Sahil Mahaldar, Jasbindra Singh, A. Riyami, Nasser Mahrooqi, M. Abri, Sulaiman Mandhari, Salwa Hikmani, Maitham Al Humaid, Yousuf Sinani, I. Mahruqi, Nasser Al Azri, Sina Mohajeri
Digital transformation (Dx) is increasingly becoming a key enabler in oil and gas industry to reduce costs, make faster and better decisions and increase productivity. The difference between leading the next innovation wave or being left behind may depend on how proficiently we embrace digital enablers, and how quickly we can test, prototype and scale these digital solutions to create value for the business. Digital technologies are not new to Petroleum Development Oman (PDO). In fact, the company has a track record of testing and adopting a wide range of new technology and integrated organisational capabilities to improve its business performance. Significant investments have been made into instrumenting its fields, including the IT infrastructure, Real-Time Operations, Exception Based Surveillance, Collaborative Work Environment (CWE), Smart Fields, NIBRAS, data management, analytics trials, to name a few. Yet consensus that Dx has significant further upside across PDO, led to the initiation of an asset-led pilot to digitally transform an existing PDO South Field – "S". The focus of the pilot was to identify new Dx opportunities while leveraging on existing PDO investments into digitalization, leading to quantified improvement in business performance of field –S. The project workscope was based on the outcome of an Opportunity Framing Event (OFE), in which a total of 27 opportunities were identified and ranked in terms of business value vs. feasibility or cost of implementation (Figure 1). Technical Subject Matter Experts (SMEs), asset field - surface, sub-surface, data management teams and other relevant support functions participated in the OFE so that business improvement synergies could be identified across the multiple disciplines in an integrated fashion. Following an agile approach, 5 Valuestreams (VS) were selected for Minimum Viable Product (MVP) implementation, in phase 1 of the pilot. Focus of this paper, however, is to elaborate further only one of the 5 VSs i.e. use of machine learning for "Evergreen Production Forecast for Field Development Plan (FDP) optimization and Locate the Remaining Oil (LTRO)".
{"title":"Evergreen Forecast & Predictive LTRO Using Machine Learning – Case Study from PDO South","authors":"Sahil Mahaldar, Jasbindra Singh, A. Riyami, Nasser Mahrooqi, M. Abri, Sulaiman Mandhari, Salwa Hikmani, Maitham Al Humaid, Yousuf Sinani, I. Mahruqi, Nasser Al Azri, Sina Mohajeri","doi":"10.2118/200114-ms","DOIUrl":"https://doi.org/10.2118/200114-ms","url":null,"abstract":"\u0000 Digital transformation (Dx) is increasingly becoming a key enabler in oil and gas industry to reduce costs, make faster and better decisions and increase productivity. The difference between leading the next innovation wave or being left behind may depend on how proficiently we embrace digital enablers, and how quickly we can test, prototype and scale these digital solutions to create value for the business.\u0000 Digital technologies are not new to Petroleum Development Oman (PDO). In fact, the company has a track record of testing and adopting a wide range of new technology and integrated organisational capabilities to improve its business performance. Significant investments have been made into instrumenting its fields, including the IT infrastructure, Real-Time Operations, Exception Based Surveillance, Collaborative Work Environment (CWE), Smart Fields, NIBRAS, data management, analytics trials, to name a few. Yet consensus that Dx has significant further upside across PDO, led to the initiation of an asset-led pilot to digitally transform an existing PDO South Field – \"S\". The focus of the pilot was to identify new Dx opportunities while leveraging on existing PDO investments into digitalization, leading to quantified improvement in business performance of field –S. The project workscope was based on the outcome of an Opportunity Framing Event (OFE), in which a total of 27 opportunities were identified and ranked in terms of business value vs. feasibility or cost of implementation (Figure 1). Technical Subject Matter Experts (SMEs), asset field - surface, sub-surface, data management teams and other relevant support functions participated in the OFE so that business improvement synergies could be identified across the multiple disciplines in an integrated fashion.\u0000 Following an agile approach, 5 Valuestreams (VS) were selected for Minimum Viable Product (MVP) implementation, in phase 1 of the pilot. Focus of this paper, however, is to elaborate further only one of the 5 VSs i.e. use of machine learning for \"Evergreen Production Forecast for Field Development Plan (FDP) optimization and Locate the Remaining Oil (LTRO)\".","PeriodicalId":10940,"journal":{"name":"Day 2 Tue, March 22, 2022","volume":"5 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76972533","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}
C. Yuan, W. Pu, M. Varfolomeev, Jian Hui, Shuai Zhao, Xiaojie Zheng, A. Timofeeva
Foam flooding is one of promising enhanced oil recovery (EOR) methods for waterflooded reservoirs due to its good mobility control capability. However, its application in high-temperature and high-salinity reservoir has always been a challenge. This work presents salt-tolerant foam that can be used at about 100 °C under the salinity of more than 200000 mg/L (Ca2+ + Mg2+ >10000 mg/L). Its displacement efficiency was evaluated at different permeability heterogeneity conditions. The surfactant (foaming agent) solution was prepared using reservoir formation water (total salinity 204672 mg/L, Ca2+ + Mg2+ 11480 mg/L) obtained from a reservoir in Tarim Basin, China. The displacement efficiency of foam was investigated in different permeability conditions (35.47, 72.72, 165.75, 265.28, 410.73, 600.38, and 950.11 mD) using single-core flooding experiment and in different permeability heterogeneity (permeability max-min ratio of 3.34, 6.62, 9.22, and 11.98) using parallel-core flooding experiments (one high-permeability core and one low-permeability core). For all flooding experiments, nitrogen foam was used by co-injection of nitrogen and surfactant solution. For all permeability conditions in single-core flooding experiments, after