One of the biggest challenges after the initial gas field discovery lies in the transportation. The natural gas supply is constructed in such a way that transportation remains an integral part of the gas utilization system. This is because the operator has to understand the mechanism behind transporting from the well to the wellhead; from the wellhead to the topside while efficiently avoiding hydrate formation; from the topside to the processing facilities and from the processing facilities to the delivery point for the final consumers. This paper was structured to address subsea gas pipeline flow assurance issues relating to the initiation of hydrate and internal corrosion. Through experience and extensive literature studies, an Optimization Systematic Model was developed. This model is procedural in nature, incorporating both risk analysis and predictive models. The model was further used to investigate the susceptibility of the case study, Inter-western African Gas Pan Pipeline (IAGPP), to hydrate and internal corrosion. The results of the case study confirmed that the model is helpful in that it can bring flow assurance issues to management focus. This research suggested a new derived equation – the Thermo-Mechanistic Model (T-MM), used to explain PIPESIM simulation results and the optimization options. The T-MM can be used to understand the behavior of gas enthalpy to variations in gas pipeline flowrate. In general, there is a need to keep gas pipeline capacity optimization in focus; to proactively avert cases of hydrate and internal corrosion by using the model developed. Learning from the IAGPP case study also shows that there is the need to accurately assess gas availability for transmission.
{"title":"A Mechanistic Approach to Subsea Gas Pipeline Capacity Utilization – Case Study","authors":"Ogenethoja Umuteme, E. Umeh","doi":"10.2118/198767-MS","DOIUrl":"https://doi.org/10.2118/198767-MS","url":null,"abstract":"\u0000 One of the biggest challenges after the initial gas field discovery lies in the transportation. The natural gas supply is constructed in such a way that transportation remains an integral part of the gas utilization system. This is because the operator has to understand the mechanism behind transporting from the well to the wellhead; from the wellhead to the topside while efficiently avoiding hydrate formation; from the topside to the processing facilities and from the processing facilities to the delivery point for the final consumers.\u0000 This paper was structured to address subsea gas pipeline flow assurance issues relating to the initiation of hydrate and internal corrosion. Through experience and extensive literature studies, an Optimization Systematic Model was developed. This model is procedural in nature, incorporating both risk analysis and predictive models. The model was further used to investigate the susceptibility of the case study, Inter-western African Gas Pan Pipeline (IAGPP), to hydrate and internal corrosion. The results of the case study confirmed that the model is helpful in that it can bring flow assurance issues to management focus. This research suggested a new derived equation – the Thermo-Mechanistic Model (T-MM), used to explain PIPESIM simulation results and the optimization options. The T-MM can be used to understand the behavior of gas enthalpy to variations in gas pipeline flowrate. In general, there is a need to keep gas pipeline capacity optimization in focus; to proactively avert cases of hydrate and internal corrosion by using the model developed. Learning from the IAGPP case study also shows that there is the need to accurately assess gas availability for transmission.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"50 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84962816","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}
Francis Nwaochei, Abayomi Adelowotan, Trond Liu, Jorge Goldman
According to Wikipedia, "Data Science is an interdisciplinary field that uses scientific methods, processes, algorithms and systems to extract knowledge and insights from data in various forms, both structured and unstructured, similar to data mining." The oil and gas industry is increasingly expanding its activities by moving into the Data Science and analytics space to increase efficiency, reduce costs, make better decisions and improve quality of technical products and services. Through the extraction of knowledge and insights from historical data, oil and gas companies can systematically process the huge data available to them using scientific methods and algorithms to identify trends for problem identification and optimization opportunities. The data processing can also be used to perform analytics to provide Descriptive, Diagnostic, predictive or Prescriptive solutions for value creation. For Chevron offshore and onshore non-rig wellwork, the existing methodology of planning and scheduling Non-Rig Workovers (NRWOs) for execution is a spreadsheet or a Project typically run on Microsoft applications or software. This process does not incorporate numerous factors that affect the value realization through executing the NRWO such as historical Data Analytics, predictions and several extreme constraints. The value in building a prioritized candidate selection schedule is allowing the business to shift to a data-driven model based from a method of simple basic programs with limited options and typically biased by human input. Historical data from various sources is being collected to provide an encompassing view of the NRWO prioritization, planning and scheduling environment. The scope of this study involves utilizing Data Science to generate solutions comprising of prioritized scheduled workovers that are optimized by various constraints to rank these workovers such as individual well Non-Rig workover cost per barrel. The approach can be replicated using other operational and well related constraints to generate alternative optimized rigless well prioritization solutions. The resulting wells will be gauged against established business drivers to develop an optimal prioritized solution which is then applied at the start of the business plan year to provide an optimized wellwork schedule for the planning year. Data Science applied to this project utilizes the various systems of records within the offshore and onshore fields such as Wellwork candidate listings and categorization database, project maturation database, cost schedules, possibility of success, reserves, production profiles, etc. The systems of records are then integrated through Data Science and prioritized by ranking the various parameters through automation based on constraints specified by customers. The long-term project will reduce NPT by 2-3% annually, save well work maturation recycle time, and increase efficiency in executing wellwork through an optimized schedule. Equiva
