I. C. Nwogu, Asaolu Ayo, Osamuedemen Asemota, Ozzy Ajibade
Capacitance Resistance Model (CRM) is an analytical tool for estimating reservoir properties and connectivity between producer-injector pairs in an established waterflooded oil reservoir system. The analysis incorporates historical production data, injection rates and available bottom hole pressures. In Swamp Field B (Niger Delta Nigeria), there were concerns of connectivity between producer and injector pairs in the K2 reservoir. CRM analysis was applied to resolve the uncertainty in producer-injector connectivity and provide better understanding of the reservoir flow dynamics. Understanding the connectivity between existing injectors and producers, to ensure adequate water injection distribution for reservoir voidage balance and pressure maintenance necessitated a geologic and engineering review of existing data. The results of the study revealed strong inter-well connectivity between active producers and two idle injectors in the reservoir for the period analyzed, corroborating a revised geologic interpretation of the reservoir. The idle injectors were previously left shut-in due to a geologic interpretation of the presence of shale impacting connectivity and performance. Upon implementing recommendations from the study, an immediate pressure and production response was observed within three months of restoring the two idle injectors. The reactivation of the idle injectors also resulted in $20 MM savings by averting further work on a proposed new water injector. This paper discusses the application of CRM in understanding producer-injector connectivity and emphasizes the use of digital analytic tools to better understand waterflood performance and address challenges with balancing voidage and maintaining reservoir pressure. It demonstrates the value of CRM technique in brown fields and the multidisciplinary approach adopted. Further application of similar techniques in other waterflood reservoirs within Chevron Nigeria is currently ongoing.
电容电阻模型(CRM)是一种分析工具，用于估计已建立的水驱油藏系统的储层性质和采油-注油对之间的连通性。该分析结合了历史生产数据、注入速率和可用的井底压力。在Swamp Field B(尼日利亚尼日尔三角洲)，K2油藏的生产和注入对之间存在连通性问题。CRM分析用于解决产注连通性的不确定性，并更好地了解储层流动动力学。了解现有注入器和生产者之间的连通性，以确保足够的注水分配，以实现油藏空隙平衡和压力维持，需要对现有数据进行地质和工程审查。研究结果表明，在分析的时间段内，油藏中活跃的采油者和两个闲置的注水井之间的井间连通性很强，这证实了对油藏的修订地质解释。由于页岩的地质解释影响了连通性和性能，闲置的注入器之前一直处于关闭状态。根据该研究的建议，在恢复两个闲置注入器后的三个月内，观察到压力和产量的立即响应。闲置注入器的重新启动还节省了2000万美元，避免了对拟议中的新注入器进行进一步的工作。本文讨论了客户关系管理(CRM)在了解产注连通性方面的应用，并强调了数字分析工具的使用，以更好地了解水驱性能，解决平衡空隙和保持油藏压力的挑战。它展示了客户关系管理技术在棕地的价值和所采用的多学科方法。目前，类似技术正在雪佛龙尼日利亚公司的其他注水油藏中进一步应用。
{"title":"Successful Application of Capacitance Resistance Modeling to Understand Reservoir Dynamics in Brown Field Waterflood – A Niger Delta Swamp Field Case Study","authors":"I. C. Nwogu, Asaolu Ayo, Osamuedemen Asemota, Ozzy Ajibade","doi":"10.2118/198819-MS","DOIUrl":"https://doi.org/10.2118/198819-MS","url":null,"abstract":"\u0000 Capacitance Resistance Model (CRM) is an analytical tool for estimating reservoir properties and connectivity between producer-injector pairs in an established waterflooded oil reservoir system. The analysis incorporates historical production data, injection rates and available bottom hole pressures. In Swamp Field B (Niger Delta Nigeria), there were concerns of connectivity between producer and injector pairs in the K2 reservoir. CRM analysis was applied to resolve the uncertainty in producer-injector connectivity and provide better understanding of the reservoir flow dynamics.\u0000 Understanding the connectivity between existing injectors and producers, to ensure adequate water injection distribution for reservoir voidage balance and pressure maintenance necessitated a geologic and engineering review of existing data.\u0000 The results of the study revealed strong inter-well connectivity between active producers and two idle injectors in the reservoir for the period analyzed, corroborating a revised geologic interpretation of the reservoir. The idle injectors were previously left shut-in due to a geologic interpretation of the presence of shale impacting connectivity and performance.\u0000 Upon implementing recommendations from the study, an immediate pressure and production response was observed within three months of restoring the two idle injectors. The reactivation of the idle injectors also resulted in $20 MM savings by averting further work on a proposed new water injector.\u0000 This paper discusses the application of CRM in understanding producer-injector connectivity and emphasizes the use of digital analytic tools to better understand waterflood performance and address challenges with balancing voidage and maintaining reservoir pressure. It demonstrates the value of CRM technique in brown fields and the multidisciplinary approach adopted. Further application of similar techniques in other waterflood reservoirs within Chevron Nigeria is currently ongoing.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"59 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82081845","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}