water flooding with a 98% water cut, the injection of foam could increase the injection pressure. Foam injection together with its subsequent water flooding could yeild an additional oil recovery of 11.73, 12.35, 12.8, 13.04, 15.45, 16.04, and 17.51% under the permeability of 35.47, 72.72, 165.75, 265.28, 410.73, 600.38, and 950.11 mD, respectively. Obviously, the yielded additional oil recovery increased with permeability. Under the permeability max-min ratio of 3.34, 6.62, and 9.22, an addtition oil recovery can be yielded from both high- and low-permeability cores, but the additional oil recovery from low-permeability core was higher. This implies that the injection of foam can not only improve displacement efficiency after water flooding, but also can effectively increase flow resistance in high-permeability core, and thus improving oil recovery in low-permeability core. However, when the permeability max-min ratio was increased to 11.98, the oil in low-permeability core cannot be mobilized even after foam injection, which means that foam injection can effectively work only in a certain permeability heterogeneity condition. When permeability heterogeneity is strong, enhanced foam should be considered to increase the strength of foam using polymer (only for low temperature), gel or nanoparticles, etc. The obtained results show that the developed foam formulation has a great potential for improving displacement efficiency and sweep efficiency in water-flooded heterogenous reservoirs with very high temperature and ultra-high salinity.
{"title":"Foam for High Temperature and Ultra-High Salinity Conditions: Its Displacement Efficiency Under Different Permeability Heterogeneity","authors":"C. Yuan, W. Pu, M. Varfolomeev, Jian Hui, Shuai Zhao, Xiaojie Zheng, A. Timofeeva","doi":"10.2118/200078-ms","DOIUrl":"https://doi.org/10.2118/200078-ms","url":null,"abstract":"\u0000 Foam flooding is one of promising enhanced oil recovery (EOR) methods for waterflooded reservoirs due to its good mobility control capability. However, its application in high-temperature and high-salinity reservoir has always been a challenge. This work presents salt-tolerant foam that can be used at about 100 °C under the salinity of more than 200000 mg/L (Ca2+ + Mg2+ >10000 mg/L). Its displacement efficiency was evaluated at different permeability heterogeneity conditions.\u0000 The surfactant (foaming agent) solution was prepared using reservoir formation water (total salinity 204672 mg/L, Ca2+ + Mg2+ 11480 mg/L) obtained from a reservoir in Tarim Basin, China. The displacement efficiency of foam was investigated in different permeability conditions (35.47, 72.72, 165.75, 265.28, 410.73, 600.38, and 950.11 mD) using single-core flooding experiment and in different permeability heterogeneity (permeability max-min ratio of 3.34, 6.62, 9.22, and 11.98) using parallel-core flooding experiments (one high-permeability core and one low-permeability core). For all flooding experiments, nitrogen foam was used by co-injection of nitrogen and surfactant solution.\u0000 For all permeability conditions in single-core flooding experiments, after water flooding with a 98% water cut, the injection of foam could increase the injection pressure. Foam injection together with its subsequent water flooding could yeild an additional oil recovery of 11.73, 12.35, 12.8, 13.04, 15.45, 16.04, and 17.51% under the permeability of 35.47, 72.72, 165.75, 265.28, 410.73, 600.38, and 950.11 mD, respectively. Obviously, the yielded additional oil recovery increased with permeability. Under the permeability max-min ratio of 3.34, 6.62, and 9.22, an addtition oil recovery can be yielded from both high- and low-permeability cores, but the additional oil recovery from low-permeability core was higher. This implies that the injection of foam can not only improve displacement efficiency after water flooding, but also can effectively increase flow resistance in high-permeability core, and thus improving oil recovery in low-permeability core. However, when the permeability max-min ratio was increased to 11.98, the oil in low-permeability core cannot be mobilized even after foam injection, which means that foam injection can effectively work only in a certain permeability heterogeneity condition. When permeability heterogeneity is strong, enhanced foam should be considered to increase the strength of foam using polymer (only for low temperature), gel or nanoparticles, etc.\u0000 The obtained results show that the developed foam formulation has a great potential for improving displacement efficiency and sweep efficiency in water-flooded heterogenous reservoirs with very high temperature and ultra-high salinity.","PeriodicalId":10940,"journal":{"name":"Day 2 Tue, March 22, 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":"74725052","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}
P. Bolourinejad, D. Groenendijk, J. V. van Wunnik, Miranda Mooijer- van den Heuvel
In order to improve the waterflooding efficiency, surfactants and polymers are added to the water; this process is called surfactant–polymer (SP) flooding. One of the problems for this process is high adsorption of surfactants to the rock surface and specially to carbonate rock surfaces. The focus of this work is: to quantify experimentally the adsorption of anionic surfactants to carbonate rock surfaces, obtain a qualitative understanding of the mechanisms at play and identify suitable adsorption inhibitors. The main outcomes of the work are: the adsorption of the surfactants used can be around three times higher (mg per g of rock) on calcite than on sandstone and dolomite. Higher concentrations of divalent ions lead to higher adsorption, and the adsorption also depends on the monovalent ion concentration. Several adsorption inhibitors are identified that can reduce the adsorption substantially, of which polyacrylate showed the most significant reduction. The divalent ions are thought to form a bridge between the anionic surfactants and the charged rock surfaces. The adsorption inhibitors capture the divalent ions, reducing their concentration in solution and, consequently, the adsorption of surfactants. More work is needed on the effectiveness of this concept at higher salinities before a first-pass technical and economic evaluation on the use of adsorption reducing agents on a field-scale can be performed.