{"title":"Prioritizing Non-Rig Well Work Candidates Using Data Science","authors":"Francis Nwaochei, Abayomi Adelowotan, Trond Liu, Jorge Goldman","doi":"10.2118/198821-MS","DOIUrl":"https://doi.org/10.2118/198821-MS","url":null,"abstract":"\u0000 According to Wikipedia, \"Data Science is an interdisciplinary field that uses scientific methods, processes, algorithms and systems to extract knowledge and insights from data in various forms, both structured and unstructured, similar to data mining.\"\u0000 The oil and gas industry is increasingly expanding its activities by moving into the Data Science and analytics space to increase efficiency, reduce costs, make better decisions and improve quality of technical products and services. Through the extraction of knowledge and insights from historical data, oil and gas companies can systematically process the huge data available to them using scientific methods and algorithms to identify trends for problem identification and optimization opportunities. The data processing can also be used to perform analytics to provide Descriptive, Diagnostic, predictive or Prescriptive solutions for value creation.\u0000 For Chevron offshore and onshore non-rig wellwork, the existing methodology of planning and scheduling Non-Rig Workovers (NRWOs) for execution is a spreadsheet or a Project typically run on Microsoft applications or software. This process does not incorporate numerous factors that affect the value realization through executing the NRWO such as historical Data Analytics, predictions and several extreme constraints. The value in building a prioritized candidate selection schedule is allowing the business to shift to a data-driven model based from a method of simple basic programs with limited options and typically biased by human input. Historical data from various sources is being collected to provide an encompassing view of the NRWO prioritization, planning and scheduling environment.\u0000 The scope of this study involves utilizing Data Science to generate solutions comprising of prioritized scheduled workovers that are optimized by various constraints to rank these workovers such as individual well Non-Rig workover cost per barrel. The approach can be replicated using other operational and well related constraints to generate alternative optimized rigless well prioritization solutions. The resulting wells will be gauged against established business drivers to develop an optimal prioritized solution which is then applied at the start of the business plan year to provide an optimized wellwork schedule for the planning year.\u0000 Data Science applied to this project utilizes the various systems of records within the offshore and onshore fields such as Wellwork candidate listings and categorization database, project maturation database, cost schedules, possibility of success, reserves, production profiles, etc. The systems of records are then integrated through Data Science and prioritized by ranking the various parameters through automation based on constraints specified by customers.\u0000 The long-term project will reduce NPT by 2-3% annually, save well work maturation recycle time, and increase efficiency in executing wellwork through an optimized schedule. Equiva","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"80 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80929237","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}
Haruna M. Onuh, Ilyas Abdulsalaam, Fatima Abdurahaman, Emmanuel Osarowaji, Rohan Chemmarikattil, Charles Ibrahim, Greg Ntiwunka
The "balanced cement plug" concept has long been a standard industry practice for setting plugs in a wellbore. This requires setting a hydrostatic plug consisting of a column of brine, spacers, and cement slurry pumped into the annulus of a tubing/drillstring to create a balanced U-Tube that equates the hydrostatic head in the drillstring/tubing and annulus. Fluid volumes are calculated accounting for fluids both inside and outside the pipe at the given gradient, thus resulting in a hydrostatically "balanced system." Recently, this technology has been successfully deployed for cement packer design and execution using coiled tubing (CT) at a depth of 1,899 ft above the production packer with 111 bbl of calcium chloride brine existing (cement accelerator) below the tubing punch interval in the tubing-casing annulus. The cement packer installation design was for accessing bypassed hydrocarbon in high-angle (65 to 72º) deviated wells offshore the Niger Delta. Design considerations are reviewed and precautions for placement of high angle cement packer through CT are discussed. Initial designs to isolate the lower depleted zone were futile because of failed zonal isolation with mechanical plugs. Thus, an attempt to isolate the lower interval by pumping cement with 15% excess (openhole volume) led to having 17 bbl (1,899 ft) of cement within the 3.5-in. production tubing, and above the production packer. The CT deployed cement packer installation without a cement retainer presents unconventional solutions for placing cement at the height of 1,899 ft. The operation was successfully executed and the temperature log confirmed top of cement as proposed during the design phase. The holdup depth in the tubing was also tagged as expected with no cement U-tubing from the annulus. Post-job shut-in tubing and casing pressures, quantity of cement pumped, and flow testing have proven the success of the design and procedure implemented in challenging wellbores.