J. Tumba, A. Agi, Afeez O. Gbadamosi, R. Junin, Azza Hashim Abbas, Kourosh Rajaei, J. Gbonhinbor
The use of surfactants in chemical enhanced oil recovery can recover more oil trapped in the reservoir. However, the loss of surfactant due to adsorption on porous media renders the process ineffective and economically unfeasible. In this study, the adsorption of sodium dodecyl sulfate (SDS) and 4-octylphenol polyethoxylated (TX-100) on different clay minerals (kaolinite, montmorillonite, illite and quartz) as a function of the surfactant concentration, pH and salinity has been investigated. Besides, the use of lignin alkali as a sacrificial agent to reduce adsorption of surfactants in the reservoir is proposed. Surfactant adsorption on the different minerals was determined using the surface tension technique and batch equilibrium adsorption process with lignin as sacrificial agent. The experiment was conducted at varying pH and electrolyte concentrations. Furthermore, oil displacement test was conducted in a sandpack to determine the amount of oil recovered by the surfactant before and after pre-flush with lignin alkaline. Experimental result reveals that SDS adsorbed more on kaolinite while, TX-100 on montmorillonite. The decrease in pH increased the adsorption of SDS on kaolinite and illite, meanwhile, the adsorption of TX-100 on montmorillonite increased significantly at low pH. The optimum salinity concentration for both surfactants was at 20,000ppm for all the minerals except for kaolinite which was at 30,000ppm. Lignin alkaline reduced the surfactant adsorption by 50% and 53.2% for SDS and TX-100 respectively. Oil displacement test with SDS and TX-100 surfactants after water flooding had additional recovery of 7.44% and 4.18% respectively while, after pre-flush the recovery increased by 2.2%.
{"title":"Lignin As a Potential Additive For Minimizing Surfactant Adsorption On Clay Minerals In Different Electrolyte Concentration","authors":"J. Tumba, A. Agi, Afeez O. Gbadamosi, R. Junin, Azza Hashim Abbas, Kourosh Rajaei, J. Gbonhinbor","doi":"10.2118/198713-MS","DOIUrl":"https://doi.org/10.2118/198713-MS","url":null,"abstract":"\u0000 The use of surfactants in chemical enhanced oil recovery can recover more oil trapped in the reservoir. However, the loss of surfactant due to adsorption on porous media renders the process ineffective and economically unfeasible. In this study, the adsorption of sodium dodecyl sulfate (SDS) and 4-octylphenol polyethoxylated (TX-100) on different clay minerals (kaolinite, montmorillonite, illite and quartz) as a function of the surfactant concentration, pH and salinity has been investigated. Besides, the use of lignin alkali as a sacrificial agent to reduce adsorption of surfactants in the reservoir is proposed. Surfactant adsorption on the different minerals was determined using the surface tension technique and batch equilibrium adsorption process with lignin as sacrificial agent. The experiment was conducted at varying pH and electrolyte concentrations. Furthermore, oil displacement test was conducted in a sandpack to determine the amount of oil recovered by the surfactant before and after pre-flush with lignin alkaline. Experimental result reveals that SDS adsorbed more on kaolinite while, TX-100 on montmorillonite. The decrease in pH increased the adsorption of SDS on kaolinite and illite, meanwhile, the adsorption of TX-100 on montmorillonite increased significantly at low pH. The optimum salinity concentration for both surfactants was at 20,000ppm for all the minerals except for kaolinite which was at 30,000ppm. Lignin alkaline reduced the surfactant adsorption by 50% and 53.2% for SDS and TX-100 respectively. Oil displacement test with SDS and TX-100 surfactants after water flooding had additional recovery of 7.44% and 4.18% respectively while, after pre-flush the recovery increased by 2.2%.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80798406","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. Oviawele, S. Onwukwe, N. Nwachukwu, I. Onyejekwe
Disposal of condensate produced from stranded gas field have been a major concern to producing companies due to unavailability of nearby oil flow stations to receive the condensate, which have resulted to abandonment of such fields. This work seek to improve the thermodynamic properties (Heat Capacity, Heating Value, Specific Heat capacity, Heat of Vaporization and Enthalpy) of the export gas through condensate spiking. This was carried out by simulating a natural gas plant, consisting of condensate line and spiking mixer. The simulation was done using Aspen HYSYS, to include the point at which the condensate stream was spiked into the high-pressure dry natural gas stream. Phase envelope and hydrate formation curve for the streams (dry natural