Following the last couple of years marked by a drop-in oil price, there has been a requirement to optimize costs for operating and maintaining existing and ageing facilities and equipment and Water disposal wells are no exception. Case study considered onshore wells which were initially completed as oil producing wells in the mid-1970s to early 1980s and in their later life converted for water disposal after the Ultimate Recovery (UR) of the associated reservoirs had been reached and produced water injectivity for wells positively ascertained. The need to initiate this method of produced water management was to ensure its proper and efficient disposal in line with best practices, government regulations and associated cost efficiencies. As these wells stay long in service, they witness several impairments that affect their injectivity. These impairments amongst others include oil slippages, suspended solids, fine sand, corrosion products, microbial activity and carbonate scale particles. These in turn create blockage around perforations which reduce the effective path area for movement of water molecules into subject reservoirs. One of the key actions in maintaining ‘old’ water injection wells is periodic chemical treatment to ensure optimal injectivity. Chemical treatments maybe conducted routinely as a preventive and corrective maintenance activity. As a view to optimising costs we looked to change this to a "Just-in-time" treatment philosophy to manage its overall impact on operating costs and schedule for execution. A surveillance program was developed for older water injection wells which do not have sophisticated sub surface gauges, by relying on surface parameters and associated equipment condition monitoring to schedule chemical treatments for the water injection wells. Some of the surface parameters that was utilized are Water Injection Pump Discharge Pressures, Injection Tubing Head Pressure (ITHP), Injection Flow Line Pressure (IFLP). Following analysis, an empirical system has been developed that enables the prediction for chemical injection treatment without the need to conduct sub-surface investigations using Coil Tubing equipment. This paper discusses a simple, cost effective and easy to use methodology which can be adopted as a first step towards ensuring the adequacy of water injection surveillance program.
{"title":"Utilizing Surface Parameters in Determining Periodic Chemical Injection Treatment Intervals for Aged Water Disposal Wells","authors":"O. Onwuemene, Happiness Deele, O. Numbere","doi":"10.2118/198711-MS","DOIUrl":"https://doi.org/10.2118/198711-MS","url":null,"abstract":"\u0000 Following the last couple of years marked by a drop-in oil price, there has been a requirement to optimize costs for operating and maintaining existing and ageing facilities and equipment and Water disposal wells are no exception.\u0000 Case study considered onshore wells which were initially completed as oil producing wells in the mid-1970s to early 1980s and in their later life converted for water disposal after the Ultimate Recovery (UR) of the associated reservoirs had been reached and produced water injectivity for wells positively ascertained.\u0000 The need to initiate this method of produced water management was to ensure its proper and efficient disposal in line with best practices, government regulations and associated cost efficiencies.\u0000 As these wells stay long in service, they witness several impairments that affect their injectivity. These impairments amongst others include oil slippages, suspended solids, fine sand, corrosion products, microbial activity and carbonate scale particles. These in turn create blockage around perforations which reduce the effective path area for movement of water molecules into subject reservoirs.\u0000 One of the key actions in maintaining ‘old’ water injection wells is periodic chemical treatment to ensure optimal injectivity. Chemical treatments maybe conducted routinely as a preventive and corrective maintenance activity.\u0000 As a view to optimising costs we looked to change this to a \"Just-in-time\" treatment philosophy to manage its overall impact on operating costs and schedule for execution. A surveillance program was developed for older water injection wells which do not have sophisticated sub surface gauges, by relying on surface parameters and associated equipment condition monitoring to schedule chemical treatments for the water injection wells. Some of the surface parameters that was utilized are Water Injection Pump Discharge Pressures, Injection Tubing Head Pressure (ITHP), Injection Flow Line Pressure (IFLP).\u0000 Following analysis, an empirical system has been developed that enables the prediction for chemical injection treatment without the need to conduct sub-surface investigations using Coil Tubing equipment.\u0000 This paper discusses a simple, cost effective and easy to use methodology which can be adopted as a first step towards ensuring the adequacy of water injection surveillance program.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"2 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80844581","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}
