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}
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}
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}
Accurate determination of the dew point pressure of gas condensates in nano-porous ultra-low permeability reservoirs is crucial to prevent liquid dropout inside the formation. This paper presents a proof of concept experimental data and procedure to explain the effect of the pore size distribution on the degree and direction of the shift in the saturation pressure of gas mixtures under confinement compared to the bulk behavior. We built a packed bed of BaTiO3 nanoparticles, providing a homogenous porous medium with pores of 5 to 50 nm, providing a volume more than 1000 times larger than typical nano channels. We designed an isochoric apparatus to monitor pressure for a fixed volume of fluid under confinement and bulk conditions simultaneously. A binary mixture of ethane-pentane undergoes an isochoric process with pressures of 10 to 1500 psi and temperatures of 290 to 425 K. The result is a set of Isochoric lines for the bulk and confined sample, plotted on the phase envelope to demonstrate the change in saturation pressure. Many attempts in explaining the shift in saturation pressures of the reservoir fluid confined in the narrow pores of unconventional reservoirs compared to those of the bulk can be found in the literature. However, there are some contradiction between the predicted behavior using different mathematical approaches. Experimental data could be substantially helpful in both validating models and improving the understanding of the fluid behavior in these formations. Contrary to what many published models predict, our results show that confinement effects shift the dew point pressure towards higher values compared to the bulk for a fixed temperature in the retrograde region. In the non-retrograde region, however, this shift is towards lower dew point pressure values for the confined fluid compared to the bulk. Capillary condensation is assumed to be the main source of the deviations observed in the behavior of fluids inside nanopores. We evaluate published models, including those based on EOS modifications, by comparing it to experimental results to provide a quantification of their accuracy in predicting saturation pressure values for confined mixture. This paper provides an alternative approach to examine the effect of pore size on phase behavior over a decent and practical range of pressures and temperatures. The synthesized porous medium is very helpful in uncoupling the effect of pore size from the effect of mineralogy on the observed deviations in behavior. Experimental findings are valuable for validating existing theories and can be used to adjust proposed mathematical approaches towards better predictions of saturation pressures for other systems.
{"title":"Experimental Investigation of the Effect of Pore Size on Saturation Pressure for Gas Mixtures","authors":"Shadi Salahshoor, M. Fahes","doi":"10.2118/191399-MS","DOIUrl":"https://doi.org/10.2118/191399-MS","url":null,"abstract":"\u0000 Accurate determination of the dew point pressure of gas condensates in nano-porous ultra-low permeability reservoirs is crucial to prevent liquid dropout inside the formation. This paper presents a proof of concept experimental data and procedure to explain the effect of the pore size distribution on the degree and direction of the shift in the saturation pressure of gas mixtures under confinement compared to the bulk behavior.\u0000 We built a packed bed of BaTiO3 nanoparticles, providing a homogenous porous medium with pores of 5 to 50 nm, providing a volume more than 1000 times larger than typical nano channels. We designed an isochoric apparatus to monitor pressure for a fixed volume of fluid under confinement and bulk conditions simultaneously. A binary mixture of ethane-pentane undergoes an isochoric process with pressures of 10 to 1500 psi and temperatures of 290 to 425 K. The result is a set of Isochoric lines for the bulk and confined sample, plotted on the phase envelope to demonstrate the change in saturation pressure.\u0000 Many attempts in explaining the shift in saturation pressures of the reservoir fluid confined in the narrow pores of unconventional reservoirs compared to those of the bulk can be found in the literature. However, there are some contradiction between the predicted behavior using different mathematical approaches. Experimental data could be substantially helpful in both validating models and improving the understanding of the fluid behavior in these formations. Contrary to what many published models predict, our results show that confinement effects shift the dew point pressure towards higher values compared to the bulk for a fixed temperature in the retrograde region. In the non-retrograde region, however, this shift is towards lower dew point pressure values for the confined fluid compared to the bulk. Capillary condensation is assumed to be the main source of the deviations observed in the behavior of fluids inside nanopores. We evaluate published models, including those based on EOS modifications, by comparing it to experimental results to provide a quantification of their accuracy in predicting saturation pressure values for confined mixture.\u0000 This paper provides an alternative approach to examine the effect of pore size on phase behavior over a decent and practical range of pressures and temperatures. The synthesized porous medium is very helpful in uncoupling the effect of pore size from the effect of mineralogy on the observed deviations in behavior. Experimental findings are valuable for validating existing theories and can be used to adjust proposed mathematical approaches towards better predictions of saturation pressures for other systems.","PeriodicalId":11015,"journal":{"name":"Day 1 Mon, September 24, 2018","volume":"207 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-09-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75076161","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}
