N. Al-Maqsseed, E. Anthony, R. Bhagavatula, C. Rodenboog, E. Jamieson, A. Jha, Gong Hua, G. Al-Sharhan
The North Kuwait asset has several stacked producing reservoirs, further subdivided into multiple sub-layers, each sub-layer with substantial production potential. Over 75% of these sub-layers are depletion drive reservoirs requiring water injection for pressure support. Many existing/planned Injectors penetrated over- and under-lying layers that has good production potential. Similarly, many Producers penetrated adjacent reservoirs/layers that required injection support. With limited surface real estate available to accommodate the increasing demand for appropriately located Injectors and Producers, conventional single-purpose wellbores have become an unaffordable luxury. An innovative concept was developed in-house by using a single wellbore for an unconventional dual purpose, namely, Simultaneous Injection and Production (SIP). Owing to the significant differences in fluid rates and temperatures, absolute and relative tubular movement play a significant role in completion integrity and longevity. Collaboration with one of KOC’s major Electrical Submersible Pump (ESP) service partners yielded a unique dual concentric design that facilitates ease in completion deployment and equal ease in retrieval when necessary. Two (2) scenarios were considered in the dual concentric Completion design, namely Inject above, produce below (Scenario – A), and Inject below, produce above (Scenario – B). Tubing stress/movement software were used to simulate and design tubular specifications that would maintain optimum completion integrity in either of three (3) Operating Conditions: Inject only, Produce only, and Simultaneous Injection and Artificial Lift Production. Due to the complexity and uniqueness of the SIP configuration, completing the Well on Paper (CWOP) sessions proved to be a very effective tool in the planning process of this completion. The ESP Service Partner performed a System Integration Test (SIT) in a test well to verify equipment functionality and optimize the assembly procedure. Following the successful (SIT), the first installation was completed in early 2017. The systems installed to date were originally Producers that were ideally located for injection in an adjacent reservoir. The new Injection layer was stimulated initially, to assure maximum injectivity and longevity. The outer 5½" ESP Production string was run and landed first, followed by the inner 3½" string. The ESP’s were operated initially while the surface injection flow lines were fabricated and connected. Injection was then commissioned and monitored for inter-string communication. Initially, zero communication was observed with over 14,000 bwpd consistently injected over certain injection periods while maintaining original production rates. Evidence of possible leakage and inter-string communication was observed after seven (7) – eight (8) months of continuous injection. Investigations and analysis of integrity-longevity-failure to conclude root cause(s) and remedial solut
{"title":"First Global Application of Simultaneous Injection & Production SIP Technology Using Dual Concentric Strings with ESP","authors":"N. Al-Maqsseed, E. Anthony, R. Bhagavatula, C. Rodenboog, E. Jamieson, A. Jha, Gong Hua, G. Al-Sharhan","doi":"10.2118/191430-MS","DOIUrl":"https://doi.org/10.2118/191430-MS","url":null,"abstract":"\u0000 The North Kuwait asset has several stacked producing reservoirs, further subdivided into multiple sub-layers, each sub-layer with substantial production potential. Over 75% of these sub-layers are depletion drive reservoirs requiring water injection for pressure support. Many existing/planned Injectors penetrated over- and under-lying layers that has good production potential. Similarly, many Producers penetrated adjacent reservoirs/layers that required injection support. With limited surface real estate available to accommodate the increasing demand for appropriately located Injectors and Producers, conventional single-purpose wellbores have become an unaffordable luxury.\u0000 An innovative concept was developed in-house by using a single wellbore for an unconventional dual purpose, namely, Simultaneous Injection and Production (SIP). Owing to the significant differences in fluid rates and temperatures, absolute and relative tubular movement play a significant role in completion integrity and longevity. Collaboration with one of KOC’s major Electrical Submersible Pump (ESP) service partners yielded a unique dual concentric design that facilitates ease in completion deployment and equal ease in retrieval when necessary. Two (2) scenarios were considered in the dual concentric Completion design, namely Inject above, produce below (Scenario – A), and Inject below, produce above (Scenario – B). Tubing stress/movement software were used to simulate and design tubular specifications that would maintain optimum completion integrity in either of three (3) Operating Conditions: Inject only, Produce only, and Simultaneous Injection and Artificial Lift Production.\u0000 Due to the complexity and uniqueness of the SIP configuration, completing the Well on Paper (CWOP) sessions proved to be a very effective tool in the planning process of this completion.