Emmanuel Mogbolu, C. Awa, J. Ekwealor, V. Jaja, O. Okereke
Uncertainty management for resource volume of a brown field is relevant. An analytical approach via dynamic model was used to evaluate this impact on a developed gas reservoir (brown) by two other reservoirs. One of them is a green oil-rim reservoir, while the other is a developed oil reservoir. This is due to sand-to-sand juxtaposition with the two reservoirs. Integration of available data over time, while considering all the reservoir uncertainties was adopted. This was buttressed by the continuous production from the gas reservoir, that had already gone past the initially evaluated Gas Initially in Place (GIIP). The brown reservoir is a highly faulted gas reservoir with twenty-seven (27) years production history, by seven wells. The reservoir's GIIP re-evaluation had been done twice over the years. This was because it had fully developed its ultimate recovery, with three wells still producing. This GIIP re-evaluation approach could no longer be utilized, as it had very good well coverage. Fault seal analysis, pressure, PVT sample and log data taken over time reveal the likelihood of communication across the stacked reservoirs. A multi-tank material balance model (MBAL) was built via a multidisciplinary approach. The model was history matched using an experimental design approach that saved time and contacts were calibrated. The result showed the quantity of hydrocarbon in both reservoirs that have flowed into the developed gas reservoir. This provides a snapshot on the resource volume impact of the reservoirs with respect to their development and uncertainty management. Revised development plans and resource booking for the reservoirs are also study outcomes. This is relevant for business decisions on resource volume booking and reservoir management. This approach is a quick win within the Well, Reservoir and Facility Management (WRFM) workspace. Further work by building a 3D simulation model and pressure data acquisition is required for robust benchmarking.
{"title":"Best Practices in Evaluating Production Performance: A Niger Delta Case Study with Inter-Reservoir Communication","authors":"Emmanuel Mogbolu, C. Awa, J. Ekwealor, V. Jaja, O. Okereke","doi":"10.2118/198854-MS","DOIUrl":"https://doi.org/10.2118/198854-MS","url":null,"abstract":"\u0000 Uncertainty management for resource volume of a brown field is relevant. An analytical approach via dynamic model was used to evaluate this impact on a developed gas reservoir (brown) by two other reservoirs. One of them is a green oil-rim reservoir, while the other is a developed oil reservoir. This is due to sand-to-sand juxtaposition with the two reservoirs. Integration of available data over time, while considering all the reservoir uncertainties was adopted. This was buttressed by the continuous production from the gas reservoir, that had already gone past the initially evaluated Gas Initially in Place (GIIP).\u0000 The brown reservoir is a highly faulted gas reservoir with twenty-seven (27) years production history, by seven wells. The reservoir's GIIP re-evaluation had been done twice over the years. This was because it had fully developed its ultimate recovery, with three wells still producing. This GIIP re-evaluation approach could no longer be utilized, as it had very good well coverage.\u0000 Fault seal analysis, pressure, PVT sample and log data taken over time reveal the likelihood of communication across the stacked reservoirs. A multi-tank material balance model (MBAL) was built via a multidisciplinary approach. The model was history matched using an experimental design approach that saved time and contacts were calibrated. The result showed the quantity of hydrocarbon in both reservoirs that have flowed into the developed gas reservoir. This provides a snapshot on the resource volume impact of the reservoirs with respect to their development and uncertainty management. Revised development plans and resource booking for the reservoirs are also study outcomes. This is relevant for business decisions on resource volume booking and reservoir management.\u0000 This approach is a quick win within the Well, Reservoir and Facility Management (WRFM) workspace. Further work by building a 3D simulation model and pressure data acquisition is required for robust benchmarking.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"93 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74105321","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}
Business Process Outsourcing can be aptly described as the process of forging a contractual relationship with external supplier for the provision of capacity that has been previously undertaken within an organization. In the global oil and gas industry, Business Process Outsourcing (BPO) has emerged in contemporary times as a potent tool in their operational mix. This is particularly hinged on the imperatives to find a delicate balance between rising global demand, diminishing reserves in some of the world's major oil fields, while managing distribution and operating costs. The collapse of crude oil prices from US$100.00 in May 2014 to about US$30.00 and even below in early 2016 has reinforced outsourcing. Empirical studies reveal that outsourcing of non-core activities may result in 25% cost saving associated with on-/near-site operations and as much as 50-75% for offshore operations compared to the cost of engaging in same activities in-house. Apart from cost-cutting, other benefits associated with BPO include a stronger focus on core competencies; improved regulatory conformity and compliance; as well as access to a larger talent pool and novel technologies. The oil and gas industry has emerged as the cornerstone of Nigeria's economy, accounting for about 70% of annual government revenue and more than 90% of the nation's foreign exchange reserves. Since the 1990s, outsourcing has assumed an increasing dimension in the nation's oil and gas industry. Empirical studies reveal, for example, that up until the early 1990s, employees in the oil industry comprised about 70% and 30% of permanent and temporary employees, respectively. The temporary employees were initially focused on non-core activities. However, in recent times core activities are increasingly contracted to service providers, reversing the structure of employment in the industry by 2010, with 40% of permanent employees, while 60% were permanent employees. The increasing replacement of permanent employees with temporary ones has fueled concern in the industry, led by labour unions, which have expressed concern about the sub-standard welfare of contract workers. This development has led the Federal government of Nigeria to issue guidelines on staff contracting and outsourcing in the Nigerian oil and gas industry.