gas and the mixture after spiking) were obtained. Case study in HYSYS was used to carry out Sensitivity analysis, to determine the effect of temperature, pressure and flow rate of the condensate on the mixture (export gas). Economic analysis of the project was carried out. Results obtained from the thermodynamic analysis shows that the thermodynamic properties of the export gas after spiking improves, such that the heating value and enthalpy of the export gas increases. The phase envelops shows that hydrate will not form in the export gas streams. Through the sensitivity analyses, the effect of variation in the parameters of the condensate shows that the vapour fraction of the export gas increases as the temperature increase and decrease as the pressure increases. The maximum condensate flow rate was obtained to be 12,500 bbl/day, at a dry gas flow rate of 382.2 MMScfd, for a maximum vapour fraction of 0.953, with this operating parameters, flow assurance problem of hydrate formation, liquid holdup and high pressure drops along the pipeline with be eliminated. Hydrocarbon dew point of −13.41°C was obtained showing that liquid hydrocarbon will not condense out of the gas during transportation. Economic analysis shows that the NPV and IRR are $432.778 million and 33%, indicating that the project is viable for investment. Therefore, it is possible to spike condensate into treated export gas without causing flow assurance problems, and helps mitigate against risk associated with environmental pollution.
{"title":"Improving the Thermodynamic Properties of Export Gas Through Condensate Spiking","authors":"P. Oviawele, S. Onwukwe, N. Nwachukwu, I. Onyejekwe","doi":"10.2118/198805-MS","DOIUrl":"https://doi.org/10.2118/198805-MS","url":null,"abstract":"\u0000 Disposal of condensate produced from stranded gas field have been a major concern to producing companies due to unavailability of nearby oil flow stations to receive the condensate, which have resulted to abandonment of such fields. This work seek to improve the thermodynamic properties (Heat Capacity, Heating Value, Specific Heat capacity, Heat of Vaporization and Enthalpy) of the export gas through condensate spiking. This was carried out by simulating a natural gas plant, consisting of condensate line and spiking mixer. The simulation was done using Aspen HYSYS, to include the point at which the condensate stream was spiked into the high-pressure dry natural gas stream. Phase envelope and hydrate formation curve for the streams (dry natural gas and the mixture after spiking) were obtained. Case study in HYSYS was used to carry out Sensitivity analysis, to determine the effect of temperature, pressure and flow rate of the condensate on the mixture (export gas). Economic analysis of the project was carried out. Results obtained from the thermodynamic analysis shows that the thermodynamic properties of the export gas after spiking improves, such that the heating value and enthalpy of the export gas increases. The phase envelops shows that hydrate will not form in the export gas streams. Through the sensitivity analyses, the effect of variation in the parameters of the condensate shows that the vapour fraction of the export gas increases as the temperature increase and decrease as the pressure increases. The maximum condensate flow rate was obtained to be 12,500 bbl/day, at a dry gas flow rate of 382.2 MMScfd, for a maximum vapour fraction of 0.953, with this operating parameters, flow assurance problem of hydrate formation, liquid holdup and high pressure drops along the pipeline with be eliminated. Hydrocarbon dew point of −13.41°C was obtained showing that liquid hydrocarbon will not condense out of the gas during transportation. Economic analysis shows that the NPV and IRR are $432.778 million and 33%, indicating that the project is viable for investment. Therefore, it is possible to spike condensate into treated export gas without causing flow assurance problems, and helps mitigate against risk associated with environmental pollution.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"15 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90713953","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. Okpalla, V. Chaloupka, Romain Djenani, Victor Okengwu, T. Akinniyi, B. Orluwosu, Kenneth Johnson
A service company was challenged to deliver best-in-class upper and lower completions by leveraging deep water completion experiences throughout West Africa with the operator and service company's global best practices and lessons learned. An operator reduced lower completion times, standalone screens, and openhole gravel packs by 60% between the 1st and 24th well while reducing upper completion times by 40% for the same wells. Well construction durations, including drilling and completion, currently averages 24 days per well, with lower and upper completion operating efficiencies and run reliabilities exceeding 97%.