{"title":"Surfactant Adsorption on Carbonate Rocks","authors":"P. Bolourinejad, D. Groenendijk, J. V. van Wunnik, Miranda Mooijer- van den Heuvel","doi":"10.2118/200079-ms","DOIUrl":"https://doi.org/10.2118/200079-ms","url":null,"abstract":"\u0000 In order to improve the waterflooding efficiency, surfactants and polymers are added to the water; this process is called surfactant–polymer (SP) flooding. One of the problems for this process is high adsorption of surfactants to the rock surface and specially to carbonate rock surfaces. The focus of this work is: to quantify experimentally the adsorption of anionic surfactants to carbonate rock surfaces, obtain a qualitative understanding of the mechanisms at play and identify suitable adsorption inhibitors.\u0000 The main outcomes of the work are: the adsorption of the surfactants used can be around three times higher (mg per g of rock) on calcite than on sandstone and dolomite. Higher concentrations of divalent ions lead to higher adsorption, and the adsorption also depends on the monovalent ion concentration. Several adsorption inhibitors are identified that can reduce the adsorption substantially, of which polyacrylate showed the most significant reduction. The divalent ions are thought to form a bridge between the anionic surfactants and the charged rock surfaces. The adsorption inhibitors capture the divalent ions, reducing their concentration in solution and, consequently, the adsorption of surfactants. More work is needed on the effectiveness of this concept at higher salinities before a first-pass technical and economic evaluation on the use of adsorption reducing agents on a field-scale can be performed.","PeriodicalId":10940,"journal":{"name":"Day 2 Tue, March 22, 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":"89732486","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}
Badar Al Amri, H. Setiawan, Muhammad Rifki Akbar, Yaqoob Al Rashdi, Fahad Al Nabhani
This is an extended polymer-injectivity-test where the main objectives are to prove that polymer solution can be injected at acceptable conditions and injectivity can be sustained for a considerable time period. Other objectives include determining the need for certain protective additives, evaluating the possibility of oil gain in producing wells around the test injector and providing some input to the process of flood pattern optimization. A nine-month's polymer injectivity test has been implemented in HRD sandstone reservoir (Karim Small Fields’ Cluster, Sultanate of Oman) as part of the ongoing chemical flood evaluation. Selected polymer and desired concentrations are based on extensive laboratory test programs. The subject reservoir has been producing for over thirty years, mostly on primary conditions but with a successful waterflood (using inverted, irregular seven-spot patterns) during the last seven years that is still ongoing. Reservoir oil is highly under-saturated, 29° API gravity with initial viscosity of about 15 cP. Average depth is 1,200 mMD and absolute permeability is in the range of 250-500 mD. Chemical flooding is selected as the appropriate EOR method and is currently being evaluated in order to determine the optimum process design that can provide maximum incremental oil recovery over the ongoing waterflood. Preliminary results from the polymer injectivity test confirm that injection rate of about 150 m3/d can be sustained at maximum surface injection pressure of around 4,000 kPa. Polymer break-through (at low traces) is observed in two of the six surrounding producing wells. Oil gain observed in surrounding producing wells is in the range of 0 - 5 m3/d/well which is lower than the values predicted by the simulation model. The reasons leading to low oil gain and general reservoir behavior within the injectivity pattern are discussed in the paper. The discussed reasons and behavior are essential design aspects of a potential chemical-flooding pilot that can be implemented for analogous fields.
