O. Garnier, M. Jacob, Véronique Gauchou, Stéphane Nowe, P. Cordelier, Michal Němeček, D. Tvrzník, Lukáš Václavík
Polymer flooding projects require hundreds of ppm of polymer (often HPAM) to viscosify the injection water. It is well known that the required dose of HPAM to obtain a targeted viscosity will decrease by reducing the salinity of the inlet water. When the water salinity is low enough, desalination of water for reducing the required polymer concentration brings effective cost savings. In a scenario where the produced water has a salinity of 6 g/L, desalination of this water down to 1 g/L before polymer injection would reduce by half polymer consumption (from 1300 ppm down to 700 ppm). Such low salinity can be found in many existing polymer flooding projects in sandstones reservoirs. A lower concentration of polymer leads to significant reductions of CAPEX (storage tank, pump size) and OPEX (polymer cost, transport and handling). But there are also indirect advantages and cost savings impact of low incoming Polymer concentration in polymer flooding projects. Polymer flooding technology increases and accelerates the oil production by a so-called piston effect pushing an oil bank and enhancing conformance in the reservoir. But there are issues relative to polymer production such as lower separation efficiency, thermal clogging of the polymer in the heat exchangers and poor performance of produced water treatment due to the presence of polymer. It was proven that the impact on water treatment performance is directly related to the concentration of polymer in the produced water. To reduce this impact, existing technical solutions (such as mechanical or chemical degradation, separation by centrifugation) are costly. The presence of polymer is very detrimental to any filtration technologies (membrane fouling) and therefore Oil in Water reduction below 20 ppm is becoming challenging. Waiting for suitable cost effective water treatment technologies, existing polymer flooding projects have adopted a different strategy aiming at reducing or stopping polymer solution injection when the back produced polymer concentration was about to reach a limit known to impact the existing water treatment. Using the EDR technology to reduce required polymer concentration will thus reduce the back produced polymer concentration and could allow the existing water treatment technologies to handle back produced polymer without additional modification and cost. EDR adaptation to desalination of produced water in presence of polymer, dispersed oil, and production chemicals was performed by Total, MemBrain and MEGA. The development of suitable membrane and stack withstanding up to 80°C was engineered by MemBrain and tested during a few weeks on synthetic produced water on a semi-industrial scale pilot treating 10 m3/h synthetic water (in closed loop) with an EDR stack containing 29.2 m2 membrane area. After a few reference tests for characterizing the EDR stack performances, the pilot was operated during 1 month in presence of a salt matrix representative of the case study: 6
{"title":"Polymer Flooding Cost Optimization Using Electrodialysis Reversal EDR for Produced Water Desalination","authors":"O. Garnier, M. Jacob, Véronique Gauchou, Stéphane Nowe, P. Cordelier, Michal Němeček, D. Tvrzník, Lukáš Václavík","doi":"10.2118/200295-ms","DOIUrl":"https://doi.org/10.2118/200295-ms","url":null,"abstract":"\u0000 Polymer flooding projects require hundreds of ppm of polymer (often HPAM) to viscosify the injection water. It is well known that the required dose of HPAM to obtain a targeted viscosity will decrease by reducing the salinity of the inlet water. When the water salinity is low enough, desalination of water for reducing the required polymer concentration brings effective cost savings. In a scenario where the produced water has a salinity of 6 g/L, desalination of this water down to 1 g/L before polymer injection would reduce by half polymer consumption (from 1300 ppm down to 700 ppm). Such low salinity can be found in many existing polymer flooding projects in sandstones reservoirs. A lower concentration of polymer leads to significant reductions of CAPEX (storage tank, pump size) and OPEX (polymer cost, transport and handling). But there are also indirect advantages and cost savings impact of low incoming Polymer concentration in polymer flooding projects.\u0000 Polymer flooding technology increases and accelerates the oil production by a so-called piston effect pushing an oil bank and enhancing conformance in the reservoir. But there are issues relative to polymer production such as lower separation efficiency, thermal clogging of the polymer in the heat exchangers and poor performance of produced water treatment due to the presence of polymer. It was proven that the impact on water treatment performance is directly related to the concentration of polymer in the produced water. To reduce this impact, existing technical solutions (such as mechanical or chemical degradation, separation by centrifugation) are costly. The presence of polymer is very detrimental to any filtration technologies (membrane fouling) and therefore Oil in Water reduction below 20 ppm is becoming challenging.\u0000 Waiting for suitable cost effective water treatment technologies, existing polymer flooding projects have adopted a different strategy aiming at reducing or stopping polymer solution injection when the back produced polymer concentration was about to reach a limit known to impact the existing water treatment. Using the EDR technology to reduce required polymer concentration will thus reduce the back produced polymer concentration and could allow the existing water treatment technologies to handle back produced polymer without additional modification and cost. EDR adaptation to desalination of produced water in presence of polymer, dispersed oil, and production chemicals was performed by Total, MemBrain and MEGA. The development of suitable membrane and stack withstanding up to 80°C was engineered by MemBrain and tested during a few weeks on synthetic produced water on a semi-industrial scale pilot treating 10 m3/h synthetic water (in closed loop) with an EDR stack containing 29.2 m2 membrane area.