{"title":"The Rise of Business Process Outsourcing in Nigeria's Oil and Gas Industry and Implications for Industrial Relations","authors":"S. Igbatayo","doi":"10.2118/198831-MS","DOIUrl":"https://doi.org/10.2118/198831-MS","url":null,"abstract":"\u0000 Business Process Outsourcing can be aptly described as the process of forging a contractual relationship with external supplier for the provision of capacity that has been previously undertaken within an organization. In the global oil and gas industry, Business Process Outsourcing (BPO) has emerged in contemporary times as a potent tool in their operational mix. This is particularly hinged on the imperatives to find a delicate balance between rising global demand, diminishing reserves in some of the world's major oil fields, while managing distribution and operating costs. The collapse of crude oil prices from US$100.00 in May 2014 to about US$30.00 and even below in early 2016 has reinforced outsourcing. Empirical studies reveal that outsourcing of non-core activities may result in 25% cost saving associated with on-/near-site operations and as much as 50-75% for offshore operations compared to the cost of engaging in same activities in-house. Apart from cost-cutting, other benefits associated with BPO include a stronger focus on core competencies; improved regulatory conformity and compliance; as well as access to a larger talent pool and novel technologies. The oil and gas industry has emerged as the cornerstone of Nigeria's economy, accounting for about 70% of annual government revenue and more than 90% of the nation's foreign exchange reserves. Since the 1990s, outsourcing has assumed an increasing dimension in the nation's oil and gas industry. Empirical studies reveal, for example, that up until the early 1990s, employees in the oil industry comprised about 70% and 30% of permanent and temporary employees, respectively. The temporary employees were initially focused on non-core activities. However, in recent times core activities are increasingly contracted to service providers, reversing the structure of employment in the industry by 2010, with 40% of permanent employees, while 60% were permanent employees. The increasing replacement of permanent employees with temporary ones has fueled concern in the industry, led by labour unions, which have expressed concern about the sub-standard welfare of contract workers. This development has led the Federal government of Nigeria to issue guidelines on staff contracting and outsourcing in the Nigerian oil and gas industry.","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":"74211376","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 days of easy hydrocarbon Exploration and Production are fast disappearing in the petroleum business. Today, the industry is saddled with the task to sustain world hydrocarbon resources to meet current and future energy demands. This has resulted in prospecting for hydrocarbon in deep hydrocarbon plays or accumulations at much deeper depths in the Earth's subsurface. These deep hydrocarbon plays are sometimes below brown fields with significant production from reservoirs that are depleted and below hydrostatic pressure. Exploiting these deep plays requires wells that could traverse these depleted reservoirs, as well as other virgin reservoirs. These plays are often associated with abnormal formation pressures, with reduced drilling margins, defined by elevated formation pressures and fracture gradients. These pore pressures and fracture gradients information drive the well design and delivery (i.e. mud schedule, casing scheme, and rig/wellhead equipment selection). Thus, in well design and delivery, drilling operations should be planned to manage the different pressure regimes and transition zones to be encountered during drilling. Recently, several Health, Safety, and Environmental (HSE) incidents have been recorded across the globe from well control related incidents that affected lives, assets, and the environment, because formation strength integrity was compromised during oil/gas well operations. One key factor in ensuring that wells are drilled and completed to desired depth without well control incidents is a proper estimation of the formation strength or pressure containment of the open-hole formation during well operations – this is defined by the formation fracture gradient. The main objective of this paper is to propose a new methodology to estimate fracture gradients based on the application of two different methods for virgin and depleted reservoirs: i.e. the Effective Stress Ratio and the Stress Path methods, respectively. These methods were adapted to the Niger Delta in an integrated modeling workflow as proposed in Reservoir GeoMechanics literature (see ref. #6). Uncertainty management relating to their broad application of this workflow to all onshore/shallow offshore wells/fields has been managed by incorporating a new calibration function to validate the estimated fracture gradients using the actual Leak-Off Test (LOT) data, taken from offset or nearby wells in the formation of interest or its analogue. In this paper, 120 LOT data from existing wells drilled across 36 onshore fields in Niger Delta were used to determine a correlation between the ratios of the horizontal/vertical effective stresses and depth. This was then used in the Effective Stress Ratio (ESR) workflow for fracture gradient estimation to obtain the in-situ/original fracture gradient of the formation. This defines the static condition and stress state of the formation and sets the scene for the estimation of the current fracture gradient in the Reserv