这是一种扩展的聚合物注入测试，其主要目的是证明聚合物溶液可以在可接受的条件下注入，并且注入能力可以持续相当长的时间。其他目标包括确定某些保护添加剂的需求，评估测试注入器周围生产井产油量增加的可能性，以及为优化注水模式提供一些输入。在阿曼苏丹国的HRD砂岩油藏(Karim Small Fields’Cluster, Sultanate of Oman)进行了为期9个月的聚合物注入测试，作为化学驱评估的一部分。选定的聚合物和所需的浓度是基于广泛的实验室测试程序。该油藏已经生产了30多年，大部分是在初级条件下生产的，但在过去的7年里，成功的注水(使用倒置的、不规则的7点模式)仍在进行中。储层油高度不饱和，API度为29°，初始粘度约为15 cP，平均深度为1200 mMD，绝对渗透率在250-500 mD之间。化学驱被选为合适的提高采收率方法，目前正在进行评估，以确定最佳工艺设计，从而在正在进行的注水过程中提供最大的产油量增量。聚合物注入性测试的初步结果证实，在最大地面注入压力约4,000 kPa的情况下，注入速率约为150 m3/d。在周围的6口生产井中，有2口观察到聚合物突破(低道)。周围生产井的产油量为0 ~ 5 m3/d/井，低于模拟模型预测的产油量。本文讨论了导致低产油量的原因和注入模式下的一般储层行为。所讨论的原因和行为是潜在的化学驱试验设计的基本方面，可以在类似的油田实施。
{"title":"Extended Polymer Injectivity Test in a Medium Viscosity Sandstone Oil Reservoir, Sultanate of Oman","authors":"Badar Al Amri, H. Setiawan, Muhammad Rifki Akbar, Yaqoob Al Rashdi, Fahad Al Nabhani","doi":"10.2118/200031-ms","DOIUrl":"https://doi.org/10.2118/200031-ms","url":null,"abstract":"\u0000 This is an extended polymer-injectivity-test where the main objectives are to prove that polymer solution can be injected at acceptable conditions and injectivity can be sustained for a considerable time period. Other objectives include determining the need for certain protective additives, evaluating the possibility of oil gain in producing wells around the test injector and providing some input to the process of flood pattern optimization.\u0000 A nine-month's polymer injectivity test has been implemented in HRD sandstone reservoir (Karim Small Fields’ Cluster, Sultanate of Oman) as part of the ongoing chemical flood evaluation. Selected polymer and desired concentrations are based on extensive laboratory test programs. The subject reservoir has been producing for over thirty years, mostly on primary conditions but with a successful waterflood (using inverted, irregular seven-spot patterns) during the last seven years that is still ongoing. Reservoir oil is highly under-saturated, 29° API gravity with initial viscosity of about 15 cP. Average depth is 1,200 mMD and absolute permeability is in the range of 250-500 mD. Chemical flooding is selected as the appropriate EOR method and is currently being evaluated in order to determine the optimum process design that can provide maximum incremental oil recovery over the ongoing waterflood.\u0000 Preliminary results from the polymer injectivity test confirm that injection rate of about 150 m3/d can be sustained at maximum surface injection pressure of around 4,000 kPa. Polymer break-through (at low traces) is observed in two of the six surrounding producing wells. Oil gain observed in surrounding producing wells is in the range of 0 - 5 m3/d/well which is lower than the values predicted by the simulation model.\u0000 The reasons leading to low oil gain and general reservoir behavior within the injectivity pattern are discussed in the paper. The discussed reasons and behavior are essential design aspects of a potential chemical-flooding pilot that can be implemented for analogous fields.","PeriodicalId":10940,"journal":{"name":"Day 2 Tue, March 22, 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":"87303769","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}
Khazzan, the gas giant in Oman, and its new gas processing facility were started up in 2017 delivering a daily contractual volume of gas o the local grid. The wells had high gas deliverability potential, and yet they were constrained to deliver the contractual volume specified by the commercial agreement with the government. To maximize the value of this excess gas potential, a new digital tool was utilized to optimize our condensate production – increasing production by 2-3% with no additional cost. The first step was to create a digital twin of the asset, including the structure of the asset and the fluid dynamics of the flow regimes, temperatures and pressures. Historical data was used to populate the digital twin, and sensors in the asset were set up to send real time data to the functioning twin of the physical asset. Any constraints in the production system were built into the digital twin to provide the most accurate simulation. The tool was then used to monitor, simulate and optimize production, by testing multiple variables until an optimal solution was found for the entire production system from wells, through facilities, to export. Significant value was obtained by utilizing the digital toolkit, delivering not only economic value but progressing innovation as well. Traditional production management requires considerable time to manually integrate the complex infrastructure and fluid dynamics. This digital twin of Khazzan enabled the work to be automated and completed much faster than conventional methods–allowing petroleum engineers to focus on evaluating well performance rather than running time-consuming scenarios of anticipated or likely events. The response time to any changes in gas nomination was also reduced significantly, by running simulations with a few clicks on the screen and updating them in the live streaming Wells Overview sheet. Condensate optimization was not only achieved through maximizing condensate production, but there an opportunity was realized to minimize condensate flared volumes during plant upsets which ultimately impact recovered condensate. This was completed in conjunction with the live streaming Wells Overview – to capitalize on utilizing a digital workflow to reduce flaring volumes. Overall, this digital twin benefited BP Oman by indicating where efficiencies can be improved and potential problems in the production system, leading to significant business value being added to the company.
