The paper seeks to find the optimum solution on how to develop some portion of a unitized field. The case study involves two fields straddling across four oil mining leases (OMLs), in Niger Delta, Nigeria. Each field were operated independently by JV-A and JV-B until mid-2016 when the operatorship of the straddling reservoirs (SRs) in the unit was granted to JV-B by the regulators, as it is a law in Nigeria that all straddling reservoirs should be developed as a unit under a single operator. The decision on whether JV-A should grant JV-B the right to also operate the non-straddling reservoirs (NSRs) in the unit will depend on the amount of tariff imposed. JV-A will be required to pay hydrocarbon transportation and processing tariffs if it flows its share of the produced hydrocarbon through JV-B's existing facility. The exact amount of tariff is unknown and will be negotiated. Additionally, four feasible evacuation routes exist and will be considered for this evaluation to decide the most profitable and capital efficient investment option. The result shows that the opportunity is very sensitive to hydrocarbon handling tariff; necessitating JV-A choice of evacuation route. In addition, the paper demonstrates how using appropriate project framing and considerations of who will operate the JV-A's non-straddling reservoirs, relied heavily on different hydrocarbon transportation and processing tariffs. It is hoped that this paper having highlighted the importance of tariff charges and the role of proper framing on decision quality will encourage decision makers to adopt this approach during decision analysis and ultimately improve the quality of investment decisions particularly for Non-operated venture (NOV) projects.
{"title":"Third Party Tariff: A Key Input to NOV Projects Decision Analysis & Decision Quality","authors":"P. Obeahon, C. Ikpera, A. Laoye","doi":"10.2118/198852-MS","DOIUrl":"https://doi.org/10.2118/198852-MS","url":null,"abstract":"\u0000 The paper seeks to find the optimum solution on how to develop some portion of a unitized field. The case study involves two fields straddling across four oil mining leases (OMLs), in Niger Delta, Nigeria. Each field were operated independently by JV-A and JV-B until mid-2016 when the operatorship of the straddling reservoirs (SRs) in the unit was granted to JV-B by the regulators, as it is a law in Nigeria that all straddling reservoirs should be developed as a unit under a single operator.\u0000 The decision on whether JV-A should grant JV-B the right to also operate the non-straddling reservoirs (NSRs) in the unit will depend on the amount of tariff imposed. JV-A will be required to pay hydrocarbon transportation and processing tariffs if it flows its share of the produced hydrocarbon through JV-B's existing facility. The exact amount of tariff is unknown and will be negotiated. Additionally, four feasible evacuation routes exist and will be considered for this evaluation to decide the most profitable and capital efficient investment option.\u0000 The result shows that the opportunity is very sensitive to hydrocarbon handling tariff; necessitating JV-A choice of evacuation route. In addition, the paper demonstrates how using appropriate project framing and considerations of who will operate the JV-A's non-straddling reservoirs, relied heavily on different hydrocarbon transportation and processing tariffs. It is hoped that this paper having highlighted the importance of tariff charges and the role of proper framing on decision quality will encourage decision makers to adopt this approach during decision analysis and ultimately improve the quality of investment decisions particularly for Non-operated venture (NOV) projects.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"22 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74575466","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}
Blessyn Okpowo, Ebenezer Ageh, Peter Agodo, A. Okon, B. Mfon, Tata Emmanuel
The Oil Mining License (OML) 26 Asset is in Isoko North Local Government Area, about 60km east of Warri in Delta State, an onshore asset in the northern Niger Delta. NPDC and FHN are partners for a joint operation of the mining lease and currently executes its function through an Asset Management Team (AMT), comprising employees of NPDC and FHN. The company (OML 26 JV) entered into a Global Memorandum of Understanding (GMOU) with OML 26 host communities to create an understanding and guide its relationship with the communities. The GMOU did not produced the desired result as OML 26 operations have often been interrupted by Community related issues. There is a lack of mutual trust on both sides and the Community and its agents tend to hold the company to ransom at the slightest opportunity. In a bid to reverse the trend, the AMT took the initiative to step back and assess the root cause of the acrimony, thoroughly engage the right elements within the Community to gauge their perspectives, and then developed a series of initiatives aimed at regaining the trust of the host communities. A framework is being developed that has engendered collaboration with the host communities (within its operating area) to build a mutually beneficial and symbiotic relationship that enables each party to achieve their goals and aspirations albeit in a peaceful, hitch free atmosphere. The AMT in line with the vision of the JV Partners is committed to sustainable community development, human capital development and capacity building, economic empowerment, and infrastructural growth. This paper highlights the key elements of the framework and the engagement strategies that has enabled the AMT to enjoy relative peace and operational stability while ramping up production and executing developmental projects in the communities.