\u0000 The ESP Service Partner performed a System Integration Test (SIT) in a test well to verify equipment functionality and optimize the assembly procedure. Following the successful (SIT), the first installation was completed in early 2017. The systems installed to date were originally Producers that were ideally located for injection in an adjacent reservoir. The new Injection layer was stimulated initially, to assure maximum injectivity and longevity. The outer 5½\" ESP Production string was run and landed first, followed by the inner 3½\" string. The ESP’s were operated initially while the surface injection flow lines were fabricated and connected. Injection was then commissioned and monitored for inter-string communication. Initially, zero communication was observed with over 14,000 bwpd consistently injected over certain injection periods while maintaining original production rates. Evidence of possible leakage and inter-string communication was observed after seven (7) – eight (8) months of continuous injection. Investigations and analysis of integrity-longevity-failure to conclude root cause(s) and remedial solut","PeriodicalId":11015,"journal":{"name":"Day 1 Mon, September 24, 2018","volume":"6 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-09-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85691797","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}
Smart oilfield technologies and management real-time data surveillance, in terms of reliability and availability, has proven essential in the process of prolonging asset lifespan, improving asset integrity, and proactively preventing problems. This illustrates a leadership role in the integration of cutting-edge technologies by utilizing an Intelligent Field concept. Surveillance capitalizes on real-time data transmitted from Intelligent Field equipment, where mathematical algorithms and logic are automated and imposed. The application captures specific sets of data to help identify and analyze challenges associated with Intelligent Field equipment. Major prevailing benefits include, identifying systematic techniques to utilize automated diagnostics for reduction in human intervention, develop field level surveillance, cross-validating measurements through online modeling, and further enhance collaboration. This paper details the methodology, the outcome, the requirements, and considerations associated with effective real-time data utilization in energy industry applications. The platform allows business team members and their partners to communicate, collaborate, and coordinate activities in real time.
{"title":"Smart Oilfield Technologies and Management: Maximizing Real-Time Surveillance and Utilization","authors":"Mohammad S. Al-Kadem, K. Yateem, M. A. Amri","doi":"10.2118/191493-MS","DOIUrl":"https://doi.org/10.2118/191493-MS","url":null,"abstract":"\u0000 Smart oilfield technologies and management real-time data surveillance, in terms of reliability and availability, has proven essential in the process of prolonging asset lifespan, improving asset integrity, and proactively preventing problems. This illustrates a leadership role in the integration of cutting-edge technologies by utilizing an Intelligent Field concept. Surveillance capitalizes on real-time data transmitted from Intelligent Field equipment, where mathematical algorithms and logic are automated and imposed. The application captures specific sets of data to help identify and analyze challenges associated with Intelligent Field equipment. Major prevailing benefits include, identifying systematic techniques to utilize automated diagnostics for reduction in human intervention, develop field level surveillance, cross-validating measurements through online modeling, and further enhance collaboration. This paper details the methodology, the outcome, the requirements, and considerations associated with effective real-time data utilization in energy industry applications. The platform allows business team members and their partners to communicate, collaborate, and coordinate activities in real time.","PeriodicalId":11015,"journal":{"name":"Day 1 Mon, September 24, 2018","volume":"30 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-09-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84185000","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}
Adeoluwa Oyewole, M. Kelkar, E. Pereyra, C. Sarica
The challenge facing reservoir and production engineers remains ensuring continued production from a well, including additional recovery with artificial lift methods. To accomplish this, means to determine the production performance of a well until the end of its life is desired. This challenge is even greater when dealing with production from unconventional formations. This paper presents a methodology to model the production performance of a well producing from an unconventional oil or gas formation. Emphasis is placed on the use of readily-available information to production engineers for the day-to-day analysis and optimization of production from the field. For developing the model, traditional flow regimes observed during the production of a well are utilized. Using this information as well as superposition principle, a working model is developed, tested and validated. Technical contributions of this paper include a procedure to implement this solution in any producing oil or gas well from an unconventional formation, and an Inflow Performance Relationship (IPR) framework for visualizing productivity changes with time of a particular well.