{"title":"Condensate Optimization Through Digital Tools","authors":"Ghaida Al Farsi, Angeni Jayawickramarajah","doi":"10.2118/200186-ms","DOIUrl":"https://doi.org/10.2118/200186-ms","url":null,"abstract":"\u0000 Khazzan, the gas giant in Oman, and its new gas processing facility were started up in 2017 delivering a daily contractual volume of gas o the local grid. The wells had high gas deliverability potential, and yet they were constrained to deliver the contractual volume specified by the commercial agreement with the government. To maximize the value of this excess gas potential, a new digital tool was utilized to optimize our condensate production – increasing production by 2-3% with no additional cost.\u0000 The first step was to create a digital twin of the asset, including the structure of the asset and the fluid dynamics of the flow regimes, temperatures and pressures. Historical data was used to populate the digital twin, and sensors in the asset were set up to send real time data to the functioning twin of the physical asset. Any constraints in the production system were built into the digital twin to provide the most accurate simulation. The tool was then used to monitor, simulate and optimize production, by testing multiple variables until an optimal solution was found for the entire production system from wells, through facilities, to export.\u0000 Significant value was obtained by utilizing the digital toolkit, delivering not only economic value but progressing innovation as well. Traditional production management requires considerable time to manually integrate the complex infrastructure and fluid dynamics. This digital twin of Khazzan enabled the work to be automated and completed much faster than conventional methods–allowing petroleum engineers to focus on evaluating well performance rather than running time-consuming scenarios of anticipated or likely events. The response time to any changes in gas nomination was also reduced significantly, by running simulations with a few clicks on the screen and updating them in the live streaming Wells Overview sheet.\u0000 Condensate optimization was not only achieved through maximizing condensate production, but there an opportunity was realized to minimize condensate flared volumes during plant upsets which ultimately impact recovered condensate. This was completed in conjunction with the live streaming Wells Overview – to capitalize on utilizing a digital workflow to reduce flaring volumes.\u0000 Overall, this digital twin benefited BP Oman by indicating where efficiencies can be improved and potential problems in the production system, leading to significant business value being added to the company.","PeriodicalId":10940,"journal":{"name":"Day 2 Tue, March 22, 2022","volume":"15 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89426124","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}
This paper details the implementation of lean engineering principles for formulating the material handling study at an Oil & Gas Onshore Island facility. The paper analyses a case study at a major offshore island facility in the Abu Dhabi region, comparing the traditional methods followed in material handling with the proposed lean method of material handling. Principles of lean engineering such as simplification & standardization have been implemented to create a lean-approach. A key aspect of the lean philosophy is to incorporate a "Fit-for-purpose" design rather than an over design for material handling cases that the facility might never see in its 25-year lifetime. An offshore island brings several challenges with respect to material handling due to its location compared to an onshore facility because of the limited availability of traditional maintenance equipment like Mobile cranes. Following the lean method not only saves manhours while developing the material handling philosophy during the design phase of the project but also helps in lowering the procurement costs associated with the equipment required to aid material handling. This lean engineering approach, when applied to material handling study has resulted in the reduction of both CAPEX & OPEX cost for an offshore island facility. Standardizing the way material handling philosophies are developed in a project helped in improving the overall process efficiency, reducing errors, lowering the time taken for study, improving quality, and client satisfaction. The novelty of the proposed material handling study model involves using lean engineering principles which are typically used in manufacturing/assembly lines in a study for maintenance of equipment on an offshore island.
{"title":"Asset Integrity Management Through Lean Engineered Material Handling Study for Oil & Gas Processing Facilities on an Offshore Island Facility","authors":"Aravind Kannan, Diponkar Saha","doi":"10.2118/200245-ms","DOIUrl":"https://doi.org/10.2118/200245-ms","url":null,"abstract":"\u0000 \u0000 \u0000 This paper details the implementation of lean engineering principles for formulating the material handling study at an Oil & Gas Onshore Island facility.\u0000 \u0000 \u0000 \u0000 The paper analyses a case study at a major offshore island facility in the Abu Dhabi region, comparing the traditional methods followed in material handling with the proposed lean method of material handling. Principles of lean engineering such as simplification & standardization have been implemented to create a lean-approach. A key aspect of the lean philosophy is to incorporate a \"Fit-for-purpose\" design rather than an over design for material handling cases that the facility might never see in its 25-year lifetime.\u0000 \u0000 \u0000 \u0000 An offshore island brings several challenges with respect to material handling due to its location compared to an onshore facility because of the limited availability of traditional maintenance equipment like Mobile cranes. Following the lean method not only saves manhours while developing the material handling philosophy during the design phase of the project but also helps in lowering the procurement costs associated with the equipment required to aid material handling. This lean engineering approach, when applied to material handling study has resulted in the reduction of both CAPEX & OPEX cost for an offshore island facility. Standardizing the way material handling philosophies are developed in a project helped in improving the overall process efficiency, reducing errors, lowering the time taken for study, improving quality, and client satisfaction.\u0000 \u0000 \u0000 \u0000 The novelty of the proposed material handling study model involves using lean engineering principles which are typically used in manufacturing/assembly lines in a study for maintenance of equipment on an offshore island.\u0000","PeriodicalId":10940,"journal":{"name":"Day 2 Tue, March 22, 2022","volume":"72 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84072258","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-Suleimani, Juan Chavez, Hazim Abbass, Radouan Smaoui, A. Abassi, Bachir El Hamal, Aissa Bachir, Srichand Poludasu, M. Yi, B. Attia, A. Ouenes
Horizontal wells with multiple transverse fractures were defined as the key well architecture and completion strategy oriented to develop clastic tight gas accumulation otherwise impossible to be developed with vertical wells. However, a detailed evaluation during early deployment indicates the need for an integrated subsurface platform (ISP) covering geophysics, geology and geomechanics, to support well placement, well orientation and hydraulic fractured design. Detailed subsurface characterization was used to build the ISP. Geomechanical logs estimated using the drilling data, as wells as, wireline logs are used to define engineered completion strategies. The ISP provide us with three dimensional properties maps capturing lithogical, petrophysical and geomechanical properties distribution, this allow the identification of the properties anisotropy coveing key variables including, elastic properties, in-situ stress variation, stress rotation across the field and stress anisotropy, thecombination of the predicted stimulated reservoir volume and the dynamic model, both part of the ISP, were used to access potential production forecast for selected well locations. The ISP support the identification of geological sweet spot to definelanding zones and optimizing the hydraulic fracturing to improve the production performance. We will discuss how the geomechanical evaluation provides us the spatially varying stress magnitude and stress orientation and strain across the tight reservoir units. The use of the geological and geomechanical data within the ISP can be used to estimate geomechanical half lengths that are used to improve fracture design. We will also discuss how completion optimization and number of perforation clusters can be defined to maximize gas production based on a better understading of the special variation of petrophysical, geomechanical and lithological properties across reservoir units. The described integrated subsurface platform can be used to help optimize horizontal well placement, well orientation and fracture completion design. It will be discussed the procedures and process of integration geophysical, geological and geomechanical reservoir properties into the ISP, as well as, how this was used to support the continuous development of these tight gas accumulation in Oman.
