Fa-yang Jin, Qi-hang Li, Yong Liu, W. Pu, C. Yuan, Xiaoman Yuan, Chuanjia Liu, Qing Chen, M. Varfolomeev, Kexing Li
The HD Oilfield, operated by PetroChina, is located in Tarim Basin. It is characterized by high temperature (112 ℃) and high salinity (291000 mg/L), and developed by wide spacing of wells (average 700 m). High vertical and areal heterogeneity lead to early water breakthrough and a poor water sweep efficiency. Effective conformance control is urgently needed, but harsh reservoir conditions, wide well spacing, and discontinuous interlayers pose great challenges for conformance treatments in this field. Because of wide well spacing and discontinuous interlayers, water channeling and crossflow in in-depth part of reservoir could still occur after conformance treatment. To prevent this, in-depth conformance improvement treatments with injecting large volumes of low-cost profile control agents were proposed. To achieve this goal, we designed delayed water-swelling, flexible gel particles that have high deformability and elasticity. Simultaneously, to meet the harsh reservoir conditions, gel particles were designed to have long-term tolerance to high temperature and high salinity. The first treatment was implemented in May 2016, and the total incremental oil by June 2019 was 17347 tons. The treatment validity is more than 36 months, and it keeps being effective. Until now, 9 treatments have been finished. The total incremental oil is 102100 tons until May 2020, and the increment is still going on. The input-output ratio for these 9 treatments is about 8.45, which indicates the treatments were an economic and technical success. In this paper, first we describe the design of gel particles and their properties evaluation by extensive experiments, including water-swelling ability, long-term tolerance to high temperature and high salinity, elasticity, tenacity, injectivity, selectivity, plugging ability, and scouring resistance, etc. Then, we present operation design and control in the field, which is especially important for the success of these treatments. Furthermore, according to production performance as well as the wellhead pressure drop curve, pressure curve of water injection, and water injectivity in injection well, treatment results are discussed in detail to evaluate if the treatment is successful or not. Finally, several important experiences with respect to how to do operation design and field control are summarized. This paper documents a successful case history of in-depth waterflood conformance improvement in wide spacing of wells. These successful field cases together with summarized experience will provide a detailed guide and an updated framework for conformance improvement treatment for operators. In addition, this paper presents an alternative agent, i.e., delayed water-swelling, flexible gel particles, for in-depth waterflood conformance improvement in high temperature and high salinity reservoirs.
{"title":"Successful Field Application of Delayed Water-Swelling, Flexible Gel Particles for In-Depth Waterflood Conformance Improvement in Wide Spacing of Wells with High Temperature and High Salinity","authors":"Fa-yang Jin, Qi-hang Li, Yong Liu, W. Pu, C. Yuan, Xiaoman Yuan, Chuanjia Liu, Qing Chen, M. Varfolomeev, Kexing Li","doi":"10.2118/207974-ms","DOIUrl":"https://doi.org/10.2118/207974-ms","url":null,"abstract":"\u0000 The HD Oilfield, operated by PetroChina, is located in Tarim Basin. It is characterized by high temperature (112 ℃) and high salinity (291000 mg/L), and developed by wide spacing of wells (average 700 m). High vertical and areal heterogeneity lead to early water breakthrough and a poor water sweep efficiency. Effective conformance control is urgently needed, but harsh reservoir conditions, wide well spacing, and discontinuous interlayers pose great challenges for conformance treatments in this field. Because of wide well spacing and discontinuous interlayers, water channeling and crossflow in in-depth part of reservoir could still occur after conformance treatment. To prevent this, in-depth conformance improvement treatments with injecting large volumes of low-cost profile control agents were proposed. To achieve this goal, we designed delayed water-swelling, flexible gel particles that have high deformability and elasticity. Simultaneously, to meet the harsh reservoir conditions, gel particles were designed to have long-term tolerance to high temperature and high salinity.\u0000 The first treatment was implemented in May 2016, and the total incremental oil by June 2019 was 17347 tons. The treatment validity is more than 36 months, and it keeps being effective. Until now, 9 treatments have been finished. The total incremental oil is 102100 tons until May 2020, and the increment is still going on. The input-output ratio for these 9 treatments is about 8.45, which indicates the treatments were an economic and technical success. In this paper, first we describe the design of gel particles and their properties evaluation by extensive experiments, including water-swelling ability, long-term tolerance to high temperature and high salinity, elasticity, tenacity, injectivity, selectivity, plugging ability, and scouring resistance, etc. Then, we present operation design and control in the field, which is especially important for the success of these treatments. Furthermore, according to production performance as well as the wellhead pressure drop curve, pressure curve of water injection, and water injectivity in injection well, treatment results are discussed in detail to evaluate if the treatment is successful or not. Finally, several important experiences with respect to how to do operation design and field control are summarized.\u0000 This paper documents a successful case history of in-depth waterflood conformance improvement in wide spacing of wells. These successful field cases together with summarized experience will provide a detailed guide and an updated framework for conformance improvement treatment for operators. In addition, this paper presents an alternative agent, i.e., delayed water-swelling, flexible gel particles, for in-depth waterflood conformance improvement in high temperature and high salinity reservoirs.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"99 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79256356","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}
Achraf Ourir, Jed Oukmal, B. Rondeleux, Zinyat Agharzayeva, Philippe Barrault
Analytical models, in particular Decline Curve Analysis (DCA) are widely used in the oil and gas industry. However, they are often solely based on production data from the declining wells and do not leverage the other data available in the field e.g. petrophysics at well, completion length, distance to contacts... This paper describes a workflow to quickly build hybrid models for reservoir production forecast based on a mix of classic reservoir methods and machine learning algorithms. This workflow is composed of three main steps applied on a well by well basis. First, we build an object called forecaster which contains the subject matter knowledge. This forecaster can represent parametric functions trained on the well itself or more complex models that learn from a larger data set (production and petrophysics data, synthesis properties). Secondly this forecaster is tested on a subset of production history to qualify it. Finally, the full data set is used to forecast the production profile. It has been applied to all fluids (oil, water, gas, liquid) and revealed particularly useful for fields with large number of wells and long history, as an alternative to classical simulations when grid models are too complex or difficult to history match. Two use cases from conventional and unconventional fields will be presented in which this workflow helped quickly generate robust forecast for existing wells (declining or non-declining) and new wells. This workflow brings the technology, structure and measurability of Data Science to Reservoir Engineering. It enables the application of the state of the art data science methods to solve concrete reservoir engineering problems. In addition, forecast results can be confronted to historical data using what we call "Blind Testing" which allows a quantification of the forecast uncertainty and avoid biases. Finally, the automated workflow has been used to generate a range of possible realizations and allows the quantification the uncertainty associated with the models.
