribution, trap, seal, source, hydrocarbon migration pathway from source into reservoir) and initial possible hydrocarbon content/type evaluation (e.g. DHI evaluation) without disrupting your current workflow. The results will quickly delineate possible structural and stratigraphic targets. This will also provide the Production Asset with additional support in their appraisal and development drilling programmes. Optimally place horizontal wells and injectors / offtakes in Improved Oil Recovery/Enhanced Oil Recovery (IOR / EOR) projects in areas of the field having the highest reservoir continuity to optimize the cycle time from concept to production. The case studies and examples presented will demonstrate how the technology and approach serve to increase the probability of success leading to increased capital efficiency and profitability.","PeriodicalId":11075,"journal":{"name":"Day 1 Mon, June 28, 2021","volume":"29 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78546853","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}
In July 2021, commemorations will be held to mark the 33 years since the 1988 Piper Alpha tragedy in the UK sector of the North Sea where 167 oil field workers lost their lives. Without question, the incident was a watershed event for the international oil and gas industry not simply because of the immediate toll in human lives lost, but also in terms of the devasting aftermath endured by countless friends, families and loved ones whose lives were forever changed. The tragedy also served to illustrate just how poorly the oil and gas industry really understood and managed those operating risks that possessed the potential for catastrophic loss, both in terms of business cost and overall reputational impact. In the wake of the public enquiry that followed and chaired by Lord Cullen of Whitekirk, one of the principal recommendations required that the international oil and gas industry do a much better job in determining both its major hazards (i.e. major operating risks) and also in creating the necessary operating conditions to demonstrate that such things were being well managed. The objective being to provide tangible assurance that the likelihood of the industry ever incurring such a calamitous event again in the future had been reduced to as low as reasonably practicable (ALARP). In taking its responsibilities very seriously, the international oil and gas industry responded by raising the profile of the management of Health, Safety and the Environment (HSE) across the wide spectrum of its global operations. By the mid-nineties, the industry had implemented comprehensive and structured systems of work within the framework of purposely built HSE Management Systems using templates designed and developed for the industry via the International Oil and Gas Producers (IOGP)*.
{"title":"Catastrophic Events and Human Error: A Few Rotten Apples or Organizational Dysfunction?","authors":"Peter V. Bridle","doi":"10.2118/200942-ms","DOIUrl":"https://doi.org/10.2118/200942-ms","url":null,"abstract":"\u0000 In July 2021, commemorations will be held to mark the 33 years since the 1988 Piper Alpha tragedy in the UK sector of the North Sea where 167 oil field workers lost their lives. Without question, the incident was a watershed event for the international oil and gas industry not simply because of the immediate toll in human lives lost, but also in terms of the devasting aftermath endured by countless friends, families and loved ones whose lives were forever changed. The tragedy also served to illustrate just how poorly the oil and gas industry really understood and managed those operating risks that possessed the potential for catastrophic loss, both in terms of business cost and overall reputational impact.\u0000 In the wake of the public enquiry that followed and chaired by Lord Cullen of Whitekirk, one of the principal recommendations required that the international oil and gas industry do a much better job in determining both its major hazards (i.e. major operating risks) and also in creating the necessary operating conditions to demonstrate that such things were being well managed. The objective being to provide tangible assurance that the likelihood of the industry ever incurring such a calamitous event again in the future had been reduced to as low as reasonably practicable (ALARP).\u0000 In taking its responsibilities very seriously, the international oil and gas industry responded by raising the profile of the management of Health, Safety and the Environment (HSE) across the wide spectrum of its global operations. By the mid-nineties, the industry had implemented comprehensive and structured systems of work within the framework of purposely built HSE Management Systems using templates designed and developed for the industry via the International Oil and Gas Producers (IOGP)*.","PeriodicalId":11075,"journal":{"name":"Day 1 Mon, June 28, 2021","volume":"26 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74557552","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}
J. Álvarez, O. Espinola, Luis Rodrigo Diaz, Lilith Cruces
Increase recovery from mature oil reservoirs requires the definition of enhanced reservoir management strategies, involving the implementation of advanced methodologies and technologies in the field's operation. This paper presents a digital workflow enabling the integration of commonly isolated elements such as: gauges, flowmeters, inflow control devices; analysis methods and data, used to improve scientific understanding of subsurface flow dynamics and determine improved operational decisions that support field's reservoir management strategy. It also supports evaluation of reservoir extent, hydraulic communication, artificial lift impact in the near-wellbore zone and reservoir response to injected fluids and coning phenomenon. This latest is used as an example to demonstrate the applicability of this workflow to improve and support operational decisions, minimizing water and gas production due to coning, that usually results in increasing production operation costs and it has a direct impact decreasing reservoir energy in mature saturated oil reservoirs. This innovative workflow consists on the continuous interpretation of data from downhole gauges, referred in this paper as data-driven; as well as analytical and numerical simulation methodologies using real-time raw data as an input, referred in this paper as model-driven, not commonly used to analyze near wellbore subsurface phenomena like coning and its impact in surface operation. The resulting analyses are displayed through an extensive visualization tool that provides instant insight to reservoir characterization and productivity groups, improving well and reservoir performance prediction capabilities for complex reservoirs such as mature saturated reservoirs with an associated aquifer, where undesired water and gas production is a continuous challenge that incorporates unexpected operational expenses.