{"title":"3D Enhanced Subsurface Data Visualization and Integration for Effective Horizontal Well Multi Transverse Fracture Development on a Clastic Tight Gas Field in Oman","authors":"A. Al-Suleimani, Juan Chavez, Hazim Abbass, Radouan Smaoui, A. Abassi, Bachir El Hamal, Aissa Bachir, Srichand Poludasu, M. Yi, B. Attia, A. Ouenes","doi":"10.2118/200157-ms","DOIUrl":"https://doi.org/10.2118/200157-ms","url":null,"abstract":"\u0000 Horizontal wells with multiple transverse fractures were defined as the key well architecture and completion strategy oriented to develop clastic tight gas accumulation otherwise impossible to be developed with vertical wells. However, a detailed evaluation during early deployment indicates the need for an integrated subsurface platform (ISP) covering geophysics, geology and geomechanics, to support well placement, well orientation and hydraulic fractured design.\u0000 Detailed subsurface characterization was used to build the ISP. Geomechanical logs estimated using the drilling data, as wells as, wireline logs are used to define engineered completion strategies. The ISP provide us with three dimensional properties maps capturing lithogical, petrophysical and geomechanical properties distribution, this allow the identification of the properties anisotropy coveing key variables including, elastic properties, in-situ stress variation, stress rotation across the field and stress anisotropy, thecombination of the predicted stimulated reservoir volume and the dynamic model, both part of the ISP, were used to access potential production forecast for selected well locations.\u0000 The ISP support the identification of geological sweet spot to definelanding zones and optimizing the hydraulic fracturing to improve the production performance. We will discuss how the geomechanical evaluation provides us the spatially varying stress magnitude and stress orientation and strain across the tight reservoir units. The use of the geological and geomechanical data within the ISP can be used to estimate geomechanical half lengths that are used to improve fracture design. We will also discuss how completion optimization and number of perforation clusters can be defined to maximize gas production based on a better understading of the special variation of petrophysical, geomechanical and lithological properties across reservoir units.\u0000 The described integrated subsurface platform can be used to help optimize horizontal well placement, well orientation and fracture completion design. It will be discussed the procedures and process of integration geophysical, geological and geomechanical reservoir properties into the ISP, as well as, how this was used to support the continuous development of these tight gas accumulation in Oman.","PeriodicalId":10940,"journal":{"name":"Day 2 Tue, March 22, 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":"86681070","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}
High heterogeneity and complex fluid flow behavior aggravates the recovery by conventional means from naturaly fractured reservoirs (NFRs). The last years have seen an increasing interest and a lot of laboratory and field tests were perfomed with the surfactants as Enhanced Oil Recovery (EOR) agents for this type of unconventional reservoirs. However, most of the attention was focused on application of the surfactants in mixed- to oil-wet conditions and not much is reported for the water-wet rocks. The aim of this study is to better understand and provide the quantitave analysis of the low interfacial tension (IFT) aided surfactant EOR mechanisms in water-wet NFRs. For this purpose, the previously published experiments are reproduced by means of numerical modeling employing commercialy available CMG simulator. Static and dynamic imbibition experiments in water-wet core samples performed by Schechter et al. (1994) and by Al-Quraishi (2004) respectively, showed incremental oil recovery effects of low IFT surfactants. Using the reported data and boundary conditions, conceptual numerical models are built for each of the experiments. In addition to numerical simulations, manual calculations of the Bond Number, which is not accounted for in the numerical simulator, has given a detailed insight on the balance between capillary and gravitational forces as well their contribution on oil desaturation. Simulation results of low IFT static imbibition experiments without initial water saturation have shown that the critical capillary numbers used for the matching of the experiments are orders of magnitude lower than those typically reported in literature. Calculation of the Bond number values also revealed that the observed low IFT incremental recovery effects cannot be explained by intensification of the gravitational forces. On the other hand, numerical analysis of dynamic imbibition experiments indicated considerable contribution of viscous forces towards incremental oil recovery, in contrary to conventional believe that the visous forces have limited effect on recovery from NFRs. The conducted numerical simulation study revealed that contribution of low IFT aided gravity forces on oil desaturation is minor. Overall the performed study revealed the weak contribution of the gravitational forces on oil desaturation in low permeability cores. Evaluation of the Bond numbers from the experiments, suggested that reduction to ultra-low IFT values can help to achieve the reasonable effect of gravity forces on recovery. However, the validation of this postulate requires implementation of further studies and laboratory experiments.