石油开采许可证(OML) 26资产位于Isoko North Local Government Area，位于三角洲州Warri以东约60公里处，是尼日尔三角洲北部的陆上资产。NPDC和FHN是采矿租赁联合运营的合作伙伴，目前通过由NPDC和FHN员工组成的资产管理团队(AMT)执行其职能。该公司(OML 26合资公司)与OML 26主办社区签署了一份全球谅解备忘录(GMOU)，以建立谅解并指导其与社区的关系。GMOU没有产生预期的结果，因为OML 26的操作经常被与社区有关的问题中断。双方缺乏相互信任，社区及其代理人往往一有机会就会向公司勒索赎金。为了扭转这一趋势，AMT主动退后一步，评估恶语相向的根本原因，彻底让社区内的合适人士参与进来，评估他们的观点，然后制定了一系列旨在重新获得东道社区信任的举措。目前正在拟订一个框架，促成与东道社区(在其业务范围内)的合作，以建立一种互利和共生的关系，使每一方能够在和平、无阻碍的气氛中实现其目标和愿望。根据合资伙伴的愿景，AMT致力于可持续社区发展、人力资本开发和能力建设、经济赋权和基础设施增长。本文强调了框架和参与战略的关键要素，这些要素使AMT能够在提高生产和执行社区发展项目的同时享有相对的和平和运营稳定。
{"title":"Gains of an Effective Community Management Framework: The OML26 Experience","authors":"Blessyn Okpowo, Ebenezer Ageh, Peter Agodo, A. Okon, B. Mfon, Tata Emmanuel","doi":"10.2118/198802-MS","DOIUrl":"https://doi.org/10.2118/198802-MS","url":null,"abstract":"\u0000 The Oil Mining License (OML) 26 Asset is in Isoko North Local Government Area, about 60km east of Warri in Delta State, an onshore asset in the northern Niger Delta. NPDC and FHN are partners for a joint operation of the mining lease and currently executes its function through an Asset Management Team (AMT), comprising employees of NPDC and FHN.\u0000 The company (OML 26 JV) entered into a Global Memorandum of Understanding (GMOU) with OML 26 host communities to create an understanding and guide its relationship with the communities. The GMOU did not produced the desired result as OML 26 operations have often been interrupted by Community related issues. There is a lack of mutual trust on both sides and the Community and its agents tend to hold the company to ransom at the slightest opportunity. In a bid to reverse the trend, the AMT took the initiative to step back and assess the root cause of the acrimony, thoroughly engage the right elements within the Community to gauge their perspectives, and then developed a series of initiatives aimed at regaining the trust of the host communities. A framework is being developed that has engendered collaboration with the host communities (within its operating area) to build a mutually beneficial and symbiotic relationship that enables each party to achieve their goals and aspirations albeit in a peaceful, hitch free atmosphere. The AMT in line with the vision of the JV Partners is committed to sustainable community development, human capital development and capacity building, economic empowerment, and infrastructural growth. This paper highlights the key elements of the framework and the engagement strategies that has enabled the AMT to enjoy relative peace and operational stability while ramping up production and executing developmental projects in the communities.","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":"83099697","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}
Ejimofor Agbo, Chinedu Anyanwu, Oluwasola Olowoyeye, Titus Ini, Victor Emah
This paper demonstrates how 280ft of oil column spread unevenly across multiple and differentially depleted reservoir units separated by shale layers of varying thicknesses in a highly deviated (62 deg.) well was perforated in a one trip system and how the project cost was minimized by achieving multiple perforations in a single trip whilst retaining capacity to effectively cure losses and mitigating post-perforation well control risks. Against the conventional perforation methodology where reservoir units are perforated individually, isolated before carrying out the next perforation in the subsequent reservoir. The one trip system was designed and deployed in one run targeting all the 6 separate carefully selected sand lobes in one run ensuring good standoff from the contact and zonal isolation behind casing. Successful execution was confirmed with all the expected physical outcomes which includes pipe vibration, brine loss as well inspection of the spent guns. A post perforation noise and production logging also confirmed flow across all planned perforation intervals. Perforation of a highly deviated well in differentially depleted multi-lobed reservoirs present significant operational risks. This paper illustrates how one can safely collapse multiple conventional perforation runs into a single trip with its attendant benefits on cost efficiency, crossflow and well control. This is the first of its kind in a swampy terrain, shallow offshore Niger Delta.