{"title":"Cement Packer Installation in Highly Deviated Well Using the Balanced Hydrostatic Plug Concept through Coiled Tubing: Offshore Niger Delta","authors":"Haruna M. Onuh, Ilyas Abdulsalaam, Fatima Abdurahaman, Emmanuel Osarowaji, Rohan Chemmarikattil, Charles Ibrahim, Greg Ntiwunka","doi":"10.2118/198836-MS","DOIUrl":"https://doi.org/10.2118/198836-MS","url":null,"abstract":"\u0000 The \"balanced cement plug\" concept has long been a standard industry practice for setting plugs in a wellbore. This requires setting a hydrostatic plug consisting of a column of brine, spacers, and cement slurry pumped into the annulus of a tubing/drillstring to create a balanced U-Tube that equates the hydrostatic head in the drillstring/tubing and annulus. Fluid volumes are calculated accounting for fluids both inside and outside the pipe at the given gradient, thus resulting in a hydrostatically \"balanced system.\"\u0000 Recently, this technology has been successfully deployed for cement packer design and execution using coiled tubing (CT) at a depth of 1,899 ft above the production packer with 111 bbl of calcium chloride brine existing (cement accelerator) below the tubing punch interval in the tubing-casing annulus. The cement packer installation design was for accessing bypassed hydrocarbon in high-angle (65 to 72º) deviated wells offshore the Niger Delta. Design considerations are reviewed and precautions for placement of high angle cement packer through CT are discussed.\u0000 Initial designs to isolate the lower depleted zone were futile because of failed zonal isolation with mechanical plugs. Thus, an attempt to isolate the lower interval by pumping cement with 15% excess (openhole volume) led to having 17 bbl (1,899 ft) of cement within the 3.5-in. production tubing, and above the production packer. The CT deployed cement packer installation without a cement retainer presents unconventional solutions for placing cement at the height of 1,899 ft. The operation was successfully executed and the temperature log confirmed top of cement as proposed during the design phase. The holdup depth in the tubing was also tagged as expected with no cement U-tubing from the annulus. Post-job shut-in tubing and casing pressures, quantity of cement pumped, and flow testing have proven the success of the design and procedure implemented in challenging wellbores.","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":"83013984","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}
Corporate social responsibility has become a business imperative as organization deliberately and strategically include public interest on corporate decision in an attempt to satisfy the demand of sustainable development. Balancing short term sight and long term perspective against triple bottom requirements in the face of rapidly changing social environment presents uncharted challenges and opportunities for businesses. For marginal oil field operators located in the Niger Delta, the region is characterized by poverty, underdevelopment and violent conflicts. The study investigated the strategies adopted by marginal oil field operators in the region to achieve competitive advantage and success. Combining several methodological framework through literature review and multiple firm level case study to examine the various strategies that marginal oil field operators in Niger Delta region adopts in their efforts to becoming social responsible corporate entity. Data gathering is through internet and review of existing literature. The study established that marginal field operators may apply different strategies in responses to social demands in their operating environment. It is observed that the dynamic response or interactive strategy have produced beneficial result by sustaining peace in their operating environment in the long run compared to reactive or adaptive strategy which might gain temporary benefits in the short run. The significance of the study is that it would benefit investors in marginal oil field development as it would provide an understanding of the challenges in the business environment and the different strategic responses needed to handle these challenges. The study recommends that investors in oil and gas business assess their operating environment carefully in order to develop strategies that would result in a cost effective way of managing business and bring about harmonious relationship between the host communities and the oil company.