About 83% of energy used to generate power in Nigeria is currently derived from gas. This is understandable since the country has huge volumes of gas resources which it intends to take advantage of to grow its economy. Nigeria's gas reserves stands at 199 Tcf as at 01/01/2018 (Department of Petroleum Resources Annual Reserves and Production Report). Gas is the preferred source of energy because of the following; Efficiency in energy generationRelatively low per capita costMeans of eliminating gas flaresIncome generation earner for stakeholderOpportunity for additional job creation Several gas development projects have been embarked upon within the Nigerian Oil and Gas industry to deliver gas to the domestic sector. The Nigerian domestic gas sector is classified into the following three (3) sectors as contained in the Nigerian Gas Master Plan (NGMP); Power – Independent Power Plants (IPPs) e.t.cCommercial – Industries utilizing gas as fuel e.g. Cement PlantsGas Based Industry – Industries utilizing gas as feedstock e.g. Fertilizer Plants Presently, twenty five (25) gas fired plants with a combined installed capacity of about 11,500 MW exist in country. The total gas requirement to run all the plants at full capacity is approximately 3.0Bscfd. Between 2018 and 2037, it is expected that fifty five (55) additional thermal plants will come on stream (Transmission Company of Nigeria Transmission Masterplan). These plants will generate an additional combined power of 19,000 MW and will require gas volumes of approximately 5Bscf/d to generate the power equivalent. As the country's gas reserves are growing, gas production has increased over the years. A current total gas volume of about 8Bscfd is being produced in Nigeria out of which 45% is exported (NLNG), 8.5% is flared, 15% is consumed domestically (Power & Industries) while the balance is either re-injected for pressure maintenance or utilized for operational purposes. The gas to power value chain has been bedeviled by issues which have affected the full generation of power based on installed capacity of existing gas fired power plants. Major among the issues are; Lack of sufficient power transmission capacity from the power generating plantsOff Spec gas volumes supplied to power generating plantsLegacy Debt repayment and payment for gas supplyInadequate gas transportation infrastructureWeak payment structure within the power value chainFunding constraints for development of upstream gas supply sourcesDiffering priorities between upstream gas developersAbsence or ineffective contractual terms between stakeholder parties Steps are being taken to address these issues. Alongside the development of Power Plants, Gas Transportation and Power Transmission Infrastructure are also being developed according to laid down Master Plans. To achieve the ultimate objective of power generation to meet the country's domestic needs, there is a need for alignment on existing master plans within the gas and power
{"title":"Gas to Power: Generating Power to Meet Nigeria's Domestic Needs","authors":"Salahuddeen M. Tahir, Ali Sheriff","doi":"10.2118/198768-MS","DOIUrl":"https://doi.org/10.2118/198768-MS","url":null,"abstract":"\u0000 About 83% of energy used to generate power in Nigeria is currently derived from gas. This is understandable since the country has huge volumes of gas resources which it intends to take advantage of to grow its economy. Nigeria's gas reserves stands at 199 Tcf as at 01/01/2018 (Department of Petroleum Resources Annual Reserves and Production Report). Gas is the preferred source of energy because of the following; Efficiency in energy generationRelatively low per capita costMeans of eliminating gas flaresIncome generation earner for stakeholderOpportunity for additional job creation\u0000 Several gas development projects have been embarked upon within the Nigerian Oil and Gas industry to deliver gas to the domestic sector. The Nigerian domestic gas sector is classified into the following three (3) sectors as contained in the Nigerian Gas Master Plan (NGMP); Power – Independent Power Plants (IPPs) e.t.cCommercial – Industries utilizing gas as fuel e.g. Cement PlantsGas Based Industry – Industries utilizing gas as feedstock e.g. Fertilizer Plants\u0000 Presently, twenty five (25) gas fired plants with a combined installed capacity of about 11,500 MW exist in country. The total gas requirement to run all the plants at full capacity is approximately 3.0Bscfd. Between 2018 and 2037, it is expected that fifty five (55) additional thermal plants will come on stream (Transmission Company of Nigeria Transmission Masterplan). These plants will generate an additional combined power of 19,000 MW and will require gas volumes of approximately 5Bscf/d to generate the power equivalent.\u0000 As the country's gas reserves are growing, gas production has increased over the years. A current total gas volume of about 8Bscfd is being produced in Nigeria out of which 45% is exported (NLNG), 8.5% is flared, 15% is consumed domestically (Power & Industries) while the balance is either re-injected for pressure maintenance or utilized for operational purposes.\u0000 The gas to power value chain has been bedeviled by issues which have affected the full generation of power based on installed capacity of existing gas fired power plants. Major among the issues are; Lack of sufficient power transmission capacity from the power generating plantsOff Spec gas volumes supplied to power generating plantsLegacy Debt repayment and payment for gas supplyInadequate gas transportation infrastructureWeak payment structure within the power value chainFunding constraints for development of upstream gas supply sourcesDiffering priorities between upstream gas developersAbsence or ineffective contractual terms between stakeholder parties\u0000 Steps are being taken to address these issues. Alongside the development of Power Plants, Gas Transportation and Power Transmission Infrastructure are also being developed according to laid down Master Plans. To achieve the ultimate objective of power generation to meet the country's domestic needs, there is a need for alignment on existing master plans within the gas and power","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"214 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75570210","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 outcome of the Technological Risk Assessment is the major risk register that contains all the major incident scenarios including the top ten scenarios and their corresponding barriers towards prevention, control & mitigation of potential consequences. The expected result of an effective Barrier Risk Management is to reduce and or minimize the possibility of a major process safety incident happening due to weaknesses developed in these barriers and ensuring that all the necessary mitigation and mechanisms are robust enough and in place should an incident happen. Are our Barrier risk assessment for process safety accidents properly assessed with adequate barriers defined to prevent the occurrence of major incidents? This means that, the assurance of Process Safety is defined on the basics that all our Safety Critical Barriers (SCBs) are clearly understood, by knowing what our critical controls are, assessing and monitoring their health status in our day-to-day operations towards ensuring that they are functionally available on demand to prevent, mitigate and control process safety incidents. This Paper in detail, will describe the operationalization of the Bow Tie Barrier Risk management, beginning with the Identification of Safety Critical Barriers for operating plants in an integrated approach, defining potential threats from major accident scenarios, its effects and their barriers in one holistic view with the BowTie, act as a line of sight for individual barrier performance management, action plans and improvement. Converting the BowTie from a static to a dynamic barrier management tool by identifying any missing or possible degraded barriers and manage corrective actions implementation, plug in other operational elements such as incidents, audits, inspections, change management and safety and inspections information to create relationship between the barriers and any operational disturbances.
{"title":"Effective Barrier Risk Management in Process Safety Utilizing the Bow Tie Methodology","authors":"D. Abia, M. Iwegbu, C. Onofeghara, I. Anozie","doi":"10.2118/198853-MS","DOIUrl":"https://doi.org/10.2118/198853-MS","url":null,"abstract":"\u0000 The outcome of the Technological Risk Assessment is the major risk register that contains all the major incident scenarios including the top ten scenarios and their corresponding barriers towards prevention, control & mitigation of potential consequences. The expected result of an effective Barrier Risk Management is to reduce and or minimize the possibility of a major process safety incident happening due to weaknesses developed in these barriers and ensuring that all the necessary mitigation and mechanisms are robust enough and in place should an incident happen. Are our Barrier risk assessment for process safety accidents properly assessed with adequate barriers defined to prevent the occurrence of major incidents?\u0000 This means that, the assurance of Process Safety is defined on the basics that all our Safety Critical Barriers (SCBs) are clearly understood, by knowing what our critical controls are, assessing and monitoring their health status in our day-to-day operations towards ensuring that they are functionally available on demand to prevent, mitigate and control process safety incidents.\u0000 This Paper in detail, will describe the operationalization of the Bow Tie Barrier Risk management, beginning with the Identification of Safety Critical Barriers for operating plants in an integrated approach, defining potential threats from major accident scenarios, its effects and their barriers in one holistic view with the BowTie, act as a line of sight for individual barrier performance management, action plans and improvement. Converting the BowTie from a static to a dynamic barrier management tool by identifying any missing or possible degraded barriers and manage corrective actions implementation, plug in other operational elements such as incidents, audits, inspections, change management and safety and inspections information to create relationship between the barriers and any operational disturbances.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"3 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86394680","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}
Over the years, oil and gas companies in Nigeria have adopted several policy approaches to corporate social responsibility (CSR) to complement their stakeholder relations strategy. These include corporate philanthropy, strategic CSR as well as partnership schemes. Some companies have also gone further to demonstrate significant commitment and interest for CSR delivery by increasing their expenditure on CSR. To derive maximum value, companies need to report with certainty, the direct and indirect impact of their contributions to sustainable development. Yet, there are challenges in determining the actual impact and outcomes of CSR initiatives, and reporting same to internal and external stakeholders, without greenwashing. Many CSR projects have been known to fail shortly after completion and handing over to beneficiaries. This is partly due to initial failure to incorporate a robust set of sustainability criteria into the design and implementation process. On the other hand, attempts to measure project impacts after completion sometimes do not yield the desired results for effective CSR communication due to deployment of poorly designed methodology for data collection and analysis. This paper provides guidance on sustainability assurance and evaluation criteria which can assist companies to move beyond the annual reporting on the number of completed projects and amount of money spent (i.e. quantity delivered), to telling the story of the impact of projects on beneficiaries as well as the macroeconomic, social and environmental effects (i.e. quality and value-added). The paper concludes that the knowledge and full understanding of the impacts and effects of completed community development projects are crucial inputs for effective CSR communication as well as lessons for the planning and delivery of subsequent projects.
