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}
I. Eiroboyi, S. S. Ikiensikimama, B. Oriji, I. Okoye
The stability of polymers used in enhanced oil recovery especially in polymer flooding is largely based on their ability to withstand challenging reservoir conditions such as the effect of high salinity and high temperature. Polymers like Hydrolysed Polyacrylamide (HPAM) and its derivatives lose their viscosity when subjected to high salinity conditions due to the screening of the ions of the polymer backbone chain. HPAM is not only sensitive to salinity and temperature but also very susceptible to shear degradation. Research show that Xanthan gum; a commercial biopolymer used mostly in polymer flooding show more tolerance to shear degradation and even better stability to salinity and temperature than HPAM but not frequently used due to its high cost. The work is centered on the study of stability of some selected low cost biopolymers like Guar gum, Locust bean gum, Gum Arabic as well as the commercial Xanthan gum. This study captures the effect of monovalent and divalent ions on the polymers in order to establish their degree of stability and the impact of these ions with respect to varying salinity conditions. The rheological performance of these polymers were analysed using both NaCl and CaCl under both medium and high saline conditions which are similar to reservoir conditions. The results show that all polymers show appreciable resistance and stability when compared to Xanthan gum especially Locust bean gum in the presence of monovalent ions, Gum Arabic displayed the least tolerance to the ions. Although, the presence of divalent ions had more impact than the monovalent ions on all polymers' stability, however, higher concentrations of the polymers resulted in more resistance to the presence of these ions.
{"title":"The Effect of Monovalent and Divalent Ions on Biodegradable Polymers in Enhanced Oil Recovery","authors":"I. Eiroboyi, S. S. Ikiensikimama, B. Oriji, I. Okoye","doi":"10.2118/198788-MS","DOIUrl":"https://doi.org/10.2118/198788-MS","url":null,"abstract":"\u0000 The stability of polymers used in enhanced oil recovery especially in polymer flooding is largely based on their ability to withstand challenging reservoir conditions such as the effect of high salinity and high temperature. Polymers like Hydrolysed Polyacrylamide (HPAM) and its derivatives lose their viscosity when subjected to high salinity conditions due to the screening of the ions of the polymer backbone chain. HPAM is not only sensitive to salinity and temperature but also very susceptible to shear degradation. Research show that Xanthan gum; a commercial biopolymer used mostly in polymer flooding show more tolerance to shear degradation and even better stability to salinity and temperature than HPAM but not frequently used due to its high cost.\u0000 The work is centered on the study of stability of some selected low cost biopolymers like Guar gum, Locust bean gum, Gum Arabic as well as the commercial Xanthan gum. This study captures the effect of monovalent and divalent ions on the polymers in order to establish their degree of stability and the impact of these ions with respect to varying salinity conditions. The rheological performance of these polymers were analysed using both NaCl and CaCl under both medium and high saline conditions which are similar to reservoir conditions. The results show that all polymers show appreciable resistance and stability when compared to Xanthan gum especially Locust bean gum in the presence of monovalent ions, Gum Arabic displayed the least tolerance to the ions. Although, the presence of divalent ions had more impact than the monovalent ions on all polymers' stability, however, higher concentrations of the polymers resulted in more resistance to the presence of these ions.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"47 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73805478","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}
Understanding why incidents re-occur from similar causes despite the previous experiences, lessons and available tools to ensure that they do not happen again has been a cause of concern for company management for years and different reasons have been attributed to this issue. In recent past, below are few examples of incidents from similar causes. On 25 January 2012, during the pre-mob inspection of a pile load tester pump by a DIL pile rig operator (Mechanical-24yrs old) with his Supervisor, the unit was put under pressure three times successfully but there was no movement of the pump piston. The pump was put under pressure the fourth time with a declared pressure of 500 bars, the pile load tester flange suddenly gave way and caused several severe injuries to the operator. He was confirmed dead at around 18h30. The unit was brand new with test certificate; IP was trained for it and note that the design pressure of the pile load tester was 690bars. In addition, when the unit failed, the 25 out of 26 bolts of the flange cut off while the last one had its nut pulled out. On 15 May 2017, a fatal accident occurred when an analyzer engineer removed the cover on an explosion-proof enclosure as part of the routine task for the day. The ~5.5kg weighing threaded cover and with a 14 inches in diameter was propelled forcefully from the enclosure as the Engineer unscrewed it inflicting a fatal head injury. The pressure inside the enclosure from leaking sample gas or instrument air components caused the forceful propulsion of the enclosure cover. There was no gauge or indicator on the enclosure to monitor the internal pressure inside the enclosure and there was no means to relieve internal pressure (http://www.safteng.net/images/2017_Posts_Pics/CVXIndustryAlertJune2017.pdf).