{"title":"Strategic Responses to Social Demands: Some Lessons for Marginal Oil Field Operators in Niger-Delta Region","authors":"H. Oruwari, Opiribo Dagogo","doi":"10.2118/198832-MS","DOIUrl":"https://doi.org/10.2118/198832-MS","url":null,"abstract":"\u0000 Corporate social responsibility has become a business imperative as organization deliberately and strategically include public interest on corporate decision in an attempt to satisfy the demand of sustainable development. Balancing short term sight and long term perspective against triple bottom requirements in the face of rapidly changing social environment presents uncharted challenges and opportunities for businesses. For marginal oil field operators located in the Niger Delta, the region is characterized by poverty, underdevelopment and violent conflicts. The study investigated the strategies adopted by marginal oil field operators in the region to achieve competitive advantage and success. Combining several methodological framework through literature review and multiple firm level case study to examine the various strategies that marginal oil field operators in Niger Delta region adopts in their efforts to becoming social responsible corporate entity. Data gathering is through internet and review of existing literature. The study established that marginal field operators may apply different strategies in responses to social demands in their operating environment. It is observed that the dynamic response or interactive strategy have produced beneficial result by sustaining peace in their operating environment in the long run compared to reactive or adaptive strategy which might gain temporary benefits in the short run. The significance of the study is that it would benefit investors in marginal oil field development as it would provide an understanding of the challenges in the business environment and the different strategic responses needed to handle these challenges. The study recommends that investors in oil and gas business assess their operating environment carefully in order to develop strategies that would result in a cost effective way of managing business and bring about harmonious relationship between the host communities and the oil company.","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":"89706184","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}
Obikpo field was discovered in the late 1960s, and since then over 40 wells have been drilled. By the end of the year 2018, more than 68 MMstb oil would have been produced from the field. Water cut has risen to over 65% and this affects performances of oil wells. The field is geologically complex, heterogeneous and divided by large faults; leading to local permeability enhancements that most times serves as barriers to uniform fluid displacement. Average gross thickness of the reservoir is about 80 ft. Recovery is mainly by the strong bottom water influx, expansion and secondary support from water injection. Obikpo fluid typically is heavy in nature resulting in poor mobility ratio which keeps the water table irregularly distributed across the sands. To improve on the recovery across Obikpo field, Inflow Control Device (ICD) technology is being utilized in all Obikpo wells to mitigate heel to toe coning effects and channeling / fingering of unwanted water into completions. Inflow Control devices are passive flow control devices installed in the completion sand face to alter fluid production near the wellbore by either creating a uniform influx into the wellbore or delaying unwanted fluid breakthrough. Obikpo 33, like other wells in this reservoir, was completed with ICDs and this paper discusses the history matching of Obikpo 33 well. The objective of every history match is to accurately determine the distribution of the oil remaining in the reservoir to help predict the performance of existing and future wells. The typical reservoir model is built on a large scale and this does not typically incorporate near wellbore fine details such as the ICDs. Running a history match (HM) of the reservoir without incorporating these ICDs into the field model may lead to certain parameters being wrongly modified to match late water breakthrough and lower water production because the ICDs create a pseudo distributed productivity effect in the horizontal which alters the natural fluid flow pattern within the near wellbore region. Matching water breakthrough in this well using conventional HM techniques failed due to ICD design and segmentation not incorporated into the model. To account for this effect the ICD wellbore model is coupled with the reservoir model using a multi-segmented well modelling approach, this enabled the calculation of the additional pressure drops in each well segment arising from the varying nozzle sizes along the lateral. This achieved regulation of water influx from the reservoir boundaries and channels by automatic distribution of flux along the lateral. This approach gave excellent results in history matching of Obikpo33 and thus presented a reliable prediction tool for forecasting reservoir performance. The simulated results also confirmed that the delayed water breakthrough and lower water production observed during the production life of the well is due to the ICD nozzles installed in the completion. The presented workflow and m
{"title":"Use of ICD Wellbore Models to Improve History Match in ICD Completions","authors":"Uche Chukwunonso Ifeanyi, Onwukwe Stanley, Obah Boniface, C. Anyadiegwu, Ezinne Nneobocha","doi":"10.2118/198748-MS","DOIUrl":"https://doi.org/10.2118/198748-MS","url":null,"abstract":"\u0000 Obikpo field was discovered in the late 1960s, and since then over 40 wells have been drilled. By the end of the year 2018, more than 68 MMstb oil would have been produced from the field. Water cut has risen to over 65% and this affects performances of oil wells. The field is geologically complex, heterogeneous and divided by large faults; leading to local permeability enhancements that most times serves as barriers to uniform fluid displacement. Average gross thickness of the reservoir is about 80 ft. Recovery is mainly by the strong bottom water influx, expansion and secondary support from water injection. Obikpo fluid typically is heavy in nature resulting in poor mobility ratio which keeps the water table irregularly distributed across the sands. To improve on the recovery across Obikpo field, Inflow Control Device (ICD) technology is being utilized in all Obikpo wells to mitigate heel to toe coning effects and channeling / fingering of unwanted water into completions. Inflow Control devices are passive flow control devices installed in the completion sand face to alter fluid production near the wellbore by either creating a uniform influx into the wellbore or delaying unwanted fluid breakthrough. Obikpo 33, like other wells in this reservoir, was completed with ICDs and this paper discusses the history matching of Obikpo 33 well.