This article reports on a novel simple method for transforming the high-salinity-incompatible petroleum sulfonates into a persistently stable oil-swollen micelles, referred to here as nanosurfactant. We present and discuss the effect of three different nanosurfactant formulations on the interfacial tension (IFT) between high-salinity water and crude oil, their phase behavior, and the effect of their dilution on IFT to assess their ability to reduce mobilize oil after injection into high-salinity and temperature reservoirs. The three nanosurfactant formulations were prepared in high-salinity water following a direct-mixing procedure in which solutions in fresh water of 5 wt% petroleum sulfonate in mineral oil and three 4 wt% zwitterionic co-surfactants were mixed with high-salinity water at room temperature to give a combined concentration of all active ingredients of 0.2 wt%. The IFT between crude oil and different nanosurfactant formulations was measured using a spinning drop interfacial tensiometer at 90°C. IFT was measured every 5 minutes while the oil drop was spinning at ~4000 rpm. The phase behavior was investigated by monitoring the turbidity and UV absorbance changes in a system of crude oil atop of the nanosurfactant formulation over time at 100°C without any mechanical mixing. The particle size of the three nanosurfactant formulations is in the range of 40 to 80 nm, depending on the co-surfactant used. All formulations were persistently stable, colloidally, and chemically under high-salinity (~56,000 ppm) and temperature (100°C) for more than four months. All formulations showed substantial reduction in IFT with crude oil compared to high-salinity water alone. Dilution with high-salinity water up to five times further reduced the IFT, suggesting improved performance after injection into the reservoir. This behavior was consistent with the observed gradual decrease in surface tension of the nanosurfactant formulation as its concentration decreases toward the CMC value. Phase behavior experiments showed enhanced formation of homogeneous micelles at 100°C without the aid of any mixing. Our results demonstrate the ability of nanosurfactants to solubilize oil under typical carbonate reservoir conditions. Their colloidal nature allows them to migrate deeper in the reservoir compared to conventional surfactants due to size exclusion and chromatographic effects. Nanosurfactants are novel oil-swollen micelles of the inexpensive and abundant petroleum sulfonate salts that are efficient in reducing IFT under typical carbonate reservoir conditions. The formulation method can be extended to other surfactants and chemical treatments that are incompatible with high-salinity water at high temperatures. Their nanoparticle character and colloidal behavior suggest their ability to migrate and penetrate deep in the reservoir. Nanosurfactants can therefore help overcome some of the most critical drawbacks in conventional chemical EOR technologies.
{"title":"Novel Nano-Surfactant Formulation to Overcome Key Drawbacks in Conventional Chemical EOR Technologies","authors":"Afnan Mashat, A. Gizzatov, A. Abdel-Fattah","doi":"10.2118/192135-MS","DOIUrl":"https://doi.org/10.2118/192135-MS","url":null,"abstract":"\u0000 This article reports on a novel simple method for transforming the high-salinity-incompatible petroleum sulfonates into a persistently stable oil-swollen micelles, referred to here as nanosurfactant. We present and discuss the effect of three different nanosurfactant formulations on the interfacial tension (IFT) between high-salinity water and crude oil, their phase behavior, and the effect of their dilution on IFT to assess their ability to reduce mobilize oil after injection into high-salinity and temperature reservoirs.\u0000 The three nanosurfactant formulations were prepared in high-salinity water following a direct-mixing procedure in which solutions in fresh water of 5 wt% petroleum sulfonate in mineral oil and three 4 wt% zwitterionic co-surfactants were mixed with high-salinity water at room temperature to give a combined concentration of all active ingredients of 0.2 wt%. The IFT between crude oil and different nanosurfactant formulations was measured using a spinning drop interfacial tensiometer at 90°C. IFT was measured every 5 minutes while the oil drop was spinning at ~4000 rpm. The phase behavior was investigated by monitoring the turbidity and UV absorbance changes in a system of crude oil atop of the nanosurfactant formulation over time at 100°C without any mechanical mixing.\u0000 The particle size of the three nanosurfactant formulations is in the range of 40 to 80 nm, depending on the co-surfactant used. All formulations were persistently stable, colloidally, and chemically under high-salinity (~56,000 ppm) and temperature (100°C) for more than four months. All formulations showed substantial reduction in IFT with crude oil compared to high-salinity water alone. Dilution with high-salinity water up to five times further reduced the IFT, suggesting improved performance after injection into the reservoir. This behavior was consistent with the observed gradual decrease in surface tension of the nanosurfactant formulation as its concentration decreases toward the CMC value. Phase behavior experiments showed enhanced formation of homogeneous micelles at 100°C without the aid of any mixing. Our results demonstrate the ability of nanosurfactants to solubilize oil under typical carbonate reservoir conditions. Their colloidal nature allows them to migrate deeper in the reservoir compared to conventional surfactants due to size exclusion and chromatographic effects.\u0000 Nanosurfactants are novel oil-swollen micelles of the inexpensive and abundant petroleum sulfonate salts that are efficient in reducing IFT under typical carbonate reservoir conditions. The formulation method can be extended to other surfactants and chemical treatments that are incompatible with high-salinity water at high temperatures. Their nanoparticle character and colloidal behavior suggest their ability to migrate and penetrate deep in the reservoir. Nanosurfactants can therefore help overcome some of the most critical drawbacks in conventional chemical EOR technologies.","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"02 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86077490","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}