{"title":"Well Performance Modeling in Unconventional Oil and Gas Wells","authors":"Adeoluwa Oyewole, M. Kelkar, E. Pereyra, C. Sarica","doi":"10.2118/191694-MS","DOIUrl":"https://doi.org/10.2118/191694-MS","url":null,"abstract":"\u0000 The challenge facing reservoir and production engineers remains ensuring continued production from a well, including additional recovery with artificial lift methods. To accomplish this, means to determine the production performance of a well until the end of its life is desired. This challenge is even greater when dealing with production from unconventional formations. This paper presents a methodology to model the production performance of a well producing from an unconventional oil or gas formation.\u0000 Emphasis is placed on the use of readily-available information to production engineers for the day-to-day analysis and optimization of production from the field. For developing the model, traditional flow regimes observed during the production of a well are utilized. Using this information as well as superposition principle, a working model is developed, tested and validated.\u0000 Technical contributions of this paper include a procedure to implement this solution in any producing oil or gas well from an unconventional formation, and an Inflow Performance Relationship (IPR) framework for visualizing productivity changes with time of a particular well.","PeriodicalId":11015,"journal":{"name":"Day 1 Mon, September 24, 2018","volume":"51 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-09-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79535198","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}
Lei Yang, D. Bale, D. Yang, M. Raum, O. Bello, Roberto Failla, David Lerohl, David Knowles, Andy Kwari, Mattew Cannon, S. Ye
The distributed nature of fiber-optic measurements such as distributed temperature sensing (DTS), distributed acoustic sensing (DAS), and distributed strain sensing (DSS) enables nearly continuous monitoring of the downhole environment in both space and time. Though continuous monitoring opens the door to a rich new set of asset management applications, it comes with its own set of challenges in terms of data transmission, management, and security. Recently, cloud-based fiber-optic data management services have been successfully introduced to the oil and gas industry as an effective way to collect, transfer, store and display distributed measurement data from the downhole environment. To maximize the value of such cloud-based data management systems, and further improve the return on investment for asset managers, the large volume of distributed sensing data collected must be converted to value in a simple and easy-to-use form, depending on different applications. Traditionally, interpretation of distributed sensing data is a manual process conducted by engineers in a post-job workflow. This paper presents the successful integration of an analytics library into the cloud-based fiber-optic data management system. This integration enables real-time, and in some cases near real-time, asset decision making. The design of the analytics architecture is open to meet the wide range of application requirements by asset managers. A few application examples of the analytics integration will be presented using real-time data streamed directly from the field.
{"title":"Enabling Real-Time Asset Analytics for a Cloud-Based Fiber-Optic Data Management System","authors":"Lei Yang, D. Bale, D. Yang, M. Raum, O. Bello, Roberto Failla, David Lerohl, David Knowles, Andy Kwari, Mattew Cannon, S. Ye","doi":"10.2118/191592-MS","DOIUrl":"https://doi.org/10.2118/191592-MS","url":null,"abstract":"\u0000 The distributed nature of fiber-optic measurements such as distributed temperature sensing (DTS), distributed acoustic sensing (DAS), and distributed strain sensing (DSS) enables nearly continuous monitoring of the downhole environment in both space and time. Though continuous monitoring opens the door to a rich new set of asset management applications, it comes with its own set of challenges in terms of data transmission, management, and security. Recently, cloud-based fiber-optic data management services have been successfully introduced to the oil and gas industry as an effective way to collect, transfer, store and display distributed measurement data from the downhole environment. To maximize the value of such cloud-based data management systems, and further improve the return on investment for asset managers, the large volume of distributed sensing data collected must be converted to value in a simple and easy-to-use form, depending on different applications. Traditionally, interpretation of distributed sensing data is a manual process conducted by engineers in a post-job workflow. This paper presents the successful integration of an analytics library into the cloud-based fiber-optic data management system. This integration enables real-time, and in some cases near real-time, asset decision making. The design of the analytics architecture is open to meet the wide range of application requirements by asset managers. A few application examples of the analytics integration will be presented using real-time data streamed directly from the field.","PeriodicalId":11015,"journal":{"name":"Day 1 Mon, September 24, 2018","volume":"57 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-09-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79808117","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
T. Kristiansen, T. Dyngeland, S. Kinn, R. Flatebø, N. Aarseth
Shale is a general term used for argillaceous (clay-rich) rocks which are the most abundant sediment on the earth. It is believed that clay rich rocks comprise more than 50-75% of the geologic column. Shale has very varying petrophysical and mechanical properties. Shale is in the most cases acting as a trap or seal for hydrocarbon migration, but has also in more recent years been targeted as a reservoir target in some basins. In some wells it has been observed on cement bond logs that shales in uncemented intervals have moved in and closed the annulus. Pressure communication testing has been performed on these sections and the sections has been qualified as well barrier elements (Williams et al., 2009) for plug and abandonment (P&A) purposes. The main mechanism behind the deformation process is believed to be shale creep. In this paper we will discuss shale creep and other shale deformation mechanisms and how an understanding of these can be used to activate shale that has not contacted the casing yet to form a well barrier. We have developed a numerical model based on first order principles to better understand the mechanical deformation process. We are also supporting the modeling results with laboratory experiments, before we discuss a couple of field cases where shale intervals have been activated and verified to have formed a well barrier as part of the well construction process in new wells.