{"title":"Digital Workflow to Enhance Reservoir Management Strategies for A Complex Oil Field Through Real Time and Advanced Engineering Monitoring Solution","authors":"J. Álvarez, O. Espinola, Luis Rodrigo Diaz, Lilith Cruces","doi":"10.2118/200932-ms","DOIUrl":"https://doi.org/10.2118/200932-ms","url":null,"abstract":"\u0000 Increase recovery from mature oil reservoirs requires the definition of enhanced reservoir management strategies, involving the implementation of advanced methodologies and technologies in the field's operation.\u0000 This paper presents a digital workflow enabling the integration of commonly isolated elements such as: gauges, flowmeters, inflow control devices; analysis methods and data, used to improve scientific understanding of subsurface flow dynamics and determine improved operational decisions that support field's reservoir management strategy. It also supports evaluation of reservoir extent, hydraulic communication, artificial lift impact in the near-wellbore zone and reservoir response to injected fluids and coning phenomenon. This latest is used as an example to demonstrate the applicability of this workflow to improve and support operational decisions, minimizing water and gas production due to coning, that usually results in increasing production operation costs and it has a direct impact decreasing reservoir energy in mature saturated oil reservoirs.\u0000 This innovative workflow consists on the continuous interpretation of data from downhole gauges, referred in this paper as data-driven; as well as analytical and numerical simulation methodologies using real-time raw data as an input, referred in this paper as model-driven, not commonly used to analyze near wellbore subsurface phenomena like coning and its impact in surface operation. The resulting analyses are displayed through an extensive visualization tool that provides instant insight to reservoir characterization and productivity groups, improving well and reservoir performance prediction capabilities for complex reservoirs such as mature saturated reservoirs with an associated aquifer, where undesired water and gas production is a continuous challenge that incorporates unexpected operational expenses.","PeriodicalId":11075,"journal":{"name":"Day 1 Mon, June 28, 2021","volume":"355 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76496385","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}
Julio Cesar Villanueva Alonso, Oswaldo Espinola Gonzalez, Julieta Alvarez Martínez
Most operator companies work under a philosophy of responding with mitigation strategies rather than prevention ones to flow assurance problems when they arise. Although mitigation strategies help to maintain a stable production, gas condensate fields require the implementation of proactive techniques to be prepared for future scenarios, especially when it comes to deep water environments, since the combination of the changes in composition of a condensate fluid and the thermodynamic considerations of producing in deep water fields increase the frequency of operational problems and therefore, additional costs and risks. Furthermore, the concept of management is not frequently applied to the Flow Assurance area as much as the concept of Reservoir Management. Analogous to best Reservoir Management practices, this concept can be translated to the design and operation in the flow assurance area to provide more robust and precise analysis. Taking these considerations into account, a proactive approach is required, so that operator companies can better prepare and act in an optimum way. This paper presents a Flow Assurance Management Strategy (FAMS) methodology focused on increasing and improving the response capacity through understanding the behavior of production trends, predicting the come up of potential flow assurance problems. By the implementation of this methodology, we are seeking to operators obtain a full perspective of all the potential problems that will eventually can take place in their fields, identifying, when, where and why they will occur, and thus, allowing to set proactive actions to minimize unexpected potential flow assurance problems. The objective of this paper is to share a detailed methodology, which is intended to apply for any kind of flow assurance problem, helping operators to implement the best solution according to their capabilities and to set a base to homologate the concept of management, additionally, a short case in which an optimization study was carried out is shown for demonstration purposes.