{"title":"Single Trip Tubing Conveyed Perforations Across Multi-Lobed Differentially Depleted Reservoir Complexes In A Highly Deviated Well – Challenges, Lessons Learned & Best Practices","authors":"Ejimofor Agbo, Chinedu Anyanwu, Oluwasola Olowoyeye, Titus Ini, Victor Emah","doi":"10.2118/198757-MS","DOIUrl":"https://doi.org/10.2118/198757-MS","url":null,"abstract":"\u0000 This paper demonstrates how 280ft of oil column spread unevenly across multiple and differentially depleted reservoir units separated by shale layers of varying thicknesses in a highly deviated (62 deg.) well was perforated in a one trip system and how the project cost was minimized by achieving multiple perforations in a single trip whilst retaining capacity to effectively cure losses and mitigating post-perforation well control risks. Against the conventional perforation methodology where reservoir units are perforated individually, isolated before carrying out the next perforation in the subsequent reservoir. The one trip system was designed and deployed in one run targeting all the 6 separate carefully selected sand lobes in one run ensuring good standoff from the contact and zonal isolation behind casing. Successful execution was confirmed with all the expected physical outcomes which includes pipe vibration, brine loss as well inspection of the spent guns. A post perforation noise and production logging also confirmed flow across all planned perforation intervals. Perforation of a highly deviated well in differentially depleted multi-lobed reservoirs present significant operational risks. This paper illustrates how one can safely collapse multiple conventional perforation runs into a single trip with its attendant benefits on cost efficiency, crossflow and well control. This is the first of its kind in a swampy terrain, shallow offshore Niger Delta.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"47 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88579467","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 use of Artificial Intelligence continues to grow in popularity within the geosciences in view of ever-growing complexity and magnitude of available subsurface data. This is equally evident by the need for faster and accurate interpretations required to find hydrocarbons in ever more challenging and increasingly complex basins. This drive is made necessary in a continuously evolving and cost conscious petroleum industry business environment. Advances in computing architecture now easily allows for more common application of machine learning techniques in day to day geoscience workflows. The use of machine learning in permeability prediction is becoming ever more common place as more specialists adopt this technique for modelling and prediction purposes. Typical machine learning techniques include Fuzzy Logic, Artificial Neural Networks (ANN) and Self Organizing Maps (SOM) amongst others which are run both in supervised and unsupervised modes. The described workflow in this paper was carried out using an available commercial standard petrophysical package with ANN built in modules. This paper describes a typical workflow for predicting reservoir permeability based on an integrated workflow utilizing core measurements integrated with available log data. Permeability is a key rock parameter for understanding fluid flow dynamics and flow rates and its modelling usually poses some unique challenges. Traditionally and statistically, this can be done at a fairly coarse level in cored wells by utilizing Poro-Perm correlations that usually do not capture fine scale variability observed at core scale measurement. These Poro-Perm transforms are subsequently applied on uncored wells to predict permeability. This paper analyses a workflow that aims to utilize a depth-normalized log and core data set trained using an Artificial Neural Network (ANN) module, blind tested on few key cored wells and subsequently used to predict permeability in uncored wells. In conclusion, the recommended workflow will ensure much more realistic and better matching permeability predictions.