\u0000 After a few reference tests for characterizing the EDR stack performances, the pilot was operated during 1 month in presence of a salt matrix representative of the case study: 6","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":" 88","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91410727","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The objective of this study was to find an optimum EOR strategy for a Middle-East offshore heavy-oil reservoir that exhibits reservoir-fluids-properties variations with depth using non-isothermal compositional simulations that honor the fluids-compositional variations with depth. The observed compositional variations are such that the oil density changes from 20 °API in the crest to 11 °API in the deep part and the live-oil viscosity increases from 14 cP in the crest part to 449 cP in the deep part of the reservoir. Because the concept of thermodynamic equilibrium is not valid for the reservoir with compositional variations, we used the theory of irreversible thermodynamics to develop a compositional PVT model that captures the observed compositional and oil-properties variations with depth. Next, the PVT model was tuned against CO2 and hydrocarbon-gas swelling and MMP tests. Subsequently, we developed a compositional reservoir dynamic model that uses the single compositional PVT model and can simulate the degree of CO2/hydrocarbon-gas miscibility in oil. Then, we performed a dynamic IOR/EOR screening that includes water injection, hydrocarbon-gas injection, CO2 injection, water-alternating-CO2 injection, polymer injection, polymer-alternating-CO2 injection (PAG-CO2), and simultaneous polymer and CO2 injection (SPCO2). For simultaneous polymer and CO2 injection, polymer was injected at the top while CO2 was injected at the bottom. The simulation runs of these scenarios were elucidated in detail. The developed compositional PVT model successfully reproduces the observed fluids-properties and compositional variations with depth. In this way, the calculated fluids properties are continuous with depth because there is only a single PVT model for a single PVT region. The performances of different EOR scenarios were compared with each other. The simulated incremental oil recovery increases in the sequence of water injection, hydrocarbon-gas injection, WAG-CO2 injection, CO2 injection, polymer (22 cP) injection, PAG-CO2, and SPCO2. The reason for higher incremental recoveries with combined CO2-polymer scenarios is that both the macroscopic sweep (with polymer) and microscopic displacement efficiency (with CO2 and polymer) remain high. Although the CO2 injection pressure is lower than the MMP, the condensing- and vaporizing-gas drives are very efficient to the remaining oil saturation to low values (< 0.10). The other advantage of SPCO2 injection is that the intermediate and deep layers are well contacted and swept by the injected fluids. At the crest scale, combined CO2-polymer scenarios can increase the do-nothing recovery by 85–119%.
{"title":"Non-Isothermal Compositional Simulation Study for Determining an Optimum EOR Strategy for a Middle-East Offshore Heavy-Oil Reservoir with Compositional Variations with Depth","authors":"H. Salimi, Bram Sieders, J. Rostami","doi":"10.2118/200274-ms","DOIUrl":"https://doi.org/10.2118/200274-ms","url":null,"abstract":"\u0000 The objective of this study was to find an optimum EOR strategy for a Middle-East offshore heavy-oil reservoir that exhibits reservoir-fluids-properties variations with depth using non-isothermal compositional simulations that honor the fluids-compositional variations with depth. The observed compositional variations are such that the oil density changes from 20 °API in the crest to 11 °API in the deep part and the live-oil viscosity increases from 14 cP in the crest part to 449 cP in the deep part of the reservoir. Because the concept of thermodynamic equilibrium is not valid for the reservoir with compositional variations, we used the theory of irreversible thermodynamics to develop a compositional PVT model that captures the observed compositional and oil-properties variations with depth. Next, the PVT model was tuned against CO2 and hydrocarbon-gas swelling and MMP tests. Subsequently, we developed a compositional reservoir dynamic model that uses the single compositional PVT model and can simulate the degree of CO2/hydrocarbon-gas miscibility in oil. Then, we performed a dynamic IOR/EOR screening that includes water injection, hydrocarbon-gas injection, CO2 injection, water-alternating-CO2 injection, polymer injection, polymer-alternating-CO2 injection (PAG-CO2), and simultaneous polymer and CO2 injection (SPCO2). For simultaneous polymer and CO2 injection, polymer was injected at the top while CO2 was injected at the bottom. The simulation runs of these scenarios were elucidated in detail.\u0000 The developed compositional PVT model successfully reproduces the observed fluids-properties and compositional variations with depth. In this way, the calculated fluids properties are continuous with depth because there is only a single PVT model for a single PVT region. The performances of different EOR scenarios were compared with each other. The simulated incremental oil recovery increases in the sequence of water injection, hydrocarbon-gas injection, WAG-CO2 injection, CO2 injection, polymer (22 cP) injection, PAG-CO2, and SPCO2. The reason for higher incremental recoveries with combined CO2-polymer scenarios is that both the macroscopic sweep (with polymer) and microscopic displacement efficiency (with CO2 and polymer) remain high. Although the CO2 injection pressure is lower than the MMP, the condensing- and vaporizing-gas drives are very efficient to the remaining oil saturation to low values (< 0.10). The other advantage of SPCO2 injection is that the intermediate and deep layers are well contacted and swept by the injected fluids. At the crest scale, combined CO2-polymer scenarios can increase the do-nothing recovery by 85–119%.","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"25 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83327566","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}
F. Yahyaai, Basayir Lawati, Sara Abri, Maryam Salmi, Mohamed Razvi, Salha Mahruqi, Arlene Winchester, Koning Maartje