{"title":"Egina Deep Water Development Completion Success: One Team Working Together Setting New Performance Standards","authors":"C. Okpalla, V. Chaloupka, Romain Djenani, Victor Okengwu, T. Akinniyi, B. Orluwosu, Kenneth Johnson","doi":"10.2118/198869-MS","DOIUrl":"https://doi.org/10.2118/198869-MS","url":null,"abstract":"\u0000 A service company was challenged to deliver best-in-class upper and lower completions by leveraging deep water completion experiences throughout West Africa with the operator and service company's global best practices and lessons learned. An operator reduced lower completion times, standalone screens, and openhole gravel packs by 60% between the 1st and 24th well while reducing upper completion times by 40% for the same wells. Well construction durations, including drilling and completion, currently averages 24 days per well, with lower and upper completion operating efficiencies and run reliabilities exceeding 97%.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"34 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79325655","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}
Revenue from petroleum operations remains the most important contributor to government expenditures in Nigeria. Hence, the onus is on the central government to design fiscal regime that would maximize economic rents to the nation. The Petroleum Industry Fiscal Bill (PIFB) of 2018 seems to be the awaited bill that may satisfy the economic objectives of the Nigerian government. PIFB 2018 proposes the replacement of the default petroleum profit tax with single tax system, petroleum income tax and additional petroleum income tax to cater for windfall profits. This research uses deterministic spreadsheet approach to evaluate the impacts of this new tax scheme on the profitability of oil ventures in Nigerian deep-water production sharing contracts. The deterministic results were subjected to Monte Carlo Simulation using Crystal Ball Risk analysis software to account for risks and uncertainties inherent in the business. The typical project examined under PIFB (2018) generated a positive Net Present Value (NPV) of MM$595.18, an Internal Rate of Return (IRR) of 23.7% which is higher than opportunity cost of capital, Profitability Index (PI) of 1.34, Contractor take of 11.9% and Host Government take of 88.1%. All evaluated indicators gave positive results meaning that investments under this new fiscal regime will be profitable giving the government higher take as compared to the current regime. The results also show that the contractor take can increase to as high as 25% taking advantage of Reserves Replacement Ratio (RRR) tied to additional production allowance. The bill however, does not explicitly state the conditions for cost recovery limit and profit oil sharing, as such could create a lot concerns to investors and may also hamper investment in the industry. Hence, the bill should be reviewed before passage into law.
{"title":"The Impact of the Proposed Petroleum Industry Fiscal Bill PIFB, 2018 Tax Scheme on the Economics of Oil Production in Nigeria","authors":"Bariture Nyoor, Adeogun Oyebimpe, O. Iledare","doi":"10.2118/198782-MS","DOIUrl":"https://doi.org/10.2118/198782-MS","url":null,"abstract":"\u0000 Revenue from petroleum operations remains the most important contributor to government expenditures in Nigeria. Hence, the onus is on the central government to design fiscal regime that would maximize economic rents to the nation. The Petroleum Industry Fiscal Bill (PIFB) of 2018 seems to be the awaited bill that may satisfy the economic objectives of the Nigerian government. PIFB 2018 proposes the replacement of the default petroleum profit tax with single tax system, petroleum income tax and additional petroleum income tax to cater for windfall profits. This research uses deterministic spreadsheet approach to evaluate the impacts of this new tax scheme on the profitability of oil ventures in Nigerian deep-water production sharing contracts. The deterministic results were subjected to Monte Carlo Simulation using Crystal Ball Risk analysis software to account for risks and uncertainties inherent in the business. The typical project examined under PIFB (2018) generated a positive Net Present Value (NPV) of MM$595.18, an Internal Rate of Return (IRR) of 23.7% which is higher than opportunity cost of capital, Profitability Index (PI) of 1.34, Contractor take of 11.9% and Host Government take of 88.1%. All evaluated indicators gave positive results meaning that investments under this new fiscal regime will be profitable giving the government higher take as compared to the current regime. The results also show that the contractor take can increase to as high as 25% taking advantage of Reserves Replacement Ratio (RRR) tied to additional production allowance. The bill however, does not explicitly state the conditions for cost recovery limit and profit oil sharing, as such could create a lot concerns to investors and may also hamper investment in the industry. Hence, the bill should be reviewed before passage into law.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"6 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76430691","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}
R. Amorin, E. Broni-Bediako, Collins Westkinn, Prince Opoku Appau