{"title":"Machine Learning Application to Permeability Prediction Using Log & Core Measurements: A Realistic Workflow Application for Reservoir Characterization","authors":"Francis Eriavbe, Uzoamaka Okene","doi":"10.2118/198874-MS","DOIUrl":"https://doi.org/10.2118/198874-MS","url":null,"abstract":"\u0000 The use of Artificial Intelligence continues to grow in popularity within the geosciences in view of ever-growing complexity and magnitude of available subsurface data. This is equally evident by the need for faster and accurate interpretations required to find hydrocarbons in ever more challenging and increasingly complex basins. This drive is made necessary in a continuously evolving and cost conscious petroleum industry business environment.\u0000 Advances in computing architecture now easily allows for more common application of machine learning techniques in day to day geoscience workflows. The use of machine learning in permeability prediction is becoming ever more common place as more specialists adopt this technique for modelling and prediction purposes. Typical machine learning techniques include Fuzzy Logic, Artificial Neural Networks (ANN) and Self Organizing Maps (SOM) amongst others which are run both in supervised and unsupervised modes. The described workflow in this paper was carried out using an available commercial standard petrophysical package with ANN built in modules. This paper describes a typical workflow for predicting reservoir permeability based on an integrated workflow utilizing core measurements integrated with available log data.\u0000 Permeability is a key rock parameter for understanding fluid flow dynamics and flow rates and its modelling usually poses some unique challenges. Traditionally and statistically, this can be done at a fairly coarse level in cored wells by utilizing Poro-Perm correlations that usually do not capture fine scale variability observed at core scale measurement. These Poro-Perm transforms are subsequently applied on uncored wells to predict permeability. This paper analyses a workflow that aims to utilize a depth-normalized log and core data set trained using an Artificial Neural Network (ANN) module, blind tested on few key cored wells and subsequently used to predict permeability in uncored wells. In conclusion, the recommended workflow will ensure much more realistic and better matching permeability predictions.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"31 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87950090","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 notion of Water Saturation is of importance in determining the hydrocarbon saturation (1-Sw) in reservoirs, calculating hydrocarbon in place, hence a vital evidence of reliable formation evaluation. Preconceptions in reserves quantification and hydrocarbon in place estimations arise once the outcome of the water saturation value is erroneous. Several models in the literature have been used for estimating water saturation and oftentimes the variance in confidence level of their results lead to substantial variance in original hydrocarbon in place volumes. Obtaining a better resolution with deeper understanding of the gaps observed in the existing approaches for estimating water saturation (Sw) values have been a major challenge in accurate calculation of hydrocarbon in place. This paper presents a non-resistivity approach for estimating water saturation using Leverett J-function and Reservoir Quality Index with dependency on fluid and facies Values. The innovative approach involves the use of Saturation Height Modelling through Leverett J- function, build facies through Magnetic Resonance Graphical-Based clustering (MRGC) option, use of Regression method and making a simple scripting using logging language (LOGLAN) program in Geolog to achieve the purpose. This current approach has been applied to Niger-Delta alternate shale-sand formation in optimisation of somewhat low recovery of the hydrocarbon reserves due to probably erroneous over estimation of Water Saturation value from Resistivity-based approach. Reliable results from current non-resistivity approach were obtained with average Water Saturation value of 25% as compared to resistivity approach presented by Juhasz with average water saturation value of 32% and non-resistivity approach presented by Brooks-Corey with average water saturation value of 26% and Leverett J- function with average water saturation values of 27% respectively.