\u0000 The objective of every history match is to accurately determine the distribution of the oil remaining in the reservoir to help predict the performance of existing and future wells. The typical reservoir model is built on a large scale and this does not typically incorporate near wellbore fine details such as the ICDs. Running a history match (HM) of the reservoir without incorporating these ICDs into the field model may lead to certain parameters being wrongly modified to match late water breakthrough and lower water production because the ICDs create a pseudo distributed productivity effect in the horizontal which alters the natural fluid flow pattern within the near wellbore region. Matching water breakthrough in this well using conventional HM techniques failed due to ICD design and segmentation not incorporated into the model. To account for this effect the ICD wellbore model is coupled with the reservoir model using a multi-segmented well modelling approach, this enabled the calculation of the additional pressure drops in each well segment arising from the varying nozzle sizes along the lateral. This achieved regulation of water influx from the reservoir boundaries and channels by automatic distribution of flux along the lateral. This approach gave excellent results in history matching of Obikpo33 and thus presented a reliable prediction tool for forecasting reservoir performance. The simulated results also confirmed that the delayed water breakthrough and lower water production observed during the production life of the well is due to the ICD nozzles installed in the completion. The presented workflow and m","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"293 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86442791","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}
Z. Lawan, K. Lawal, C. Ukaonu, S. Eyitayo, S. Matemilola
The global energy demand is constantly rising due to urbanisation and population growth. Consequently, the petroleum industry has been ensuring affordable supply to match demand through exploitation and production of oil and gas. Nonetheless, there is increasing drive to shift towards renewables being an energy source that is ‘inexhaustible’, while decreasing the intensity of anthropogenic greenhouse gases as well as mitigating other negative environmental impacts of hydrocarbon field development. However, this shift is a threat to the upstream sector of the petroleum industry, specifically to petroleum engineering (PE), given its potential to lower hydrocarbon demand while raising carbon taxes of oil and gas companies. Against this background, this paper takes a closer look at what lies ahead for PE in an emerging renewable energy (RE) world. It is shown that RE can be integrated into some conventional PE activities such as the use of solar energy for thermally enhanced-oil recovery and the application of its skillsets to advance the body of knowledge in geothermal engineering. Despite RE's comparative advantages, it faces challenges in energy storage and intermittency of supply. The paper examines the influence of PE in some industries that depend on its products and relevant skill sets. It also explores the interplay between PE and other apparently remote industries is explored. In conclusion, the future of PE is considered promising, though it needs to continuously re-invent itself. The reality is that it contributes not only to energy production, but many aspects of daily life. Compared to petroleum derivatives, the alternative products are yet to attain sufficient maturity for sustained large-scale utilisation. In principle, the breadth and depth of challenges that RE faces suggest that the world's dependence on PE is not likely to shift dramatically in the next couple of decades.
{"title":"The Future of Petroleum Engineering in an Emerging Renewable-Energy World","authors":"Z. Lawan, K. Lawal, C. Ukaonu, S. Eyitayo, S. Matemilola","doi":"10.2118/198743-MS","DOIUrl":"https://doi.org/10.2118/198743-MS","url":null,"abstract":"\u0000 The global energy demand is constantly rising due to urbanisation and population growth. Consequently, the petroleum industry has been ensuring affordable supply to match demand through exploitation and production of oil and gas. Nonetheless, there is increasing drive to shift towards renewables being an energy source that is ‘inexhaustible’, while decreasing the intensity of anthropogenic greenhouse gases as well as mitigating other negative environmental impacts of hydrocarbon field development. However, this shift is a threat to the upstream sector of the petroleum industry, specifically to petroleum engineering (PE), given its potential to lower hydrocarbon demand while raising carbon taxes of oil and gas companies.\u0000 Against this background, this paper takes a closer look at what lies ahead for PE in an emerging renewable energy (RE) world. It is shown that RE can be integrated into some conventional PE activities such as the use of solar energy for thermally enhanced-oil recovery and the application of its skillsets to advance the body of knowledge in geothermal engineering.\u0000 Despite RE's comparative advantages, it faces challenges in energy storage and intermittency of supply. The paper examines the influence of PE in some industries that depend on its products and relevant skill sets. It also explores the interplay between PE and other apparently remote industries is explored.\u0000 In conclusion, the future of PE is considered promising, though it needs to continuously re-invent itself. The reality is that it contributes not only to energy production, but many aspects of daily life. Compared to petroleum derivatives, the alternative products are yet to attain sufficient maturity for sustained large-scale utilisation. In principle, the breadth and depth of challenges that RE faces suggest that the world's dependence on PE is not likely to shift dramatically in the next couple of decades.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"134 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77399960","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The paper aims to highlight the importance of using adequate dynamic data to ground-truth reservoir simulation models early in the production life of a field. This study also highlights the benefits of adequate instrumentation and data capture, as well as the need to review assumptions made for green fields in their first few production years. This study reviews two vintages of probabilistic assessment for an offshore gas condensate reservoir. An earlier probabilistic assessment for the case study reservoir was built based primarily on core data from two analogous reservoirs, one of which was from the same field, prior to the availability of bottom hole pressure and drawdown data. Initial history match and forecasts showed a significantly poor production performance with significant impact on the condensate reserves volumes from the single well in the reservoir. Following the acquisition of pressure data from the downhole gauges and pressure transient analyses results, the model recalibrated in line with estimated distance to boundaries, drawdown and productivity indices. Incorporating the additional data from the downhole instrumentation during the history match showed the earth model severely underestimated the permeability of the reservoir. Matching the drawdown and well test data required a significant permeability multiplier for the low and mid case models for the reservoir. A comparison of results from both model vintages showed significant differences in the expected production plateau for the reservoir and consequently reserves estimates. These finding demonstrates value of the acquisition of multiple downhole dynamic data and the pitfalls with reservoir performance forecasts and reserves assessments when simulation models are not adequately constrained with dynamic well data early in the production life of the reservoir.