Good cementing job practices are required for an efficient advancement in drilling and production operations. Most drilled oil and gas wells in Ghana employ the use of class G cement in its cementing operations. This class G cement is imported, scarcely available and relatively more expensive compared to other forms of cements. It also does not promote the local content and local participation policy of the country in the oil and gas sector. This has therefore necessitated the need to research into available local cements (easily available and relatively inexpensive) as an alternative to serve the same purpose as the imported class G cement. This research therefore assesses the performance of class G cement blended with local cement at different ratios in an attempt to reducing the overdependence of the class G cement while considering the technical requirements and economic implications. All the blended samples met the minimum API compressive strength requirement of 1500 psi when cured for 8 hours at 140 °F. Though, free fluid values increased with increasing amount of local cement ratio, all values recorded were below the maximum field requirement value of 5.9%. The blended samples exhibited the ability to be pumpable, recording plastic viscosity less than the maximum recommended value of 100 centipoise (cP). It was therefore established that the use of blended samples (local and Class G) for oil well cementing operations in Ghana would save the industry from 19.57% to 78.28% of money over the use of class G cement only. Considering the performance and economic benefits of the blended cement over the class G cement only at the test conditions, it is highly recommended that, the industry adopts the blending of class G cement with the local cement in their cementing operations to boost the local economy as well as to reducing their cementing operation cost.
{"title":"Performance Assessment and Economic Analysis of Blended Class G Cement With Local Cement for Oil Well Cementing Operations: A Case Study of Ghana","authors":"R. Amorin, E. Broni-Bediako, Collins Westkinn, Prince Opoku Appau","doi":"10.2118/198823-MS","DOIUrl":"https://doi.org/10.2118/198823-MS","url":null,"abstract":"\u0000 Good cementing job practices are required for an efficient advancement in drilling and production operations. Most drilled oil and gas wells in Ghana employ the use of class G cement in its cementing operations. This class G cement is imported, scarcely available and relatively more expensive compared to other forms of cements. It also does not promote the local content and local participation policy of the country in the oil and gas sector. This has therefore necessitated the need to research into available local cements (easily available and relatively inexpensive) as an alternative to serve the same purpose as the imported class G cement. This research therefore assesses the performance of class G cement blended with local cement at different ratios in an attempt to reducing the overdependence of the class G cement while considering the technical requirements and economic implications. All the blended samples met the minimum API compressive strength requirement of 1500 psi when cured for 8 hours at 140 °F. Though, free fluid values increased with increasing amount of local cement ratio, all values recorded were below the maximum field requirement value of 5.9%. The blended samples exhibited the ability to be pumpable, recording plastic viscosity less than the maximum recommended value of 100 centipoise (cP). It was therefore established that the use of blended samples (local and Class G) for oil well cementing operations in Ghana would save the industry from 19.57% to 78.28% of money over the use of class G cement only. Considering the performance and economic benefits of the blended cement over the class G cement only at the test conditions, it is highly recommended that, the industry adopts the blending of class G cement with the local cement in their cementing operations to boost the local economy as well as to reducing their cementing operation cost.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"60 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78959122","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}
Intelligent field completions have seen more frequent deployment in the oil and gas industry in recent times. This is most likely due to the benefits that have been observed from real-time data acquisition, surveillance and optimization based on analysis of data gathered. With continuous acquisition of real-time data, analysis of the transient pressure and rate data can be used to understand changes in reservoir and well performance over time. The aim of this paper is to show how the evolution of parameters obtained from pressure transient analysis can be used to optimize well and reservoir performance. Key parameters obtained from pressure transient analysis (PTA) are permeability, skin, reservoir pressure and information on boundaries depending on shut-in duration. Analyses are performed for all shut-ins of the completion, both planned shut-ins and unplanned shut-ins (emergency shutdowns - ESDs). The results of all these analyses are catalogued to provide an historical surveillance data which, when trended, can provide insight into the near-wellbore performance of a completion as well as the reservoir. This paper demonstrates how Pressure Transient Analysis of real-time data was used in the Agbami Field to optimize production from the field. Two case studies are presented where analysis of transient pressure data was used to identify water injection front movement in a waterflooded reservoir and increasing near-wellbore damage due to fines migration. The results were used to optimize injection into a waterflooded reservoir to achieve a balance between maintaining reservoir pressure and optimizing voidage. In the case of continually increasing skin, the completion was stimulated with production increasing by a factor of 15.