The SN-Deep field is located in the central area of the Sultanate of Oman, 20 km west of the Qarn Alam (QA) station and is operated by the Gas Directorate. The field consists of three deep sandstone reservoirs with rich and lean gas fluids. 50% of GIIP has been produced resulting in significant pressure depletion. This paper will: Illustrate the WRFM approaches used to manage some of the late life of the field challenges such as sand production, water breakthrough, and scale formation, which were not predicted during the fields’ development phase. Enhanced field production recovery through new technologies to unlock additional reserves. Extensive well, reservoir, and field management (WRFM) interventions have reduced the field's production decline and sustained the production performance through the following: Water producing wells – analytical techniques are used to predict water production and forecast which wells are expected to reach critical rates. Resources are therefore allocated yearly for wells expected to show significant water production, limiting well down time. In addition, velocity strings with water shut-off are deployed to minimize deferment and cost. During interventions, wells with additional behind casing reserves volumes are also produced. Foam assisted lift (FAL) and permanent installation has been used as secondary means to reduce additional hydrostatic heads for wells with high water production. A trial with FAL on some wells showed sustainable gas rate with high WGR after foam injection. Scaling and salting – to prevent declining production potentials, proactive fresh water bull heading is used to treat symptomatic wells. The technique and the frequent well interventions were able to reduce the deferment and the need for other expensive resources. Solids production – sand production in the field is managed via implementing an integrated sand management strategy that covered all aspects related to required investigation, arresting, and control monitoring.
SN-Deep油田位于阿曼苏丹国中部地区，Qarn Alam (QA)站以西20公里处，由天然气理事会运营。该油田由三个深层砂岩储层组成，具有富贫气流体。GIIP的50%已经开采，导致压力显著下降。本文将阐述WRFM方法用于管理油田后期的一些挑战，如出砂、窜水和结垢，这些问题在油田开发阶段是无法预测的。通过新技术提高油田采收率，释放更多储量。广泛的井、储层和油田管理(WRFM)干预措施减少了油田的产量下降，并通过以下方式维持了生产业绩:产水井——分析技术用于预测产水量，并预测哪些井有望达到临界产量。因此，资源每年分配给预计会产生大量水的井，从而限制了井的停机时间。此外，采用了带堵水功能的速度串，以最大限度地减少延迟和成本。在修井期间，还生产了套管后储量增加的井。泡沫辅助举升(FAL)和永久安装已被用作减少高产水量井额外静水压头的次要手段。在一些井中进行的FAL试验表明，泡沫注入后的气产率可持续，WGR高。结垢和加盐——为了防止生产潜力下降，采用主动淡水灌头来处理有症状的井。该技术和频繁的油井干预能够减少延迟和对其他昂贵资源的需求。通过实施综合防砂策略来管理现场的固体产砂，该策略涵盖了与所需的调查、拦截和控制监测相关的所有方面。
{"title":"Challenges & Mitigations in a Matured Gas Field in the Sultanate of Oman","authors":"F. Yahyaai, Basayir Lawati, Sara Abri, Maryam Salmi, Mohamed Razvi, Salha Mahruqi, Arlene Winchester, Koning Maartje","doi":"10.2118/200113-ms","DOIUrl":"https://doi.org/10.2118/200113-ms","url":null,"abstract":"\u0000 The SN-Deep field is located in the central area of the Sultanate of Oman, 20 km west of the Qarn Alam (QA) station and is operated by the Gas Directorate. The field consists of three deep sandstone reservoirs with rich and lean gas fluids. 50% of GIIP has been produced resulting in significant pressure depletion. This paper will:\u0000 Illustrate the WRFM approaches used to manage some of the late life of the field challenges such as sand production, water breakthrough, and scale formation, which were not predicted during the fields’ development phase. Enhanced field production recovery through new technologies to unlock additional reserves.\u0000 Extensive well, reservoir, and field management (WRFM) interventions have reduced the field's production decline and sustained the production performance through the following:\u0000 Water producing wells – analytical techniques are used to predict water production and forecast which wells are expected to reach critical rates. Resources are therefore allocated yearly for wells expected to show significant water production, limiting well down time. In addition, velocity strings with water shut-off are deployed to minimize deferment and cost. During interventions, wells with additional behind casing reserves volumes are also produced. Foam assisted lift (FAL) and permanent installation has been used as secondary means to reduce additional hydrostatic heads for wells with high water production. A trial with FAL on some wells showed sustainable gas rate with high WGR after foam injection. Scaling and salting – to prevent declining production potentials, proactive fresh water bull heading is used to treat symptomatic wells. The technique and the frequent well interventions were able to reduce the deferment and the need for other expensive resources. Solids production – sand production in the field is managed via implementing an integrated sand management strategy that covered all aspects related to required investigation, arresting, and control monitoring.","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"133 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79386712","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}
Siân A. Jones, R. Bos, V. Laštovka, R. Farajzadeh, M. Riyami
The efficiency of oil processes depends on the product of volumetric sweep and microscopic sweep. In oil recovery by steam injection the microscopic sweep is generally good; however, obtaining a good volumetric sweep can be challenging. This is caused by low density and viscosity of the injected steam combined with the reservoir heterogeneity, in particular existence of thief zone. Consequently, the steam utilization factor measured by steam-to-oil ratio (SOR, kg steam/bbl of oil) for many steam-flooding projects becomes poor. All these issues can be addressed by a successful application of steam foam technology. In steam foam applications, steam (plus a non-condensing gas) is injected simulateneously with a surfactant solution. Under the favorable injection conditions a foam is formed inside the reservoir leading to significant reduction of steam mobility and can eventually improve sweep efficiency. In the literature many successful steam foam pilots have been reported. However, most of these applications are at relatively shallow reservoirs with low pressures and thus low temperatures. In our paper we investigate if steam foam can also be effectively used for applications at high steam temperatures, significantly exceeding 200°C. To test the viability of steam foam technology at high temperatures, we have tested the stability of multiple surfactants at reservoir conditions. For those surfactants that showed good stability, core flood tests have been carried out to test the ability to form foam and to assess the resulting foam strength. Steam foam tests have also been carried out at temperature up to 240°C.