{"title":"Integrated Effective Stress Ratio and Stress Path Approach to Fracture Gradient Estimation for Virgin and Depleted Reservoirs","authors":"Kelvin Okpako, Olayinka David","doi":"10.2118/198855-MS","DOIUrl":"https://doi.org/10.2118/198855-MS","url":null,"abstract":"\u0000 The days of easy hydrocarbon Exploration and Production are fast disappearing in the petroleum business. Today, the industry is saddled with the task to sustain world hydrocarbon resources to meet current and future energy demands. This has resulted in prospecting for hydrocarbon in deep hydrocarbon plays or accumulations at much deeper depths in the Earth's subsurface.\u0000 These deep hydrocarbon plays are sometimes below brown fields with significant production from reservoirs that are depleted and below hydrostatic pressure. Exploiting these deep plays requires wells that could traverse these depleted reservoirs, as well as other virgin reservoirs. These plays are often associated with abnormal formation pressures, with reduced drilling margins, defined by elevated formation pressures and fracture gradients. These pore pressures and fracture gradients information drive the well design and delivery (i.e. mud schedule, casing scheme, and rig/wellhead equipment selection). Thus, in well design and delivery, drilling operations should be planned to manage the different pressure regimes and transition zones to be encountered during drilling.\u0000 Recently, several Health, Safety, and Environmental (HSE) incidents have been recorded across the globe from well control related incidents that affected lives, assets, and the environment, because formation strength integrity was compromised during oil/gas well operations. One key factor in ensuring that wells are drilled and completed to desired depth without well control incidents is a proper estimation of the formation strength or pressure containment of the open-hole formation during well operations – this is defined by the formation fracture gradient.\u0000 The main objective of this paper is to propose a new methodology to estimate fracture gradients based on the application of two different methods for virgin and depleted reservoirs: i.e. the Effective Stress Ratio and the Stress Path methods, respectively. These methods were adapted to the Niger Delta in an integrated modeling workflow as proposed in Reservoir GeoMechanics literature (see ref. #6). Uncertainty management relating to their broad application of this workflow to all onshore/shallow offshore wells/fields has been managed by incorporating a new calibration function to validate the estimated fracture gradients using the actual Leak-Off Test (LOT) data, taken from offset or nearby wells in the formation of interest or its analogue.\u0000 In this paper, 120 LOT data from existing wells drilled across 36 onshore fields in Niger Delta were used to determine a correlation between the ratios of the horizontal/vertical effective stresses and depth. This was then used in the Effective Stress Ratio (ESR) workflow for fracture gradient estimation to obtain the in-situ/original fracture gradient of the formation. This defines the static condition and stress state of the formation and sets the scene for the estimation of the current fracture gradient in the Reserv","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"16 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81251206","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}
Accurate pressure losses prediction for flow in tubing installations is of great importance in the petroleum industry. Historically, the Bottom-Hole Pressure (BHP) determination was obtained using down-hole pressure gauges, because of the economic disadvantage and redundancy, this procedure seems to be less effective, this led to the adoption of the BHP prediction process in estimation. The wide acceptance of data-driven analytics makes the estimation procedure a valid approach in the industry today. Recently, the Artificial Neural Network (ANN), a technique which has been widely accepted because the model proved to predict better than the conventional correlations. This present work aims to develop a prediction model for BHP based on input and output data obtained from the Volve production field in Norway. Machine learning algorithm based on ANN was used to predict and further improve the accuracy of the prediction while considering a large production dataset from different wells of the field. In developing the model, the initial dataset was processed to about 2,500 data points; the model was trained, tested and cross-validated based on the parameters from the data. Results affirmed that ANN has the ability to handle large dataset, results also revealed that ANN outperformed other models, with a Coefficient of Determination of 0.99997, Root Mean Squared Error of 0.07405 and Mean Absolute Error of 0.02657, which shows high predictability of the model. These results indicated that the ANN model gives a better prediction of BHP when compared to other mechanistic models. Finally, this work supports the claim, that Production engineers can accurately predict the pressure at the sand-face of a producing well without the use of expensive BHP gauge.