{"title":"Hybrid Data Driven Approach for Reservoir Production Forecast","authors":"Achraf Ourir, Jed Oukmal, B. Rondeleux, Zinyat Agharzayeva, Philippe Barrault","doi":"10.2118/207425-ms","DOIUrl":"https://doi.org/10.2118/207425-ms","url":null,"abstract":"\u0000 Analytical models, in particular Decline Curve Analysis (DCA) are widely used in the oil and gas industry. However, they are often solely based on production data from the declining wells and do not leverage the other data available in the field e.g. petrophysics at well, completion length, distance to contacts... This paper describes a workflow to quickly build hybrid models for reservoir production forecast based on a mix of classic reservoir methods and machine learning algorithms. This workflow is composed of three main steps applied on a well by well basis. First, we build an object called forecaster which contains the subject matter knowledge. This forecaster can represent parametric functions trained on the well itself or more complex models that learn from a larger data set (production and petrophysics data, synthesis properties). Secondly this forecaster is tested on a subset of production history to qualify it. Finally, the full data set is used to forecast the production profile. It has been applied to all fluids (oil, water, gas, liquid) and revealed particularly useful for fields with large number of wells and long history, as an alternative to classical simulations when grid models are too complex or difficult to history match. Two use cases from conventional and unconventional fields will be presented in which this workflow helped quickly generate robust forecast for existing wells (declining or non-declining) and new wells.\u0000 This workflow brings the technology, structure and measurability of Data Science to Reservoir Engineering. It enables the application of the state of the art data science methods to solve concrete reservoir engineering problems. In addition, forecast results can be confronted to historical data using what we call \"Blind Testing\" which allows a quantification of the forecast uncertainty and avoid biases. Finally, the automated workflow has been used to generate a range of possible realizations and allows the quantification the uncertainty associated with the models.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"22 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77897715","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}
Rakan Al Yateem, Mohammad S. Al-Kadem, Suliman Alodhiani, Majed Kishi
Rate testing has evolved over the years. From a simple composite separator system, the scope of rate testing has morphed into a broad spectrum of sophisticated downhole and surface technologies. Knowing well behavior, performance, and associated rate are the key factors of operating an entire field with the most reliable operating strategy, assuring maximum well-life time. In regard to well modeling and optimization, valid rate test data are crucial to predict well performance efficiently. An in-house rate testing mechanism was developed to ensure proper delivery, accuracy, and validity of rate tests. The mechanism comprises a rate testing procedure and decision-making tree. The rate testing procedure includes regular checks of rate testing data reports. Also, the immediate resolution of rate testing equipment or communication issues is implemented through the utilization of an MPFM Advanced Monitoring System with automated logics. A decision-making tree constitutes pre- and post-testing process phases. The pre-testing process phase involves an assessment for rate testing readiness in terms of testing equipment and communication. The post-testing process phase includes an assessment for testing operation and rate test validity where rate test data are checked and validated based on production operational status. The enhanced testing mechanism is a user-friendly guideline for testing requirements to ensure the completion of tests captured from testing equipment. The proper implementation of this rate testing mechanism enabled a high quality and accuracy of rate test data, resulting in an increase in rate testing validity by 30%. Also, the rate testing mechanism inspired a culture of continuous effective communication for all involved parties during the testing operation. The decision-making tree transforms the validation process from subjective thinking to a systematic workflow while integrating data from nearby wells with similar behavior. A high ownership level is exhibited by taking the immediate resolution of issues results in achieving high rate testing validity percentage. Running the process through standardized operating procedures is critical in generating consistent and predictable results of well performance. Additionally, accurate optimization and prediction of well performance have been realized by feeding the well model's data before and after attaining valid rate test data, which attests to the quality of the proposed rate testing mechanism. Considering the importance of having a strategic rate testing mechanism, it is highly advised to have more frequent measurements to raise the accuracy of the measurements presented. An ideal strategic rate testing mechanism has to be economical enough to be placed in many production wells, allow the tests to be performed in an organized manner, improve measurement accuracy, and, more importantly, achieve automated and supervised well tests processes.