页岩是地球上沉积物最丰富的泥质(富含粘土)岩石的总称。据信，富含粘土的岩石占地质柱的50-75%以上。页岩具有非常不同的岩石物理和力学性质。页岩在大多数情况下作为油气运移的圈闭或密封，但近年来在一些盆地也被视为储层目标。在一些井中，水泥胶结测井观察到，未胶结层段的页岩进入并封闭环空。在这些井段进行了压力通信测试，这些井段已被认定为井眼隔离元件(Williams et al.， 2009)，可用于封井弃井(P&A)。变形过程背后的主要机制被认为是页岩蠕变。在本文中，我们将讨论页岩蠕变和其他页岩变形机制，以及如何利用对这些机制的理解来激活尚未接触套管的页岩，以形成井眼屏障。为了更好地理解机械变形过程，我们开发了基于一阶原理的数值模型。我们还通过实验室实验来支持建模结果，然后我们讨论了几个现场案例，在这些案例中，页岩层段已经被激活并验证形成了井障，这是新井建井过程的一部分。
{"title":"Activating Shale to Form Well Barriers: Theory and Field Examples","authors":"T. Kristiansen, T. Dyngeland, S. Kinn, R. Flatebø, N. Aarseth","doi":"10.2118/191607-MS","DOIUrl":"https://doi.org/10.2118/191607-MS","url":null,"abstract":"\u0000 Shale is a general term used for argillaceous (clay-rich) rocks which are the most abundant sediment on the earth. It is believed that clay rich rocks comprise more than 50-75% of the geologic column. Shale has very varying petrophysical and mechanical properties. Shale is in the most cases acting as a trap or seal for hydrocarbon migration, but has also in more recent years been targeted as a reservoir target in some basins. In some wells it has been observed on cement bond logs that shales in uncemented intervals have moved in and closed the annulus. Pressure communication testing has been performed on these sections and the sections has been qualified as well barrier elements (Williams et al., 2009) for plug and abandonment (P&A) purposes. The main mechanism behind the deformation process is believed to be shale creep.\u0000 In this paper we will discuss shale creep and other shale deformation mechanisms and how an understanding of these can be used to activate shale that has not contacted the casing yet to form a well barrier. We have developed a numerical model based on first order principles to better understand the mechanical deformation process. We are also supporting the modeling results with laboratory experiments, before we discuss a couple of field cases where shale intervals have been activated and verified to have formed a well barrier as part of the well construction process in new wells.","PeriodicalId":11015,"journal":{"name":"Day 1 Mon, September 24, 2018","volume":"3 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-09-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81913871","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 nature of well completions in the oil and gas industry continues to evolve. Although the effects of completions and spacing on initial production are well reported, how they affect ultimate recovery and terminal decline is not well understood. Over the last decade, drilling on multi-well pads has become prevalent, spacing between horizontal wells has decreased, and hydrofracture intensity has increased. These developments have decreased drilling and completion costs, while increasing initial well production. Yet, the impact of the timing, spacing, and intensity of fracturing on terminal decline rates and ultimate recovery has not been systematically investigated. In this paper, Bakken well production profiles are used to evaluate the impact of differences in completion design on the nature of long-term production decline. To evaluate these effects, production for 12,000 Bakken wells were forecast using a physics-based approach. Using descriptive statistics and advanced visualization, terminal decline rate and ultimate recovery parameters are found to depend upon date of well completion, volumes of proppant and water injected, lateral length, and well spacing. We utilize a tree-based machine learning approach to test predictability of completion parameters on terminal decline rate and estimated ultimate recovery. Our analyses show that pad drilling and increased hydrofracture intensity are apparently associated with small increases in initial production rates but have led to larger terminal decline rates. For example, in the Bakken, the terminal decline rate increases by upwards of ten percentage points for wells with modern completions in multi-well pads. Since production life is dependent upon terminal decline rates, spacing and completions effects must be accounted for in type curves for wells in multi-well pads.