{"title":"Experimental Assessment of the Viability of High Temperature Steam Foam Applications","authors":"Siân A. Jones, R. Bos, V. Laštovka, R. Farajzadeh, M. Riyami","doi":"10.2118/200198-ms","DOIUrl":"https://doi.org/10.2118/200198-ms","url":null,"abstract":"\u0000 The efficiency of oil processes depends on the product of volumetric sweep and microscopic sweep. In oil recovery by steam injection the microscopic sweep is generally good; however, obtaining a good volumetric sweep can be challenging. This is caused by low density and viscosity of the injected steam combined with the reservoir heterogeneity, in particular existence of thief zone. Consequently, the steam utilization factor measured by steam-to-oil ratio (SOR, kg steam/bbl of oil) for many steam-flooding projects becomes poor. All these issues can be addressed by a successful application of steam foam technology.\u0000 In steam foam applications, steam (plus a non-condensing gas) is injected simulateneously with a surfactant solution. Under the favorable injection conditions a foam is formed inside the reservoir leading to significant reduction of steam mobility and can eventually improve sweep efficiency.\u0000 In the literature many successful steam foam pilots have been reported. However, most of these applications are at relatively shallow reservoirs with low pressures and thus low temperatures. In our paper we investigate if steam foam can also be effectively used for applications at high steam temperatures, significantly exceeding 200°C.\u0000 To test the viability of steam foam technology at high temperatures, we have tested the stability of multiple surfactants at reservoir conditions. For those surfactants that showed good stability, core flood tests have been carried out to test the ability to form foam and to assess the resulting foam strength. Steam foam tests have also been carried out at temperature up to 240°C.","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"10 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84529299","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. Alawami, A. Al-Yami, S. Gharbi, Mohammed Murif Al-Rubaii محمد مريف الربعي
Enhancing the efficiency in drilling operations can lead to significant reduction in the overall costs of wells construction. Efficiency is generally achieved by maximizing drilling rate of penetration (ROP) while minimizing non-productive time (NPT) such as loss of circulation, well control and stuck pipe incidents. Reducing the uncertainties associated with subsurface formations, especially formation stresses around the wellbore, is one key aspect to decreasing the frequency of NPT incidents. Understanding wellbore stresses and the mechanical properties of subsurface formations is essential to optimize drilling surface parameters and drilling fluids properties to ultimately maximize drilling ROP and minimize NPT. Determination of the geomechanics drilling mud window in real time allows drilling operations to proactively prevent fractures and/or formation instabilities. The availability of the mud window in real time will enhance the rig reaction time to any abnormalities experienced while drilling to maintain bottomhole pressure (BHP) consistently within the window. The drilling mud window is constrained by a maximum and a minimum mud weight (MW) boundaries. The lower limit represents the stability gradient and the upper limit represents the fracture gradient. Drilling with a MW below the lower limit may cause formation instabilities such as caving and swelling that could lead to more severe consequences such as stuck pipes. Exceeding the upper limit MW may induce formation fractures that lead to loss of circulation that increases the risks of well control incidents. The developed model automatically and continuously calculates formation mechanical properties such as Young's modulus and Poisson's ratio using sonic logging while drilling (LWD) data. Based on formation specific correlations, the model then determines the in-situ stresses, induced stresses, and principle stresses. The fracture and stability gradients can be determined and converted to a MW for easier communication with the drilling crew. The maximum and minimum MWs are displayed as curves in real time that allows immediate adjustments to drilling parameters and/or drilling fluid properties. Geomechanics studies that contain the mud window are usually conducted pre-drilling using offset wells data, and these studies are often updated post-drilling only, which does not reduce the uncertainties associated with them. A real time model maintains the window relevant and up to date with the new data generated from the well.