{"title":"Flourishing Production Optimization thru the Development of an Enhanced Testing Validity Methodology","authors":"Rakan Al Yateem, Mohammad S. Al-Kadem, Suliman Alodhiani, Majed Kishi","doi":"10.2118/207351-ms","DOIUrl":"https://doi.org/10.2118/207351-ms","url":null,"abstract":"\u0000 Rate testing has evolved over the years. From a simple composite separator system, the scope of rate testing has morphed into a broad spectrum of sophisticated downhole and surface technologies. Knowing well behavior, performance, and associated rate are the key factors of operating an entire field with the most reliable operating strategy, assuring maximum well-life time. In regard to well modeling and optimization, valid rate test data are crucial to predict well performance efficiently.\u0000 An in-house rate testing mechanism was developed to ensure proper delivery, accuracy, and validity of rate tests. The mechanism comprises a rate testing procedure and decision-making tree. The rate testing procedure includes regular checks of rate testing data reports. Also, the immediate resolution of rate testing equipment or communication issues is implemented through the utilization of an MPFM Advanced Monitoring System with automated logics. A decision-making tree constitutes pre- and post-testing process phases. The pre-testing process phase involves an assessment for rate testing readiness in terms of testing equipment and communication. The post-testing process phase includes an assessment for testing operation and rate test validity where rate test data are checked and validated based on production operational status.\u0000 The enhanced testing mechanism is a user-friendly guideline for testing requirements to ensure the completion of tests captured from testing equipment. The proper implementation of this rate testing mechanism enabled a high quality and accuracy of rate test data, resulting in an increase in rate testing validity by 30%. Also, the rate testing mechanism inspired a culture of continuous effective communication for all involved parties during the testing operation. The decision-making tree transforms the validation process from subjective thinking to a systematic workflow while integrating data from nearby wells with similar behavior. A high ownership level is exhibited by taking the immediate resolution of issues results in achieving high rate testing validity percentage. Running the process through standardized operating procedures is critical in generating consistent and predictable results of well performance. Additionally, accurate optimization and prediction of well performance have been realized by feeding the well model's data before and after attaining valid rate test data, which attests to the quality of the proposed rate testing mechanism.\u0000 Considering the importance of having a strategic rate testing mechanism, it is highly advised to have more frequent measurements to raise the accuracy of the measurements presented. An ideal strategic rate testing mechanism has to be economical enough to be placed in many production wells, allow the tests to be performed in an organized manner, improve measurement accuracy, and, more importantly, achieve automated and supervised well tests processes.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"319 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78000003","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}
I. Maffeis, A. D. de Angelis, Riccardo Guernelli, E. Croce, Luigi Romano
During production from sour gas reservoirs, precipitation of elemental sulfur can take place in production tubing, resulting in plugging of the well and stop of production. Injection in tubing of products devoted to dissolving sulfur can be an efficient solution for plug removal and production restoring. Traditionally, organic solvents (like toluene) are employed for solid sulfur dissolution. In the present work, experimental investigations have been performed on a particular innovative liquid product designed as active phase for wellbore injection or near wellbore applications. The analyses about the behavior of the considered product were conducted at HP-HT conditions. For this purpose, PVT laboratory equipment was employed, being able to reproduce the conditions of interest for the formation of elemental sulfur plug in well. An important preliminary optimization phase on the experimental setup was necessary to assure the correct management of studied liquid substance and solid sulfur. Integration of main outcomes with other kind of analyses allowed to depict a complete representation of the behavior: microscopy analysis of the liquid phase and high-resolution tomography of solid sulfur before and after the interaction were employed. A key point of the experimental characterization is the reproduction of significant involved phenomena. A preliminary effort was necessary for reproducing the realistic crystal form expected during the precipitation of solid sulfur in well. The dissolution efficiency of the liquid product is evaluated by observing its physical interaction with sulfur in a HP-HT cell. Particular attention was paid to correctly handling employed substances at the considered pressure and temperature conditions. A detailed description of the optimized equipment used in laboratory is provided. Several dissolution tests have been conducted at different temperature and pressure conditions, aiming to observe the dependence of the dissolution efficiency on the thermodynamic parameters. A visual qualitative analysis was performed on both the liquid product and the solid plug, before and after the interaction in cell. This allowed to deepen the comprehension of the dynamics of sulfur dissolution, which takes place not only from the top face of the plug, but also from preferential paths (fractures) present inside the plug itself. The presence of sulfur crystals dispersed in the liquid product after sampling from the cell is also evident at the end of the tests. The studied novel sulfur-dissolving liquid active phase is a candidate for remedial job injection at well in case of plugging due to solid elemental sulfur precipitation. The analyses here presented allowed to characterize the dissolution potential of this product. An optimized workflow was designed, including different kind of experimental disciplines.