{"title":"Bottom-Hole Pressure Estimation from Wellhead Data Using Artificial Neural Network","authors":"O. Akinsete, Blessing Adetoye Adesiji","doi":"10.2118/198762-MS","DOIUrl":"https://doi.org/10.2118/198762-MS","url":null,"abstract":"\u0000 Accurate pressure losses prediction for flow in tubing installations is of great importance in the petroleum industry. Historically, the Bottom-Hole Pressure (BHP) determination was obtained using down-hole pressure gauges, because of the economic disadvantage and redundancy, this procedure seems to be less effective, this led to the adoption of the BHP prediction process in estimation. The wide acceptance of data-driven analytics makes the estimation procedure a valid approach in the industry today. Recently, the Artificial Neural Network (ANN), a technique which has been widely accepted because the model proved to predict better than the conventional correlations.\u0000 This present work aims to develop a prediction model for BHP based on input and output data obtained from the Volve production field in Norway. Machine learning algorithm based on ANN was used to predict and further improve the accuracy of the prediction while considering a large production dataset from different wells of the field. In developing the model, the initial dataset was processed to about 2,500 data points; the model was trained, tested and cross-validated based on the parameters from the data. Results affirmed that ANN has the ability to handle large dataset, results also revealed that ANN outperformed other models, with a Coefficient of Determination of 0.99997, Root Mean Squared Error of 0.07405 and Mean Absolute Error of 0.02657, which shows high predictability of the model. These results indicated that the ANN model gives a better prediction of BHP when compared to other mechanistic models.\u0000 Finally, this work supports the claim, that Production engineers can accurately predict the pressure at the sand-face of a producing well without the use of expensive BHP gauge.","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":"88608247","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 Voltaian basin, Ghana's largest inland basin is the least explored of the sedimentary basins in Ghana. Based on past reconnaissance surveys, albeit limited survey data, the basin is believed to have prospects of hydrocarbon reserves. The government has therefore renewed interest in the Voltaian Basin Project (VBP) to prepare and promote the basin to allow hydrocarbon exploitation activities. Ghana National Petroleum Corporation (GNPC), has been tasked to undertake this project. This paper undertook a safety assessment of the VBP and post VBP, and also examined its economic impact on the Ghanaian economy using standard risk management techniques and economic modelling respectively. It was deduced that a combination of high to low levels of risk exist in all phases of the project. Out of 64 hazards identified with the VBP and post VBP, three (3) were found to be of high risk, fifty-one (51) of medium risk and ten (10) of low risk. These risks range from gas leakage, through cement plug failure to slips, trips and falls. However, with appropriate mitigation measures such as routine inspection, routine maintenance and repairs, organizing periodic training programs and ensuring a robust Safety Management System, these risks could be reduced to the barest minimum, if not eliminated. The project is therefore a safe endeavour. In the event of commercial discovery, based on reliable data and informed estimations, the project was observed to accrue net earnings based on net present value for all stakeholders in the sums of at least $18.8 billion, $2.5 billion and $23.8 billion for government, GNPC and International Oil Companies respectively after ten (10) years of production. The project, if successful, would contribute immensely to the development of the Ghanaian economy. It is expected to replenish the country's declining reserves, provide a comparatively cheaper means of hydrocarbon exploitation, help build the capacity of the national oil company for operatorship in Exploration and Production operations and enhance Ghana's energy supply, bridging the demand gap.
{"title":"Safety and Economic Assessment of the Voltaian Basin Project","authors":"E. B. B. Fuah, F. Otoo, W. Anthony","doi":"10.2118/198820-MS","DOIUrl":"https://doi.org/10.2118/198820-MS","url":null,"abstract":"\u0000 The Voltaian basin, Ghana's largest inland basin is the least explored of the sedimentary basins in Ghana. Based on past reconnaissance surveys, albeit limited survey data, the basin is believed to have prospects of hydrocarbon reserves. The government has therefore renewed interest in the Voltaian Basin Project (VBP) to prepare and promote the basin to allow hydrocarbon exploitation activities. Ghana National Petroleum Corporation (GNPC), has been tasked to undertake this project. This paper undertook a safety assessment of the VBP and post VBP, and also examined its economic impact on the Ghanaian economy using standard risk management techniques and economic modelling respectively.\u0000 It was deduced that a combination of high to low levels of risk exist in all phases of the project. Out of 64 hazards identified with the VBP and post VBP, three (3) were found to be of high risk, fifty-one (51) of medium risk and ten (10) of low risk. These risks range from gas leakage, through cement plug failure to slips, trips and falls. However, with appropriate mitigation measures such as routine inspection, routine maintenance and repairs, organizing periodic training programs and ensuring a robust Safety Management System, these risks could be reduced to the barest minimum, if not eliminated. The project is therefore a safe endeavour.\u0000 In the event of commercial discovery, based on reliable data and informed estimations, the project was observed to accrue net earnings based on net present value for all stakeholders in the sums of at least $18.8 billion, $2.5 billion and $23.8 billion for government, GNPC and International Oil Companies respectively after ten (10) years of production.\u0000 The project, if successful, would contribute immensely to the development of the Ghanaian economy. It is expected to replenish the country's declining reserves, provide a comparatively cheaper means of hydrocarbon exploitation, help build the capacity of the national oil company for operatorship in Exploration and Production operations and enhance Ghana's energy supply, bridging the demand gap.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"62 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91247728","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. Ganiyu, A. Ochi, Olufemi Adebayo, Awotiku Oluwabiyi, Ibeh Chijioke