{"title":"A Non-Resistivity Approach for Estimating Water Saturation A Case Study in Niger-Delta, Nigeria","authors":"Olabode Awuyo, A. Sunday, A. Fadairo","doi":"10.2118/198753-MS","DOIUrl":"https://doi.org/10.2118/198753-MS","url":null,"abstract":"\u0000 The notion of Water Saturation is of importance in determining the hydrocarbon saturation (1-Sw) in reservoirs, calculating hydrocarbon in place, hence a vital evidence of reliable formation evaluation. Preconceptions in reserves quantification and hydrocarbon in place estimations arise once the outcome of the water saturation value is erroneous. Several models in the literature have been used for estimating water saturation and oftentimes the variance in confidence level of their results lead to substantial variance in original hydrocarbon in place volumes. Obtaining a better resolution with deeper understanding of the gaps observed in the existing approaches for estimating water saturation (Sw) values have been a major challenge in accurate calculation of hydrocarbon in place.\u0000 This paper presents a non-resistivity approach for estimating water saturation using Leverett J-function and Reservoir Quality Index with dependency on fluid and facies Values. The innovative approach involves the use of Saturation Height Modelling through Leverett J- function, build facies through Magnetic Resonance Graphical-Based clustering (MRGC) option, use of Regression method and making a simple scripting using logging language (LOGLAN) program in Geolog to achieve the purpose. This current approach has been applied to Niger-Delta alternate shale-sand formation in optimisation of somewhat low recovery of the hydrocarbon reserves due to probably erroneous over estimation of Water Saturation value from Resistivity-based approach. Reliable results from current non-resistivity approach were obtained with average Water Saturation value of 25% as compared to resistivity approach presented by Juhasz with average water saturation value of 32% and non-resistivity approach presented by Brooks-Corey with average water saturation value of 26% and Leverett J- function with average water saturation values of 27% respectively.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"27 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84446901","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}
Edet Ita Okon, Joseph Adeoluwa Adetuberu, D. Appah
One of the most significant challenges for extending production life in mature waterflood fields is high water production. Couple with high reservoir heterogeneity, extensive layering and faulting, these fields often developed irregular flood patterns after decades of production which compounded the challenge to optimizing recovery from these fields. The severity of this problem can be seen in the Niger Delta oil fields where there are several matured fields that are producing at high water cut after many years of water flooding. The main objective of this study is to maximize oil recovery from a matured waterflood oil field while reducing the water cut. To achieve this objective, simulation studies were conducted on two cases scenarios. The first case was modelling and running waterflood simulation studied without applying pattern flood management (No PFM) while the second case scenario was done by exploring an automated pattern flood management (PFM). This was done with the aid of Petrel E&P software platform and ECLIPSE FrontSim to efficiently optimize the rate of water allocated to individual injectors. Using data from one of the oil fields operating in the Niger Delta, their performances were compared. The PFM gave the best result with a cumulative oil production of 30,727,470 STB when compared with the case of No PFM which gave a cumulative oil production of 26,968,224 STB (about 12% increase in oil recovery). The PFM water cut was 16% when compared with the case of No PFM which gave a water cut of 47% (about 63% reduction in water production). Hence, The PFM approach has made it possible to reduce water injection in more than 30% of the injectors while more than 62% of the producers experienced increase production and reduced water cut. The productivity increased upon automation of the workflow will enable engineers to identify the optimal injection allocation factors. It will also help engineers to understand and produce from the reservoir at an optimized decline rate and ensure the increase in ultimate recovery.
{"title":"Maximising Oil Recovery in Mature Water Floods Using Automated Pattern Flood Management","authors":"Edet Ita Okon, Joseph Adeoluwa Adetuberu, D. Appah","doi":"10.2118/198797-MS","DOIUrl":"https://doi.org/10.2118/198797-MS","url":null,"abstract":"\u0000 One of the most significant challenges for extending production life in mature waterflood fields is high water production. Couple with high reservoir heterogeneity, extensive layering and faulting, these fields often developed irregular flood patterns after decades of production which compounded the challenge to optimizing recovery from these fields. The severity of this problem can be seen in the Niger Delta oil fields where there are several matured fields that are producing at high water cut after many years of water flooding. The main objective of this study is to maximize oil recovery from a matured waterflood oil field while reducing the water cut. To achieve this objective, simulation studies were conducted on two cases scenarios. The first case was modelling and running waterflood simulation studied without applying pattern flood management (No PFM) while the second case scenario was done by exploring an automated pattern flood management (PFM). This was done with the aid of Petrel E&P software platform and ECLIPSE FrontSim to efficiently optimize the rate of water allocated to individual injectors. Using data from one of the oil fields operating in the Niger Delta, their performances were compared. The PFM gave the best result with a cumulative oil production of 30,727,470 STB when compared with the case of No PFM which gave a cumulative oil production of 26,968,224 STB (about 12% increase in oil recovery). The PFM water cut was 16% when compared with the case of No PFM which gave a water cut of 47% (about 63% reduction in water production). Hence, The PFM approach has made it possible to reduce water injection in more than 30% of the injectors while more than 62% of the producers experienced increase production and reduced water cut. The productivity increased upon automation of the workflow will enable engineers to identify the optimal injection allocation factors. It will also help engineers to understand and produce from the reservoir at an optimized decline rate and ensure the increase in ultimate recovery.","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":"88921504","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. Adeyemi, G. Uwerikowe, T. Tyagi, Jed Oukmal, M. Usman