{"title":"Production Optimization through Pressure Transient Analysis","authors":"Fagbowore Olufisayo, O. Anthony","doi":"10.2118/198787-MS","DOIUrl":"https://doi.org/10.2118/198787-MS","url":null,"abstract":"\u0000 Intelligent field completions have seen more frequent deployment in the oil and gas industry in recent times. This is most likely due to the benefits that have been observed from real-time data acquisition, surveillance and optimization based on analysis of data gathered. With continuous acquisition of real-time data, analysis of the transient pressure and rate data can be used to understand changes in reservoir and well performance over time. The aim of this paper is to show how the evolution of parameters obtained from pressure transient analysis can be used to optimize well and reservoir performance.\u0000 Key parameters obtained from pressure transient analysis (PTA) are permeability, skin, reservoir pressure and information on boundaries depending on shut-in duration. Analyses are performed for all shut-ins of the completion, both planned shut-ins and unplanned shut-ins (emergency shutdowns - ESDs). The results of all these analyses are catalogued to provide an historical surveillance data which, when trended, can provide insight into the near-wellbore performance of a completion as well as the reservoir.\u0000 This paper demonstrates how Pressure Transient Analysis of real-time data was used in the Agbami Field to optimize production from the field. Two case studies are presented where analysis of transient pressure data was used to identify water injection front movement in a waterflooded reservoir and increasing near-wellbore damage due to fines migration. The results were used to optimize injection into a waterflooded reservoir to achieve a balance between maintaining reservoir pressure and optimizing voidage. In the case of continually increasing skin, the completion was stimulated with production increasing by a factor of 15.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"44 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89000043","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}
Humphrey Osita, Nico Foekema, O. Oredolapo, Raphael Ozioko, Antoine Chapoulie, Kehinde Omojowolo, John Okoroafor
This paper describes the successful technique to start a kickoff below the 36-in. conductor casing with much higher dogleg severity (DLS) capability than a conventional motor directional drilling method in a soft sediment formation by using a rotary steerable system (RSS) equipped with directional jetting. This technique uses a rotary steerable system (RSS) equipped with directional jetting to provide the operator with a step change in directional well design for reaching shallow reservoirs with inclinations close to horizontal. The challenging aspect of the well design was that only 650m (2133ft) of TVD was available to perform the directional work. This section consisted of weak and soft sediment formations that did not support conventional directional drilling methods. To address the operator's challenge, it was determined that a RSS configured for directional jetting could deliver the higher DLS for the optimal well trajectory. This system combines two techniques, rotary steerable and directional jetting, to achieve the directional objective. This field-proven application was successfully used by several operators, as described in SPE-173057-MS, and applied in this deepwater low-UCS environment. The extensive engineering evaluation, using finite-element analysis and torque-and-drag calculations, confirmed the bottom hole assembly (BHA) design was technically feasible without compromising safety and drilling efficiency. Three wells successfully delivered all directional objectives with this technique. The highest inclination was recorded in the top hole as planned; the sailing angle was lower compared to other wells drilled with conventional directional drilling methods, and the target sands reached at an angle close to horizontal. Completions ran without issues. This technique delivered above 3°/30m DLS in the deepwater soft formation and all future wells for this operator will use this technique for the tophole drilling.