{"title":"Sustainability Assurance and Evaluation for Effective Corporate Social Responsibility Communication","authors":"E. Uwem","doi":"10.2118/198776-MS","DOIUrl":"https://doi.org/10.2118/198776-MS","url":null,"abstract":"\u0000 Over the years, oil and gas companies in Nigeria have adopted several policy approaches to corporate social responsibility (CSR) to complement their stakeholder relations strategy. These include corporate philanthropy, strategic CSR as well as partnership schemes. Some companies have also gone further to demonstrate significant commitment and interest for CSR delivery by increasing their expenditure on CSR. To derive maximum value, companies need to report with certainty, the direct and indirect impact of their contributions to sustainable development. Yet, there are challenges in determining the actual impact and outcomes of CSR initiatives, and reporting same to internal and external stakeholders, without greenwashing. Many CSR projects have been known to fail shortly after completion and handing over to beneficiaries. This is partly due to initial failure to incorporate a robust set of sustainability criteria into the design and implementation process. On the other hand, attempts to measure project impacts after completion sometimes do not yield the desired results for effective CSR communication due to deployment of poorly designed methodology for data collection and analysis. This paper provides guidance on sustainability assurance and evaluation criteria which can assist companies to move beyond the annual reporting on the number of completed projects and amount of money spent (i.e. quantity delivered), to telling the story of the impact of projects on beneficiaries as well as the macroeconomic, social and environmental effects (i.e. quality and value-added). The paper concludes that the knowledge and full understanding of the impacts and effects of completed community development projects are crucial inputs for effective CSR communication as well as lessons for the planning and delivery of subsequent projects.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"6 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85995104","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}
Simulation studies are often conducted on single-reservoir levels even though hydrocarbon accumulations hardly occur in isolation. However, it is sometimes beneficial to conduct studies on multiple reservoirs to evaluate opportunities in the sequence simultaneously. This can help to optimize the development plan by enabling the combination of opportunities with multiple strings and providing an avenue to evaluate interactions among reservoirs. Where these interactions exist, they can be critical parameters in the simulation history matching process1. This approach was used in the simulation studies of five reservoirs across two fields (Field_A & Field_B). Collaboration among an interdisciplinary team helped to overcome challenges in the history matching process, especially regarding a recent observation that one reservoir was exhibiting an increasing reservoir pressure while on production with no water injection. The learnings/insights from the study were used to improve field management of reservoirs with water injection, optimize base production, and identify five development opportunities with a proposed incremental recovery of 15 MMBO.