With increasing complexity of reservoir developments, there is often a marked deviation from the field development plan (FDP), thus, requiring complementary developments with infill wells. This paper addresses this necessity whilst using the Akpo field reservoir B as a case study. Our case is an oil-bearing, highly faulted turbidite channel-levees system. The reservoir comprises three different units (Upper, Middle and Lower) with gross interval of about 140 m and good porosity and permeability values. The hydrocarbon-water contact (HWC) varies across fault blocks with little certainty about reservoir connectivity. It was assumed in the initial FDP that two producers located around the top structure would be supported by two injector wells located on the flanks near the HWC. In 2011, the first producer (Akpo-XP) was completed in the three units and equipped with an inflow control valve (ICV). From fluid samples collected and the selective acquisition of dynamic data from these intervals, results showed that the Upper unit was disconnected from the Middle and Lower units. Consequently, Akpo-XP was forced to produce only from the Middle and Lower units in order to be supported by a northern injector (Akpo-YW) in the same interval. To complete the initial development, another pair of wells (producer-injector) was drilled and completed in the upper unit. All wells were equipped with down-hole pressure gauges for connectivity assessment. In 2015, a seismic monitor was acquired, processed and interpreted whilst integrating production, injection and pressure data. The 4D seismic data confirmed specific fluid movements in the reservoir and a reservoir re-development could be sanctioned with two infill wells (one producer and one injector) with estimated increase in up to 16 Mboe of reserves and incremental production of 13 kbopd. A post-mortem analysis of these two infill wells showed a combined incremental production slightly above expectations.
{"title":"Complex Reservoir Re-Development in a Deep Offshore Maturing Field: Akpo Field Case Study","authors":"A. Adeyemi, G. Uwerikowe, T. Tyagi, Jed Oukmal, M. Usman","doi":"10.2118/198747-MS","DOIUrl":"https://doi.org/10.2118/198747-MS","url":null,"abstract":"\u0000 With increasing complexity of reservoir developments, there is often a marked deviation from the field development plan (FDP), thus, requiring complementary developments with infill wells. This paper addresses this necessity whilst using the Akpo field reservoir B as a case study. Our case is an oil-bearing, highly faulted turbidite channel-levees system. The reservoir comprises three different units (Upper, Middle and Lower) with gross interval of about 140 m and good porosity and permeability values. The hydrocarbon-water contact (HWC) varies across fault blocks with little certainty about reservoir connectivity. It was assumed in the initial FDP that two producers located around the top structure would be supported by two injector wells located on the flanks near the HWC. In 2011, the first producer (Akpo-XP) was completed in the three units and equipped with an inflow control valve (ICV). From fluid samples collected and the selective acquisition of dynamic data from these intervals, results showed that the Upper unit was disconnected from the Middle and Lower units. Consequently, Akpo-XP was forced to produce only from the Middle and Lower units in order to be supported by a northern injector (Akpo-YW) in the same interval. To complete the initial development, another pair of wells (producer-injector) was drilled and completed in the upper unit. All wells were equipped with down-hole pressure gauges for connectivity assessment.\u0000 In 2015, a seismic monitor was acquired, processed and interpreted whilst integrating production, injection and pressure data. The 4D seismic data confirmed specific fluid movements in the reservoir and a reservoir re-development could be sanctioned with two infill wells (one producer and one injector) with estimated increase in up to 16 Mboe of reserves and incremental production of 13 kbopd.\u0000 A post-mortem analysis of these two infill wells showed a combined incremental production slightly above expectations.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"8 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80450630","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 Well with plug set in both tubing was sabotaged and even after initially capping the well, it was observed that attempting to kill the Target Well via surface pumping was abortive. Therefore, in order to achieve well control, drilling a relief well became imperative and required some critical decision to be taken. This include location selection, type fluid to be used in drilling, the casing setting depth, downhole measuring tools for use, as well as contractors needed in achieving success in a suitation of incomplete well survey data. This paper presents how this keys needs were met in drilling the Relief Well planned for 97days trouble free and performed in 107days from spud to hitting Target Well. The success was on single attempt in spite of it having an incomplete survey record acquired 49 years earlier.