{"title":"Leading Edge Flow Assurance Management Strategy to Optimize the Design and Operations, for a Deepwater Gas Condensate Reservoir, Reducing Costs and Associated Risks Through Integrated Engineering Analysis","authors":"Julio Cesar Villanueva Alonso, Oswaldo Espinola Gonzalez, Julieta Alvarez Martínez","doi":"10.2118/200894-ms","DOIUrl":"https://doi.org/10.2118/200894-ms","url":null,"abstract":"\u0000 Most operator companies work under a philosophy of responding with mitigation strategies rather than prevention ones to flow assurance problems when they arise. Although mitigation strategies help to maintain a stable production, gas condensate fields require the implementation of proactive techniques to be prepared for future scenarios, especially when it comes to deep water environments, since the combination of the changes in composition of a condensate fluid and the thermodynamic considerations of producing in deep water fields increase the frequency of operational problems and therefore, additional costs and risks.\u0000 Furthermore, the concept of management is not frequently applied to the Flow Assurance area as much as the concept of Reservoir Management. Analogous to best Reservoir Management practices, this concept can be translated to the design and operation in the flow assurance area to provide more robust and precise analysis.\u0000 Taking these considerations into account, a proactive approach is required, so that operator companies can better prepare and act in an optimum way. This paper presents a Flow Assurance Management Strategy (FAMS) methodology focused on increasing and improving the response capacity through understanding the behavior of production trends, predicting the come up of potential flow assurance problems.\u0000 By the implementation of this methodology, we are seeking to operators obtain a full perspective of all the potential problems that will eventually can take place in their fields, identifying, when, where and why they will occur, and thus, allowing to set proactive actions to minimize unexpected potential flow assurance problems.\u0000 The objective of this paper is to share a detailed methodology, which is intended to apply for any kind of flow assurance problem, helping operators to implement the best solution according to their capabilities and to set a base to homologate the concept of management, additionally, a short case in which an optimization study was carried out is shown for demonstration purposes.","PeriodicalId":11075,"journal":{"name":"Day 1 Mon, June 28, 2021","volume":"18 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83429745","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}
K. Francis-LaCroix, J. King, Laura Moonilal, Reon Rauceo
The remediation of flow assurance challenges in field's offshore Trinidad is a foci of oil and gas operators in Trinidad West Indies. These challenges are heightened by field maturity and the corresponding increase in water production. With this increased water influx, production chemistry and specific flow assurance challenges also arise. One of the primary challenges include the precipitation and deposition of inorganic mineral scales. Coupled with this, mineralogy data and core data studies indicated that the sands of some of the producing fields offshore Trinidad are highly susceptible to scale precipitation in the formation water (Holder, 1990). As such, measures are often implemented to assure the successful and economical flow of hydrocarbon stream from the reservoir to the point of sale. In this geographical area, stimulation acid treatments were typically deployed for remediation of formation damage of which scale precipitation was a main type. However, based on the previous production histories, the production gains following these acid treatments were short-lived. In addition, the accompanying financial loss is often compounded by other flow assurance challenges that were precursed by scale deposition. This paper will discuss the use of inhibitory squeeze application techniques as a preventative approach to formation damage resulting from scale precipitation. This application is the first of its kind performed in the Teak field. Thus, results obtained will highlight further opportunity to successfully stimulate other fields in this region prone to scale deposition. The results obtained from this application will be represented in the form of a comparative analysis. The production indices attained via the conventional means of scale remediation, will be compared with that achieved via the strategic placement of phosphonate-based chemistries. Additionally, methods employed to avert the challenges of squeeze treatments in offshore environments will also be discussed as well as lessons learned from this approach.
{"title":"An Enhanced Approach to the Remediation of Scale Induced Formation Damage - Offshore Trinidad","authors":"K. Francis-LaCroix, J. King, Laura Moonilal, Reon Rauceo","doi":"10.2118/200903-ms","DOIUrl":"https://doi.org/10.2118/200903-ms","url":null,"abstract":"\u0000 The remediation of flow assurance challenges in field's offshore Trinidad is a foci of oil and gas operators in Trinidad West Indies. These challenges are heightened by field maturity and the corresponding increase in water production. With this increased water influx, production chemistry and specific flow assurance challenges also arise. One of the primary challenges include the precipitation and deposition of inorganic mineral scales. Coupled with this, mineralogy data and core data studies indicated that the sands of some of the producing fields offshore Trinidad are highly susceptible to scale precipitation in the formation water (Holder, 1990). As such, measures are often implemented to assure the successful and economical flow of hydrocarbon stream from the reservoir to the point of sale.\u0000 In this geographical area, stimulation acid treatments were typically deployed for remediation of formation damage of which scale precipitation was a main type. However, based on the previous production histories, the production gains following these acid treatments were short-lived. In addition, the accompanying financial loss is often compounded by other flow assurance challenges that were precursed by scale deposition.