Xingyuan Zhou, Yongtu Liang, Pengwei Di, Chengcheng Xiang, S. Xin, H. Zhang
As the most commonly used process for the secondary development of oilfields, waterflooding plays a significant role in maintaining reservoir pressure, enhancing oil recovery and achieving high and stable oil production. The previous waterflooding optimization studies usually worked out the optimal injection/production rates but didn't take into account the energy consumed by the surface waterflooding pipeline network system which transfers water from the waterflooding stations to the waterflooding wells. Taking the maximum waterflooding development profit as the objective function, this paper proposes an integrated methodology for the unified optimization of injection/production rates and the operation control of surface waterflooding pipeline network system. The objective function is defined as the oil production income minus the operation cost of the pipeline network. With a given set of injection rates of waterflooding wells, the reservoir numerical simulation is employed to obtain the oil production rates and a mixed integer nonlinear programming (MINLP) model is established for the optimal operation control of the surface waterflooding pipeline network, including the pump schedule of waterflooding stations, flowrate of pipe segments and pressure at each node. A hybrid solving strategy incorporating particle swarm optimization (PSO), linear approximation method, and branch-and-bound algorithm, is proposed for solving the results. The PSO algorithm is adopted to search for the optimal injection rates of waterflooding wells, while the linear approximation method and branch-and-bound algorithm are used for the MINLP model solving. In this study, we took the Daqing waterflooding Oilfield in China as an example. The applicability of the methodology and the stability of the solving strategy are illustrated in detail. It is proved that the proposed methodology could provide the engineers with significant guidelines for the unified optimization of waterflooding process incorporating the reservoir and surface pipeline network.
{"title":"An Integrated Methodology for the Unified Optimization of Injection/Production Rates and Surface Waterflooding Pipeline Network Operation Control","authors":"Xingyuan Zhou, Yongtu Liang, Pengwei Di, Chengcheng Xiang, S. Xin, H. Zhang","doi":"10.2118/192048-MS","DOIUrl":"https://doi.org/10.2118/192048-MS","url":null,"abstract":"\u0000 As the most commonly used process for the secondary development of oilfields, waterflooding plays a significant role in maintaining reservoir pressure, enhancing oil recovery and achieving high and stable oil production. The previous waterflooding optimization studies usually worked out the optimal injection/production rates but didn't take into account the energy consumed by the surface waterflooding pipeline network system which transfers water from the waterflooding stations to the waterflooding wells. Taking the maximum waterflooding development profit as the objective function, this paper proposes an integrated methodology for the unified optimization of injection/production rates and the operation control of surface waterflooding pipeline network system. The objective function is defined as the oil production income minus the operation cost of the pipeline network. With a given set of injection rates of waterflooding wells, the reservoir numerical simulation is employed to obtain the oil production rates and a mixed integer nonlinear programming (MINLP) model is established for the optimal operation control of the surface waterflooding pipeline network, including the pump schedule of waterflooding stations, flowrate of pipe segments and pressure at each node. A hybrid solving strategy incorporating particle swarm optimization (PSO), linear approximation method, and branch-and-bound algorithm, is proposed for solving the results. The PSO algorithm is adopted to search for the optimal injection rates of waterflooding wells, while the linear approximation method and branch-and-bound algorithm are used for the MINLP model solving. In this study, we took the Daqing waterflooding Oilfield in China as an example. The applicability of the methodology and the stability of the solving strategy are illustrated in detail. It is proved that the proposed methodology could provide the engineers with significant guidelines for the unified optimization of waterflooding process incorporating the reservoir and surface pipeline network.","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"41 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90754527","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}
W. Fu, Baojiang Sun, Zhiyuan Wang, Jianbo Zhang, Junqi Wang