{"title":"Using Data Analytics to Assess the Impact of Technology Change on Production Forecasting","authors":"Frank Male, C. Aiken, I. Duncan","doi":"10.2118/191536-MS","DOIUrl":"https://doi.org/10.2118/191536-MS","url":null,"abstract":"\u0000 The nature of well completions in the oil and gas industry continues to evolve. Although the effects of completions and spacing on initial production are well reported, how they affect ultimate recovery and terminal decline is not well understood. Over the last decade, drilling on multi-well pads has become prevalent, spacing between horizontal wells has decreased, and hydrofracture intensity has increased. These developments have decreased drilling and completion costs, while increasing initial well production. Yet, the impact of the timing, spacing, and intensity of fracturing on terminal decline rates and ultimate recovery has not been systematically investigated.\u0000 In this paper, Bakken well production profiles are used to evaluate the impact of differences in completion design on the nature of long-term production decline. To evaluate these effects, production for 12,000 Bakken wells were forecast using a physics-based approach. Using descriptive statistics and advanced visualization, terminal decline rate and ultimate recovery parameters are found to depend upon date of well completion, volumes of proppant and water injected, lateral length, and well spacing. We utilize a tree-based machine learning approach to test predictability of completion parameters on terminal decline rate and estimated ultimate recovery.\u0000 Our analyses show that pad drilling and increased hydrofracture intensity are apparently associated with small increases in initial production rates but have led to larger terminal decline rates. For example, in the Bakken, the terminal decline rate increases by upwards of ten percentage points for wells with modern completions in multi-well pads. Since production life is dependent upon terminal decline rates, spacing and completions effects must be accounted for in type curves for wells in multi-well pads.","PeriodicalId":11015,"journal":{"name":"Day 1 Mon, September 24, 2018","volume":"86 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-09-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88616231","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}
Do Hoon Kim, D. Alexis, G. NewPeter, Adam C Jackson, David Espinosa, T. Isbell, Anette Poulsen, Derek McKilligan, Mohamad Salman, Taimur Malik, Sophany Thach, V. Dwarakanath
Polymer mixing is often challenging under offshore conditions due to space constraints. A theoretical approach is required to better understand the drivers for polymer hydration and design optimal field mixing systems. We share a novel theoretical approach to gain insights into the energy required for optimum mixing of novel liquid polymers. We present a new parameter, "Specific Mixing Energy" that is measured under both lab and field mixing conditions and can be used to scale-up laboratory mixing. We developed a simplified laboratory mixing process for novel liquid polymer that provided acceptable viscosity yield, filtration ratio (FR), and non-plugging behavior during injectivity tests in a surrogate core. A FR less than 1.5 using a 1.2 μm filter at 1 bar was considered acceptable for inverted polymer quality. We developed estimates for specific mixing energy required for lab polymer inversion to achieve these stringent FR standards and comparable viscosity yield. We then conducted yard trials with both single-stage and dual-stage mixing of the novel liquid polymer and developed correlations for specific mixing energy under dynamic conditions. Based upon the results of lab and yard trials, we tested the approach in a field injectivity test. The FR and viscosity were also correlated to a specific mixing energy to establish the desired operating window range from laboratory to field-scale applications. Such information can be used to enhance EOR applications using liquid polymers in offshore environments.
{"title":"Development of the Mixing Energy Concept to Hydrate Novel Liquid Polymers for Field Injection","authors":"Do Hoon Kim, D. Alexis, G. NewPeter, Adam C Jackson, David Espinosa, T. Isbell, Anette Poulsen, Derek McKilligan, Mohamad Salman, Taimur Malik, Sophany Thach, V. Dwarakanath","doi":"10.2118/191391-MS","DOIUrl":"https://doi.org/10.2118/191391-MS","url":null,"abstract":"\u0000 Polymer mixing is often challenging under offshore conditions due to space constraints. A theoretical approach is required to better understand the drivers for polymer hydration and design optimal field mixing systems. We share a novel theoretical approach to gain insights into the energy required for optimum mixing of novel liquid polymers. We present a new parameter, \"Specific Mixing Energy\" that is measured under both lab and field mixing conditions and can be used to scale-up laboratory mixing. We developed a simplified laboratory mixing process for novel liquid polymer that provided acceptable viscosity yield, filtration ratio (FR), and non-plugging behavior during injectivity tests in a surrogate core. A FR less than 1.5 using a 1.2 μm filter at 1 bar was considered acceptable for inverted polymer quality. We developed estimates for specific mixing energy required for lab polymer inversion to achieve these stringent FR standards and comparable viscosity yield. We then conducted yard trials with both single-stage and dual-stage mixing of the novel liquid polymer and developed correlations for specific mixing energy under dynamic conditions. Based upon the results of lab and yard trials, we tested the approach in a field injectivity test. The FR and viscosity were also correlated to a specific mixing energy to establish the desired operating window range from laboratory to field-scale applications. Such information can be used to enhance EOR applications using liquid polymers in offshore environments.","PeriodicalId":11015,"journal":{"name":"Day 1 Mon, September 24, 2018","volume":"27 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-09-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73803453","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}