\u0000 This paper will discuss the use of inhibitory squeeze application techniques as a preventative approach to formation damage resulting from scale precipitation. This application is the first of its kind performed in the Teak field. Thus, results obtained will highlight further opportunity to successfully stimulate other fields in this region prone to scale deposition. The results obtained from this application will be represented in the form of a comparative analysis. The production indices attained via the conventional means of scale remediation, will be compared with that achieved via the strategic placement of phosphonate-based chemistries. Additionally, methods employed to avert the challenges of squeeze treatments in offshore environments will also be discussed as well as lessons learned from this approach.","PeriodicalId":11075,"journal":{"name":"Day 1 Mon, June 28, 2021","volume":"37 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80103885","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. Al-Azmi, T. Al-Yaqout, D. Al-Jutaili, K. Bhatia, Amr Abdelbaky, A. Alboueshi
Excessive water production from hydrocarbon reservoirs is a serious issue faced by the industry, particularly for mature fields. Higher water cut adversely affects the economics of the producing wells, thus it is undesirable. Disposal and reinjection of ever-increasing volumes of produced water poses additional liability. A significant challenge faced in the mature Umm Gudair field is assuring hydrocarbon flow through high water-prone intervals. In recent times, field development strategies have begun to prioritize new well intervention technology because of the advantages of minimized water cut, higher production rates, and improved overall reserve recovery (hydrocarbon in place). This paper discusses the field implementation of a downhole chemical methodology, "first of its kind" designed and applied, that has created a positive impact in overall productivity. To solve these challenges, the treatment was highly modified as fit-for-purpose to address the unique challenges of electric submersible pump (ESP)-driven well operations, formation technical difficulties, high-stakes economics, and high-water potential from these formations. A unique Organically Crosslinked Polymer (OCP) system with a tail-in Rigid Setting Material (RSM) system was implemented as a porosity-fill sealant in a high-water-cut well to selectively reduce water production. A pre-flush was pumped ahead of the treatment to remove deposits that could have prevented the polymer from effective gelation. The treatment was then overdisplaced with brine. The OCP system is injected into the formation as a low viscosity solution using the spot and hesitation squeeze method via bullheading. It activates at a predicted time to form a 3-D rigid hydrogel to completely shut off matrix permeability, fractures, fissures, and channels, thus creating an artificial barrier seal in the reservoir. The tail-in near wellbore RSM system rapidly develops a high compressive strength to avoid any formation loss before setting. This holistic approach helps to create a robust sealant for blocking the unwanted water-producing zone, impeding water flow, and facilitating increased hydrocarbon flow. A direct comparison of the application of this system with conventional cement squeeze treatments is presented to illustrate the advantage of having a deep matrix penetration for a more efficient water shutoff in this field. A direct result of the implemented treatment is that the post-operation well test and production data showed a high-sustained production at lower rate with significantly reduced watercut, confirming this technology is one of successful chemical water shut off techniques this field. This paper summarizes the candidate selection, design processes, challenges encountered, and production response, and can be considered a best practice for addressing high water production challenges in similar conditions in other fields.
{"title":"Application of Specially Designed Polymers in High Water Cut Wells- A Holistic Well-Intervention Technology Applied in Umm Gudair Field, Kuwait","authors":"A. Al-Azmi, T. Al-Yaqout, D. Al-Jutaili, K. Bhatia, Amr Abdelbaky, A. Alboueshi","doi":"10.2118/200957-ms","DOIUrl":"https://doi.org/10.2118/200957-ms","url":null,"abstract":"\u0000 Excessive water production from hydrocarbon reservoirs is a serious issue faced by the industry, particularly for mature fields. Higher water cut adversely affects the economics of the producing wells, thus it is undesirable. Disposal and reinjection of ever-increasing volumes of produced water poses additional liability. A significant challenge faced in the mature Umm Gudair field is assuring hydrocarbon flow through high water-prone intervals.\u0000 In recent times, field development strategies have begun to prioritize new well intervention technology because of the advantages of minimized water cut, higher production rates, and improved overall reserve recovery (hydrocarbon in place). This paper discusses the field implementation of a downhole chemical methodology, \"first of its kind\" designed and applied, that has created a positive impact in overall productivity. To solve these challenges, the treatment was highly modified as fit-for-purpose to address the unique challenges of electric submersible pump (ESP)-driven well operations, formation technical difficulties, high-stakes economics, and high-water potential from these formations.\u0000 A unique Organically Crosslinked Polymer (OCP) system with a tail-in Rigid Setting Material (RSM) system was implemented as a porosity-fill sealant in a high-water-cut well to selectively reduce water production. A pre-flush was pumped ahead of the treatment to remove deposits that could have prevented the polymer from effective gelation. The treatment was then overdisplaced with brine. The OCP system is injected into the formation as a low viscosity solution using the spot and hesitation squeeze method via bullheading. It activates at a predicted time to form a 3-D rigid hydrogel to completely shut off matrix permeability, fractures, fissures, and channels, thus creating an artificial barrier seal in the reservoir. The tail-in near wellbore RSM system rapidly develops a high compressive strength to avoid any formation loss before setting. This holistic approach helps to create a robust sealant for blocking the unwanted water-producing zone, impeding water flow, and facilitating increased hydrocarbon flow. A direct comparison of the application of this system with conventional cement squeeze treatments is presented to illustrate the advantage of having a deep matrix penetration for a more efficient water shutoff in this field.