Methane hydrate formation in water-based drilling mud is the great important issue for well control during the drilling operation in deep-water environment. However, most of researchers focus on hydrate formation in oil-dominated system and gas-dominated system. Few researchers pay enough attentions to hydrate formation in water-dominated system, especially for bubbly flow. In this work, groups of experiments of methane hydrate formation in horizontal water-dominated bubbly flow are performed at liquid fluid velocities of 0.95 to 1.4m/s and void fractions from 2.5% to 5.0%. According to experimental observations, methane hydrates does not form hydrate shells on gas bubbles in bubbly flow and no complete hydrate shells or plates are observed in experiments. Hydrate particles formed on the surface of bubbles prefers to slough off immediately by high motion of liquid fluid, which results in appearance of tiny bubbles in flow loop. According to analysis of the reaction rate factor, the intrinsic kinetic mainly dominates the hydrate formation at the high subcooling condition but the mass transfer dominates the hydrate formation at the low subcooling condition. A hydrate kinetic model is developed for the horizontal water-dominated bubbly flow, as a function of reaction rate factor, liquid fluid velocity, subcooling temperature and interfacial area. In the new model, the multiphase flow concept of interfacial area concentration is firstly brought in predicting interfacial areas for methane hydrate formation in bubbly flow. Another 8 groups of hydrate formation experiment are conducted to validate the new model and the maximum discrepancy is less than 8%.Ppa
{"title":"Characterizing Methane Hydrate Formation in Horizontal Water-Dominated Bubbly Flow","authors":"W. Fu, Baojiang Sun, Zhiyuan Wang, Jianbo Zhang, Junqi Wang","doi":"10.2118/191868-MS","DOIUrl":"https://doi.org/10.2118/191868-MS","url":null,"abstract":"\u0000 Methane hydrate formation in water-based drilling mud is the great important issue for well control during the drilling operation in deep-water environment. However, most of researchers focus on hydrate formation in oil-dominated system and gas-dominated system. Few researchers pay enough attentions to hydrate formation in water-dominated system, especially for bubbly flow. In this work, groups of experiments of methane hydrate formation in horizontal water-dominated bubbly flow are performed at liquid fluid velocities of 0.95 to 1.4m/s and void fractions from 2.5% to 5.0%. According to experimental observations, methane hydrates does not form hydrate shells on gas bubbles in bubbly flow and no complete hydrate shells or plates are observed in experiments. Hydrate particles formed on the surface of bubbles prefers to slough off immediately by high motion of liquid fluid, which results in appearance of tiny bubbles in flow loop. According to analysis of the reaction rate factor, the intrinsic kinetic mainly dominates the hydrate formation at the high subcooling condition but the mass transfer dominates the hydrate formation at the low subcooling condition. A hydrate kinetic model is developed for the horizontal water-dominated bubbly flow, as a function of reaction rate factor, liquid fluid velocity, subcooling temperature and interfacial area. In the new model, the multiphase flow concept of interfacial area concentration is firstly brought in predicting interfacial areas for methane hydrate formation in bubbly flow. Another 8 groups of hydrate formation experiment are conducted to validate the new model and the maximum discrepancy is less than 8%.Ppa","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"314 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77570992","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 full-field dynamic simulation model has traditionally been seen as the benchmark for assimilating all available static and dynamic data to develop robust production forecasts. Santos’ experience modelling the Walloon Coal Measures in its Surat Basin acreage has shown that the performance of individual wells producing from this CSG reservoir is governed by reservoir variability at a fine-scale. This presents a fundamental challenge in developing full-field dynamic models that can accurately describe and predict production performance down to the scale of individual coal seams. Current Queensland CSG projects have focussed on the most prospective acreage, however as subsequent developments move to more marginal areas a greater understanding of the subsurface will be required for optimum development. The target formations will increase in geological complexity, such as Santos’ Surat Basin acreage on the edge of the CSG fairway. Here wells produce from a greater number of distinct coal reservoir units, and how these reservoir units are structured and relate to each other governs reservoir connectivity and defines long-term production performance. Each reservoir unit is comprised of multiple coal plies, all with their own unique maceral distribution and cleating characteristics. These fine-scale properties define the reservoir's dynamic behaviour, and can be impossible to upscale such that these characteristics are preserved at a coarse scale. Consequently, accurately modelling individual well performance will require a fine-scale model to capture and characterise this variability. In development areas where the quantity and quality of reservoir data gathered from exploration and appraisal is sparsely populated, these fine-scale models will need to be populated geostatistically. Without model-scale appropriate control data from production and pressure measurement in the development wells to provide constraints however, a probabilistic model will not accurately define fine-scale behaviour of specific reservoir units. These data requirements can help shape the appraisal scope for new areas and define an appropriate level of surveillance for producing assets. Traditional full-field dynamic modelling has fundamental limitations for interrogating complex unconventional CSG reservoirs at a fine scale. Because of this, alternative workflows are required to answer the subsurface questions necessary to develop CSG assets such as the Surat Basin effectively. This paper details a selection of workflows explored to address this pragmatically, as well as their limitations and associated data requirements. This will also assist in identifying data gaps needed for optimum reservoir management and to aid in the development of these challenging CSG reservoirs.