{"title":"Numerical Analysis of Surfactant Application in Water-Wet Naturally Fractured Reservoirs","authors":"E. Hoffmann, Samir Alakbarov","doi":"10.2118/200096-ms","DOIUrl":"https://doi.org/10.2118/200096-ms","url":null,"abstract":"\u0000 High heterogeneity and complex fluid flow behavior aggravates the recovery by conventional means from naturaly fractured reservoirs (NFRs). The last years have seen an increasing interest and a lot of laboratory and field tests were perfomed with the surfactants as Enhanced Oil Recovery (EOR) agents for this type of unconventional reservoirs. However, most of the attention was focused on application of the surfactants in mixed- to oil-wet conditions and not much is reported for the water-wet rocks. The aim of this study is to better understand and provide the quantitave analysis of the low interfacial tension (IFT) aided surfactant EOR mechanisms in water-wet NFRs. For this purpose, the previously published experiments are reproduced by means of numerical modeling employing commercialy available CMG simulator.\u0000 Static and dynamic imbibition experiments in water-wet core samples performed by Schechter et al. (1994) and by Al-Quraishi (2004) respectively, showed incremental oil recovery effects of low IFT surfactants. Using the reported data and boundary conditions, conceptual numerical models are built for each of the experiments. In addition to numerical simulations, manual calculations of the Bond Number, which is not accounted for in the numerical simulator, has given a detailed insight on the balance between capillary and gravitational forces as well their contribution on oil desaturation.\u0000 Simulation results of low IFT static imbibition experiments without initial water saturation have shown that the critical capillary numbers used for the matching of the experiments are orders of magnitude lower than those typically reported in literature. Calculation of the Bond number values also revealed that the observed low IFT incremental recovery effects cannot be explained by intensification of the gravitational forces.\u0000 On the other hand, numerical analysis of dynamic imbibition experiments indicated considerable contribution of viscous forces towards incremental oil recovery, in contrary to conventional believe that the visous forces have limited effect on recovery from NFRs. The conducted numerical simulation study revealed that contribution of low IFT aided gravity forces on oil desaturation is minor.\u0000 Overall the performed study revealed the weak contribution of the gravitational forces on oil desaturation in low permeability cores. Evaluation of the Bond numbers from the experiments, suggested that reduction to ultra-low IFT values can help to achieve the reasonable effect of gravity forces on recovery. However, the validation of this postulate requires implementation of further studies and laboratory experiments.","PeriodicalId":10940,"journal":{"name":"Day 2 Tue, March 22, 2022","volume":"24 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86536968","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}
Samya Farsi, R. Bouwmeester, M. Brewer, J. Southwick, Dawood Mahruqi, V. Karpan, Diederik van Batenburg, Ian Carpenter, Sam Wilson
Alkaline Surfactant Polymer (ASP) flooding has proven to be an effective method to recover residual oil after waterflood. Yet, there are several complications that limit a wide implementation of ASP. The source water needs to be softened to avoid injectivity issues due to scale formation when alkali is mixed with divalent cations. Even when softened water is used as base water, scaling can still be an issue in producing wells due to mixing of waters with different compositions in-situ. Scale control by means of scale inhibitor squeezes on the production side or scale inhibitor on the injection side have been reported to be successful for some cases. Carbonate scaling issues are most severe when sodium carbonate is used as alkali. Even if alkalis other than carbonate are used, carbonate scale remains an issue as bicarbonate that is present in almost any formation water, will convert to carbonate at high pH and will subsequently precipitate with the divalent ions present. Ethanolamine has been proposed as an effective alkali in ASP application with high TAN oils for reservoirs that contain relatively low concentrations of divalent ions in their produced water that is reinjected. ASP implementation could significantly be simplified if softening of the produced water could be avoided. Results of a study that involved determination of scaling tendencies, compatibility testing, tube blocking tests, and core floods with and without the addition of scale inhibitor will be presented together with implications for field implementation. A potential additional advantage of adding scale inhibitor on the injection side is that the scale inhibitor travels with the components to be inhibited. This might eliminate the need for scale control measures at the production side.
{"title":"Implementing ASP Without Water Softening in Reservoirs With Low Concentrations of Divalent Ions","authors":"Samya Farsi, R. Bouwmeester, M. Brewer, J. Southwick, Dawood Mahruqi, V. Karpan, Diederik van Batenburg, Ian Carpenter, Sam Wilson","doi":"10.2118/200094-ms","DOIUrl":"https://doi.org/10.2118/200094-ms","url":null,"abstract":"\u0000 Alkaline Surfactant Polymer (ASP) flooding has proven to be an effective method to recover residual oil after waterflood. Yet, there are several complications that limit a wide implementation of ASP. The source water needs to be softened to avoid injectivity issues due to scale formation when alkali is mixed with divalent cations. Even when softened water is used as base water, scaling can still be an issue in producing wells due to mixing of waters with different compositions in-situ. Scale control by means of scale inhibitor squeezes on the production side or scale inhibitor on the injection side have been reported to be successful for some cases.\u0000 Carbonate scaling issues are most severe when sodium carbonate is used as alkali. Even if alkalis other than carbonate are used, carbonate scale remains an issue as bicarbonate that is present in almost any formation water, will convert to carbonate at high pH and will subsequently precipitate with the divalent ions present.\u0000 Ethanolamine has been proposed as an effective alkali in ASP application with high TAN oils for reservoirs that contain relatively low concentrations of divalent ions in their produced water that is reinjected. ASP implementation could significantly be simplified if softening of the produced water could be avoided.\u0000 Results of a study that involved determination of scaling tendencies, compatibility testing, tube blocking tests, and core floods with and without the addition of scale inhibitor will be presented together with implications for field implementation. A potential additional advantage of adding scale inhibitor on the injection side is that the scale inhibitor travels with the components to be inhibited. This might eliminate the need for scale control measures at the production side.","PeriodicalId":10940,"journal":{"name":"Day 2 Tue, March 22, 2022","volume":"34 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87447443","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}