\u0000 A direct result of the implemented treatment is that the post-operation well test and production data showed a high-sustained production at lower rate with significantly reduced watercut, confirming this technology is one of successful chemical water shut off techniques this field. This paper summarizes the candidate selection, design processes, challenges encountered, and production response, and can be considered a best practice for addressing high water production challenges in similar conditions in other fields.","PeriodicalId":11075,"journal":{"name":"Day 1 Mon, June 28, 2021","volume":"227 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78049249","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}
Dakhil Rasheed Al Enezi, M. Hajeri, S.. Gholum, Swetalina Nath, T. Ahmad, Z. Ramadan, Showkat Osman, A. Ahmed, N. Al-Hamad, D. Kumar, M. Siam, S. Abdelbaset
As part of any successful development plan of any hydrocarbon field, drilling boreholes safely is a key factor to make the entire process safe, economic and environmentally friendly. One of the main factors that dictates whether a borehole is going to be drilled safely or not is to understand the geomichanical behavior of the different formation to be penetrated. A definition of geomechanics could be stated as the science that studies the relationship between each of; in-situ stresses, rock mechanics, and the drilling fluid properties. In Kuwait and during the course of efforts to develop Wara channel sands in Minagish Field to the west of the country, Kuwait Oil Company (KOC) realized that continuing to drill development wells using conventional drilling practices is not any more an easy task. Considerable non-productive time has been recorded due encountering events such as shale carvings and pack off leading to stuck pipe. In addition, partial to total lost circulation were faced while drilling through Mutriba Formation which added to the complexity of problem. This study involved gathering data from offset wells to build a mechanical earth model for the area where the new well is going to be drilled. The main objective of having the model built is to perform wellbore stability analysis (WBS) and compute the quantitative mud window values to insure stable and safe borehole drilling. As the case of any study, performing reliable WBS analysis requires accurate modeling of earth stresses and rock mechanical properties. This process is primarily based on sonic logs (compressional and shear slowness), formation bulk density and lithology distribution. The study started with an audit of the available data sets in the region to select the best offset wells and generating empirical correlations to fill- up any missing and/or poor-quality data zones. Initially,7offset wells were identified, based on the geological distribution and data availability.Out of them, only four wells were found to have compressional slowness and three with bulk density measurements. However, it is worth mentioning that no shear slowness measurements were available in any of the offset wells in the region. Due to this, a correlation based compressional-shear relationship from nearby wells was proposed for the pre-drill study. The mechanical properties were characterized using the tri-axial core test results available from Wara and Burgan Formations. Empirical correlations were developed to obtain static mechanical properties from the dynamical mechanical ones and log responses. In addition, horizontal stresses in the region were constrained with formation integrity test data to have better control on the model. Finally, after the WBS model was built,it was compared to the available caliper data from the offset wells for calibration purposes. The resulted pre-drill geomechanics model was used to advise on the drilling parameters (mud weight) to be used in drilling the new
{"title":"Realtime Drilling Geomechanics Aids Safe Drilling through Unstable Shales and Channel Sands of Wara Formations, Minagish Field, West Kuwait","authors":"Dakhil Rasheed Al Enezi, M. Hajeri, S.. Gholum, Swetalina Nath, T. Ahmad, Z. Ramadan, Showkat Osman, A. Ahmed, N. Al-Hamad, D. Kumar, M. Siam, S. Abdelbaset","doi":"10.2118/200929-ms","DOIUrl":"https://doi.org/10.2118/200929-ms","url":null,"abstract":"\u0000 As part of any successful development plan of any hydrocarbon field, drilling boreholes safely is a key factor to make the entire process safe, economic and environmentally friendly. One of the main factors that dictates whether a borehole is going to be drilled safely or not is to understand the geomichanical behavior of the different formation to be penetrated. A definition of geomechanics could be stated as the science that studies the relationship between each of; in-situ stresses, rock mechanics, and the drilling fluid properties. In Kuwait and during the course of efforts to develop Wara channel sands in Minagish Field to the west of the country, Kuwait Oil Company (KOC) realized that continuing to drill development wells using conventional drilling practices is not any more an easy task. Considerable non-productive time has been recorded due encountering events such as shale carvings and pack off leading to stuck pipe. In addition, partial to total lost circulation were faced while drilling through Mutriba Formation which added to the complexity of problem.\u0000 This study involved gathering data from offset wells to build a mechanical earth model for the area where the new well is going to be drilled. The main objective of having the model built is to perform wellbore stability analysis (WBS) and compute the quantitative mud window values to insure stable and safe borehole drilling.