{"title":"Dynamic Modelling of Walloon Coal Measures: An Unsavoury Cocktail of Reservoir Variability, Mismatched Resolutions, and Unreasonable Expectations","authors":"Joshua P. Cardwell","doi":"10.2118/191917-MS","DOIUrl":"https://doi.org/10.2118/191917-MS","url":null,"abstract":"\u0000 A full-field dynamic simulation model has traditionally been seen as the benchmark for assimilating all available static and dynamic data to develop robust production forecasts. Santos’ experience modelling the Walloon Coal Measures in its Surat Basin acreage has shown that the performance of individual wells producing from this CSG reservoir is governed by reservoir variability at a fine-scale. This presents a fundamental challenge in developing full-field dynamic models that can accurately describe and predict production performance down to the scale of individual coal seams.\u0000 Current Queensland CSG projects have focussed on the most prospective acreage, however as subsequent developments move to more marginal areas a greater understanding of the subsurface will be required for optimum development. The target formations will increase in geological complexity, such as Santos’ Surat Basin acreage on the edge of the CSG fairway. Here wells produce from a greater number of distinct coal reservoir units, and how these reservoir units are structured and relate to each other governs reservoir connectivity and defines long-term production performance. Each reservoir unit is comprised of multiple coal plies, all with their own unique maceral distribution and cleating characteristics. These fine-scale properties define the reservoir's dynamic behaviour, and can be impossible to upscale such that these characteristics are preserved at a coarse scale. Consequently, accurately modelling individual well performance will require a fine-scale model to capture and characterise this variability.\u0000 In development areas where the quantity and quality of reservoir data gathered from exploration and appraisal is sparsely populated, these fine-scale models will need to be populated geostatistically. Without model-scale appropriate control data from production and pressure measurement in the development wells to provide constraints however, a probabilistic model will not accurately define fine-scale behaviour of specific reservoir units. These data requirements can help shape the appraisal scope for new areas and define an appropriate level of surveillance for producing assets.\u0000 Traditional full-field dynamic modelling has fundamental limitations for interrogating complex unconventional CSG reservoirs at a fine scale. Because of this, alternative workflows are required to answer the subsurface questions necessary to develop CSG assets such as the Surat Basin effectively. This paper details a selection of workflows explored to address this pragmatically, as well as their limitations and associated data requirements. This will also assist in identifying data gaps needed for optimum reservoir management and to aid in the development of these challenging CSG reservoirs.","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"504 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85974880","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}
Horizontal wells are superior over conventional wells in terms of production improvement due to increased reservoir contact. Despite this, these wells pose severe production challenges due to variations in permeability, reservoir pressure, reservoir fluid properties and frictional pressure drop along horizontal section. Preventing water/gas breakthrough, equalizing inflow with minimizing pressure loss, minimizing annular flow and heel-to-toe effect, delay non-uniform water progress, avoiding by-passed oil, increasing sweep efficiency and ultimate recovery are some of the primary challenges for gaining optimum advantages of horizontal wells. One of the promising technologies to address all these challenges is the application of advanced completions utilizing Passive inflow control device (ICD) with oil swellable packers. The use of Passive Inflow Control Device (ICD) along with oil swellable packer in long horizontal wells drilled in unconsolidated sandstone reservoirs has helped alleviate premature water breakthrough /high water production and sand production. Passive inflow control devices (ICDs) are effective in terms of balancing production flow and delaying the onset of water production. Nevertheless, when gas and/or water breakthrough occurs, a passive ICD will allow production of the unwanted fluid along with usual production. This paper discusses the detailed of Passive ICD design workflow and execution carried out to complete 6 nos. of horizontal wells of Oil India Limited in a reservoir having active aquifer drive considering challenges encountered due to uncertainty in permeability, water saturation, permeability distribution and saturation tables distribution. In the absence of dynamic reservoir analysis, offset well data analysis assisted in filling the data gaps by enabling geological and reservoir level understanding. The passive ICD were designed on the basis of Gamma Ray, Resistivity, NPHI (Neutron Porosity Log) and RHOB (Density Log) obtained during TLC logging. A Geological Model was constructed with certain gathered data and few Assumptions were made to obtain reservoir saturation and permeability. Moreover, in this paper an assessment is provided of the production performance review conducted over unconsolidated sandstone reservoirs developed with some horizontal wells equipped with Passive ICD completions compartmentalized with oil swellable packers versus other horizontal completions completed with conventional slotted liner completions. As drilling and completion of horizontal wells are expensive, it was critical to identify the most-suitable Passive ICD completion design with the available dataset before attempting well completion. This was addressed through a customized workflow to design and compartmentalized the horizontal section utilizing the ICD and oil swellable packers for maximizing oil recovery and water/sand breakthrough problem elimination.