Gas lift is one of the most common and economical methods of artificial lift deployed in mature oil fields in the Niger Delta. Availability of lift gas on the oil production jacket or platform is a critical enabler for gas lift initiation. Most mature fields do not have the luxury of gas lift supply on its jackets either because gas flowlines were not laid at inception or the gas flowlines are out-of-service due to integrity issues. Jacket X had four active oil well streams producing on natural flow at inception. In early 2017, these wells stopped production one after the other due to low tubing head pressure (LTHP) because of increasing watercut and declining reservoir pressure. The wells were producing at a combined rate of over 1,000 barrels of oil per day (BOPD) prior to stopping production. Well diagnostic and preliminary Nodal Analysis revealed the need to place the wells on gas lift to improve the vertical lift performance. However, this could not be executed as jacket X was not on the field gas lift flowline network. Without conventional lift gas on Jacket X, it was imperative to source for the most economic means of getting gas on the jacket. This paper highlights the processes and methodology of sourcing lift gas through an existing idle wellbore. During the bi-anual field review, the team of Operations personnel, Facilities Engineering and Asset Management reviewed and mapped out low cost strategy to restore production of the shut-in wells. Since most of these wells stopped production due to LTHP, improving vertical lift performance became the critical success factor. To address this issue economically, the asset team developed an ingenious method of sourcing the required lift gas on the same Jacket X through rigless well intervention on one of the existing idle wellbores. The innovative approach deployed involved identification of gas bearing reservoir in one of the idle wellbores, cement squeeze operations to provide zonal isolation, oriented perforation of identified gas reservoir, topside modification of existing wellhead configuration and eventual supply of lift gas to the casing of the shut-in wells. Utilizing the lift gas, the wells were placed on gas lift with 1,100 barrels of oil and 3.5 MMScfd of gas restored to production. Significant cost savings were realized during the execution of this project through the application of rigless interventions which eliminated the requirement of laying new flowlines to deliver required lift gas to Jacket X. Finally, this paper will share some of the challenges, lesson learned, and best practices adopted while executing this project.
{"title":"Production Restoration Through Innovative Sourcing of Lift Gas - Jacket X Case Study","authors":"A. Ganiyu, A. Ochi, Olufemi Adebayo, Awotiku Oluwabiyi, Ibeh Chijioke","doi":"10.2118/198834-MS","DOIUrl":"https://doi.org/10.2118/198834-MS","url":null,"abstract":"Gas lift is one of the most common and economical methods of artificial lift deployed in mature oil fields in the Niger Delta. Availability of lift gas on the oil production jacket or platform is a critical enabler for gas lift initiation. Most mature fields do not have the luxury of gas lift supply on its jackets either because gas flowlines were not laid at inception or the gas flowlines are out-of-service due to integrity issues.\u0000 Jacket X had four active oil well streams producing on natural flow at inception. In early 2017, these wells stopped production one after the other due to low tubing head pressure (LTHP) because of increasing watercut and declining reservoir pressure. The wells were producing at a combined rate of over 1,000 barrels of oil per day (BOPD) prior to stopping production. Well diagnostic and preliminary Nodal Analysis revealed the need to place the wells on gas lift to improve the vertical lift performance. However, this could not be executed as jacket X was not on the field gas lift flowline network. Without conventional lift gas on Jacket X, it was imperative to source for the most economic means of getting gas on the jacket. This paper highlights the processes and methodology of sourcing lift gas through an existing idle wellbore.\u0000 During the bi-anual field review, the team of Operations personnel, Facilities Engineering and Asset Management reviewed and mapped out low cost strategy to restore production of the shut-in wells. Since most of these wells stopped production due to LTHP, improving vertical lift performance became the critical success factor. To address this issue economically, the asset team developed an ingenious method of sourcing the required lift gas on the same Jacket X through rigless well intervention on one of the existing idle wellbores. The innovative approach deployed involved identification of gas bearing reservoir in one of the idle wellbores, cement squeeze operations to provide zonal isolation, oriented perforation of identified gas reservoir, topside modification of existing wellhead configuration and eventual supply of lift gas to the casing of the shut-in wells.\u0000 Utilizing the lift gas, the wells were placed on gas lift with 1,100 barrels of oil and 3.5 MMScfd of gas restored to production. Significant cost savings were realized during the execution of this project through the application of rigless interventions which eliminated the requirement of laying new flowlines to deliver required lift gas to Jacket X.\u0000 Finally, this paper will share some of the challenges, lesson learned, and best practices adopted while executing this project.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"13 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73474900","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}