\u0000 As the case of any study, performing reliable WBS analysis requires accurate modeling of earth stresses and rock mechanical properties. This process is primarily based on sonic logs (compressional and shear slowness), formation bulk density and lithology distribution. The study started with an audit of the available data sets in the region to select the best offset wells and generating empirical correlations to fill- up any missing and/or poor-quality data zones. Initially,7offset wells were identified, based on the geological distribution and data availability.Out of them, only four wells were found to have compressional slowness and three with bulk density measurements. However, it is worth mentioning that no shear slowness measurements were available in any of the offset wells in the region. Due to this, a correlation based compressional-shear relationship from nearby wells was proposed for the pre-drill study.\u0000 The mechanical properties were characterized using the tri-axial core test results available from Wara and Burgan Formations. Empirical correlations were developed to obtain static mechanical properties from the dynamical mechanical ones and log responses. In addition, horizontal stresses in the region were constrained with formation integrity test data to have better control on the model. Finally, after the WBS model was built,it was compared to the available caliper data from the offset wells for calibration purposes.\u0000 The resulted pre-drill geomechanics model was used to advise on the drilling parameters (mud weight) to be used in drilling the new","PeriodicalId":11075,"journal":{"name":"Day 1 Mon, June 28, 2021","volume":"12 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88228628","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}
In 2015 and 2016, the Ministry of Energy and Energy Industries (MEEI) undertook a National Facilities Audit (NFA) to augment the periodic audit exercises of the Ministry. This Audit was the first of its kind conducted in Trinidad and Tobago and involved upstream, midstream and downstream energy sector companies. Some companies scored highly in the Audit, some were average and others below average. This paper will provide guidance to operators who scored below the average so that they can make the necessary adjustments to improve their Asset Integrity scores to above average and beyond in future. The selected consultant who performed the NFA developed a standardized audit protocol to audit all the companies. The MEEI set up a Steering Committee to oversee the execution and delivery of the audit to ensure it was conducted within the project's objectives. The consultant and MEEI representatives conducted joint audits, which involved document reviews, interviews and site visits. A Systems and Equipment Audit was conducted followed by a site visit. The project lasted 9 months, a total of 30 audits were conducted during the period, and a report prepared and presented to the MEEI by the consulta nts with the findings and recommendations. Scores were assigned to various categories in both the System and Equipment Audits, which contributed to a System score and Equipment score. From these two scores, an overall score was determined. The audit found that Asset Integrity Management (AIM) systems showed a wide variation across the industry, international companies were typically more advanced with AIM than domestic companies, the state-owned companies had the lowest scores and Joint Venture companies generally had the highest scores. Generally, many companies did poorly in the audit due to lack of proper documented internal procedures with respect to Asset Integrity. Companies that did well had well-documented procedures for process safety management. The paper will show the benefit of conducting a nationwide Asset Integrity Audit that can inspire other countries to consider doing likewise and thus encourage improved Asset Integrity Management in the global energy sector. The paper will go into the details of the audit so that in future companies would be more prepared for a similar type of audit, and who show significant improvements with their scores.
{"title":"Raising the National Average for Asset Integrity Management in the Energy Sector of a Small Island Developing State","authors":"M. Rudder, A. Kissoon, Indira Rampaul-Cheddie","doi":"10.2118/200934-ms","DOIUrl":"https://doi.org/10.2118/200934-ms","url":null,"abstract":"In 2015 and 2016, the Ministry of Energy and Energy Industries (MEEI) undertook a National Facilities Audit (NFA) to augment the periodic audit exercises of the Ministry. This Audit was the first of its kind conducted in Trinidad and Tobago and involved upstream, midstream and downstream energy sector companies. Some companies scored highly in the Audit, some were average and others below average. This paper will provide guidance to operators who scored below the average so that they can make the necessary adjustments to improve their Asset Integrity scores to above average and beyond in future. The selected consultant who performed the NFA developed a standardized audit protocol to audit all the companies. The MEEI set up a Steering Committee to oversee the execution and delivery of the audit to ensure it was conducted within the project's objectives. The consultant and MEEI representatives conducted joint audits, which involved document reviews, interviews and site visits. A Systems and Equipment Audit was conducted followed by a site visit. The project lasted 9 months, a total of 30 audits were conducted during the period, and a report prepared and presented to the MEEI by the consulta nts with the findings and recommendations. Scores were assigned to various categories in both the System and Equipment Audits, which contributed to a System score and Equipment score. From these two scores, an overall score was determined. The audit found that Asset Integrity Management (AIM) systems showed a wide variation across the industry, international companies were typically more advanced with AIM than domestic companies, the state-owned companies had the lowest scores and Joint Venture companies generally had the highest scores. Generally, many companies did poorly in the audit due to lack of proper documented internal procedures with respect to Asset Integrity. Companies that did well had well-documented procedures for process safety management. The paper will show the benefit of conducting a nationwide Asset Integrity Audit that can inspire other countries to consider doing likewise and thus encourage improved Asset Integrity Management in the global energy sector. The paper will go into the details of the audit so that in future companies would be more prepared for a similar type of audit, and who show significant improvements with their scores.","PeriodicalId":11075,"journal":{"name":"Day 1 Mon, June 28, 2021","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87497246","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. Izurieta, Alexander Albuja, A. Brito, W. Xuepeng, Feng Yuliang, I. Solis, Karina Proaño, Nelson Ramirez
