Felix O. Okoro, E. Arochukwu, Segun Adomokhai, L. Dennar
The M001 project involved the hook-up of 12 wells (17 conduits) which were drilled and completed between year 2000 and 2005 but were closed-in for operational reasons, until year 2019 when the first seven (7) conduits on cluster MX1 were cleaned up successfully. The seven conduits (Well-A, Well-B, Well-C, Well-D, Well-E, Well-F & Well-G) were expected to flow via three 8" bulk lines. Post well open-up and handover to production, significant bulking / backing out effects were observed. An average Flow Line Pressure (FLP) of ∼22 bar was recorded on the flowlines, hence limiting the capacity to bulk the wells, [FLP increases towards Flowing Tubing Head Pressure (FTHP) hence, pushing the well out of the critical flow envelope as FTHP<<1.7FLP]. Due to this challenge, total production from Cluster MX1 was sub-optimal with only five (5) conduits out of seven (7) able to flow due to bulking and backing out effect. The sub-optimal performance from the conduits were investigated using the Integrated Production System Model (IPSM) / PIPESIM models. Four different scenarios were run in the model and the calibrated IPSM model indicated all 7 conduits should flow if there are no surface restrictions. The model identified pressure, mass and rate imbalances in the integrated system and suggested the presence of a restriction at the manifold, causing sub-optimal production from the wells. The model outcome triggered an onsite investigation / troubleshooting from the wellhead to the manifold at the facilities end where an adjustable choke was identified in the ligaments of the manifold. In line with process safety requirements, a risk assessment was carried out and a Management of Change (MOC) raised to remove the adjustable choke at the manifold. Post implementation of the intervention, all the seven (7) conduits produced without any bulking effect. Total production realized from the seven (7) conduits post execution of the recommended action is ca. 9.3 kbopd against 5.2 kbopd pre-intervention. A total of ca. 4.1 kbopd production gain was realized and 10 mln USD proposed for additional bulkline was saved.
{"title":"Front-End Integrated Production System Modelling for Production Optimization – Experience from a Niger Delta Field","authors":"Felix O. Okoro, E. Arochukwu, Segun Adomokhai, L. Dennar","doi":"10.2118/207124-ms","DOIUrl":"https://doi.org/10.2118/207124-ms","url":null,"abstract":"\u0000 The M001 project involved the hook-up of 12 wells (17 conduits) which were drilled and completed between year 2000 and 2005 but were closed-in for operational reasons, until year 2019 when the first seven (7) conduits on cluster MX1 were cleaned up successfully. The seven conduits (Well-A, Well-B, Well-C, Well-D, Well-E, Well-F & Well-G) were expected to flow via three 8\" bulk lines. Post well open-up and handover to production, significant bulking / backing out effects were observed.\u0000 An average Flow Line Pressure (FLP) of ∼22 bar was recorded on the flowlines, hence limiting the capacity to bulk the wells, [FLP increases towards Flowing Tubing Head Pressure (FTHP) hence, pushing the well out of the critical flow envelope as FTHP<<1.7FLP]. Due to this challenge, total production from Cluster MX1 was sub-optimal with only five (5) conduits out of seven (7) able to flow due to bulking and backing out effect. The sub-optimal performance from the conduits were investigated using the Integrated Production System Model (IPSM) / PIPESIM models. Four different scenarios were run in the model and the calibrated IPSM model indicated all 7 conduits should flow if there are no surface restrictions. The model identified pressure, mass and rate imbalances in the integrated system and suggested the presence of a restriction at the manifold, causing sub-optimal production from the wells.\u0000 The model outcome triggered an onsite investigation / troubleshooting from the wellhead to the manifold at the facilities end where an adjustable choke was identified in the ligaments of the manifold. In line with process safety requirements, a risk assessment was carried out and a Management of Change (MOC) raised to remove the adjustable choke at the manifold.\u0000 Post implementation of the intervention, all the seven (7) conduits produced without any bulking effect. Total production realized from the seven (7) conduits post execution of the recommended action is ca. 9.3 kbopd against 5.2 kbopd pre-intervention. A total of ca. 4.1 kbopd production gain was realized and 10 mln USD proposed for additional bulkline was saved.","PeriodicalId":10899,"journal":{"name":"Day 2 Tue, August 03, 2021","volume":"73 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-02","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80595278","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}
Bassey Akong, Samuel Orimoloye, F. Otutu, Akinwale Ojo, Goodluck Mfonnom, O. Mrakpor, Edward Obasuyi, Ogba Samuel, Olumide Oladoyin