{"title":"Integrated Static/Dynamic Modeling of Reservoir Stack Helps to Resolve History Match Challenge and Identify New Drill Opportunities","authors":"N. Yusuf, P. Bovet, Lynn Silpngarmlers","doi":"10.2118/198850-MS","DOIUrl":"https://doi.org/10.2118/198850-MS","url":null,"abstract":"\u0000 Simulation studies are often conducted on single-reservoir levels even though hydrocarbon accumulations hardly occur in isolation. However, it is sometimes beneficial to conduct studies on multiple reservoirs to evaluate opportunities in the sequence simultaneously. This can help to optimize the development plan by enabling the combination of opportunities with multiple strings and providing an avenue to evaluate interactions among reservoirs. Where these interactions exist, they can be critical parameters in the simulation history matching process1.\u0000 This approach was used in the simulation studies of five reservoirs across two fields (Field_A & Field_B). Collaboration among an interdisciplinary team helped to overcome challenges in the history matching process, especially regarding a recent observation that one reservoir was exhibiting an increasing reservoir pressure while on production with no water injection. The learnings/insights from the study were used to improve field management of reservoirs with water injection, optimize base production, and identify five development opportunities with a proposed incremental recovery of 15 MMBO.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"56 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86925856","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. Kuku, Mobolaji Omotayo-Johnson, O. Achinivu, Oluwabiyi Awotiku, Akomeno Oyegwa
Spring Field was discovered in 1963 and started production in 1965. Waterflooding began in 1999 in one reservoir and has subsequently expanded to nine reservoirs to date. Waterflooding in the Spring Field is basically a peripheral water injection system with the use of brackish water as injection water. Waterflooding in Spring Field has been instrumental in "arresting" base decline, sustaining and re-pressurization of depleted reservoirs. There are currently 29 active producing reservoirs in the Spring Field with waterflooded reservoirs accounting for ~ 63% of current oil Production and ~ 52% of the estimated ultimate recovery (EUR). The management of waterflood systems can most often be quite challenging with Spring Field not being an exception. Waterflood challenges observed in Spring Field include both surface and subsurface issues such as non- uniform volumetric sweep due to complex reservoir architecture (Compartmentalized/ Multi-lobed Reservoirs), long fill-up time due to late startup of water injection, unbalanced Injectivity, out of zone injection, injection pumps reliability to mention a few. Managing and resolving these issues would therefore require a systematic and logical structured approach to ascertain the "health" of the Waterflood system in place with the overall objective of improving its efficiency, hence the purpose for this paper. This paper focuses on the use of the Surveillance, Analysis and Optimization (SA&O) workflow processes in the management of the water flood system currently in place in the Spring Field. The paper also highlights examples where this workflow process has helped in identifying gaps and optimization opportunities in the Spring Field. The Surveillance, Analysis and Optimization process include the following: ➢Surveillance- Acquisition of necessary data from multiple sources.➢Analysis- Review/ Interpretation of acquired data using various diagnostic tools. For ease of Analysis and Reviews, this element is subdivided into three distinct categories:● Health Check Category● Predictive Category● Problem Identification Category➢Optimization- Recommended corrective actions and efforts carried out to improve Waterflood efficiency based on observations from various analysis.
{"title":"Waterflood Management in Spring Field","authors":"A. Kuku, Mobolaji Omotayo-Johnson, O. Achinivu, Oluwabiyi Awotiku, Akomeno Oyegwa","doi":"10.2118/198810-MS","DOIUrl":"https://doi.org/10.2118/198810-MS","url":null,"abstract":"Spring Field was discovered in 1963 and started production in 1965. Waterflooding began in 1999 in one reservoir and has subsequently expanded to nine reservoirs to date. Waterflooding in the Spring Field is basically a peripheral water injection system with the use of brackish water as injection water. Waterflooding in Spring Field has been instrumental in \"arresting\" base decline, sustaining and re-pressurization of depleted reservoirs. There are currently 29 active producing reservoirs in the Spring Field with waterflooded reservoirs accounting for ~ 63% of current oil Production and ~ 52% of the estimated ultimate recovery (EUR). The management of waterflood systems can most often be quite challenging with Spring Field not being an exception. Waterflood challenges observed in Spring Field include both surface and subsurface issues such as non- uniform volumetric sweep due to complex reservoir architecture (Compartmentalized/ Multi-lobed Reservoirs), long fill-up time due to late startup of water injection, unbalanced Injectivity, out of zone injection, injection pumps reliability to mention a few. Managing and resolving these issues would therefore require a systematic and logical structured approach to ascertain the \"health\" of the Waterflood system in place with the overall objective of improving its efficiency, hence the purpose for this paper. This paper focuses on the use of the Surveillance, Analysis and Optimization (SA&O) workflow processes in the management of the water flood system currently in place in the Spring Field. The paper also highlights examples where this workflow process has helped in identifying gaps and optimization opportunities in the Spring Field. The Surveillance, Analysis and Optimization process include the following: ➢Surveillance- Acquisition of necessary data from multiple sources.