{"title":"Efficient Placement of Relief Well Using Combination of Tools","authors":"A. Pedro, D. Feltracco, A. Pasquale, E. Gravante","doi":"10.2118/198760-MS","DOIUrl":"https://doi.org/10.2118/198760-MS","url":null,"abstract":"\u0000 A Well with plug set in both tubing was sabotaged and even after initially capping the well, it was observed that attempting to kill the Target Well via surface pumping was abortive.\u0000 Therefore, in order to achieve well control, drilling a relief well became imperative and required some critical decision to be taken. This include location selection, type fluid to be used in drilling, the casing setting depth, downhole measuring tools for use, as well as contractors needed in achieving success in a suitation of incomplete well survey data.\u0000 This paper presents how this keys needs were met in drilling the Relief Well planned for 97days trouble free and performed in 107days from spud to hitting Target Well. The success was on single attempt in spite of it having an incomplete survey record acquired 49 years earlier.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"78 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83759393","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}
S. Mohammed, Prosper Anumah, Justice Sarkodie-kyeremeh, Anthony Morgan, E. Acheaw
Arps’ hyperbolic model has historically been used to analyze and forecast gas well performance. This is largely due to its simplicity and explicit nature. Unfortunately, because of the variations of viscosity-compressibility product with average reservoir pressure during boundary-dominated flow (BDF) period, the Arps’ hyperbolic model overestimates gas reserves and future rates. Consequently, existing rate-decline models rely heavily on pseudotime. Unfortunately, pseudotime requires iteration, which is time-consuming. This paper proposes an empirical rate-decline model for a gas well producing at a constant pressure during BDF. The proposed model utilizes a drawdown correlating parameter that accounts for formation and water compressibilities, as well as the variations of gas properties with pressure. Due to its explicit nature, the proposed rate-decline model can be used to forecast future gas well performance. An explicit model for estimating the decline exponent for a gas well is also proposed. In addition, this paper presents a semi-empirical flowing material balance (SE-FMB) method that allows the estimation of initial gas-in-place, real gas productivity index and estimated ultimate recovery. The advantages of the proposed SE-FMB over the existing methods are two-folds: first, it is iterationless; and second, it avoids the use of a functional relation (or curve fitting) of viscosity-compressibility product and pressure. The results of this study suggest that the decline exponent for a gas well is time-independent at early-time BDF period and time-dependent at late-time BDF period. At very late-time BDF period, the decline exponent tends to zero. Thus, gas well production data exhibit a hyperbolic decline at early-time BDF period and a transition period at late-time BDF period. At very late-time BDF period, an exponential decline is expected. While the exponential-decline period is not observed in practice due to economic-rate constraints, the hyperbolic-decline period is observed in practice. The transition period may or may not be observed in practice depending on the magnitude of the drawdown parameter and the economic-rate constraints. Comparison of the models results indicates that the proposed rate-decline and the classical Arps’ hyperbolic models are consistent with the rate history during the hyperbolic-decline period; however, the proposed rate-decline model out-performs the classical Arps’ hyperbolic model when the transition period prevails. The results of this study also indicate that ignoring the formation and water compressibilities lead to an overestimation of gas reserves even for a normally-pressured gas reservoir. Simulated and field data have been used to demonstrate the validity and applicability of the proposed model and analysis method.