Economical production from low-permeability oil-saturated reservoirs has always been a challenge in a basin known for its mature assets. M2 limestone is a new challenge. To characterize, it was necessary to use the methodology based on shale plays, integrating information from different logs using a proprietary evaluation method. Applying pillar fracturing, creating stable voids between pillars, and hence, infinite-conductivity channels in geomechanically competent candidates resulted in economical production and proved reserves from a low-permeability calcareous shale. Geomechanics, mineralogy, and saturated intervals were addressed by using a combination of rock mechanical properties and mineralogy, carbon/oxygen logs, and X-ray diffraction (XRD) on drilling cuttings. Once the prospective zones in the M2 limestone intervals were selected, a conventional fracturing treatment was designed using a 3-D gridded simulator. The candidate well was evaluated for pillar fracturing by using results from geomechanics and the conventional fracture application. A pumping schedule that included pillar volume, spacer, and tail in stages was then designed. Results from the fracture simulator were loaded in a numerical reservoir simulator, and different development scenarios were evaluated. M2 limestone has shown production potential near areas where volcanic intrusion is present, or indicated hydrocarbon potential by oil shows observed on cuttings and high-gas readings during drilling. The data used for this project was collected during conventional reservoir development but had never been evaluated using an unconventional reservoir approach. XRD analysis and acid solubility tests confirmed that the reservoir does not contain a high-carbonate content nor acid solubility. Diagnostic Fracture Injection Test (DFIT) and minifrac analysis helped to define the size and fracturing technique to be used. Results from this work provided a better understanding of the reservoir; a development plan is needed to improve the investment return for this type of project. Geomechanical evaluation is fundamental to the application and design of pillar fracturing. This fracturing technique was selected because it used 43% less proppant than a conventional job, reduced risk of screen out, and provided higher productivity over a conventional fracturing job. This is the first time that pillar fracturing has been applied in this Ecuadorian reservoir. The production outcome proved reserves of 32°API oil and resulted in the largest fracturing job in Ecuador. Different development scenarios are proposed based on the results from this well. A complete workflow to characterize, design a hydraulic fracture job using proprietary geomechanical candidate selection criteria, and develop an unconventional calcareous shale is presented. The available data are the same as in a conventional reservoir, whereas the evaluation technique, as well as fracture design, is customized to this type of re
{"title":"Pillar Fracturing Production Enhancement Results for an Unconventional Calcareous Shale in Ecuador","authors":"A. Izurieta, Alexander Albuja, A. Brito, W. Xuepeng, Feng Yuliang, I. Solis, Karina Proaño, Nelson Ramirez","doi":"10.2118/200987-ms","DOIUrl":"https://doi.org/10.2118/200987-ms","url":null,"abstract":"\u0000 Economical production from low-permeability oil-saturated reservoirs has always been a challenge in a basin known for its mature assets. M2 limestone is a new challenge. To characterize, it was necessary to use the methodology based on shale plays, integrating information from different logs using a proprietary evaluation method. Applying pillar fracturing, creating stable voids between pillars, and hence, infinite-conductivity channels in geomechanically competent candidates resulted in economical production and proved reserves from a low-permeability calcareous shale.\u0000 Geomechanics, mineralogy, and saturated intervals were addressed by using a combination of rock mechanical properties and mineralogy, carbon/oxygen logs, and X-ray diffraction (XRD) on drilling cuttings. Once the prospective zones in the M2 limestone intervals were selected, a conventional fracturing treatment was designed using a 3-D gridded simulator. The candidate well was evaluated for pillar fracturing by using results from geomechanics and the conventional fracture application. A pumping schedule that included pillar volume, spacer, and tail in stages was then designed. Results from the fracture simulator were loaded in a numerical reservoir simulator, and different development scenarios were evaluated.\u0000 M2 limestone has shown production potential near areas where volcanic intrusion is present, or indicated hydrocarbon potential by oil shows observed on cuttings and high-gas readings during drilling. The data used for this project was collected during conventional reservoir development but had never been evaluated using an unconventional reservoir approach. XRD analysis and acid solubility tests confirmed that the reservoir does not contain a high-carbonate content nor acid solubility. Diagnostic Fracture Injection Test (DFIT) and minifrac analysis helped to define the size and fracturing technique to be used. Results from this work provided a better understanding of the reservoir; a development plan is needed to improve the investment return for this type of project. Geomechanical evaluation is fundamental to the application and design of pillar fracturing. This fracturing technique was selected because it used 43% less proppant than a conventional job, reduced risk of screen out, and provided higher productivity over a conventional fracturing job. This is the first time that pillar fracturing has been applied in this Ecuadorian reservoir. The production outcome proved reserves of 32°API oil and resulted in the largest fracturing job in Ecuador. Different development scenarios are proposed based on the results from this well.