Wei‐Ting Dai, Brian Noel, C. Alvord, Johnson Njoku, Joseph A. Hopper, Lee M. Smith
Casing wear caused by rotating drill strings can lead to reduced well life, failed or burst casing strings, and expensive non-productive time (NPT) for remedial actions. In Alaska's Alpine Development field, where logistics are challenging, regulations are strict, and the operational window is small, drilling increasingly long laterals has vastly increased the cost and risk of casing wear, necessitating effective mitigation. After detailed analyses of Alpine field wells, one operator successfully implemented a casing wear mitigation plan combining new tools, modeling techniques and analyses. The plan required strategic placement of Non-Rotating Protectors (NRPs) based on predicted casing wear, analyzed side forces, and lateral length. Additionally, the operations group wanted to simultaneously improve computer modeling for both casing wear and torque and drag (T&D) analysis. One major challenge was predicting appropriate wear factors for casing wear modeling. Operational challenges included how to deploy the plan in managed pressure drilling (MPD) operations, where preventing premature wear on rotating control device (RCD) sealing elements had to be considered. Implementing this casing wear mitigation plan allowed the operator to successfully drill extended reach multilateral wells to planned total depth while keeping wear below maximum allowable thresholds. The paper describes the challenges and approach to predict casing wear, as well as successful mitigation strategies and lessons learned from an extensive offset database. Included are comparisons to field results from casing logs, and several wells that deployed the casing wear mitigation plan, versus an offset well that was drilled without a plan. The paper describes new techniques for predicting and modeling casing wear which, in combination with utilization of specific tools, results in a readily-applicable approach to wear mitigation in extended-reach drilling (ERD).
{"title":"A Practical Approach to Casing Wear Prediction, Modeling and Mitigation on Challenging ERD Wells","authors":"Wei‐Ting Dai, Brian Noel, C. Alvord, Johnson Njoku, Joseph A. Hopper, Lee M. Smith","doi":"10.2118/191495-MS","DOIUrl":"https://doi.org/10.2118/191495-MS","url":null,"abstract":"\u0000 Casing wear caused by rotating drill strings can lead to reduced well life, failed or burst casing strings, and expensive non-productive time (NPT) for remedial actions. In Alaska's Alpine Development field, where logistics are challenging, regulations are strict, and the operational window is small, drilling increasingly long laterals has vastly increased the cost and risk of casing wear, necessitating effective mitigation.\u0000 After detailed analyses of Alpine field wells, one operator successfully implemented a casing wear mitigation plan combining new tools, modeling techniques and analyses. The plan required strategic placement of Non-Rotating Protectors (NRPs) based on predicted casing wear, analyzed side forces, and lateral length. Additionally, the operations group wanted to simultaneously improve computer modeling for both casing wear and torque and drag (T&D) analysis.\u0000 One major challenge was predicting appropriate wear factors for casing wear modeling. Operational challenges included how to deploy the plan in managed pressure drilling (MPD) operations, where preventing premature wear on rotating control device (RCD) sealing elements had to be considered.\u0000 Implementing this casing wear mitigation plan allowed the operator to successfully drill extended reach multilateral wells to planned total depth while keeping wear below maximum allowable thresholds. The paper describes the challenges and approach to predict casing wear, as well as successful mitigation strategies and lessons learned from an extensive offset database. Included are comparisons to field results from casing logs, and several wells that deployed the casing wear mitigation plan, versus an offset well that was drilled without a plan.\u0000 The paper describes new techniques for predicting and modeling casing wear which, in combination with utilization of specific tools, results in a readily-applicable approach to wear mitigation in extended-reach drilling (ERD).","PeriodicalId":11015,"journal":{"name":"Day 1 Mon, September 24, 2018","volume":"37 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-09-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89962691","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}
Ala Eddine Aoun, Faouzi Maougal, Lahcene Kabour, Tony Liao, Brahim AbdallahElhadj, Sabrina Behaz