Unstable boreholes due to tensile & shear failure results in serious drilling problems. This increases the non-productive time spent in the field and the cost of reviving failed wells in the oil and gas industry in order to mitigate or prevent borehole failure, different rock strength criteria models have been developed to predict the optimum required mud weight but unfortunately, not all models fit for all formation considering the different drilling conditions, hence these models need to be evaluated to check their validity and accuracy for drilling stable wells in the Niger Delta. To achieve this purpose, collapse and fracture pressure that defines the lower and upper boundary of a mud weight window are calculated using derived formula equations from three failure criteria models; Hoek-Brown failure criterion, Mohr-Coulomb failure criterion and Mogi-Coulomb criterion failure criterion. This is achieved using Microsoft Excel and the simulation is done on a plot to show the different mud window by each model for comparison. The input parameters relevant for this study are pore pressure, in-situ stress data and rock mechanical properties which were acquired from a high-pressured zone in an xxx-onshore oilfield of the Niger Delta. A plot of the predicted optimum mud weight vs the actual mud weight against depth is compared to check the accuracy of each model to conclude on the failure criterion that is best fit for the formation in this field. The results showed that Hoek-Brown failure criterion gave an unrealistic outcome, when used to drill will lead to borehole breakout. Mohr-Coulomb and 3D Mogi-Coulomb criteria gave similar results which can be used but Mogi-Coulomb is recommended for drilling stabilized vertical wells due to the consideration of intermediate principal stress effect on rock strength over the conservative Mohr-Coulomb.
{"title":"Evaluation of Rock Failure Models for The Determination of a Safe Mud Weight Window During Drilling Operations in The Niger Delta","authors":"Chioma Ogbechie Success","doi":"10.2118/198826-MS","DOIUrl":"https://doi.org/10.2118/198826-MS","url":null,"abstract":"\u0000 Unstable boreholes due to tensile & shear failure results in serious drilling problems. This increases the non-productive time spent in the field and the cost of reviving failed wells in the oil and gas industry in order to mitigate or prevent borehole failure, different rock strength criteria models have been developed to predict the optimum required mud weight but unfortunately, not all models fit for all formation considering the different drilling conditions, hence these models need to be evaluated to check their validity and accuracy for drilling stable wells in the Niger Delta. To achieve this purpose, collapse and fracture pressure that defines the lower and upper boundary of a mud weight window are calculated using derived formula equations from three failure criteria models; Hoek-Brown failure criterion, Mohr-Coulomb failure criterion and Mogi-Coulomb criterion failure criterion. This is achieved using Microsoft Excel and the simulation is done on a plot to show the different mud window by each model for comparison. The input parameters relevant for this study are pore pressure, in-situ stress data and rock mechanical properties which were acquired from a high-pressured zone in an xxx-onshore oilfield of the Niger Delta. A plot of the predicted optimum mud weight vs the actual mud weight against depth is compared to check the accuracy of each model to conclude on the failure criterion that is best fit for the formation in this field. The results showed that Hoek-Brown failure criterion gave an unrealistic outcome, when used to drill will lead to borehole breakout. Mohr-Coulomb and 3D Mogi-Coulomb criteria gave similar results which can be used but Mogi-Coulomb is recommended for drilling stabilized vertical wells due to the consideration of intermediate principal stress effect on rock strength over the conservative Mohr-Coulomb.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"30 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77022886","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 Nigerian gas market experienced growth in recent years due to the gas development policies of the government such as the Nigerian gas master plan. Nevertheless, the gas supply and utilization per capita has barely changed while policy objectives are largely unfulfilled. A new national gas policy 2017 recognized a full-blown energy crises in Nigeria in spite of its abundant gas resources. It thereby aims to increase gas utilization with more contribution to GDP, grow key sectors of the economy and reduce gas flaring to 2 percent. A policy of the magnitude of gas monetization policy a posteriori would have significant positive or negative impacts on macroeconomic, sectoral and distributional indicators. Is gas monetization policy good for all all? Employing the comparative static CGE model, this study carries out evaluation of increased gas supply on the Nigeria economy from 80 percent flare gas reduction and 30 percent reduction in direct tax rate on production. Results show that increased gas supply from flareout have positive influences on economic growth but slowed down with application of production tax incentives. The GDP, real investments, government revenues and sectors experienced growths except agriculture and transport sectors. The drop in average consumer prices encouraged household consumption as well as increased welfare. The study established causal relationship between increased gas utilization and economic growth. Efforts in driving the gas flaredown of monetization policy should be facilitated. The government shall exercise caution to ensure protection of the economy to guarantee proportionate health of the sectors that were negatively impacted such as agriculture and transport.