{"title":"Occupational deaths from Similar Causes; Why?","authors":"G. Shittu","doi":"10.2118/198710-MS","DOIUrl":"https://doi.org/10.2118/198710-MS","url":null,"abstract":"\u0000 Understanding why incidents re-occur from similar causes despite the previous experiences, lessons and available tools to ensure that they do not happen again has been a cause of concern for company management for years and different reasons have been attributed to this issue. In recent past, below are few examples of incidents from similar causes.\u0000 On 25 January 2012, during the pre-mob inspection of a pile load tester pump by a DIL pile rig operator (Mechanical-24yrs old) with his Supervisor, the unit was put under pressure three times successfully but there was no movement of the pump piston. The pump was put under pressure the fourth time with a declared pressure of 500 bars, the pile load tester flange suddenly gave way and caused several severe injuries to the operator. He was confirmed dead at around 18h30. The unit was brand new with test certificate; IP was trained for it and note that the design pressure of the pile load tester was 690bars. In addition, when the unit failed, the 25 out of 26 bolts of the flange cut off while the last one had its nut pulled out.\u0000 On 15 May 2017, a fatal accident occurred when an analyzer engineer removed the cover on an explosion-proof enclosure as part of the routine task for the day. The ~5.5kg weighing threaded cover and with a 14 inches in diameter was propelled forcefully from the enclosure as the Engineer unscrewed it inflicting a fatal head injury. The pressure inside the enclosure from leaking sample gas or instrument air components caused the forceful propulsion of the enclosure cover. There was no gauge or indicator on the enclosure to monitor the internal pressure inside the enclosure and there was no means to relieve internal pressure (http://www.safteng.net/images/2017_Posts_Pics/CVXIndustryAlertJune2017.pdf).","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"192 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73337342","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A. Ekebafe, Ezeokafor Tobechukwu, Ololade T. Skaioye, Lawani Raymond
The AX field is located in Deepwater Offshore Nigeria and has been in production for ca.12 years through FPSO with a waterflood scheme providing pressure maintenance and sweep for the reservoirs. Over the years, AX field has moved from the use of deviated frac-pack injectors to horizontal SAS injectors due to significant declining injectivity observed with the deviated injectors. The switch to horizontal injectors was premised on various studies proposing that horizontal water injectors in deep water are expected to have longer well life due to the larger flow area and ability to inject at lower flow velocities (matrix condition) compared to vertical water injectors. The benefits of going horizontal is further enhanced by keeping the well in Matrix mode for as long as possible before switching into frac mode. However, damage is inevitable afterwards, even for relatively clean injection water. This may be primarily due to various factors, one of which is fines influx into the well during abrupt shut-ins/trips from the FPSO. AX field started operating horizontal injectors since 2011. On the average, most horiziontal injectors in AX field begin to experience injectvty decline about 1 – 2 yrs after start of injection as was the case with AX9 injector. AX9 is a horizontal injector providing support to 2 producers in the field. Over the past four years injection had declined from 40 kbwpd to 21 kbwpd at 395 barg IBHP with II of 20 bpd/psi. This drop in the injectivity index led to a production curtailment of ca. 5 kbopd from the supported producers. From a cross learning opportunity, it was identified that there is higher possibility of success (POS) with stimulating horizontal water injectors while still in matrix mode. Leveraging on this knowledge we decided to attempt stimulating the AX9 well for better performance. Stimulation was carried out successfully under matrix condition using a deepwater rig in May 2018. Post stimulation, well was ramped up to 43 kbpwd at 330 barg IBHP. Increase of ca. 15 kbwpd with a corresponding 21% drop in BHP. Initial performance shows a four-fold improvement in injectivity index; current injectivity index is 80 – 100 bpd/psi. The success of the AX9 stimulation has validated early stimulation of injectors while still in matrix mode rather than later when the well would have switched to frac mode. Additionally, the acid recipe has opened opportunities to mitigating injectivity decline in deepwater water injectors.