\u0000 A complete workflow to characterize, design a hydraulic fracture job using proprietary geomechanical candidate selection criteria, and develop an unconventional calcareous shale is presented. The available data are the same as in a conventional reservoir, whereas the evaluation technique, as well as fracture design, is customized to this type of re","PeriodicalId":11075,"journal":{"name":"Day 1 Mon, June 28, 2021","volume":"51 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73082761","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}
Y. A. Mohamed, R. Ahmed, Ayman Abd El-ghany Al-Zahry, Amr Ismail Moustafa, Radi Ahmed Elnashar, Ayman Salama, A. Ouda, A. Mohamed
Drilling operations might require increasing mud weight beyond formation's fracture gradient margin which may lead to downhole losses into formation and other potential problems resulting in Non-Productive Time (NPT). This paper describes successful application of wellbore strengthening software (WSS) to simulate formations’ strengthening process by increasing Hoop Stress while drilling depleted reservoir sand or mechanically weak formations. The software model takes into consideration well design, basic rock properties and in-situ earth stresses. The paper also defines design of mud formula and lab procedures verifying the designed wellbore strengthening materials (WSM) blend and successful application in field. Design and selection of mud formula are main pillars of successful formation strengthening procedure to match with induced fractures width. Unlike other software models that use generic particle size distribution (PSD) data, software in this study takes into consideration PSD of specific batches of WSM to simulate wellbore strengthening process and recommend the optimum WSM blend, concentrations. Based on mud formula design from WSS, lab tests were conducted to verify concentrations and selection of WSM and accordingly formulas were applied successfully for complicated drilling operations. Static and dynamic formation strengthening techniques were applied successfully in multiple wells. Based on software results and recommendations, Techniques’ application managed to strengthen weak formations up to 121% of original fracture gradient, decreased section drilling time by 20% which resulted in drilling costs reduction by up to 24.2 %. As a result of this successful application in many critical wells, WSS results are now integral to operator's well plan to enhance wellbore pressure integrity of weak intervals, in following drilling operations. The presented study is based on an innovative approach to strengthen weak and depleted formations in critical drilling operations using exact PSD data of WSM batches, formation properties and customized software model, an optimum concentrations blend can be selected to strengthen wellbore and hence it can be customized for every application where optimum formation strengthening is required.
{"title":"Field Application of Software Model and Wellbore Strengthening Materials for Drilling Depleted Reservoirs and Mechanically Weak Formations in Gulf of Suez","authors":"Y. A. Mohamed, R. Ahmed, Ayman Abd El-ghany Al-Zahry, Amr Ismail Moustafa, Radi Ahmed Elnashar, Ayman Salama, A. Ouda, A. Mohamed","doi":"10.2118/200943-ms","DOIUrl":"https://doi.org/10.2118/200943-ms","url":null,"abstract":"\u0000 Drilling operations might require increasing mud weight beyond formation's fracture gradient margin which may lead to downhole losses into formation and other potential problems resulting in Non-Productive Time (NPT). This paper describes successful application of wellbore strengthening software (WSS) to simulate formations’ strengthening process by increasing Hoop Stress while drilling depleted reservoir sand or mechanically weak formations. The software model takes into consideration well design, basic rock properties and in-situ earth stresses. The paper also defines design of mud formula and lab procedures verifying the designed wellbore strengthening materials (WSM) blend and successful application in field. Design and selection of mud formula are main pillars of successful formation strengthening procedure to match with induced fractures width. Unlike other software models that use generic particle size distribution (PSD) data, software in this study takes into consideration PSD of specific batches of WSM to simulate wellbore strengthening process and recommend the optimum WSM blend, concentrations. Based on mud formula design from WSS, lab tests were conducted to verify concentrations and selection of WSM and accordingly formulas were applied successfully for complicated drilling operations. Static and dynamic formation strengthening techniques were applied successfully in multiple wells. Based on software results and recommendations, Techniques’ application managed to strengthen weak formations up to 121% of original fracture gradient, decreased section drilling time by 20% which resulted in drilling costs reduction by up to 24.2 %. As a result of this successful application in many critical wells, WSS results are now integral to operator's well plan to enhance wellbore pressure integrity of weak intervals, in following drilling operations. The presented study is based on an innovative approach to strengthen weak and depleted formations in critical drilling operations using exact PSD data of WSM batches, formation properties and customized software model, an optimum concentrations blend can be selected to strengthen wellbore and hence it can be customized for every application where optimum formation strengthening is required.","PeriodicalId":11075,"journal":{"name":"Day 1 Mon, June 28, 2021","volume":"17 2 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76991981","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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