{"title":"Experimental Methods for the Evaluation of the Efficiency of an Innovative Sulfur-Dissolving Product in HP-HT Conditions","authors":"I. Maffeis, A. D. de Angelis, Riccardo Guernelli, E. Croce, Luigi Romano","doi":"10.2118/207845-ms","DOIUrl":"https://doi.org/10.2118/207845-ms","url":null,"abstract":"\u0000 During production from sour gas reservoirs, precipitation of elemental sulfur can take place in production tubing, resulting in plugging of the well and stop of production. Injection in tubing of products devoted to dissolving sulfur can be an efficient solution for plug removal and production restoring.\u0000 Traditionally, organic solvents (like toluene) are employed for solid sulfur dissolution. In the present work, experimental investigations have been performed on a particular innovative liquid product designed as active phase for wellbore injection or near wellbore applications.\u0000 The analyses about the behavior of the considered product were conducted at HP-HT conditions. For this purpose, PVT laboratory equipment was employed, being able to reproduce the conditions of interest for the formation of elemental sulfur plug in well. An important preliminary optimization phase on the experimental setup was necessary to assure the correct management of studied liquid substance and solid sulfur.\u0000 Integration of main outcomes with other kind of analyses allowed to depict a complete representation of the behavior: microscopy analysis of the liquid phase and high-resolution tomography of solid sulfur before and after the interaction were employed.\u0000 A key point of the experimental characterization is the reproduction of significant involved phenomena. A preliminary effort was necessary for reproducing the realistic crystal form expected during the precipitation of solid sulfur in well.\u0000 The dissolution efficiency of the liquid product is evaluated by observing its physical interaction with sulfur in a HP-HT cell. Particular attention was paid to correctly handling employed substances at the considered pressure and temperature conditions. A detailed description of the optimized equipment used in laboratory is provided.\u0000 Several dissolution tests have been conducted at different temperature and pressure conditions, aiming to observe the dependence of the dissolution efficiency on the thermodynamic parameters.\u0000 A visual qualitative analysis was performed on both the liquid product and the solid plug, before and after the interaction in cell. This allowed to deepen the comprehension of the dynamics of sulfur dissolution, which takes place not only from the top face of the plug, but also from preferential paths (fractures) present inside the plug itself. The presence of sulfur crystals dispersed in the liquid product after sampling from the cell is also evident at the end of the tests.\u0000 The studied novel sulfur-dissolving liquid active phase is a candidate for remedial job injection at well in case of plugging due to solid elemental sulfur precipitation. The analyses here presented allowed to characterize the dissolution potential of this product. An optimized workflow was designed, including different kind of experimental disciplines.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"18 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75844849","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}
Maximum Reservoir Contact wells (MRCs) are a potential alternative to reduce the number of wells required to develop hydrocarbon reservoirs, improve sweeping efficiency and delay gas and water breakthrough. The well completions design is critical for the success of MRCs. In this study we present a case study of a MRC well completion design using Limited Entry Liners (LEL) in a mature carbonate reservoir under water and miscible gas injection. We developed an integrated workflow that considered a high-resolution numerical simulation model calibrated to static and dynamic data and wellbore-reservoir models coupling, for capturing the details of the flow interaction between both systems. Flow restrictions in the form of additional pressure drops to the flow from the reservoir into the wellbore were used to simulate the effect of small open flow areas, i.e.shot densities, in the LELs. Our work allowed identifying the most likely entry points of gas and water and design the well to minimize their impact on oil production. We observe that longer lengths open to flow outweighs the detrimental effect of producing from intervals closer to the water saturated zones. We also observed that balancing the inflow profile along the wellbore did not report beneficial results to oil production as it stimulates production from the reservoir zone from which the gas breakthrough is expected (middle of the producing section); this result is particularly relevant as it shows that designing the well completions with base only on static data could lead to poor production performance. The suggested completion for the MRC well encompasses four segments; a segment covering almost 50 % of the well length and located at the middle of the producing section with a blind liner (close to flow for gas control) and the remaining three with slotted liners with enough open area as to avoid causing significant pressure drops.