{"title":"Demonstrating the Value of Early Incorporation of Dynamic Data during Probabilistic Assessment for a Niger Delta Gas Condensate Reservoir","authors":"F. Ogbuagu, Lynn Silpngarmlers","doi":"10.2118/198830-MS","DOIUrl":"https://doi.org/10.2118/198830-MS","url":null,"abstract":"\u0000 The paper aims to highlight the importance of using adequate dynamic data to ground-truth reservoir simulation models early in the production life of a field. This study also highlights the benefits of adequate instrumentation and data capture, as well as the need to review assumptions made for green fields in their first few production years.\u0000 This study reviews two vintages of probabilistic assessment for an offshore gas condensate reservoir. An earlier probabilistic assessment for the case study reservoir was built based primarily on core data from two analogous reservoirs, one of which was from the same field, prior to the availability of bottom hole pressure and drawdown data. Initial history match and forecasts showed a significantly poor production performance with significant impact on the condensate reserves volumes from the single well in the reservoir.\u0000 Following the acquisition of pressure data from the downhole gauges and pressure transient analyses results, the model recalibrated in line with estimated distance to boundaries, drawdown and productivity indices. Incorporating the additional data from the downhole instrumentation during the history match showed the earth model severely underestimated the permeability of the reservoir. Matching the drawdown and well test data required a significant permeability multiplier for the low and mid case models for the reservoir.\u0000 A comparison of results from both model vintages showed significant differences in the expected production plateau for the reservoir and consequently reserves estimates. These finding demonstrates value of the acquisition of multiple downhole dynamic data and the pitfalls with reservoir performance forecasts and reserves assessments when simulation models are not adequately constrained with dynamic well data early in the production life of the reservoir.","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":"81615190","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}
In this study, a 3-Dimensional non-linear partial differential equation (PDE) describing flow of non-Newtonian fluid in porous media was developed for a no-flow boundary reservoir. Non-Newtonian fluid flow in porous media has direct applications in polymer flooding for secondary oil recovery operations and flow of heavy crude in the reservoir. This novel work presents the pressure behavior of horizontal wells with non-Newtonian fluid flow in porous media as well as the methodology for analyzing pressure transient data from non-Newtonian reservoirs. The main assumptions in the mathematical modeling of the differential equation are; permeability anisotropy with directional permeabilities kx, ky and kz horizontal well is in the y-direction perpendicular to direction of maximum permeability kx effects of gravity, skin and wellbore storage were neglected and the reservoir fluid was considered to be a non-Newtonian pseudo plastic fluid that obeys power law model in an isothermal condition. The derived equation was discretized using finite difference approach; A 3D numerical simulator was developed with the aid of MATLAB to solve the system of linear equations obtained from the discretization of a 15 X15 × 15 grid system to obtain pressure transient data. Type curves in terms of PwD and tD were generated for different power law flow index n ranging from 0.1 to 1 for horizontal well length of 600ft, 1000ft and 1200ft. The developed type curves in this study were validated with a Newtonian case using Tiab Direct synthesis (TDS) technique to analyze the radial flow regime for the determination of average permeability as well as the early linear flow for determining kx The results obtained from the Newtonian fluid case were very close to the actual property been determined.