{"title":"Horizontal Matrix Injector Stimulation in Unconsolidated Sand","authors":"A. Ekebafe, Ezeokafor Tobechukwu, Ololade T. Skaioye, Lawani Raymond","doi":"10.2118/198807-MS","DOIUrl":"https://doi.org/10.2118/198807-MS","url":null,"abstract":"\u0000 The AX field is located in Deepwater Offshore Nigeria and has been in production for ca.12 years through FPSO with a waterflood scheme providing pressure maintenance and sweep for the reservoirs. Over the years, AX field has moved from the use of deviated frac-pack injectors to horizontal SAS injectors due to significant declining injectivity observed with the deviated injectors.\u0000 The switch to horizontal injectors was premised on various studies proposing that horizontal water injectors in deep water are expected to have longer well life due to the larger flow area and ability to inject at lower flow velocities (matrix condition) compared to vertical water injectors. The benefits of going horizontal is further enhanced by keeping the well in Matrix mode for as long as possible before switching into frac mode. However, damage is inevitable afterwards, even for relatively clean injection water. This may be primarily due to various factors, one of which is fines influx into the well during abrupt shut-ins/trips from the FPSO.\u0000 AX field started operating horizontal injectors since 2011. On the average, most horiziontal injectors in AX field begin to experience injectvty decline about 1 – 2 yrs after start of injection as was the case with AX9 injector.\u0000 AX9 is a horizontal injector providing support to 2 producers in the field. Over the past four years injection had declined from 40 kbwpd to 21 kbwpd at 395 barg IBHP with II of 20 bpd/psi. This drop in the injectivity index led to a production curtailment of ca. 5 kbopd from the supported producers.\u0000 From a cross learning opportunity, it was identified that there is higher possibility of success (POS) with stimulating horizontal water injectors while still in matrix mode. Leveraging on this knowledge we decided to attempt stimulating the AX9 well for better performance.\u0000 Stimulation was carried out successfully under matrix condition using a deepwater rig in May 2018. Post stimulation, well was ramped up to 43 kbpwd at 330 barg IBHP. Increase of ca. 15 kbwpd with a corresponding 21% drop in BHP. Initial performance shows a four-fold improvement in injectivity index; current injectivity index is 80 – 100 bpd/psi.\u0000 The success of the AX9 stimulation has validated early stimulation of injectors while still in matrix mode rather than later when the well would have switched to frac mode. Additionally, the acid recipe has opened opportunities to mitigating injectivity decline in deepwater water injectors.","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":"75413001","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 discusses the effect of crude oil price fluctuation on the personnel, projects and finances of oil & gas exploration and producing companies, as well as, the cost optimization efforts carried out during the era of lowcrude oil price. Following investigation and historical data, it is evident that crude oil price fluctuation is cyclical in nature. To make their product available for sale, oil & gas organizations, at the peak of the crude oil cycle engage in high operating-cost systems. With drastic fall in the price of the product, as experienced between July 2014 and February 2015, such organizations were faced with the challenge of continuing production at a non-profitable cost. Crude oil price fall, have always had a big negative impact on the personnel, projects and operations of organizations in the Nigerian oil and gas industry. For personnel, the most prevalent impact was the loss of jobs, for company operations it was the reduction in revenue (income) for the companies and for projects it was the delay or cancellation of projects earlier considered profitable. These losses or delay of projects led to reduction in product portfolio and/or divestments for the organizations involved. For the Nigerian oil and gas companies to adapt to the economic changes occasioned by the change in price, several measures have been proposed which include individual companies initiating and utilizing procedures that ensure good costing of projects, benchmarking of relevant prices and promoting good costing practices and proper management of balance sheet and adhering strongly to sustainable OPEX and CAPEX levels, to ensure opportunities are identified and utilized. The researchers asserts that crude oil price fall with its attendant negative impact could be scientifically explained. A quantitative research methodology has been applied in the study of this topic. Using online survey, information has been gathered from respondents from six different oil and gas companies indicating their demography, individual experience, companies experience and project experience during the last crude oil price fall (2014 -2017). Secondary data obtained from historical records helped to show the influence of crude price slump on the financial health status of oil and gas exploration and producing companies. The data also helped to confirm the primary data received in the online survey.
{"title":"Paper Hedging Against Cyclical Crude Oil Price Fluctuations: Cost Optimization Initiatives for the Nigerian Oil & Gas Industry","authors":"J. Ugolo, Debo Fagbami, M. Iwegbu","doi":"10.2118/198808-MS","DOIUrl":"https://doi.org/10.2118/198808-MS","url":null,"abstract":"\u0000 This paper discusses the effect of crude oil price fluctuation on the personnel, projects and finances of oil & gas exploration and producing companies, as well as, the cost optimization efforts carried out during the era of lowcrude oil price. Following investigation and historical data, it is evident that crude oil price fluctuation is cyclical in nature. To make their product available for sale, oil & gas organizations, at the peak of the crude oil cycle engage in high operating-cost systems. With drastic fall in the price of the product, as experienced between July 2014 and February 2015, such organizations were faced with the challenge of continuing production at a non-profitable cost.\u0000 Crude oil price fall, have always had a big negative impact on the personnel, projects and operations of organizations in the Nigerian oil and gas industry. For personnel, the most prevalent impact was the loss of jobs, for company operations it was the reduction in revenue (income) for the companies and for projects it was the delay or cancellation of projects earlier considered profitable. These losses or delay of projects led to reduction in product portfolio and/or divestments for the organizations involved.\u0000 For the Nigerian oil and gas companies to adapt to the economic changes occasioned by the change in price, several measures have been proposed which include individual companies initiating and utilizing procedures that ensure good costing of projects, benchmarking of relevant prices and promoting good costing practices and proper management of balance sheet and adhering strongly to sustainable OPEX and CAPEX levels, to ensure opportunities are identified and utilized.\u0000 The researchers asserts that crude oil price fall with its attendant negative impact could be scientifically explained. A quantitative research methodology has been applied in the study of this topic. Using online survey, information has been gathered from respondents from six different oil and gas companies indicating their demography, individual experience, companies experience and project experience during the last crude oil price fall (2014 -2017). Secondary data obtained from historical records helped to show the influence of crude price slump on the financial health status of oil and gas exploration and producing companies. The data also helped to confirm the primary data received in the online survey.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"284 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76845183","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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