{"title":"A Geoengineering Approach to Maximum Reservoir Contact Wells Design: Case Study in a Carbonate Reservoir Under Water and Miscible Gas Injection","authors":"A. Freites, Victor Segura, Muhammad Muneeb","doi":"10.2118/207300-ms","DOIUrl":"https://doi.org/10.2118/207300-ms","url":null,"abstract":"\u0000 Maximum Reservoir Contact wells (MRCs) are a potential alternative to reduce the number of wells required to develop hydrocarbon reservoirs, improve sweeping efficiency and delay gas and water breakthrough. The well completions design is critical for the success of MRCs. In this study we present a case study of a MRC well completion design using Limited Entry Liners (LEL) in a mature carbonate reservoir under water and miscible gas injection. We developed an integrated workflow that considered a high-resolution numerical simulation model calibrated to static and dynamic data and wellbore-reservoir models coupling, for capturing the details of the flow interaction between both systems. Flow restrictions in the form of additional pressure drops to the flow from the reservoir into the wellbore were used to simulate the effect of small open flow areas, i.e.shot densities, in the LELs. Our work allowed identifying the most likely entry points of gas and water and design the well to minimize their impact on oil production. We observe that longer lengths open to flow outweighs the detrimental effect of producing from intervals closer to the water saturated zones. We also observed that balancing the inflow profile along the wellbore did not report beneficial results to oil production as it stimulates production from the reservoir zone from which the gas breakthrough is expected (middle of the producing section); this result is particularly relevant as it shows that designing the well completions with base only on static data could lead to poor production performance. The suggested completion for the MRC well encompasses four segments; a segment covering almost 50 % of the well length and located at the middle of the producing section with a blind liner (close to flow for gas control) and the remaining three with slotted liners with enough open area as to avoid causing significant pressure drops.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"16 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73120881","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}
Sheldon Seales, Ahmed Rashed Alaleeli, Jan Erik Tveteraas, Daniel M. Roberts, Glenn Aasland, Patrick Ray Billomos
This paper outlines a new and innovative technology for brine recovery after the displacement of Reservoir Drill-In Fluid Non-Aqueous Fluid (RDF NAF) to Completion Brine and the associated operational, logistical, environmental and economic benefits associated with it. A unique slop treatment technology has been utilized to recover and reuse more than 2,168 bbl per well of expensive contaminated completion fluid to help manage losses and avoid injecting valuable completion fluid into operator's injection well. This has also resulted in reducing impact to the life of the injection well and burden on formation, thereby minimizing impact to subsurface environment and contributing to lower well cost. The contaminated brine was transferred from the displacement of RDF NAF to brine and processed using a novel slop treatment technology to reduce the NTU and TSS to completion brine specifications required for completion operations. After displacing the well from RDF NAF to brine, typical contaminants would be RDF NAF and hi-vis spacer (water-based). The oil-contaminated brine was usually transferred to the tanks of the cuttings treatment contractor, treated and injected into the operator's cuttings re-injection (CRI) well. The new procedure isolated the contaminated brine to be processed through the slop treatment technology to separate and remove the oil and solids from the brine. The slop treatment involved passing the contaminated fluid through a decanter, solids particulate filter, three-phase separator and then a polishing filter to process the fluid to the required NTU and TSS specifications. The slops treatment unit was implemented for brine processing in 2020 and since then, the solution has achieved desirable operational, logistical, sub-surface environmental and cost related benefits. 2,168 bbl of expensive, contaminated completion brine has been processed per well, for subsequent reuse in the completion operations. Utilization and implementation of this mechanical process, versus the historical filter press process, at the source has had clear tangible savings that can be achieved in all areas of the operation, due to the capability to process oil-contaminated brine at a higher clarity and also the viscous brine at a faster rate. This new processing strategy allowed the operator to set new standards with regards to the recovery of oil-contaminated brine, in the UAE. This is the first successful processing of oil-contaminated brine to be completed in the UAE utilizing a mechanical technology. This process has established new baselines for the operator to be able to recover oil-contaminated brine. By adapting the existing site-based slop treatment technology, this solution has bridged a gap in the market by using a novel mechanical process to optimize oil-contaminated brine recovery efficiency and maximize returns for operators.
{"title":"Maximizing Brine Recovery After the Displacement of Reservoir Drill-in Fluids to Reduce Well Cost Via New, Alternate Technology In a Reservoir Offshore Abu Dhabi","authors":"Sheldon Seales, Ahmed Rashed Alaleeli, Jan Erik Tveteraas, Daniel M. Roberts, Glenn Aasland, Patrick Ray Billomos","doi":"10.2118/207785-ms","DOIUrl":"https://doi.org/10.2118/207785-ms","url":null,"abstract":"\u0000 \u0000 \u0000 This paper outlines a new and innovative technology for brine recovery after the displacement of Reservoir Drill-In Fluid Non-Aqueous Fluid (RDF NAF) to Completion Brine and the associated operational, logistical, environmental and economic benefits associated with it. A unique slop treatment technology has been utilized to recover and reuse more than 2,168 bbl per well of expensive contaminated completion fluid to help manage losses and avoid injecting valuable completion fluid into operator's injection well. This has also resulted in reducing impact to the life of the injection well and burden on formation, thereby minimizing impact to subsurface environment and contributing to lower well cost.\u0000 \u0000 \u0000 \u0000 The contaminated brine was transferred from the displacement of RDF NAF to brine and processed using a novel slop treatment technology to reduce the NTU and TSS to completion brine specifications required for completion operations. After displacing the well from RDF NAF to brine, typical contaminants would be RDF NAF and hi-vis spacer (water-based). The oil-contaminated brine was usually transferred to the tanks of the cuttings treatment contractor, treated and injected into the operator's cuttings re-injection (CRI) well. The new procedure isolated the contaminated brine to be processed through the slop treatment technology to separate and remove the oil and solids from the brine. The slop treatment involved passing the contaminated fluid through a decanter, solids particulate filter, three-phase separator and then a polishing filter to process the fluid to the required NTU and TSS specifications.