Hassi Messaoud (HMD) is a mature oil field with approximately 1100 production wells. About half of the wells are natural flow and the other half are continuously gas lifted (CGL) with concentric (CCE) strings. CCE gas lift is different from conventional gas lift as the lift gas is injected in the well through the CCE string while production is from the annulus between the CCE string and the tubing. The typical production tubing size is 4 ½". The sizes of the CCE strings include 1.315", 1.66", and 1.9". The 1.66" CCE is most commonly used in gas lift wells. The typical gas lift injection line on the surface is 2" from the gas network to the wellhead. A choke is used on the gas lift line to control the lift gas injected into each well. As the injection gas pressure is high from the source of available lift gas, large pressure drops across the lift gas injection chokes exist in some wells. Due to the Joule-Thompson effects, a big temperature drop is associated with the large pressure drop across the lift gas injection choke. This temperature drop can result in hydrate formation in the lift gas line downstream of the gas lift choke. Hydrate formation in the gas injection lines, especially in winter has seriously disrupted production due to plugging of lift gas lines. Salt deposition is a big challenge in Hassi Messaoud field operation. The reservoir interstitial water contains high salt concentration in excess of 300 g/l. During well production, salt deposits in the wellbore and across the production choke. Periodically, water is required to be injected into the well to dissolve the salt and restore well productivity. A CCE string allows water to be injected into the wellbore either concurrently with injection lift gas or separately by itself for a specific period of time. High volumes of lift gas are injected in many wells due to the lack of effective control in the lift gas injection rates. The excessive gas from lift gas injection and production in the system can lead to the need to flare occasionally when the facility gas capacity limit is exceeded. In order to reduce the usage of the high volume of lift gas, Intermittent Gas Lift (IGL) was selected in a pilot project to evaluate its applicability in the Hassi Messaoud field. Three CGL wells were selected for this pilot project. The selected wells are characterized by high GOR, low PI and without continuous concurrent water injection (with lift gas) to dissolve salt deposited down-hole. IGL operation parameters were designed by using modified empirical correlations to those presented in the API Recommended Practice for Intermittent Gas Lift. The modifications were suited for the operating conditions in Hassi Messaoud Field. Static and dynamic well and network models were created to simulate the field test results and guide new designs and future applications. This paper presents the pilot test programs and the results from this project in mitigating both the excessive lift gas injection p
{"title":"Hydrate Mitigation and Flare Reduction Using Intermittent Gas Lift in Hassi Messaoud, Algeria","authors":"Ala Eddine Aoun, Faouzi Maougal, Lahcene Kabour, Tony Liao, Brahim AbdallahElhadj, Sabrina Behaz","doi":"10.2118/191542-MS","DOIUrl":"https://doi.org/10.2118/191542-MS","url":null,"abstract":"\u0000 Hassi Messaoud (HMD) is a mature oil field with approximately 1100 production wells. About half of the wells are natural flow and the other half are continuously gas lifted (CGL) with concentric (CCE) strings. CCE gas lift is different from conventional gas lift as the lift gas is injected in the well through the CCE string while production is from the annulus between the CCE string and the tubing. The typical production tubing size is 4 ½\". The sizes of the CCE strings include 1.315\", 1.66\", and 1.9\". The 1.66\" CCE is most commonly used in gas lift wells. The typical gas lift injection line on the surface is 2\" from the gas network to the wellhead. A choke is used on the gas lift line to control the lift gas injected into each well. As the injection gas pressure is high from the source of available lift gas, large pressure drops across the lift gas injection chokes exist in some wells. Due to the Joule-Thompson effects, a big temperature drop is associated with the large pressure drop across the lift gas injection choke. This temperature drop can result in hydrate formation in the lift gas line downstream of the gas lift choke. Hydrate formation in the gas injection lines, especially in winter has seriously disrupted production due to plugging of lift gas lines.\u0000 Salt deposition is a big challenge in Hassi Messaoud field operation. The reservoir interstitial water contains high salt concentration in excess of 300 g/l. During well production, salt deposits in the wellbore and across the production choke. Periodically, water is required to be injected into the well to dissolve the salt and restore well productivity. A CCE string allows water to be injected into the wellbore either concurrently with injection lift gas or separately by itself for a specific period of time.\u0000 High volumes of lift gas are injected in many wells due to the lack of effective control in the lift gas injection rates. The excessive gas from lift gas injection and production in the system can lead to the need to flare occasionally when the facility gas capacity limit is exceeded.\u0000 In order to reduce the usage of the high volume of lift gas, Intermittent Gas Lift (IGL) was selected in a pilot project to evaluate its applicability in the Hassi Messaoud field.\u0000 Three CGL wells were selected for this pilot project. The selected wells are characterized by high GOR, low PI and without continuous concurrent water injection (with lift gas) to dissolve salt deposited down-hole.\u0000 IGL operation parameters were designed by using modified empirical correlations to those presented in the API Recommended Practice for Intermittent Gas Lift. The modifications were suited for the operating conditions in Hassi Messaoud Field. Static and dynamic well and network models were created to simulate the field test results and guide new designs and future applications.\u0000 This paper presents the pilot test programs and the results from this project in mitigating both the excessive lift gas injection p","PeriodicalId":11015,"journal":{"name":"Day 1 Mon, September 24, 2018","volume":"56 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-09-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86278744","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}