{"title":"A Real Time Geomechanics Drilling Mud Window to Enhance Drilling Efficiency","authors":"M. Alawami, A. Al-Yami, S. Gharbi, Mohammed Murif Al-Rubaii محمد مريف الربعي","doi":"10.2118/200033-ms","DOIUrl":"https://doi.org/10.2118/200033-ms","url":null,"abstract":"\u0000 Enhancing the efficiency in drilling operations can lead to significant reduction in the overall costs of wells construction. Efficiency is generally achieved by maximizing drilling rate of penetration (ROP) while minimizing non-productive time (NPT) such as loss of circulation, well control and stuck pipe incidents. Reducing the uncertainties associated with subsurface formations, especially formation stresses around the wellbore, is one key aspect to decreasing the frequency of NPT incidents.\u0000 Understanding wellbore stresses and the mechanical properties of subsurface formations is essential to optimize drilling surface parameters and drilling fluids properties to ultimately maximize drilling ROP and minimize NPT. Determination of the geomechanics drilling mud window in real time allows drilling operations to proactively prevent fractures and/or formation instabilities. The availability of the mud window in real time will enhance the rig reaction time to any abnormalities experienced while drilling to maintain bottomhole pressure (BHP) consistently within the window.\u0000 The drilling mud window is constrained by a maximum and a minimum mud weight (MW) boundaries. The lower limit represents the stability gradient and the upper limit represents the fracture gradient. Drilling with a MW below the lower limit may cause formation instabilities such as caving and swelling that could lead to more severe consequences such as stuck pipes. Exceeding the upper limit MW may induce formation fractures that lead to loss of circulation that increases the risks of well control incidents.\u0000 The developed model automatically and continuously calculates formation mechanical properties such as Young's modulus and Poisson's ratio using sonic logging while drilling (LWD) data. Based on formation specific correlations, the model then determines the in-situ stresses, induced stresses, and principle stresses. The fracture and stability gradients can be determined and converted to a MW for easier communication with the drilling crew. The maximum and minimum MWs are displayed as curves in real time that allows immediate adjustments to drilling parameters and/or drilling fluid properties.\u0000 Geomechanics studies that contain the mud window are usually conducted pre-drilling using offset wells data, and these studies are often updated post-drilling only, which does not reduce the uncertainties associated with them. A real time model maintains the window relevant and up to date with the new data generated from the well.","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"33 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82844239","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}
Roland Grillneder, Markus Marx, Karl Jamek, Wiston Rodriguez
Cost-effective treatment of produced water is crucial for the implementation of EOR technologies. A multi-chamber flotation unit was tested under real-field conditions for a polymer flood of the Matzen field, Austria. The operating conditions, performance, and potential for cost-effective separation were successfully assessed with HPAM polymers for a concentration up to 800 ppm. In order to evaluate the performance of the flotation technology, a comprehensive test matrix for a widespread operating envelope was defined. Characteristics of the feed water were varied by selecting specific production wells from the Torton reservoir. Consequently, a wide range of retention times, oil-in-water contents, oil droplet size distributions, and EOR polymer concentrations were tested. The unit was operated with and without the application of a water clarifier. Performance was evaluated by measuring inlet and outlet water quality parameters via laboratory analyses and an in-line monitoring device. The impact of EOR polymer on the treatment efficiency clearly indicated a turning-point of treatment efficiency dependent on polymer concentration. Produced water conditions of polymer flooding operations are considered harsh due to the impact on oil droplet coalescing behavior and impacted viscosity. The influence of oil droplet size and shearing of polymer versus the impact of retention time on effectiveness was assessed. On-site core-flood tests were performed to evaluate the injection behavior of treated water with different HPAM polymer concentrations and in combination with and without a water clarifier.
{"title":"Field Tests with a Multi Chamber Flotation Technology: Advanced Water Treatment in EOR Polymer Operation","authors":"Roland Grillneder, Markus Marx, Karl Jamek, Wiston Rodriguez","doi":"10.2118/200231-ms","DOIUrl":"https://doi.org/10.2118/200231-ms","url":null,"abstract":"\u0000 Cost-effective treatment of produced water is crucial for the implementation of EOR technologies. A multi-chamber flotation unit was tested under real-field conditions for a polymer flood of the Matzen field, Austria. The operating conditions, performance, and potential for cost-effective separation were successfully assessed with HPAM polymers for a concentration up to 800 ppm.\u0000 In order to evaluate the performance of the flotation technology, a comprehensive test matrix for a widespread operating envelope was defined. Characteristics of the feed water were varied by selecting specific production wells from the Torton reservoir. Consequently, a wide range of retention times, oil-in-water contents, oil droplet size distributions, and EOR polymer concentrations were tested. The unit was operated with and without the application of a water clarifier. Performance was evaluated by measuring inlet and outlet water quality parameters via laboratory analyses and an in-line monitoring device. The impact of EOR polymer on the treatment efficiency clearly indicated a turning-point of treatment efficiency dependent on polymer concentration. Produced water conditions of polymer flooding operations are considered harsh due to the impact on oil droplet coalescing behavior and impacted viscosity. The influence of oil droplet size and shearing of polymer versus the impact of retention time on effectiveness was assessed. On-site core-flood tests were performed to evaluate the injection behavior of treated water with different HPAM polymer concentrations and in combination with and without a water clarifier.","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90861024","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}
Ikhsan Nugraha, D. Widjaja, A. G. Raffn, V. Mathiesen
During the production of horizontal oil wells, it is crucial to normalize the drawdown once gas breakthrough has occurred. This challenge must be addressed either mechanically or chemically to reduce the gas-oil ratio. Unfortunately, without the use of inflow control devices (ICDs) this can result in loss of oil production. This challenge can potentially be addressed by implementing an advanced inflow control valve completion to suppress the gas-oil ratio (GOR) and maintain oil production. Uneven inflow in a horizontal oil well will usually occur due to a pressure drop in the liner, reservoir fractures and heterogeneities. In fields with free gas, this will cause gas coning and breakthrough leading to a high GOR. As the breakthrough expands, the oil production is reduced due to excessive gas production. Passive ICDs have shown that oil production can be increased. Conventional ICDs are not able to shut off the unwanted gas and water production completely. The newest generation of self-regulated ICDs (SRICDs), utilizes valves where their movement is governed by fluid properties being produced, which autonomously shut off the gas and maximize oil recovery. This paper presents the SRICD technology design evolution to match the reservoir challenges, installation processes and well performance comparison before and after completion deployment. A near wellbore inflow simulator was also used to support and model the completion placement, productivity and evaluate the completion performance together with the well production data. The well completion installation and production optimization was successful, and a significant reduction of the GOR was achieved.