水平井由于增加了储层接触，在提高产量方面优于常规井。尽管如此，由于渗透率、储层压力、储层流体性质和水平段摩擦压降的变化，这些井的生产面临着严峻的挑战。防止水/气突破，平衡流入，最大限度地减少压力损失，最大限度地减少环空流动和脚跟到脚趾效应，延迟水的不均匀流动，避免旁溢油，提高波及效率和最终采收率是水平井获得最佳优势的一些主要挑战。解决所有这些挑战的一种很有前途的技术是采用带油膨胀封隔器的被动流入控制装置(ICD)的先进完井技术。在未固结砂岩油藏的长水平井中，采用被动流入控制装置(ICD)和油膨胀封隔器，有助于缓解过早见水/高出水和出砂的问题。被动流入控制装置(icd)在平衡生产流量和延迟产水开始方面是有效的。然而，当气体和/或水发生突破时，被动ICD将允许在正常生产的同时生产不需要的流体。考虑到渗透率、含水饱和度、渗透率分布和饱和度表分布的不确定性所带来的挑战，本文详细讨论了Oil India Limited在含水层活动驱动油藏中完成6口水平井的被动式ICD设计工作流程和执行情况。在缺乏动态油藏分析的情况下，通过对地质和油藏水平的了解，邻井数据分析有助于填补数据空白。无源ICD是根据在TLC测井中获得的伽马射线、电阻率、中子孔隙度测井(NPHI)和密度测井(RHOB)进行设计的。利用收集到的一定数据，建立了一个地质模型，并对储层饱和度和渗透率进行了较少的假设。此外，本文还对未固结砂岩油藏的生产性能进行了评估，其中一些水平井采用了可膨胀封隔器的被动ICD完井，而另一些水平井则采用了常规的开槽尾管完井。由于水平井的钻井和完井成本高昂，因此在尝试完井之前，利用现有数据集确定最合适的被动ICD完井设计至关重要。通过定制的工作流程，利用ICD和油膨胀封隔器设计和划分水平段，以最大限度地提高采收率，消除水/砂突破问题。
{"title":"Use of Passive ICD and Swellable Packer for Successful Horizontal Well Completion in Unconsolidated Sand Stone Reservoir to Eliminate Sand Breakthrough Problem Having Active Aquifer Drive: A Detailed Case Study in Assam-Arakan Basin","authors":"P. Saikia, U. Dutta, P. Goswami","doi":"10.2118/191941-MS","DOIUrl":"https://doi.org/10.2118/191941-MS","url":null,"abstract":"\u0000 Horizontal wells are superior over conventional wells in terms of production improvement due to increased reservoir contact. Despite this, these wells pose severe production challenges due to variations in permeability, reservoir pressure, reservoir fluid properties and frictional pressure drop along horizontal section. Preventing water/gas breakthrough, equalizing inflow with minimizing pressure loss, minimizing annular flow and heel-to-toe effect, delay non-uniform water progress, avoiding by-passed oil, increasing sweep efficiency and ultimate recovery are some of the primary challenges for gaining optimum advantages of horizontal wells. One of the promising technologies to address all these challenges is the application of advanced completions utilizing Passive inflow control device (ICD) with oil swellable packers.\u0000 The use of Passive Inflow Control Device (ICD) along with oil swellable packer in long horizontal wells drilled in unconsolidated sandstone reservoirs has helped alleviate premature water breakthrough /high water production and sand production. Passive inflow control devices (ICDs) are effective in terms of balancing production flow and delaying the onset of water production. Nevertheless, when gas and/or water breakthrough occurs, a passive ICD will allow production of the unwanted fluid along with usual production.\u0000 This paper discusses the detailed of Passive ICD design workflow and execution carried out to complete 6 nos. of horizontal wells of Oil India Limited in a reservoir having active aquifer drive considering challenges encountered due to uncertainty in permeability, water saturation, permeability distribution and saturation tables distribution. In the absence of dynamic reservoir analysis, offset well data analysis assisted in filling the data gaps by enabling geological and reservoir level understanding. The passive ICD were designed on the basis of Gamma Ray, Resistivity, NPHI (Neutron Porosity Log) and RHOB (Density Log) obtained during TLC logging. A Geological Model was constructed with certain gathered data and few Assumptions were made to obtain reservoir saturation and permeability. Moreover, in this paper an assessment is provided of the production performance review conducted over unconsolidated sandstone reservoirs developed with some horizontal wells equipped with Passive ICD completions compartmentalized with oil swellable packers versus other horizontal completions completed with conventional slotted liner completions.\u0000 As drilling and completion of horizontal wells are expensive, it was critical to identify the most-suitable Passive ICD completion design with the available dataset before attempting well completion. This was addressed through a customized workflow to design and compartmentalized the horizontal section utilizing the ICD and oil swellable packers for maximizing oil recovery and water/sand breakthrough problem elimination.","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"43 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87719034","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
T. Heu, Anson Wee, C. Combe, Razif Mohd-Radzi, Ting-Ting Zhang
Conventional ‘textbook’ primary cement job execution has always been associated with the combination of bumping top wiper plug, successful casing pressure test and/or no losses during the job. These criteria have been referenced by the general industry as positive indications and conveniently adopted as qualification for a successful cement job without considering other key parameters that contributes to proper cement isolation behind casing. In a deepwater development campaign offshore Malaysia, cement isolation behind the 9-5/8" production casing serves as critical barrier to ensure well integrity throughout the production lifecycle. To achieve this, the authors have deployed a structured approach focused on designing for success and optimizing a set of key performance indicators (KPIs) with pre- and post-drilled hole conditions. This paper outlines the approach based on the experience from the drilling campaign of nine oil producer wells.