{"title":"Analysis of Boundary-Dominated Gas Well Production Data","authors":"S. Mohammed, Prosper Anumah, Justice Sarkodie-kyeremeh, Anthony Morgan, E. Acheaw","doi":"10.2118/198732-MS","DOIUrl":"https://doi.org/10.2118/198732-MS","url":null,"abstract":"\u0000 Arps’ hyperbolic model has historically been used to analyze and forecast gas well performance. This is largely due to its simplicity and explicit nature. Unfortunately, because of the variations of viscosity-compressibility product with average reservoir pressure during boundary-dominated flow (BDF) period, the Arps’ hyperbolic model overestimates gas reserves and future rates. Consequently, existing rate-decline models rely heavily on pseudotime. Unfortunately, pseudotime requires iteration, which is time-consuming.\u0000 This paper proposes an empirical rate-decline model for a gas well producing at a constant pressure during BDF. The proposed model utilizes a drawdown correlating parameter that accounts for formation and water compressibilities, as well as the variations of gas properties with pressure. Due to its explicit nature, the proposed rate-decline model can be used to forecast future gas well performance. An explicit model for estimating the decline exponent for a gas well is also proposed. In addition, this paper presents a semi-empirical flowing material balance (SE-FMB) method that allows the estimation of initial gas-in-place, real gas productivity index and estimated ultimate recovery. The advantages of the proposed SE-FMB over the existing methods are two-folds: first, it is iterationless; and second, it avoids the use of a functional relation (or curve fitting) of viscosity-compressibility product and pressure.\u0000 The results of this study suggest that the decline exponent for a gas well is time-independent at early-time BDF period and time-dependent at late-time BDF period. At very late-time BDF period, the decline exponent tends to zero. Thus, gas well production data exhibit a hyperbolic decline at early-time BDF period and a transition period at late-time BDF period. At very late-time BDF period, an exponential decline is expected. While the exponential-decline period is not observed in practice due to economic-rate constraints, the hyperbolic-decline period is observed in practice. The transition period may or may not be observed in practice depending on the magnitude of the drawdown parameter and the economic-rate constraints. Comparison of the models results indicates that the proposed rate-decline and the classical Arps’ hyperbolic models are consistent with the rate history during the hyperbolic-decline period; however, the proposed rate-decline model out-performs the classical Arps’ hyperbolic model when the transition period prevails. The results of this study also indicate that ignoring the formation and water compressibilities lead to an overestimation of gas reserves even for a normally-pressured gas reservoir. Simulated and field data have been used to demonstrate the validity and applicability of the proposed model and analysis method.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"49 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87982701","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 research entails evaluation of existing interfacial friction factor, gas-wall shear stress, and liquid wall shear stress correlations for the prediction of liquid holdup in pipelines. In addition, a statistical analysis was conducted on the predicted and measured flow parameters. Stratified horizontal two-phase flow equation was used in deriving an equation that solves for liquid holdup that is dependent on the interfacial shear stress. The model was implemented in a MATLAB integrated development environment to observe the effect of interfacial friction factors obtained from existing correlations. The results obtained from the comparative study of selected friction factors indicate that some of the correlations show high deviation from experimentally determined values. The largest deviation was observed in the model proposed by Sinai which was because of the condition for which it was originally developed is not suited for horizontal stratified two-phase gas-liquid flow. It was also observed that the correlation of Petalas and Aziz gave the best result and least deviation from the measured values. The performance of each correlation was observed to vary with the assumed values of liquid height. All the correlations gave good predictions at 30% liquid height but performed poorly at 40% liquid height.
{"title":"Evaluation of Interfacial Friction Models in Stratified Flow: Gas-Liquid Two-Phase Flow","authors":"Mobolaji Abegunde, T. Briggs, F. Abam, T. Awolola","doi":"10.2118/198840-MS","DOIUrl":"https://doi.org/10.2118/198840-MS","url":null,"abstract":"\u0000 This research entails evaluation of existing interfacial friction factor, gas-wall shear stress, and liquid wall shear stress correlations for the prediction of liquid holdup in pipelines. In addition, a statistical analysis was conducted on the predicted and measured flow parameters. Stratified horizontal two-phase flow equation was used in deriving an equation that solves for liquid holdup that is dependent on the interfacial shear stress. The model was implemented in a MATLAB integrated development environment to observe the effect of interfacial friction factors obtained from existing correlations. The results obtained from the comparative study of selected friction factors indicate that some of the correlations show high deviation from experimentally determined values. The largest deviation was observed in the model proposed by Sinai which was because of the condition for which it was originally developed is not suited for horizontal stratified two-phase gas-liquid flow. It was also observed that the correlation of Petalas and Aziz gave the best result and least deviation from the measured values. The performance of each correlation was observed to vary with the assumed values of liquid height. All the correlations gave good predictions at 30% liquid height but performed poorly at 40% liquid height.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"3 5","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91431094","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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