Non-ionic alkyl polyglucoside (APG) surfactants have been considered as eco-friendly, nontoxic and biodegradable surfactants. In this study, the physicochemical properties of two APG surfactants under high-temperature and high-salinity conditions were evaluated. The effectiveness of the surfactants as imbibition agents on improving oil production in carbonate reservoirs was investigated. A formulation with ultra-low interfacial tension (IFT) was introduced and the mechanisms resulting in such low IFT were probed and discussed. Two APG surfactants were studied. Compatibility was evaluated by the transparency in brine solutions after aging. IFT was measured with the formulations of surfactant/additives. The morphology of network formed by surfactant/additives was observed via scanning electron microscope (SEM). The static adsorption of the APGs onto carbonate powder was determined by total organic carbon (TOC) analyzer. The contact angle of oil droplet on surface of carbonate core was measured in surfactant solution. The oil production via spontaneous imbibition of water in carbonate core was obtained using Amott cell. An imbibition simulation model was validated by the experimental results using UTCHEM simulator. Both surfactants APG-1 and APG-2 exhibited excellent compatibility with the simulated high salinity water at reservoir temperature. They also demonstrated low static adsorption on carbonate reservoir. The surfactant containing larger hydrophobic carbons (APG-1) showed more incremental oil production potential than the other one bearing shorter hydrophobic chain (APG-2). At a concentration of 0.2 wt%, APG-1 yielded a low IFT in the order of 10-2 mN/m and an ultra-low IFT in the order of 10-3 mN/m was obtained upon addition of a small amount of additives. SEM pictures indicated that APG-1 and the additives synergistically generated a more compact structure via interaction between hydrophobic moieties of the chemicals compared to the aggregated structure formed by APG-1 alone. Such an effect could eventually lead to a decrease in IFT between oil and water. APG-1 slightly altered the wettability of carbonate core surface toward water-wet. The experimental results of spontaneous imbibition tests showed an oil production of 28% and 21% by APG-1 and APG-2, respectively. After parameter tuning, the yielded curves from numerical simulation by UTCHEM simulator perfectly matched the experimental data. A new APG-based formulation was designed with an ultra-low IFT resulting in a much more compact amphiphilic structure along the oil-water interface. This study shows a great potential of APG surfactants and the relevant derivative formulations in improving oil production application for high-temperature and high-salinity carbonate reservoirs.
{"title":"Non-Ionic Surfactant Formulation with Ultra-Low Interfacial Tension at High-Temperature and High-Salinity Conditions","authors":"Shaohua Chen, M. Han, A. AlSofi, A. Fuseni","doi":"10.2118/200273-ms","DOIUrl":"https://doi.org/10.2118/200273-ms","url":null,"abstract":"\u0000 Non-ionic alkyl polyglucoside (APG) surfactants have been considered as eco-friendly, nontoxic and biodegradable surfactants. In this study, the physicochemical properties of two APG surfactants under high-temperature and high-salinity conditions were evaluated. The effectiveness of the surfactants as imbibition agents on improving oil production in carbonate reservoirs was investigated. A formulation with ultra-low interfacial tension (IFT) was introduced and the mechanisms resulting in such low IFT were probed and discussed.\u0000 Two APG surfactants were studied. Compatibility was evaluated by the transparency in brine solutions after aging. IFT was measured with the formulations of surfactant/additives. The morphology of network formed by surfactant/additives was observed via scanning electron microscope (SEM). The static adsorption of the APGs onto carbonate powder was determined by total organic carbon (TOC) analyzer. The contact angle of oil droplet on surface of carbonate core was measured in surfactant solution. The oil production via spontaneous imbibition of water in carbonate core was obtained using Amott cell. An imbibition simulation model was validated by the experimental results using UTCHEM simulator.\u0000 Both surfactants APG-1 and APG-2 exhibited excellent compatibility with the simulated high salinity water at reservoir temperature. They also demonstrated low static adsorption on carbonate reservoir. The surfactant containing larger hydrophobic carbons (APG-1) showed more incremental oil production potential than the other one bearing shorter hydrophobic chain (APG-2). At a concentration of 0.2 wt%, APG-1 yielded a low IFT in the order of 10-2 mN/m and an ultra-low IFT in the order of 10-3 mN/m was obtained upon addition of a small amount of additives. SEM pictures indicated that APG-1 and the additives synergistically generated a more compact structure via interaction between hydrophobic moieties of the chemicals compared to the aggregated structure formed by APG-1 alone. Such an effect could eventually lead to a decrease in IFT between oil and water. APG-1 slightly altered the wettability of carbonate core surface toward water-wet. The experimental results of spontaneous imbibition tests showed an oil production of 28% and 21% by APG-1 and APG-2, respectively. After parameter tuning, the yielded curves from numerical simulation by UTCHEM simulator perfectly matched the experimental data.\u0000 A new APG-based formulation was designed with an ultra-low IFT resulting in a much more compact amphiphilic structure along the oil-water interface. This study shows a great potential of APG surfactants and the relevant derivative formulations in improving oil production application for high-temperature and high-salinity carbonate reservoirs.","PeriodicalId":10940,"journal":{"name":"Day 2 Tue, March 22, 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":"90991450","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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