{"title":"Structured Approach in Qualifying Cement Isolation Through the Use of Cementing Scorecard and Post-Job Execution Data","authors":"T. Heu, Anson Wee, C. Combe, Razif Mohd-Radzi, Ting-Ting Zhang","doi":"10.2118/192096-MS","DOIUrl":"https://doi.org/10.2118/192096-MS","url":null,"abstract":"\u0000 Conventional ‘textbook’ primary cement job execution has always been associated with the combination of bumping top wiper plug, successful casing pressure test and/or no losses during the job. These criteria have been referenced by the general industry as positive indications and conveniently adopted as qualification for a successful cement job without considering other key parameters that contributes to proper cement isolation behind casing. In a deepwater development campaign offshore Malaysia, cement isolation behind the 9-5/8\" production casing serves as critical barrier to ensure well integrity throughout the production lifecycle. To achieve this, the authors have deployed a structured approach focused on designing for success and optimizing a set of key performance indicators (KPIs) with pre- and post-drilled hole conditions. This paper outlines the approach based on the experience from the drilling campaign of nine oil producer wells.","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84397932","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}
As Malaysia’s first tension leg platform, the Shell Malikai project, represents an unconventional approach towards deepwater operation in this region. In a field embedded characterized by reservoir drawdown from adjacent production wells, the lowest cementing margin is 0.65 ppg. Annular gaps between casings of as tight as 0.53 in each side further elevates the equivalent circulating density (ECD). Cementing software simulation predicts risk of heavy losses during cement placement and subsequently lack of isolation between multiple hydrocarbon-bearing zones. The loss of zonal isolation would mean crossflow between the reservoir. At worst case, some of the water injector wells may be abandoned due to inability to inject into the target reservoir and uncertainties of injection efficiency. This represents a significant loss of capital investment. A two-pronged solution has been developed to secure the long-term well integrity of the deepwater project. Implementation involved front-end design, modelling, planning, and execution. Two-stage cementing is a technique by which selected intervals along the casing can be cemented in separate stages. It reduces the risk of losses due to long column of cement slurry exerting high hydrostatic head towards the weak formation. In 11 3/4in liner with tight annular gap, the risk of taking losses is high. Therefore, two-stage cementing was employed, combined with specialized blended lightweight 11.5-ppg cement. First-stage cement will provide good liner shoe strength for drilling ahead, and second-stage cement will provide zonal isolation for two hydrocarbon zones near the top of the liner. For 9 5/8in liner, due to the presence of a pressure ramp at the top of the section and weak formation at the bottom, managed pressure cementing (MPC) was the chosen approach to mitigate the risk of losses. MPC is a technique that enables cementation to be conducted in a hydrostatically underbalanced condition where surface backpressure (SBP) is applied to maintain the bottomhole pressure between the highest pore pressure and the lowest fracture pressure of the well. The combination of MPC and two-stage cementing, together with other existing best practices, formed an integrated solution in narrow margin cementing. This has resulted in flawless cementation for two water injector wells. No losses were observed during cement displacement, there was no gas migration, and the liner top packer was successfully set, and pressure tested in MPC mode. A subsequent cement log confirmed the top of cement requirement was fulfilled. The paper will further explain on how this unconventional technique were planned and executed.
{"title":"Unconventional Techniques Overcome Narrow-Margin Cementing: Case Studies from Malikai Deepwater Project, Malaysia","authors":"Yijing Hoe, Anh Duong, T. Heu, Mohd Razif Radzi","doi":"10.2118/191953-MS","DOIUrl":"https://doi.org/10.2118/191953-MS","url":null,"abstract":"\u0000 As Malaysia’s first tension leg platform, the Shell Malikai project, represents an unconventional approach towards deepwater operation in this region. In a field embedded characterized by reservoir drawdown from adjacent production wells, the lowest cementing margin is 0.65 ppg. Annular gaps between casings of as tight as 0.53 in each side further elevates the equivalent circulating density (ECD). Cementing software simulation predicts risk of heavy losses during cement placement and subsequently lack of isolation between multiple hydrocarbon-bearing zones. The loss of zonal isolation would mean crossflow between the reservoir. At worst case, some of the water injector wells may be abandoned due to inability to inject into the target reservoir and uncertainties of injection efficiency. This represents a significant loss of capital investment. A two-pronged solution has been developed to secure the long-term well integrity of the deepwater project. Implementation involved front-end design, modelling, planning, and execution.\u0000 Two-stage cementing is a technique by which selected intervals along the casing can be cemented in separate stages. It reduces the risk of losses due to long column of cement slurry exerting high hydrostatic head towards the weak formation. In 11 3/4in liner with tight annular gap, the risk of taking losses is high. Therefore, two-stage cementing was employed, combined with specialized blended lightweight 11.5-ppg cement. First-stage cement will provide good liner shoe strength for drilling ahead, and second-stage cement will provide zonal isolation for two hydrocarbon zones near the top of the liner. For 9 5/8in liner, due to the presence of a pressure ramp at the top of the section and weak formation at the bottom, managed pressure cementing (MPC) was the chosen approach to mitigate the risk of losses. MPC is a technique that enables cementation to be conducted in a hydrostatically underbalanced condition where surface backpressure (SBP) is applied to maintain the bottomhole pressure between the highest pore pressure and the lowest fracture pressure of the well.