➢Analysis- Review/ Interpretation of acquired data using various diagnostic tools. For ease of Analysis and Reviews, this element is subdivided into three distinct categories:● Health Check Category● Predictive Category● Problem Identification Category➢Optimization- Recommended corrective actions and efforts carried out to improve Waterflood efficiency based on observations from various analysis.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"33 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77404199","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 presents a comparative analysis of economics of a commercial gas pipeline using the extant fixed tariff and a calculated tariff based on the Rate of Return Regulation framework. While the extant tariff is fixed at 0.8$/Mscf irrespective of throughput and location, the calculated tariff adjusts tariff levels to cost profiles and aligns it with the operators cost of capital. The arbitrarily fixed gas pipeline tariff has resulted in poor response by international investors to an otherwise lucrative sector of the gas industry while increasing the burden of a pipeline development on government in the face of limited resources. Using the proposed 48" x 127-Kilometer Obiafu-Obrikom-Oben Pipeline (OB3) as a case study, the discounted cashflow and stochastic analysis methodology are adopted to estimate economic indicators. Results show that the payback period is very attractive at less than 6.5 years for the calculated tariff while the payback period is in excess of 7.7 years for the extant tariff. NPV of the calculated tariff indicate a less likely than not chance of project failure while analysis with the extant tariff indicates a 23 percent likelihood of project failure. The paper provides additive information needed for would-be investors and the Nigerian government towards ensuring a workable framework to engender the envisaged infrastructure for gas pipeline.
{"title":"Comparative Analysis of Commercial Natural Gas Pipeline Economics under the Extant and Calculated Tariff Systems","authors":"A.D. Adejumo, O. Iledare, J. Echendu","doi":"10.2118/198736-MS","DOIUrl":"https://doi.org/10.2118/198736-MS","url":null,"abstract":"\u0000 This paper presents a comparative analysis of economics of a commercial gas pipeline using the extant fixed tariff and a calculated tariff based on the Rate of Return Regulation framework. While the extant tariff is fixed at 0.8$/Mscf irrespective of throughput and location, the calculated tariff adjusts tariff levels to cost profiles and aligns it with the operators cost of capital. The arbitrarily fixed gas pipeline tariff has resulted in poor response by international investors to an otherwise lucrative sector of the gas industry while increasing the burden of a pipeline development on government in the face of limited resources. Using the proposed 48\" x 127-Kilometer Obiafu-Obrikom-Oben Pipeline (OB3) as a case study, the discounted cashflow and stochastic analysis methodology are adopted to estimate economic indicators. Results show that the payback period is very attractive at less than 6.5 years for the calculated tariff while the payback period is in excess of 7.7 years for the extant tariff. NPV of the calculated tariff indicate a less likely than not chance of project failure while analysis with the extant tariff indicates a 23 percent likelihood of project failure. The paper provides additive information needed for would-be investors and the Nigerian government towards ensuring a workable framework to engender the envisaged infrastructure for gas pipeline.","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":"85585706","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 investigates the effect of pressure surge referred to as "water hammer" on the formation as a result of shut - in procedure. Two methods are generally used to shut – in the well when kick is experienced: a soft shut – in or a hard shut – in. It is generally believed that when a well is hard shut – in, the additional surge pressure is capable of fracturing the formation creating a big issue in well pressure control. Hence, most operators advise against the use of this procedure. Drill sim 50 was used to simulate various kick sizes ranging from 2bbls to 20bbls and the resultant pressure surge due to water hammer was calculated and added. The result obtained indicated that soft shut – in procedure allows additional influx that increases the pressure on the formation while hard shut – in reduces the additional influx thereby reduces the possibility of formation breakdown. For all the kick sizes considered, the BHP for hard shut – in with additional pressure surge due to water hammer effect was not up to formation fracture pressure of the various depths considered. The paper concludes that more time will be saved to prevent additional influx if hard shut – in procedure is adopted especially in an onshore location of Niger Delta on which the simulation studies was carried out.