{"title":"Rotary Steerable Directional Jetting Service Successfully Delivering Step Change in Directional Well Design for Soft Sediment Formation in Deepwater Nigeria","authors":"Humphrey Osita, Nico Foekema, O. Oredolapo, Raphael Ozioko, Antoine Chapoulie, Kehinde Omojowolo, John Okoroafor","doi":"10.2118/198754-MS","DOIUrl":"https://doi.org/10.2118/198754-MS","url":null,"abstract":"\u0000 This paper describes the successful technique to start a kickoff below the 36-in. conductor casing with much higher dogleg severity (DLS) capability than a conventional motor directional drilling method in a soft sediment formation by using a rotary steerable system (RSS) equipped with directional jetting. This technique uses a rotary steerable system (RSS) equipped with directional jetting to provide the operator with a step change in directional well design for reaching shallow reservoirs with inclinations close to horizontal.\u0000 The challenging aspect of the well design was that only 650m (2133ft) of TVD was available to perform the directional work. This section consisted of weak and soft sediment formations that did not support conventional directional drilling methods.\u0000 To address the operator's challenge, it was determined that a RSS configured for directional jetting could deliver the higher DLS for the optimal well trajectory. This system combines two techniques, rotary steerable and directional jetting, to achieve the directional objective. This field-proven application was successfully used by several operators, as described in SPE-173057-MS, and applied in this deepwater low-UCS environment. The extensive engineering evaluation, using finite-element analysis and torque-and-drag calculations, confirmed the bottom hole assembly (BHA) design was technically feasible without compromising safety and drilling efficiency.\u0000 Three wells successfully delivered all directional objectives with this technique. The highest inclination was recorded in the top hole as planned; the sailing angle was lower compared to other wells drilled with conventional directional drilling methods, and the target sands reached at an angle close to horizontal. Completions ran without issues. This technique delivered above 3°/30m DLS in the deepwater soft formation and all future wells for this operator will use this technique for the tophole drilling.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"6 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89967882","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. Amos, E. Osanaiye, S. Louis, E. Ighavini, Grace Ahabike, A. Olofin, Rebecca Ejukorlem-Okusi
Recently, a multinational exploration and production (E&P) company identified an opportunity for production optimization in a shallow reservoir with the zone of interest behind casing and without using any form of isolation for completions. A major challenge during this operation was the engineering design, as this was the first time a catenary cement operation of more than 31.8 m3 (200 bbl) of slurry would be pumped through coiled tubing (CT), in addition to the high well deviation (~79°) consideration for installation of the cement retainer. Additionally, insufficient deck space on the platform and load-bearing capacity to accommodate the intervention spread presented a potential derailer for the attic oil development. A rigless well intervention program was designed using a 1.75-in. (125K) CT catenary system unit, which could be installed on a barge. The system would allow better CT reach and a higher injector snub/pull capacity. CT was used to install the cement retainer, punch holes in the 4 1/2-in. tubing, and pump cement. A total of 34.6 m3 (218 bbl) of 15.8-lbm/gal resilient slurry was pumped through CT, which was equivalent to pumping a cement volume approximately six times greater than the CT volume. This was necessary to place a 1056-m cement packer in the 4 1/2-in. tubing 9 5/8-in. casing annulus and place 200 m of cement on the cement retainer. The operation was successfully completed using CT, avoiding more costly rig options for recompletion of the well. Zonal isolation was achieved, and the bypassed reservoir pay was perforated with ~600 B/D production. This approach proved to be cost-effective, with savings of approximately USD 1.3 million, which was achieved without compromising operational and safety performance. Rigless recompletion has been a cost-effective approach for production optimization in mature fields. However, existing well architecture, access to bypassed hydrocarbon pays, and environmental characteristics present challenges for developing some of these reserves.