{"title":"Macroeconomic, Sectoral and Distributional Impact of Gas Monetization Policy in Nigeria: A CGE Application","authors":"Emmanuel O. Agiaye","doi":"10.2118/198809-MS","DOIUrl":"https://doi.org/10.2118/198809-MS","url":null,"abstract":"\u0000 The Nigerian gas market experienced growth in recent years due to the gas development policies of the government such as the Nigerian gas master plan. Nevertheless, the gas supply and utilization per capita has barely changed while policy objectives are largely unfulfilled. A new national gas policy 2017 recognized a full-blown energy crises in Nigeria in spite of its abundant gas resources. It thereby aims to increase gas utilization with more contribution to GDP, grow key sectors of the economy and reduce gas flaring to 2 percent. A policy of the magnitude of gas monetization policy a posteriori would have significant positive or negative impacts on macroeconomic, sectoral and distributional indicators. Is gas monetization policy good for all all? Employing the comparative static CGE model, this study carries out evaluation of increased gas supply on the Nigeria economy from 80 percent flare gas reduction and 30 percent reduction in direct tax rate on production. Results show that increased gas supply from flareout have positive influences on economic growth but slowed down with application of production tax incentives. The GDP, real investments, government revenues and sectors experienced growths except agriculture and transport sectors. The drop in average consumer prices encouraged household consumption as well as increased welfare. The study established causal relationship between increased gas utilization and economic growth. Efforts in driving the gas flaredown of monetization policy should be facilitated. The government shall exercise caution to ensure protection of the economy to guarantee proportionate health of the sectors that were negatively impacted such as agriculture and transport.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"88 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73077463","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}
Nigeria has huge natural gas resources, yet there is a great concern on the availability of natural gas supply for primary energy requirement to power its economy. This paper focuses on evaluating the efficiency of natural gas utilization in Nigeria from 1995 to 2017. Its purpose is to evaluate gas use with respect to industrial development and susceptibility of GDP to a sudden decrease in natural gas production. Data Envelopment Analysis (DEA), which is a mathematical (optimization) tool for assessing the relative efficiencies of decision making units (DMU), was applied to show that natural gas is not fully utilized in Nigeria and has thus impacted economic growth negatively. The vulnerability indexes for the period under consideration were high, suggesting that Nigeria is not self-sufficient in natural gas. In addition, there is strong evidence from empirical results to suggest that as gas consumption increases GDP rises as well. This implies that a right policy framework and implementation strategies need to be in place to advance Nigeria's economic growth aspiration.
{"title":"Data Envelopment Analysis DEA of Natural Gas Utilization in Nigeria","authors":"Lolo Ojaraida, O. Iledare, Adekunle J. Idowu","doi":"10.2118/198783-MS","DOIUrl":"https://doi.org/10.2118/198783-MS","url":null,"abstract":"\u0000 Nigeria has huge natural gas resources, yet there is a great concern on the availability of natural gas supply for primary energy requirement to power its economy. This paper focuses on evaluating the efficiency of natural gas utilization in Nigeria from 1995 to 2017. Its purpose is to evaluate gas use with respect to industrial development and susceptibility of GDP to a sudden decrease in natural gas production.\u0000 Data Envelopment Analysis (DEA), which is a mathematical (optimization) tool for assessing the relative efficiencies of decision making units (DMU), was applied to show that natural gas is not fully utilized in Nigeria and has thus impacted economic growth negatively. The vulnerability indexes for the period under consideration were high, suggesting that Nigeria is not self-sufficient in natural gas. In addition, there is strong evidence from empirical results to suggest that as gas consumption increases GDP rises as well. This implies that a right policy framework and implementation strategies need to be in place to advance Nigeria's economic growth aspiration.","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":"73891210","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. Emeka, Y. Adeeyo, A. Etim, Opeyemi Oluwalade, Onyema Ohabuike, Uzoamaka Okene, Leziga Bakor, I. Ukauku, Niyi Afolabi, Jolomi Esimaje
OML 18, operated by Eroton Exploration and Production Company (EROTON E&P) and located within the Coastal Swamp of Eastern Niger Delta contains several producing fields. As a brown asset with over 50 years historical production and ageing infrastructure, rapidly declining oil production caused by rising water cut and depleting reservoir pressure has become a normal feature for most of the reservoirs in the block. There arises therefore, urgent need to maximize the value of these mature fields by deploying fit for purpose and cost-effective technologies and methods. Thus, we deployed artificial lift technique using the abundant associated gas resources within the asset as one method of managing the rapid decline in oil production. Gas lift is a robust and inexpensive artificial lift solution which can be deployed at any period in the life-cycle of a well. The natural reservoir energy to