{"title":"Using Autonomous Inflow Control Device Completion to Manage Gas Breakthrough Challenges","authors":"Ikhsan Nugraha, D. Widjaja, A. G. Raffn, V. Mathiesen","doi":"10.2118/200168-ms","DOIUrl":"https://doi.org/10.2118/200168-ms","url":null,"abstract":"\u0000 During the production of horizontal oil wells, it is crucial to normalize the drawdown once gas breakthrough has occurred. This challenge must be addressed either mechanically or chemically to reduce the gas-oil ratio. Unfortunately, without the use of inflow control devices (ICDs) this can result in loss of oil production. This challenge can potentially be addressed by implementing an advanced inflow control valve completion to suppress the gas-oil ratio (GOR) and maintain oil production.\u0000 Uneven inflow in a horizontal oil well will usually occur due to a pressure drop in the liner, reservoir fractures and heterogeneities. In fields with free gas, this will cause gas coning and breakthrough leading to a high GOR. As the breakthrough expands, the oil production is reduced due to excessive gas production. Passive ICDs have shown that oil production can be increased. Conventional ICDs are not able to shut off the unwanted gas and water production completely. The newest generation of self-regulated ICDs (SRICDs), utilizes valves where their movement is governed by fluid properties being produced, which autonomously shut off the gas and maximize oil recovery.\u0000 This paper presents the SRICD technology design evolution to match the reservoir challenges, installation processes and well performance comparison before and after completion deployment. A near wellbore inflow simulator was also used to support and model the completion placement, productivity and evaluate the completion performance together with the well production data. The well completion installation and production optimization was successful, and a significant reduction of the GOR was achieved.","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"49 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77487734","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A. Al-Jumah, M. Gokmen, Ameera Harrasi, Ibrahim Abri, Salim Buwaiqi, G. Urdaneta
This paper summarizes the results and learnings from the Autonomous Inflow Control Device (AICD) deployment and installation in multiple heavy oil fields in south Oman, allowing for swift utilization in other fields with similar characteristics. Those AICDs were mainly deployed and tested in those oil fields comprehensively, in horizontal producers, and the results were supported by rigorous lab tests was conducted to understand their behavior. This paper is a continuation of the work in reference [1]. In recent decades, horizontal drilling for producing wells became a widely known and used technology, this is due to the fact they improve the overall recovery, efficiency of production, drainage of the reservoir, as well as delay unwanted fluids (e.g. gas & water). However, this solution was not perfect, as due to highly fractured and heterogeneous reservoirs, premature water and gas production can and will take place, causing remaining oil to be bypassed, and hence, reducing the reservoir's recovery and eventually the profitability [2]. In south Sultanate of Oman, many fields have been developed with the use of the horizontal well technology, but together with its advantages, the geological nature of the formations and the physical properties of the produced fluids, have introduced important challenges regarding production optimization. One of the assets in question comprises of naturally fractured carbonate reservoirs drained through long horizontal open-hole completions. It has been developed with water flood and GOGD system. The main production optimization challenge faced for that asset is the fracture-dominated inflow, which leads to either high water or gas production. On the other hand, another asset where the trial took place comprises of shallow sandstone reservoirs of heavy oil, with strong bottom aquifers and high level of reservoir heterogeneities; fractures, faults and high permeability streaks are characteristic of these reservoirs. A horizontal well usually has a much higher capacity–as compared to a vertical well–for producing fluids at the same drawdown, hence, when talking on critical rates that do not disturb the oil-water-contact, horizontal wells will definitely have a higher critical rate than those of vertical wells, but even so, the capacity of moving fluids are bigger, causing faster movement of bottom water towards the horizontal well regardless [3]. Another field of the trial fields had produced heavy oil, with viscosities in the range of 600 cP to 1000 cP. The permeability is variable and in the range of 100mD to 10D. This makes the mobility ratio very favorable to water production. Some wells have started production with less than 10 % WC, but a sudden increase of WC has been observed up to above 90 %. Most of the wells have been completed with inflatable packers (EZIPs), creating 2 to 3 segments at the horizontal reservoir section. The AICD technology is suitable for being applied in this case of very low oil mo