{"title":"Well Control: Hard or Soft Shut-In, The Onshore Experience","authors":"Ephraim O. Ogunyemi","doi":"10.2118/198866-MS","DOIUrl":"https://doi.org/10.2118/198866-MS","url":null,"abstract":"\u0000 This paper investigates the effect of pressure surge referred to as \"water hammer\" on the formation as a result of shut - in procedure. Two methods are generally used to shut – in the well when kick is experienced: a soft shut – in or a hard shut – in. It is generally believed that when a well is hard shut – in, the additional surge pressure is capable of fracturing the formation creating a big issue in well pressure control. Hence, most operators advise against the use of this procedure. Drill sim 50 was used to simulate various kick sizes ranging from 2bbls to 20bbls and the resultant pressure surge due to water hammer was calculated and added. The result obtained indicated that soft shut – in procedure allows additional influx that increases the pressure on the formation while hard shut – in reduces the additional influx thereby reduces the possibility of formation breakdown. For all the kick sizes considered, the BHP for hard shut – in with additional pressure surge due to water hammer effect was not up to formation fracture pressure of the various depths considered.\u0000 The paper concludes that more time will be saved to prevent additional influx if hard shut – in procedure is adopted especially in an onshore location of Niger Delta on which the simulation studies was carried out.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"17 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75112015","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}
O. Oladunni, Leste O. Aihevba, Richard Dokubo, Ayopo Kudayisi, Muaz Obadaki, C. Eze, Modestus Eze, Chika Ibama
Well Intervention operations are carried out to improve production performance of a declining well, restore production to a well that quit, or improve well integrity, among other reasons. Well bore clean out and stimulation are two of the common well intervention operations done on producing oil and gas wells to improve performance. Well AA, a major oil and gas producer started to decline after three years of production, therefore a well bore clean out and stimulation exercise was designed to improve performance of the well. The first Intervention operation was planned after various crude sample and precipitate analysis reports showed organic deposits (wax and asphaltenes) in the well. Slickline drift also indicated a restriction in the tubing. The treatment recipe for the well intervention was designed based on laboratory test carried out on the crude and precipitate sample that showed an 85% dissolution of the organic deposits in Xylene and 55% dissolution in Solution Z (a mixture of Xylene and HCL). The 85% dissolution was considered adequate to ensure a complete wellbore clean out, with Solution Z planned as the contingent treatment recipe for any solid deposits not dissolved by Xylene. Contingent on the successful wellbore clean out, a matrix stimulation was to be done using an Acid preflush and Regular clay acid as the main treatment. But this operation failed because instead of resulting in an increase in production, the well couldn't produce to surface and had to be shut-in. This paper will review the problems encountered from the unsuccessful intervention of well AA because of the lack of a detailed recipe design to find the best treatment to dissolve organic deposits in the well and precipitates, as well as residues formed from the reaction between organic solids and inorganic acids. In addition, this paper will present the detailed work that went into designing the right treatment recipe for well AA that resulted in successfully reviving the well after the initial failed intervention operation to become a prolific producer of over 1500 stock tank barrels of oil per day.
{"title":"Lessons Learnt from Well Intervention Operations on Well AA, and The Impact of Detailed Recipe Design on Performance of a Niger Delta Well","authors":"O. Oladunni, Leste O. Aihevba, Richard Dokubo, Ayopo Kudayisi, Muaz Obadaki, C. Eze, Modestus Eze, Chika Ibama","doi":"10.2118/198793-MS","DOIUrl":"https://doi.org/10.2118/198793-MS","url":null,"abstract":"\u0000 Well Intervention operations are carried out to improve production performance of a declining well, restore production to a well that quit, or improve well integrity, among other reasons. Well bore clean out and stimulation are two of the common well intervention operations done on producing oil and gas wells to improve performance. Well AA, a major oil and gas producer started to decline after three years of production, therefore a well bore clean out and stimulation exercise was designed to improve performance of the well. The first Intervention operation was planned after various crude sample and precipitate analysis reports showed organic deposits (wax and asphaltenes) in the well. Slickline drift also indicated a restriction in the tubing. The treatment recipe for the well intervention was designed based on laboratory test carried out on the crude and precipitate sample that showed an 85% dissolution of the organic deposits in Xylene and 55% dissolution in Solution Z (a mixture of Xylene and HCL). The 85% dissolution was considered adequate to ensure a complete wellbore clean out, with Solution Z planned as the contingent treatment recipe for any solid deposits not dissolved by Xylene. Contingent on the successful wellbore clean out, a matrix stimulation was to be done using an Acid preflush and Regular clay acid as the main treatment. But this operation failed because instead of resulting in an increase in production, the well couldn't produce to surface and had to be shut-in. This paper will review the problems encountered from the unsuccessful intervention of well AA because of the lack of a detailed recipe design to find the best treatment to dissolve organic deposits in the well and precipitates, as well as residues formed from the reaction between organic solids and inorganic acids. In addition, this paper will present the detailed work that went into designing the right treatment recipe for well AA that resulted in successfully reviving the well after the initial failed intervention operation to become a prolific producer of over 1500 stock tank barrels of oil per day.