Mahdi Mahmoudi, Morteza Roostaei, Vahidoddin Fattahpour, Colby Sutton, B. Fermaniuk, Da Zhu, Hee-Ju Jung, Jiankuan Li, C. Sun, L. Gong, S. Shuang, Xiaoyong Qiu, Hongbo Zeng, Jingli Luo
Standalone screen has been widely used as sand control solution in oil industries for over a century. Screen plugging and impairments by formation fines, scaling and corrosion cost oil and gas industry significant amount of resources. This study presents a detailed study on the corrosion and plugging of slotted liner, wire wrap screen and mesh screen samples extracted from the field to better understand some of the mechanisms for these poor field performances. Three types of standalone screen were received from operating wells to study the failure mechanism of the screen and provide recommendations for recompletion. A thorough visual inspection of all screens was performed and documented in this paper. From the results of the visual inspection a certain section of each screen was cut for further detailed microscopic study to better understand the scaling and plugging mechanism, as well as microscopic geometry of the plugged and corroded zone. The results highlighted the importance of the corrosion in the base pipe on the observed performances. All the studies pointed toward the flow dependence corrosion behavior, and the role of the water cut on the corrosion rate. The wire wrap screens have been in service for less than a year, yet the extensive corrosion led to creation of several holes in the pipe. The study showed the corrosion initiated from inside the pipe. Similarly, the corrosion of the slotted liner samples showed a strong flow dependent corrosion rate, where the corrosion rate on the slot/formation interface was slightly higher. The mesh screen showed very high plugging percentage by formation fines, where a thick film of clay and fine sand covered the space between the mesh and the base pipe. The results indicated that an inappropriate design of the mesh and pore could cause significant plugging. This paper provides several field examples of the corrosion and plugging of the standalone screens. The results could help engineer to better understand the risk of corrosion and plugging on the standalone screen design. This paper provides some general guidelines for assessing the scaling and corrosion potential at field condition based on the results of the screens studied in the paper.
{"title":"Standalone Sand Control Failure: Review of Slotted Liner, Wire Wrap Screen, and Premium Mesh Screen Failure Mechanism","authors":"Mahdi Mahmoudi, Morteza Roostaei, Vahidoddin Fattahpour, Colby Sutton, B. Fermaniuk, Da Zhu, Hee-Ju Jung, Jiankuan Li, C. Sun, L. Gong, S. Shuang, Xiaoyong Qiu, Hongbo Zeng, Jingli Luo","doi":"10.2118/191553-MS","DOIUrl":"https://doi.org/10.2118/191553-MS","url":null,"abstract":"\u0000 Standalone screen has been widely used as sand control solution in oil industries for over a century. Screen plugging and impairments by formation fines, scaling and corrosion cost oil and gas industry significant amount of resources. This study presents a detailed study on the corrosion and plugging of slotted liner, wire wrap screen and mesh screen samples extracted from the field to better understand some of the mechanisms for these poor field performances.\u0000 Three types of standalone screen were received from operating wells to study the failure mechanism of the screen and provide recommendations for recompletion. A thorough visual inspection of all screens was performed and documented in this paper. From the results of the visual inspection a certain section of each screen was cut for further detailed microscopic study to better understand the scaling and plugging mechanism, as well as microscopic geometry of the plugged and corroded zone.\u0000 The results highlighted the importance of the corrosion in the base pipe on the observed performances. All the studies pointed toward the flow dependence corrosion behavior, and the role of the water cut on the corrosion rate. The wire wrap screens have been in service for less than a year, yet the extensive corrosion led to creation of several holes in the pipe. The study showed the corrosion initiated from inside the pipe. Similarly, the corrosion of the slotted liner samples showed a strong flow dependent corrosion rate, where the corrosion rate on the slot/formation interface was slightly higher. The mesh screen showed very high plugging percentage by formation fines, where a thick film of clay and fine sand covered the space between the mesh and the base pipe. The results indicated that an inappropriate design of the mesh and pore could cause significant plugging.\u0000 This paper provides several field examples of the corrosion and plugging of the standalone screens. The results could help engineer to better understand the risk of corrosion and plugging on the standalone screen design. This paper provides some general guidelines for assessing the scaling and corrosion potential at field condition based on the results of the screens studied in the paper.","PeriodicalId":11015,"journal":{"name":"Day 1 Mon, September 24, 2018","volume":"72 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-09-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86284338","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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