Krishna K. Panthi, H. Sharma, H. Lashgari, K. Mohanty
Most carbonate reservoirs have fractures which have a detrimental effect on sweep efficiency during oil recovery. The objective of this research is to block the big fractures with polymeric particles and divert the injection fluid into the matrix for better sweep efficiency during CO2 floods. Polymeric particles have been developed that swell as salinity is increased. These particles are termed SISPP or salinity induced swelling polymeric particles. SISPPs swell more in higher concentration brine contrary to common polymeric particle gels (PPGs) which shrink. Water flood and miscible floods are conducted in fractured cores with SISPP placed in the fractures. The SISPP placement increases oil recovery in fractured cores during high salinity water floods and miscible/CO2 floods. Furthermore, a model for particle swelling, and the concomitant change in permeability, as a function of brine salinity was implemented in UTCHEM, and single phase and oil recovery corefloods were modeled. UTCHEM simulations showed good agreement with the experimental results.
{"title":"High Salinity Swelling Polymeric Particles for EOR","authors":"Krishna K. Panthi, H. Sharma, H. Lashgari, K. Mohanty","doi":"10.2118/191512-MS","DOIUrl":"https://doi.org/10.2118/191512-MS","url":null,"abstract":"\u0000 Most carbonate reservoirs have fractures which have a detrimental effect on sweep efficiency during oil recovery. The objective of this research is to block the big fractures with polymeric particles and divert the injection fluid into the matrix for better sweep efficiency during CO2 floods. Polymeric particles have been developed that swell as salinity is increased. These particles are termed SISPP or salinity induced swelling polymeric particles. SISPPs swell more in higher concentration brine contrary to common polymeric particle gels (PPGs) which shrink. Water flood and miscible floods are conducted in fractured cores with SISPP placed in the fractures. The SISPP placement increases oil recovery in fractured cores during high salinity water floods and miscible/CO2 floods. Furthermore, a model for particle swelling, and the concomitant change in permeability, as a function of brine salinity was implemented in UTCHEM, and single phase and oil recovery corefloods were modeled. UTCHEM simulations showed good agreement with the experimental results.","PeriodicalId":11015,"journal":{"name":"Day 1 Mon, September 24, 2018","volume":"7 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-09-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78887013","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}
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}
Annular gas migration through micro-annuli in cement, or casing vent flow, is a common issue over the life of a well. This results from poor cement jobs or porous cement that cannot successfully prevent gas flow from creating channels while curing. Remediating this through traditional practices of perf and squeeze or section milling is often expensive and unreliable. This paper will demonstrate a new way to create gas tight seals in casing annuli, minimizing the chance a well will experience casing vent flow by overcoming the limitations of cement in gas environments. This solution can be implemented at any stage of the well but is most effective when utilized as part of the original well construction.
{"title":"A New Look at Sealing with Bismuth and Thermite","authors":"P. Carragher, Jeff M. Fulks","doi":"10.2118/191469-ms","DOIUrl":"https://doi.org/10.2118/191469-ms","url":null,"abstract":"\u0000 Annular gas migration through micro-annuli in cement, or casing vent flow, is a common issue over the life of a well. This results from poor cement jobs or porous cement that cannot successfully prevent gas flow from creating channels while curing. Remediating this through traditional practices of perf and squeeze or section milling is often expensive and unreliable. This paper will demonstrate a new way to create gas tight seals in casing annuli, minimizing the chance a well will experience casing vent flow by overcoming the limitations of cement in gas environments. This solution can be implemented at any stage of the well but is most effective when utilized as part of the original well construction.","PeriodicalId":11015,"journal":{"name":"Day 1 Mon, September 24, 2018","volume":"16 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-09-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87483200","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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