\u0000 \u0000 \u0000 \u0000 The slops treatment unit was implemented for brine processing in 2020 and since then, the solution has achieved desirable operational, logistical, sub-surface environmental and cost related benefits. 2,168 bbl of expensive, contaminated completion brine has been processed per well, for subsequent reuse in the completion operations. Utilization and implementation of this mechanical process, versus the historical filter press process, at the source has had clear tangible savings that can be achieved in all areas of the operation, due to the capability to process oil-contaminated brine at a higher clarity and also the viscous brine at a faster rate. This new processing strategy allowed the operator to set new standards with regards to the recovery of oil-contaminated brine, in the UAE.\u0000 \u0000 \u0000 \u0000 This is the first successful processing of oil-contaminated brine to be completed in the UAE utilizing a mechanical technology. This process has established new baselines for the operator to be able to recover oil-contaminated brine. By adapting the existing site-based slop treatment technology, this solution has bridged a gap in the market by using a novel mechanical process to optimize oil-contaminated brine recovery efficiency and maximize returns for operators.\u0000","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"8 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73129710","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. Razali, Ivy Ching Hsia Chai, A.A. a Manap, M. M. Mahamad Amir
The capability of commercial nanoparticles to perform as foam stabilizer were investigated at reservoir temperature of 96°C. Al2O3, Fe3O4, Co3O4, CuO, MgO, NiO, ZrO2, ZnO and SiO2 nanoparticles that were characterized using XRD, FTIR, FESEM-EDX, TEM and PSA, were blended in the in-house formulated surfactant named IVF respectively at a particular ratio. The test was performed with and without the presence of reservoir crude oil. Results showed that formulation with nanoparticles enhanced foam stability by having longer foam half-life than the IVF surfactant alone, especially in the absence of oil. Only SiO2 nanoparticles were observed to have improved the foam stability in both test conditions. The unique properties of SiO2 as a semi-metal oxide material may have contributed to the insensitivity of SiO2 nanoparticle towards crude oil which is known as a foam destabilizer. The physical barrier that was formed by SiO2 nanoparticles at the foam lamella were probably unaffected by the presence of crude oil, thus allowing the foams to maintain its stability. In thermal stability tests, we observed the instability of all nanoparticles in the IVF formulation at 96°C. Nanoparticles were observed to have separated and settled within 24 hours. Therefore, surface modification of nanoparticle was done to establish steric stabilization by grafting macro-molecule of polymer onto the surface of SiO2. This in-house developed polymer grafted silica nanoparticles are named ZPG nanoparticles. The ZPG nanoparticles passed the thermal stability test at 96°C for a duration of 3 months. In the foam wetness analysis, ZPG nanoparticles were observed to have produced more wet foams than IVF formulation alone, indicating that ZPG is suitable to be used as foam stabilizer for EOR process as it showed catalytic behaviour and thermally well-stable at reservoir temperature.
{"title":"Enhanced Foam Stability Using Nanoparticle in High Salinity High Temperature Condition for Eor Application","authors":"N. Razali, Ivy Ching Hsia Chai, A.A. a Manap, M. M. Mahamad Amir","doi":"10.2118/208196-ms","DOIUrl":"https://doi.org/10.2118/208196-ms","url":null,"abstract":"\u0000 The capability of commercial nanoparticles to perform as foam stabilizer were investigated at reservoir temperature of 96°C. Al2O3, Fe3O4, Co3O4, CuO, MgO, NiO, ZrO2, ZnO and SiO2 nanoparticles that were characterized using XRD, FTIR, FESEM-EDX, TEM and PSA, were blended in the in-house formulated surfactant named IVF respectively at a particular ratio. The test was performed with and without the presence of reservoir crude oil. Results showed that formulation with nanoparticles enhanced foam stability by having longer foam half-life than the IVF surfactant alone, especially in the absence of oil. Only SiO2 nanoparticles were observed to have improved the foam stability in both test conditions. The unique properties of SiO2 as a semi-metal oxide material may have contributed to the insensitivity of SiO2 nanoparticle towards crude oil which is known as a foam destabilizer. The physical barrier that was formed by SiO2 nanoparticles at the foam lamella were probably unaffected by the presence of crude oil, thus allowing the foams to maintain its stability. In thermal stability tests, we observed the instability of all nanoparticles in the IVF formulation at 96°C. Nanoparticles were observed to have separated and settled within 24 hours. Therefore, surface modification of nanoparticle was done to establish steric stabilization by grafting macro-molecule of polymer onto the surface of SiO2. This in-house developed polymer grafted silica nanoparticles are named ZPG nanoparticles. The ZPG nanoparticles passed the thermal stability test at 96°C for a duration of 3 months. In the foam wetness analysis, ZPG nanoparticles were observed to have produced more wet foams than IVF formulation alone, indicating that ZPG is suitable to be used as foam stabilizer for EOR process as it showed catalytic behaviour and thermally well-stable at reservoir temperature.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"9 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79765588","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}
Arabian Gulf region with its hot, humid and prolonged summer is known to be one of the most challenging environments for radio-wave propagation. Over-the-sea microwave radio links here face degradation and unpredictability in performance due to anomalous propagation, ducting and reflective effects of large water bodies. This paper presents microwave radio link design challenges in an offshore environment and the methods implemented to overcome these challenges in the context of specific project experience in offshore field areas. A baseline design for the links was established initially which was optimized during the course of the project and during on-site implementation. Several design changes to achieve the desired performance were evaluated and implemented in the field. Required microwave link availability and performance objectives were achieved as a result of collaborative efforts between the operating company, contractor and radio manufacturer over a multi-year period. Use of quadruple diversity, optimal selection of frequencies, judicious use of ATPC (Automatic Transmit Power Control) and use of optimal signal polarisation were some of the methods used to achieve the desired link availability and performance. While these are well-known methods in radio engineering, the particular combination(s) employed to realize the desired performance objectives are identified in the paper as a lessons-learnt exercise which can be of wider application in the petroleum industry in the Gulf region. Over-water wideband microwave links are generally considered unreliable in terms of performance for utilization in process control applications involving remote shutdown and other critical operations. However, the links referred to in this paper continue to serve the field control system applications till date.