\u0000 The combination of MPC and two-stage cementing, together with other existing best practices, formed an integrated solution in narrow margin cementing. This has resulted in flawless cementation for two water injector wells. No losses were observed during cement displacement, there was no gas migration, and the liner top packer was successfully set, and pressure tested in MPC mode. A subsequent cement log confirmed the top of cement requirement was fulfilled. The paper will further explain on how this unconventional technique were planned and executed.","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"32 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90554350","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}
Jianchun Xu, Baojiang Sun, Wei Zhang, Hongjie Cheng, W. Fu
Numerical simulation of well production performance for tight oil/gas reservoirs is a hot issue during recent years. Embedded discrete facture model (EDFM) is an effective numerical simulation tool as its advantages and becomes popular. Now it is widely used in multistage fractured horizontal well performance prediction. In this paper, we will extend EDFM to study the well production performance when considering Pre-Darcy flow. Firstly, the two phases flow model is established. The conservation equations are derived for different media, i.e., fracture and matrix. For the flow in fracture, the Darcy's law is used. In the matrix, the Pre-Darcy flow is considered. Then, the solution workflow is showed and the verification is presented. The simulation results of the extended model are compared with that of local grid refined (LGR) method. Finally, the test cases are presented. We show the difference of oil/water production rate when considering Darcy flow and Pre-Darcy flow. The pressure and saturation distribution are also compared. The results show big difference will happen when using different flow model.
{"title":"Numerical Simulation of Well Production Performance Considering Pre-Darcy Flow Using EDFM","authors":"Jianchun Xu, Baojiang Sun, Wei Zhang, Hongjie Cheng, W. Fu","doi":"10.2118/192092-MS","DOIUrl":"https://doi.org/10.2118/192092-MS","url":null,"abstract":"\u0000 Numerical simulation of well production performance for tight oil/gas reservoirs is a hot issue during recent years. Embedded discrete facture model (EDFM) is an effective numerical simulation tool as its advantages and becomes popular. Now it is widely used in multistage fractured horizontal well performance prediction. In this paper, we will extend EDFM to study the well production performance when considering Pre-Darcy flow. Firstly, the two phases flow model is established. The conservation equations are derived for different media, i.e., fracture and matrix. For the flow in fracture, the Darcy's law is used. In the matrix, the Pre-Darcy flow is considered. Then, the solution workflow is showed and the verification is presented. The simulation results of the extended model are compared with that of local grid refined (LGR) method. Finally, the test cases are presented. We show the difference of oil/water production rate when considering Darcy flow and Pre-Darcy flow. The pressure and saturation distribution are also compared. The results show big difference will happen when using different flow model.","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"22 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91006472","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}
QGC's current full-field reservoir model comprises hundreds to thousands of CSG wells. This presents a considerable challenge from a history-matching standpoint compared to a conventional workflow where well-level adjustments may be made on one well at a time. In QGC, a model with an improved well-level match is desired as the resulting well forecast will enable decisions on a well-level to be made more confidently, such as the prioritization of well workovers. Previously a field-level history-match was deemed acceptable when the model was only used for field development planning. The method parameterizes the well-level relative error in simulated production from the model versus observed production. The workflow utilizes this data, known as well-level modifiers, to alter subsurface properties. This has been achieved with a semi-automated workflow to make the process efficient and repeatable, but also to enable engineering judgement to be incorporated in the history-matching process. The feedback loop is also an essential component of the workflow as it allows the well-level modifiers to be sense checked against the regional geological trends. This further encourages collaboration within a multi-disciplinary team. These well-level modifiers can also be used to create history-match metrics, which can be spatially mapped to help target specific areas for improvement in history-match quality. Some powerful use of visualization techniques discussed in this paper has not only minimized the mismatch but ensures the characteristics of the production history and geological trends are honoured to assure the robustness of the history-match and the resulting model predictability. The workflow has significantly reduced the time and efforts spent in delivering an improved well forecast when required. The technical development community in QGC has actively nurtured a culture of ideas sharing and innovation, which made the development of this workflow possible.