{"title":"Field Application of the Autonomous Inflow Control Device AICD for Optimized Heavy Oil Production in South Sultanate of Oman","authors":"A. Al-Jumah, M. Gokmen, Ameera Harrasi, Ibrahim Abri, Salim Buwaiqi, G. Urdaneta","doi":"10.2118/200279-ms","DOIUrl":"https://doi.org/10.2118/200279-ms","url":null,"abstract":"\u0000 This paper summarizes the results and learnings from the Autonomous Inflow Control Device (AICD) deployment and installation in multiple heavy oil fields in south Oman, allowing for swift utilization in other fields with similar characteristics. Those AICDs were mainly deployed and tested in those oil fields comprehensively, in horizontal producers, and the results were supported by rigorous lab tests was conducted to understand their behavior. This paper is a continuation of the work in reference [1].\u0000 In recent decades, horizontal drilling for producing wells became a widely known and used technology, this is due to the fact they improve the overall recovery, efficiency of production, drainage of the reservoir, as well as delay unwanted fluids (e.g. gas & water). However, this solution was not perfect, as due to highly fractured and heterogeneous reservoirs, premature water and gas production can and will take place, causing remaining oil to be bypassed, and hence, reducing the reservoir's recovery and eventually the profitability [2]. In south Sultanate of Oman, many fields have been developed with the use of the horizontal well technology, but together with its advantages, the geological nature of the formations and the physical properties of the produced fluids, have introduced important challenges regarding production optimization.\u0000 One of the assets in question comprises of naturally fractured carbonate reservoirs drained through long horizontal open-hole completions. It has been developed with water flood and GOGD system. The main production optimization challenge faced for that asset is the fracture-dominated inflow, which leads to either high water or gas production. On the other hand, another asset where the trial took place comprises of shallow sandstone reservoirs of heavy oil, with strong bottom aquifers and high level of reservoir heterogeneities; fractures, faults and high permeability streaks are characteristic of these reservoirs. A horizontal well usually has a much higher capacity–as compared to a vertical well–for producing fluids at the same drawdown, hence, when talking on critical rates that do not disturb the oil-water-contact, horizontal wells will definitely have a higher critical rate than those of vertical wells, but even so, the capacity of moving fluids are bigger, causing faster movement of bottom water towards the horizontal well regardless [3].\u0000 Another field of the trial fields had produced heavy oil, with viscosities in the range of 600 cP to 1000 cP. The permeability is variable and in the range of 100mD to 10D. This makes the mobility ratio very favorable to water production. Some wells have started production with less than 10 % WC, but a sudden increase of WC has been observed up to above 90 %. Most of the wells have been completed with inflatable packers (EZIPs), creating 2 to 3 segments at the horizontal reservoir section. The AICD technology is suitable for being applied in this case of very low oil mo","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"51 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78050561","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}
Microemulsion phase behavior studies are essential for screening surfactants for improving oil production. The paper presents a modified Hydrophilic-Lipophilic Deviation – Net Average Curvature (HLD-NAC) model to explicitly express the solubilization ratio with respect to a newly defined inherent parameter representing surfactant properties. It also provides a workflow to extract the critical parameters from experimental results for numerical simulation of a chemical flooding process. The equations were derived to calculate the window of Winsor Type III microemulsion. The HLD-NAC model was improved to make the solubilization ratio explicitly expressed with the inherent parameter composed of head area (as), tail length (L) and molecular weight of the surfactants (Mw). An innovated workflow was developed to integrate the microemulsion phase behavior scanning results with the HLD-NAC model. The HLD-NAC model was validated with experimental data of various surfactant formulations. The inherent parameter was applied in the improved HLD-NAC model, making it efficient for modeling microemulsion phase behavior scanning. The data of solubilization ratio and phase volume fraction were well fit in the model without needing to know the details of surfactant properties. This simplified the input of HLD-NAC parameters and made the output more accurate. The HLD-NAC model was successfully validated by experiments with various formulations including surfactant with alcohol, surfactant mixtures, and sodium carbonate-surfactant mixtures. By automatically obtaining the inherent parameter, the improved HLD-NAC model provides a promising application of microemulsion phase behavior in numerical simulation of chemical flooding. The HLD-NAC model is modified by defining an inherent parameter from experimental results of microemulsion phase behavior scanning. This makes it applicable to generate the solubilization ratio parameter for numerical simulation of chemical flooding.