move liquids to the surface through a well at expected rates declines with production time. Changing well and reservoir conditions, such as declining pressure, increasing gas liquid ratios and rising water cut can make consistent and predictable oil production a challenge. A review of the entire wells portfolio within the asset enabled an identification of all potential candidates with potential to benefit from gas lift installation. This was followed by feasibility studies to establish a connection between the magnitude of expected oil resources to be added, the oil rate potential, the existing completion status and surface facility equipment availability such as compression, gas lines and scrubbers etc. Screening of identified opportunities, often conducted in multi-disciplinary review sessions, yielded ranked list of opportunities for further maturation through design, execution and operation. Three (3) fields with over 60 wells and 38 developed reservoirs were selected for the review. The screening criteria included but not limited to reserves to be added, ease of execution, economics and regulatory approval requirements. Since these wells were not originally equipped with gas lift mandrel, alternative means of deploying gas lift equipment downhole had to be designed and implemented. Considering the advanced age of most of the wells, due consideration was given to well integrity in the final execution decision. Despite inherent challenges, EROTON was able to successfully deploy in-house technical knowledge and experience to embark on rigless well intervention campaign to restore production using retrofit gas lift equipment in existing wells, which have ceased to flow due to vertical lift issues, thus extending the life of the wells. We have successfully performed a safe and commercially viable production restoration exercise, returning a total of twelve (12) wells back to full production potential and achieving the well intervention objectives. The operation has accelerated production adding over 5,000 bopd. This paper will discuss the concept of brown fiel
{"title":"Retrofit Gas Lift Deployment for Oil Production Optimization in Onshore Niger Delta: A Case Study of EROTON E & P Oil Fields","authors":"O. Emeka, Y. Adeeyo, A. Etim, Opeyemi Oluwalade, Onyema Ohabuike, Uzoamaka Okene, Leziga Bakor, I. Ukauku, Niyi Afolabi, Jolomi Esimaje","doi":"10.2118/198790-MS","DOIUrl":"https://doi.org/10.2118/198790-MS","url":null,"abstract":"\u0000 OML 18, operated by Eroton Exploration and Production Company (EROTON E&P) and located within the Coastal Swamp of Eastern Niger Delta contains several producing fields. As a brown asset with over 50 years historical production and ageing infrastructure, rapidly declining oil production caused by rising water cut and depleting reservoir pressure has become a normal feature for most of the reservoirs in the block. There arises therefore, urgent need to maximize the value of these mature fields by deploying fit for purpose and cost-effective technologies and methods.\u0000 Thus, we deployed artificial lift technique using the abundant associated gas resources within the asset as one method of managing the rapid decline in oil production. Gas lift is a robust and inexpensive artificial lift solution which can be deployed at any period in the life-cycle of a well. The natural reservoir energy to move liquids to the surface through a well at expected rates declines with production time. Changing well and reservoir conditions, such as declining pressure, increasing gas liquid ratios and rising water cut can make consistent and predictable oil production a challenge.\u0000 A review of the entire wells portfolio within the asset enabled an identification of all potential candidates with potential to benefit from gas lift installation. This was followed by feasibility studies to establish a connection between the magnitude of expected oil resources to be added, the oil rate potential, the existing completion status and surface facility equipment availability such as compression, gas lines and scrubbers etc. Screening of identified opportunities, often conducted in multi-disciplinary review sessions, yielded ranked list of opportunities for further maturation through design, execution and operation. Three (3) fields with over 60 wells and 38 developed reservoirs were selected for the review. The screening criteria included but not limited to reserves to be added, ease of execution, economics and regulatory approval requirements. Since these wells were not originally equipped with gas lift mandrel, alternative means of deploying gas lift equipment downhole had to be designed and implemented. Considering the advanced age of most of the wells, due consideration was given to well integrity in the final execution decision. Despite inherent challenges, EROTON was able to successfully deploy in-house technical knowledge and experience to embark on rigless well intervention campaign to restore production using retrofit gas lift equipment in existing wells, which have ceased to flow due to vertical lift issues, thus extending the life of the wells. We have successfully performed a safe and commercially viable production restoration exercise, returning a total of twelve (12) wells back to full production potential and achieving the well intervention objectives. The operation has accelerated production adding over 5,000 bopd. This paper will discuss the concept of brown fiel","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"60 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84868884","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}
京公网安备 11010802042870号
京ICP备2023020795号-1
扫码关注我们
求助内容：
应助结果提醒方式：