{"title":"Cement Packer: Recovery of Bypassed Reserves in Highly Deviated Well Using Large-Volume Cement Through Coiled Tubing, Offshore Niger Delta","authors":"C. Amos, E. Osanaiye, S. Louis, E. Ighavini, Grace Ahabike, A. Olofin, Rebecca Ejukorlem-Okusi","doi":"10.2118/198727-MS","DOIUrl":"https://doi.org/10.2118/198727-MS","url":null,"abstract":"\u0000 Recently, a multinational exploration and production (E&P) company identified an opportunity for production optimization in a shallow reservoir with the zone of interest behind casing and without using any form of isolation for completions.\u0000 A major challenge during this operation was the engineering design, as this was the first time a catenary cement operation of more than 31.8 m3 (200 bbl) of slurry would be pumped through coiled tubing (CT), in addition to the high well deviation (~79°) consideration for installation of the cement retainer. Additionally, insufficient deck space on the platform and load-bearing capacity to accommodate the intervention spread presented a potential derailer for the attic oil development.\u0000 A rigless well intervention program was designed using a 1.75-in. (125K) CT catenary system unit, which could be installed on a barge. The system would allow better CT reach and a higher injector snub/pull capacity. CT was used to install the cement retainer, punch holes in the 4 1/2-in. tubing, and pump cement.\u0000 A total of 34.6 m3 (218 bbl) of 15.8-lbm/gal resilient slurry was pumped through CT, which was equivalent to pumping a cement volume approximately six times greater than the CT volume. This was necessary to place a 1056-m cement packer in the 4 1/2-in. tubing 9 5/8-in. casing annulus and place 200 m of cement on the cement retainer.\u0000 The operation was successfully completed using CT, avoiding more costly rig options for recompletion of the well. Zonal isolation was achieved, and the bypassed reservoir pay was perforated with ~600 B/D production. This approach proved to be cost-effective, with savings of approximately USD 1.3 million, which was achieved without compromising operational and safety performance.\u0000 Rigless recompletion has been a cost-effective approach for production optimization in mature fields. However, existing well architecture, access to bypassed hydrocarbon pays, and environmental characteristics present challenges for developing some of these reserves.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"85 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85574273","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 performs uncertainty quantification (UQ) to capture the risk – both from investor and government perspective – to which an integrated petroleum development project is exposed to. The current fiscal system will be compared against the proposed PIFB 2018. Following the field development concept, the comparative economics are developed using Discounted Cash Flow (DCF) in recognition of the extant fiscal provisions. The DCF is expressed in nominal terms with sensitivity and stochastic modelling. The integrated development concept incorporates a 12kbpd refinery and a 150mmscfd gas plant on a 250mmboe onshore marginal field. The results indicate that the Petroleum Industry Fiscal Bill (PIFB 2018) delivers nearly twice in expected investor value than the current Petroleum Profit Tax/Marginal Field Regulations (PPT/MFR) on the integrated project. Furthermore, government take (GT%) shrinks from 45% under the PPT/MFR to 28% under the proposed regime. Stochastic analysis shows that investors are less exposed to failure under PIFB fiscal terms and instruments than the PPT/MFR. There is a higher likelihood (54%) of investor failure under the PPT than the 46% probability of a loss under the PIFB. The expected GT under PIFB is lower than that under PPT, however, there is significant likelihood (>65%) that neither system will deliver to government as much as the expected lifecycle Take. However, decoupling the value chain reveals varying risk reward profiles for the different segments with implications for policy formulation. A key insight drawn from the study is for policy makers to encourage the development of integrated projects to deliver a "portfolio" government take. This will smoothen out volatilities in tax receipts given that in this integrated development, government inflows from the different value chain components have different timings, levels and uncertainty.
{"title":"Between PPT and PIFB 2018: Risk Assessment of Stakeholders for an Integrated Petroleum Asset Development","authors":"Kaase Gbakon, O. Iledare, O. Adeogun","doi":"10.2118/198728-MS","DOIUrl":"https://doi.org/10.2118/198728-MS","url":null,"abstract":"\u0000 This paper performs uncertainty quantification (UQ) to capture the risk – both from investor and government perspective – to which an integrated petroleum development project is exposed to. The current fiscal system will be compared against the proposed PIFB 2018. Following the field development concept, the comparative economics are developed using Discounted Cash Flow (DCF) in recognition of the extant fiscal provisions. The DCF is expressed in nominal terms with sensitivity and stochastic modelling. The integrated development concept incorporates a 12kbpd refinery and a 150mmscfd gas plant on a 250mmboe onshore marginal field. The results indicate that the Petroleum Industry Fiscal Bill (PIFB 2018) delivers nearly twice in expected investor value than the current Petroleum Profit Tax/Marginal Field Regulations (PPT/MFR) on the integrated project. Furthermore, government take (GT%) shrinks from 45% under the PPT/MFR to 28% under the proposed regime. Stochastic analysis shows that investors are less exposed to failure under PIFB fiscal terms and instruments than the PPT/MFR. There is a higher likelihood (54%) of investor failure under the PPT than the 46% probability of a loss under the PIFB. The expected GT under PIFB is lower than that under PPT, however, there is significant likelihood (>65%) that neither system will deliver to government as much as the expected lifecycle Take. However, decoupling the value chain reveals varying risk reward profiles for the different segments with implications for policy formulation. A key insight drawn from the study is for policy makers to encourage the development of integrated projects to deliver a \"portfolio\" government take. This will smoothen out volatilities in tax receipts given that in this integrated development, government inflows from the different value chain components have different timings, levels and uncertainty.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"18 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83751397","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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