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"10 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74737790","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}
Given various competing alternatives, the rigorous evaluation of development options for oil-rim reservoirs can be challenging and computationally intensive. For quick and robust decision-making, an efficient screening method that accounts for the relevant static and dynamic properties of the reservoir of interest is desirable. Based on controlled numerical simulation experiments, this paper proposes simple screening guidelines for oil-rim reservoirs under the mutually exclusive development scenarios of (i) sequential oil-then-gas (OTG); (ii) concurrent oil-and-gas (COG); and (iii) gas-only development (GOD). For simplicity, a two-level factorial design was used to create 17 experiments from a set of static and dynamic reservoir properties. A generic reservoir box model was then developed and used to conduct a total of 51 experiments. For each of the three development options, normalised surrogate models were developed for hydrocarbon recovery factor (RF) as a function of these static and dynamic properties. For the specific box model and the parameter space examined, it was found that the performance of the OTG option is most sensitive to oil API (viscosity), vertical anisotropy, oil relative permeability and liquid offtake rate. The COG case showed oil API, vertical anisotropy, liquid offtake rate and oil relative permeability as the heavy hitters, while the GOD option returned oil rim thickness, relative permeabilities and gas offtake rate as the key drivers of reservoir performance. Performance comparison of the three development options reveals that when reservoir properties are favourable to oil flow, OTG is the preferred oil-rim development option, while the GOD option is the most attractive when the reservoir is naturally less favourable to oil mobility. Although these guidelines provide indications of the most promising option, the final decision should be premised on further detailed studies, while considering both technical and non-technical factors that are peculiar to the specific project in question.
{"title":"Simple Guidelines for Screening Development Options for Oil-Rim Reservoirs","authors":"Idoko J. John, S. Matemilola, K. Lawal","doi":"10.2118/198718-MS","DOIUrl":"https://doi.org/10.2118/198718-MS","url":null,"abstract":"\u0000 Given various competing alternatives, the rigorous evaluation of development options for oil-rim reservoirs can be challenging and computationally intensive. For quick and robust decision-making, an efficient screening method that accounts for the relevant static and dynamic properties of the reservoir of interest is desirable. Based on controlled numerical simulation experiments, this paper proposes simple screening guidelines for oil-rim reservoirs under the mutually exclusive development scenarios of (i) sequential oil-then-gas (OTG); (ii) concurrent oil-and-gas (COG); and (iii) gas-only development (GOD).\u0000 For simplicity, a two-level factorial design was used to create 17 experiments from a set of static and dynamic reservoir properties. A generic reservoir box model was then developed and used to conduct a total of 51 experiments. For each of the three development options, normalised surrogate models were developed for hydrocarbon recovery factor (RF) as a function of these static and dynamic properties.\u0000 For the specific box model and the parameter space examined, it was found that the performance of the OTG option is most sensitive to oil API (viscosity), vertical anisotropy, oil relative permeability and liquid offtake rate. The COG case showed oil API, vertical anisotropy, liquid offtake rate and oil relative permeability as the heavy hitters, while the GOD option returned oil rim thickness, relative permeabilities and gas offtake rate as the key drivers of reservoir performance.\u0000 Performance comparison of the three development options reveals that when reservoir properties are favourable to oil flow, OTG is the preferred oil-rim development option, while the GOD option is the most attractive when the reservoir is naturally less favourable to oil mobility. Although these guidelines provide indications of the most promising option, the final decision should be premised on further detailed studies, while considering both technical and non-technical factors that are peculiar to the specific project in question.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"9 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85177725","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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