{"title":"3D Numerical Modeling of Linear Flow of Non-Newtonian Fluid in Porous Media: Application to Non-Newtonian Draw-Down Pressure Transient Analysis","authors":"K. Adenuga, G. Achumba, Ebuka Ezenworo","doi":"10.2118/198848-MS","DOIUrl":"https://doi.org/10.2118/198848-MS","url":null,"abstract":"\u0000 In this study, a 3-Dimensional non-linear partial differential equation (PDE) describing flow of non-Newtonian fluid in porous media was developed for a no-flow boundary reservoir. Non-Newtonian fluid flow in porous media has direct applications in polymer flooding for secondary oil recovery operations and flow of heavy crude in the reservoir. This novel work presents the pressure behavior of horizontal wells with non-Newtonian fluid flow in porous media as well as the methodology for analyzing pressure transient data from non-Newtonian reservoirs.\u0000 The main assumptions in the mathematical modeling of the differential equation are; permeability anisotropy with directional permeabilities kx, ky and kz horizontal well is in the y-direction perpendicular to direction of maximum permeability kx effects of gravity, skin and wellbore storage were neglected and the reservoir fluid was considered to be a non-Newtonian pseudo plastic fluid that obeys power law model in an isothermal condition.\u0000 The derived equation was discretized using finite difference approach; A 3D numerical simulator was developed with the aid of MATLAB to solve the system of linear equations obtained from the discretization of a 15 X15 × 15 grid system to obtain pressure transient data. Type curves in terms of PwD and tD were generated for different power law flow index n ranging from 0.1 to 1 for horizontal well length of 600ft, 1000ft and 1200ft.\u0000 The developed type curves in this study were validated with a Newtonian case using Tiab Direct synthesis (TDS) technique to analyze the radial flow regime for the determination of average permeability as well as the early linear flow for determining kx The results obtained from the Newtonian fluid case were very close to the actual property been determined.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"40 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88462844","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. N. Adewumi, O. Achugasim, R. Ogali, O. Akaranta
Starches serve as vital raw materials in many industrial applications especially in food, textile, pharmaceutical and petroleum industries. In petroleum industry, chemically modified starches are used in water based drilling mud to enhance fluid loss and viscosity in the formation during drilling. Most starches used for these applications are obtained from food sources such as corn, potato and cassava and this affects the overall production cost. Artocarpus heterophyllus Lam (AHL) is a tropical tree with large bulb (fruit) containing pulp and seed. In Nigeria, this tree grows in the wild or homes but its fruit is not seen as a food source and thus allowed to waste. Starch was extracted from the pulp of unripe but matured AHL using wet milling method, and the extracted starch was examined for its proximate composition and physicochemical properties. Starch extraction from the unripe pulp gave a starch yield of 44.12±1.13% and the physicochemical characterization shows that the starch has high amylose content (24.09±0.11%), water absorption capacity (116±0.18%), gelatinization temperature (71°C) and the swelling power increases with increase in temperature. The thermal behavior of the starch studied with differential scanning calorimeter (DSC) demonstrated a distinguished endothermic peak with distinct onset, peak and conclusion temperatures. The scanning electron microscope (SEM) result showed that the starch granules are small sized and aggregate together with high tendency of forming network of granules. The results obtained from the physicochemical characterization of unripe AHL pulp starch shows that it has high potential for oilfield applications.
{"title":"Physicochemical Characterization of Starch from Unripe Artocarpus heterophyllus Lam Pulp as a Low-Cost Starch Source for Oilfield Applications","authors":"C. N. Adewumi, O. Achugasim, R. Ogali, O. Akaranta","doi":"10.2118/198746-MS","DOIUrl":"https://doi.org/10.2118/198746-MS","url":null,"abstract":"\u0000 Starches serve as vital raw materials in many industrial applications especially in food, textile, pharmaceutical and petroleum industries. In petroleum industry, chemically modified starches are used in water based drilling mud to enhance fluid loss and viscosity in the formation during drilling. Most starches used for these applications are obtained from food sources such as corn, potato and cassava and this affects the overall production cost. Artocarpus heterophyllus Lam (AHL) is a tropical tree with large bulb (fruit) containing pulp and seed. In Nigeria, this tree grows in the wild or homes but its fruit is not seen as a food source and thus allowed to waste. Starch was extracted from the pulp of unripe but matured AHL using wet milling method, and the extracted starch was examined for its proximate composition and physicochemical properties. Starch extraction from the unripe pulp gave a starch yield of 44.12±1.13% and the physicochemical characterization shows that the starch has high amylose content (24.09±0.11%), water absorption capacity (116±0.18%), gelatinization temperature (71°C) and the swelling power increases with increase in temperature. The thermal behavior of the starch studied with differential scanning calorimeter (DSC) demonstrated a distinguished endothermic peak with distinct onset, peak and conclusion temperatures. The scanning electron microscope (SEM) result showed that the starch granules are small sized and aggregate together with high tendency of forming network of granules. The results obtained from the physicochemical characterization of unripe AHL pulp starch shows that it has high potential for oilfield applications.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"4 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89784787","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}