{"title":"Design Considerations for Over-Water Microwave Radio Links - A Case Study","authors":"Yunus Chozhiyattel, Iman Affan","doi":"10.2118/207630-ms","DOIUrl":"https://doi.org/10.2118/207630-ms","url":null,"abstract":"\u0000 Arabian Gulf region with its hot, humid and prolonged summer is known to be one of the most challenging environments for radio-wave propagation. Over-the-sea microwave radio links here face degradation and unpredictability in performance due to anomalous propagation, ducting and reflective effects of large water bodies. This paper presents microwave radio link design challenges in an offshore environment and the methods implemented to overcome these challenges in the context of specific project experience in offshore field areas.\u0000 A baseline design for the links was established initially which was optimized during the course of the project and during on-site implementation. Several design changes to achieve the desired performance were evaluated and implemented in the field. Required microwave link availability and performance objectives were achieved as a result of collaborative efforts between the operating company, contractor and radio manufacturer over a multi-year period.\u0000 Use of quadruple diversity, optimal selection of frequencies, judicious use of ATPC (Automatic Transmit Power Control) and use of optimal signal polarisation were some of the methods used to achieve the desired link availability and performance. While these are well-known methods in radio engineering, the particular combination(s) employed to realize the desired performance objectives are identified in the paper as a lessons-learnt exercise which can be of wider application in the petroleum industry in the Gulf region. Over-water wideband microwave links are generally considered unreliable in terms of performance for utilization in process control applications involving remote shutdown and other critical operations. However, the links referred to in this paper continue to serve the field control system applications till date.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"61 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83119573","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}
Mohamed A. Awwad, Ahmed Marei Al Radhi, M. Panigrahy, Suraj Kumar Gopal
Cost optimization is a continuous process in any business to drive cost reduction, while maximizing business value. Currently, cost reduction is being adopted by Oil & Gas firms as a core strategy, in order to maximize the profit margin. With global economies facing recession and wide fluctuations in energy demands, it seems low costs is becoming the safety valve for Oil & Gas companies. The oil and gas industry is under tremendous revenue and costs pressures. The indication is that globally, the oil and gas industry has experienced a huge drop in revenue in recent past. Some exploration and production oil firms have either halted or slowed down their production operations. Companies that manage their costs effectively will gain a competitive advantage. The oil market has less maneuverability with oil cartels determining the international price of oil. Project Costs are the major cost drivers of the Life Cycle costing & so Cost optimization of all mega Oil & Gas Projects became necessitated. Mega Oil & Gas projects, especially at ADNOC Offshore locations, are complex, labor-intensive and located inside Arabian Sea. These workforces are mainly from south Asian countries and so offshore sites are often subjected to the constraints of insufficient labor. These projects face multiple challenges in project management like severe weather, geographical conditions, insufficient work spaces etc. in addition to labor forces. Cost reductions are accomplished through optimization of its strong and robust project management organization, management of uncertainties, high quality engineering, and implementation of value engineering during engineering, procurement, construction and commissioning (EPCC) phases and effective management of changes along with key Stakeholders expectations throughout the project life cycle. This paper is based on the authors’ real life experience in implementation of many complex and mega upstream Oil & Gas projects with ADNOC Offshore who is currently leading multiple projects at DAS & Zirku islands. The most workable methods in this regard are listed here below.
{"title":"Cost Optimization in Mega Oil & Gas Projects","authors":"Mohamed A. Awwad, Ahmed Marei Al Radhi, M. Panigrahy, Suraj Kumar Gopal","doi":"10.2118/207751-ms","DOIUrl":"https://doi.org/10.2118/207751-ms","url":null,"abstract":"\u0000 Cost optimization is a continuous process in any business to drive cost reduction, while maximizing business value. Currently, cost reduction is being adopted by Oil & Gas firms as a core strategy, in order to maximize the profit margin. With global economies facing recession and wide fluctuations in energy demands, it seems low costs is becoming the safety valve for Oil & Gas companies. The oil and gas industry is under tremendous revenue and costs pressures. The indication is that globally, the oil and gas industry has experienced a huge drop in revenue in recent past. Some exploration and production oil firms have either halted or slowed down their production operations. Companies that manage their costs effectively will gain a competitive advantage. The oil market has less maneuverability with oil cartels determining the international price of oil. Project Costs are the major cost drivers of the Life Cycle costing & so Cost optimization of all mega Oil & Gas Projects became necessitated. Mega Oil & Gas projects, especially at ADNOC Offshore locations, are complex, labor-intensive and located inside Arabian Sea. These workforces are mainly from south Asian countries and so offshore sites are often subjected to the constraints of insufficient labor. These projects face multiple challenges in project management like severe weather, geographical conditions, insufficient work spaces etc. in addition to labor forces.\u0000 Cost reductions are accomplished through optimization of its strong and robust project management organization, management of uncertainties, high quality engineering, and implementation of value engineering during engineering, procurement, construction and commissioning (EPCC) phases and effective management of changes along with key Stakeholders expectations throughout the project life cycle.\u0000 This paper is based on the authors’ real life experience in implementation of many complex and mega upstream Oil & Gas projects with ADNOC Offshore who is currently leading multiple projects at DAS & Zirku islands. The most workable methods in this regard are listed here below.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"11 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83486542","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}