{"title":"An Efficient Approach for History-Matching Coal Seam Gas CSG Wells Production","authors":"Gladys Chang, Aibassov Gizat","doi":"10.2118/191997-MS","DOIUrl":"https://doi.org/10.2118/191997-MS","url":null,"abstract":"\u0000 QGC's current full-field reservoir model comprises hundreds to thousands of CSG wells. This presents a considerable challenge from a history-matching standpoint compared to a conventional workflow where well-level adjustments may be made on one well at a time. In QGC, a model with an improved well-level match is desired as the resulting well forecast will enable decisions on a well-level to be made more confidently, such as the prioritization of well workovers. Previously a field-level history-match was deemed acceptable when the model was only used for field development planning.\u0000 The method parameterizes the well-level relative error in simulated production from the model versus observed production. The workflow utilizes this data, known as well-level modifiers, to alter subsurface properties. This has been achieved with a semi-automated workflow to make the process efficient and repeatable, but also to enable engineering judgement to be incorporated in the history-matching process. The feedback loop is also an essential component of the workflow as it allows the well-level modifiers to be sense checked against the regional geological trends. This further encourages collaboration within a multi-disciplinary team.\u0000 These well-level modifiers can also be used to create history-match metrics, which can be spatially mapped to help target specific areas for improvement in history-match quality. Some powerful use of visualization techniques discussed in this paper has not only minimized the mismatch but ensures the characteristics of the production history and geological trends are honoured to assure the robustness of the history-match and the resulting model predictability. The workflow has significantly reduced the time and efforts spent in delivering an improved well forecast when required. The technical development community in QGC has actively nurtured a culture of ideas sharing and innovation, which made the development of this workflow possible.","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"9 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81017812","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}
Siva Rama Krishna Jandhyala, Ganesh Shriniwas Pangu, A. Deshpande, Timotheus K. T. Wolterbeek, E. K. Cornelissen, Jip van Eijden
Expansion additives have been used in cement plugs to mitigate the potential risk of plug failure resulting from shrinkage. These additives are effective only when their amount is tailored for downhole boundary conditions, and their role should be well understood. This work discusses using an improved testing method that enhances the dependability of the volume change measurement and exhibits the impact of test boundary conditions on the shrinking and expanding behaviors of cement plugs. Boundary conditions investigated with this method include temperature, pressure, water access to the cement from the formation, and the role of mechanical constraints. Dependability is demonstrated by verifying the repeatability and reproducibility of the method at two different laboratories. Together with the noninvasive continuous volume change, supplementary measurements, such as ultrasonic compressive strength, tensile strength, and chemical composition analysis, have provided inferences about the mechanism of volume change. The new method embodies all attributes listed in API 10 TR2 (1997), including a constant external stress state in all measurements and a constant pore pressure during total volume change measurement. The results of percentage volume change from this test method present an extremely small variance, highlighting its repeatability; additionally, the measurement was reproducible between laboratories. Expansion value increased with a decrease in confining pressure, and excessive expansion in the absence of an effective confining pressure produced weak samples. The absence of outside water caused cement containing the expansion aid to shrink more than its neat equivalent; such observations highlight the importance of fluid boundary on the action of expansion additives. These observations were possible because the test method can capture temporal and boundary condition effects more aptly. Thus, the improved method provides a dependable measurement for tailoring plug properties.
{"title":"Volume Change of Cement Plugs: Spotlight on the Role of Boundary Conditions Using an Improved Testing Method","authors":"Siva Rama Krishna Jandhyala, Ganesh Shriniwas Pangu, A. Deshpande, Timotheus K. T. Wolterbeek, E. K. Cornelissen, Jip van Eijden","doi":"10.2118/192054-MS","DOIUrl":"https://doi.org/10.2118/192054-MS","url":null,"abstract":"\u0000 Expansion additives have been used in cement plugs to mitigate the potential risk of plug failure resulting from shrinkage. These additives are effective only when their amount is tailored for downhole boundary conditions, and their role should be well understood. This work discusses using an improved testing method that enhances the dependability of the volume change measurement and exhibits the impact of test boundary conditions on the shrinking and expanding behaviors of cement plugs.\u0000 Boundary conditions investigated with this method include temperature, pressure, water access to the cement from the formation, and the role of mechanical constraints. Dependability is demonstrated by verifying the repeatability and reproducibility of the method at two different laboratories. Together with the noninvasive continuous volume change, supplementary measurements, such as ultrasonic compressive strength, tensile strength, and chemical composition analysis, have provided inferences about the mechanism of volume change.\u0000 The new method embodies all attributes listed in API 10 TR2 (1997), including a constant external stress state in all measurements and a constant pore pressure during total volume change measurement. The results of percentage volume change from this test method present an extremely small variance, highlighting its repeatability; additionally, the measurement was reproducible between laboratories. Expansion value increased with a decrease in confining pressure, and excessive expansion in the absence of an effective confining pressure produced weak samples. The absence of outside water caused cement containing the expansion aid to shrink more than its neat equivalent; such observations highlight the importance of fluid boundary on the action of expansion additives.\u0000 These observations were possible because the test method can capture temporal and boundary condition effects more aptly. Thus, the improved method provides a dependable measurement for tailoring plug properties.","PeriodicalId":11240,"journal":{"name":"Day 1 Tue, October 23, 2018","volume":"23 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84469839","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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