{"title":"An Improved HLD-NAC Model for Microemulsion Phase Behavior Study","authors":"Xingang Bu, M. Han, A. AlSofi, A. Fuseni","doi":"10.2118/200122-ms","DOIUrl":"https://doi.org/10.2118/200122-ms","url":null,"abstract":"\u0000 Microemulsion phase behavior studies are essential for screening surfactants for improving oil production. The paper presents a modified Hydrophilic-Lipophilic Deviation – Net Average Curvature (HLD-NAC) model to explicitly express the solubilization ratio with respect to a newly defined inherent parameter representing surfactant properties. It also provides a workflow to extract the critical parameters from experimental results for numerical simulation of a chemical flooding process. The equations were derived to calculate the window of Winsor Type III microemulsion. The HLD-NAC model was improved to make the solubilization ratio explicitly expressed with the inherent parameter composed of head area (as), tail length (L) and molecular weight of the surfactants (Mw). An innovated workflow was developed to integrate the microemulsion phase behavior scanning results with the HLD-NAC model. The HLD-NAC model was validated with experimental data of various surfactant formulations.\u0000 The inherent parameter was applied in the improved HLD-NAC model, making it efficient for modeling microemulsion phase behavior scanning. The data of solubilization ratio and phase volume fraction were well fit in the model without needing to know the details of surfactant properties. This simplified the input of HLD-NAC parameters and made the output more accurate. The HLD-NAC model was successfully validated by experiments with various formulations including surfactant with alcohol, surfactant mixtures, and sodium carbonate-surfactant mixtures. By automatically obtaining the inherent parameter, the improved HLD-NAC model provides a promising application of microemulsion phase behavior in numerical simulation of chemical flooding. The HLD-NAC model is modified by defining an inherent parameter from experimental results of microemulsion phase behavior scanning. This makes it applicable to generate the solubilization ratio parameter for numerical simulation of chemical flooding.","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"39 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81506892","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A. Vakhin, S. Sitnov, I. Mukhamatdinov, M. Varfolomeev, Allan Rojas, Raushan M. Sabiryanov, A. Al-Muntaser, V. Sudakov, D. Nurgaliev, I. Minkhanov, M. Amerkhanov, R. Akhmadullin
In this work method to improve the efficiency of the development of shallow deposits of extra-heavy oil using cyclic team stimulation (CSS) technology together with injection of catalyst for in-situ upgrading and solvent was proposed. Oil-soluble catalyst has been developed. Efficiency of catalyst was proved in laboratory. Volume and conditions of catalyst and solvent injection together with steam were determined based on simulation results. Pilot tests of technology were carried out on extra-heavy oilfield in Tatarstan, Russia. The screening of catalysts and solvents together with injection of steam was studied in high pressure reactors under reservoir conditions. Heavy oil displacement coefficients in basic scenario of steam injection and second scenario of steam injection together with catalyst and solvent were measured on self-designed experimental steam injection apparatus. The technology was simulated with tNavigator softwarre (Rock Fluid Dynamics) version 18.2, STARS. Pilot tests were carried out in several stages: preliminary short-term injection of steam to pre-heat the reservoir, injection of catalyst solution and solvent, the subsequent full-scale stage of steam injection, imbibition, and production. The results of field tests confirmed laboratory and simulation data. According to the analyzed samples after six months of field tests, the viscosity at the first stage decreases as a result of dilution with a solvent. The effect of the catalyst, which particles are adsorbed on the reservoir rocks, clearly demonstrated later. It is shown that the combined use of in-situ upgrading catalyst and a solvent in CSS method allows to increase oil recovery factor. At the same time, the produced oil has better properties. Significant degree of conversion of resins and asphaltenes to light fractions was established. Field tests on Ashal'cha oilfield have shown that this technology is effective for the development of shallow deposits of extra-heavy oil.
{"title":"Improvement of CSS Method for Extra-Heavy Oil Recovery in Shallow Reservoirs by Simultaneous Injection of in-Situ Upgrading Catalysts and Solvent: Laboratory Study, Simulation and Field Application","authors":"A. Vakhin, S. Sitnov, I. Mukhamatdinov, M. Varfolomeev, Allan Rojas, Raushan M. Sabiryanov, A. Al-Muntaser, V. Sudakov, D. Nurgaliev, I. Minkhanov, M. Amerkhanov, R. Akhmadullin","doi":"10.2118/200082-ms","DOIUrl":"https://doi.org/10.2118/200082-ms","url":null,"abstract":"\u0000 In this work method to improve the efficiency of the development of shallow deposits of extra-heavy oil using cyclic team stimulation (CSS) technology together with injection of catalyst for in-situ upgrading and solvent was proposed. Oil-soluble catalyst has been developed. Efficiency of catalyst was proved in laboratory. Volume and conditions of catalyst and solvent injection together with steam were determined based on simulation results. Pilot tests of technology were carried out on extra-heavy oilfield in Tatarstan, Russia.\u0000 The screening of catalysts and solvents together with injection of steam was studied in high pressure reactors under reservoir conditions. Heavy oil displacement coefficients in basic scenario of steam injection and second scenario of steam injection together with catalyst and solvent were measured on self-designed experimental steam injection apparatus.\u0000 The technology was simulated with tNavigator softwarre (Rock Fluid Dynamics) version 18.2, STARS. Pilot tests were carried out in several stages: preliminary short-term injection of steam to pre-heat the reservoir, injection of catalyst solution and solvent, the subsequent full-scale stage of steam injection, imbibition, and production. The results of field tests confirmed laboratory and simulation data. According to the analyzed samples after six months of field tests, the viscosity at the first stage decreases as a result of dilution with a solvent. The effect of the catalyst, which particles are adsorbed on the reservoir rocks, clearly demonstrated later.\u0000 It is shown that the combined use of in-situ upgrading catalyst and a solvent in CSS method allows to increase oil recovery factor. At the same time, the produced oil has better properties. Significant degree of conversion of resins and asphaltenes to light fractions was established. Field tests on Ashal'cha oilfield have shown that this technology is effective for the development of shallow deposits of extra-heavy oil.","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"10 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84820343","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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