Sultan Ibrahim Al Shemaili, A. Fawzy, E. Assreti, M. El Maghraby, M. Moradi, Prabodh Chaube, Tawheed Mohammed
Several techniques have been applied to improve the water conformance of injection wells to eventually improve field oil recovery. Standalone Passive flow control devices or these devices combined with Sliding sleeves have been successful to improve the conformance in the wells, however, they may fail to provide the required performance in the reservoirs with complex/dynamic properties including propagating/dilating fractures or faults and may also require intervention. This is mainly because the continuously increasing contrast in the injectivity of a section with the feature compared to the rest of the well causes diverting a great portion of the injected fluid into the thief zone which ultimately creates short-circuit to the nearby producer wells. The new autonomous injection device overcomes this issue by selectively choking the injection of fluid into the growing fractures crossing the well. Once a predefined upper flowrate limit is reached at the zone, the valves autonomously close. Well A has been injecting water into reservoir B for several years. It has been recognised from the surveys that the well passes through two major faults and the other two features/fractures with huge uncertainty around their properties. The use of the autonomous valve was considered the best solution to control the water conformance in this well. The device initially operates as a normal passive outflow control valve, and if the injected flowrate flowing through the valve exceeds a designed limit, the device will automatically shut off. This provides the advantage of controlling the faults and fractures in case they were highly conductive as compared to other sections of the well and also once these zones are closed, the device enables the fluid to be distributed to other sections of the well, thereby improving the overall injection conformance. A comprehensive study was performed to change the existing dual completion to a single completion and determine the optimum completion design for delivering the targeted rate for the well while taking into account the huge uncertainty around the faults and features properties. The retrofitted completion including 9 joints with Autonomous valves and 5 joints with Bypass ICD valves were installed in the horizontal section of the well in six compartments separated with five swell packers. The completion was installed in mid-2020 and the well has been on the injection since September 2020. The well performance outcomes show that new completion has successfully delivered the target rate. Also, the data from a PLT survey performed in Feb 2021 shows that the valves have successfully minimised the outflow toward the faults and fractures. This allows achieving the optimised well performance autonomously as the impacts of thief zones on the injected fluid conformance is mitigated and a balanced-prescribed injection distribution is maintained. This paper presents the results from one of the early installations of the valves i
{"title":"The New Generation of Outflow Control Devices Autonomously Controlling the Conformance of Water Injection Well- A Case Study with ADNOC Onshore","authors":"Sultan Ibrahim Al Shemaili, A. Fawzy, E. Assreti, M. El Maghraby, M. Moradi, Prabodh Chaube, Tawheed Mohammed","doi":"10.2118/207647-ms","DOIUrl":"https://doi.org/10.2118/207647-ms","url":null,"abstract":"\u0000 Several techniques have been applied to improve the water conformance of injection wells to eventually improve field oil recovery. Standalone Passive flow control devices or these devices combined with Sliding sleeves have been successful to improve the conformance in the wells, however, they may fail to provide the required performance in the reservoirs with complex/dynamic properties including propagating/dilating fractures or faults and may also require intervention. This is mainly because the continuously increasing contrast in the injectivity of a section with the feature compared to the rest of the well causes diverting a great portion of the injected fluid into the thief zone which ultimately creates short-circuit to the nearby producer wells. The new autonomous injection device overcomes this issue by selectively choking the injection of fluid into the growing fractures crossing the well. Once a predefined upper flowrate limit is reached at the zone, the valves autonomously close.\u0000 Well A has been injecting water into reservoir B for several years. It has been recognised from the surveys that the well passes through two major faults and the other two features/fractures with huge uncertainty around their properties. The use of the autonomous valve was considered the best solution to control the water conformance in this well. The device initially operates as a normal passive outflow control valve, and if the injected flowrate flowing through the valve exceeds a designed limit, the device will automatically shut off. This provides the advantage of controlling the faults and fractures in case they were highly conductive as compared to other sections of the well and also once these zones are closed, the device enables the fluid to be distributed to other sections of the well, thereby improving the overall injection conformance.\u0000 A comprehensive study was performed to change the existing dual completion to a single completion and determine the optimum completion design for delivering the targeted rate for the well while taking into account the huge uncertainty around the faults and features properties. The retrofitted completion including 9 joints with Autonomous valves and 5 joints with Bypass ICD valves were installed in the horizontal section of the well in six compartments separated with five swell packers. The completion was installed in mid-2020 and the well has been on the injection since September 2020. The well performance outcomes show that new completion has successfully delivered the target rate. Also, the data from a PLT survey performed in Feb 2021 shows that the valves have successfully minimised the outflow toward the faults and fractures. This allows achieving the optimised well performance autonomously as the impacts of thief zones on the injected fluid conformance is mitigated and a balanced-prescribed injection distribution is maintained.\u0000 This paper presents the results from one of the early installations of the valves i","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"29 11 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83281655","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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