Ogochukwu Benyeogor, D. Jambol, O. Amah, D. Obiga, S. Awe, A. Erinle
Managed pressure drilling (MPD) is an adaptive drilling technique used to improve the economics and to mitigate risks associated with drilling high pressure and high temperature (HPHT) exploration wells where the drilling window is often narrow. The technique involves the combination of surface back pressure and fluid hydrostatic column to provide the required bottom hole pressure for safe drilling. Typical MPD equipment spread includes rotating control device (RCD), chokes, high pressure lines and gate valves with Pressure relief valves (PRVs) incorporated. The primary purpose of the PRV is to protect the MPD surface equipment and the formation from being overpressured. The relief valve achieves this by bypassing the normal fluid flow path for MPD operations and relieving the system pressure to the rig Mud gas separator (MGS) through a dedicated line. Each time a PRV is activated the resulting loss of surface back pressure increases the risk of taking a kick. On the other hand, when a PRV is not activated, an excessive increase in surface pressure raises the risk of formation fracture leading to losses. Therefore, the performance of the PRV has an immense impact on assessing the risk of a well control situation, which may be caused by either loses due to formation breakdown and consequently a kick from loss of the hydrostatic pressure component of the equivalent surface density (ESD) or an influx as a result of loss of surface back pressure component of the ESD due to loss of integrity of surface equipment). Pressure Relief Management philosophy generally covers decisions such as which parts of the well system (surface and subsurface) are to be preferentially protected by the PRVs, selection of activation pressure for high level alarms, types, number and setpoints of PRVs in the MPD system during different phases of the drilling operations - drilling, connections and tripping, and MPD choke full-opening pressure. These values are dependent on formation integrity test (FIT), mud weight, drilling window, annular friction pressure and operating envelope of RCD. The set points require adjustment depending on the hole size and flow rate and may be different during completion and well control operations. This paper describes the Pressure Relief Management philosophy for a HPHT well drilled in the Niger delta. It looks at factors that drive the high-pressure alarm setting values, choice of PRV types, placement and the part of the well system being protected, PRV tripping and reset values, and MPD choke full opening pressures. It also describes the challenges and risk assessment that influenced the selection of set points (single or dual setpoints) for different phases of the drilling operations.
{"title":"Pressure Relief Management Philosophy for MPD Operations on Surface Stack HPHT Exploration Wells","authors":"Ogochukwu Benyeogor, D. Jambol, O. Amah, D. Obiga, S. Awe, A. Erinle","doi":"10.2118/198812-MS","DOIUrl":"https://doi.org/10.2118/198812-MS","url":null,"abstract":"\u0000 Managed pressure drilling (MPD) is an adaptive drilling technique used to improve the economics and to mitigate risks associated with drilling high pressure and high temperature (HPHT) exploration wells where the drilling window is often narrow. The technique involves the combination of surface back pressure and fluid hydrostatic column to provide the required bottom hole pressure for safe drilling. Typical MPD equipment spread includes rotating control device (RCD), chokes, high pressure lines and gate valves with Pressure relief valves (PRVs) incorporated. The primary purpose of the PRV is to protect the MPD surface equipment and the formation from being overpressured. The relief valve achieves this by bypassing the normal fluid flow path for MPD operations and relieving the system pressure to the rig Mud gas separator (MGS) through a dedicated line. Each time a PRV is activated the resulting loss of surface back pressure increases the risk of taking a kick. On the other hand, when a PRV is not activated, an excessive increase in surface pressure raises the risk of formation fracture leading to losses. Therefore, the performance of the PRV has an immense impact on assessing the risk of a well control situation, which may be caused by either loses due to formation breakdown and consequently a kick from loss of the hydrostatic pressure component of the equivalent surface density (ESD) or an influx as a result of loss of surface back pressure component of the ESD due to loss of integrity of surface equipment).\u0000 Pressure Relief Management philosophy generally covers decisions such as which parts of the well system (surface and subsurface) are to be preferentially protected by the PRVs, selection of activation pressure for high level alarms, types, number and setpoints of PRVs in the MPD system during different phases of the drilling operations - drilling, connections and tripping, and MPD choke full-opening pressure. These values are dependent on formation integrity test (FIT), mud weight, drilling window, annular friction pressure and operating envelope of RCD. The set points require adjustment depending on the hole size and flow rate and may be different during completion and well control operations.\u0000 This paper describes the Pressure Relief Management philosophy for a HPHT well drilled in the Niger delta. It looks at factors that drive the high-pressure alarm setting values, choice of PRV types, placement and the part of the well system being protected, PRV tripping and reset values, and MPD choke full opening pressures. It also describes the challenges and risk assessment that influenced the selection of set points (single or dual setpoints) for different phases of the drilling operations.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"45 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91108428","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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