The analysis of wellbore stability in gas wells is vital for effective drilling operations, especially in Brown fields and for modern drilling technologies. Tensile failure mode of Wellbore stability problems usually occur when drilling through hydrocarbon formations such as shale, unconsolidated sandstone, sand units, natural fractured formations and HPHT formations with narrow safety mud window. These problems can significantly affect drilling time, costs and the whole drilling operations. In the case of the candidate onshore gas well Niger Delta, there was severe lost circulation events and gas cut mud while drilling. However, there was need for a consistent adjustment of the tight drilling margin, flow, and mud rheology to allow for effective filter-cake formation around the penetrated natural fractures and traversed depleted intervals without jeopardizing the well integrity. Several assumptions were validly made for formations with voids or natural fractures, because the presence of these geological features influenced rock anisotropic properties, wellbore stress concentration and failure behavior with end point of partial – to-total loss circulation events. This was a complicated phenomenon, because the pre-drilled stress distribution simulation around the candidate wellbore was investigated to be affected by factors such as rock properties, far-field principal stresses, wellbore trajectory, formation pore pressure, reservoir and drilling fluids properties and time without much interest on traversing through voids or naturally fractured layers. This study reviews the major causes of the severe losses encountered, the adopted fractured permeability mid-line mudweight window mitigation process, stress caging strategies and other operational decisions adopted to further salvage and drill through the naturally fractured and depleted intervals, hence regaining the well integrity by reducing NPT and promoting well-early-time-production for the onshore gas well Niger Delta.
{"title":"Managing Wellbore Stability Window and Well Integrity by Adjusting the Tight Margin to Successfully Drill through Naturally Fractured Zone Onshore Niger Delta","authors":"Bassey Akong, Samuel Orimoloye, F. Otutu, Akinwale Ojo, Goodluck Mfonnom, O. Mrakpor, Edward Obasuyi, Ogba Samuel, Olumide Oladoyin","doi":"10.2118/207189-ms","DOIUrl":"https://doi.org/10.2118/207189-ms","url":null,"abstract":"\u0000 The analysis of wellbore stability in gas wells is vital for effective drilling operations, especially in Brown fields and for modern drilling technologies. Tensile failure mode of Wellbore stability problems usually occur when drilling through hydrocarbon formations such as shale, unconsolidated sandstone, sand units, natural fractured formations and HPHT formations with narrow safety mud window. These problems can significantly affect drilling time, costs and the whole drilling operations. In the case of the candidate onshore gas well Niger Delta, there was severe lost circulation events and gas cut mud while drilling. However, there was need for a consistent adjustment of the tight drilling margin, flow, and mud rheology to allow for effective filter-cake formation around the penetrated natural fractures and traversed depleted intervals without jeopardizing the well integrity. Several assumptions were validly made for formations with voids or natural fractures, because the presence of these geological features influenced rock anisotropic properties, wellbore stress concentration and failure behavior with end point of partial – to-total loss circulation events. This was a complicated phenomenon, because the pre-drilled stress distribution simulation around the candidate wellbore was investigated to be affected by factors such as rock properties, far-field principal stresses, wellbore trajectory, formation pore pressure, reservoir and drilling fluids properties and time without much interest on traversing through voids or naturally fractured layers. This study reviews the major causes of the severe losses encountered, the adopted fractured permeability mid-line mudweight window mitigation process, stress caging strategies and other operational decisions adopted to further salvage and drill through the naturally fractured and depleted intervals, hence regaining the well integrity by reducing NPT and promoting well-early-time-production for the onshore gas well Niger Delta.","PeriodicalId":10899,"journal":{"name":"Day 2 Tue, August 03, 2021","volume":"75 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-02","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80960061","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 present study investigates the Anambra Basin shales to determine the provenance and maturity of the sediments using standard geochemical techniques. Twelve (12) representative samples recovered from shale sequences of The Mamu Formation and Nkporo Group of The Anambra Basin were studied to determine the sediment provenance, paleoenvironment, diagenetic conditions, maturity as well as the tectonic setting. To consider in detail and establish the inherent constituents of the Major minerals, Trace and Rare Earth elements, Inductively Coupled Plasma Mass Spectrometry (ICP-MS) analyses techniques was employed. The detrital minerals determined are Al2O3 (18.27% and 21.16%), TiO2 (1.73% and 1.63%) and Fe2O3 (2.78% and 2.85%), for Nkporo Group and Mamu Formation respectively. The enrichment of SiO2, Al2O3 and TiO2 (1.14, 1.94, 3.67 respectively) supported by Chemical Index of Alteration (CIA) of 93.54 & 39.55 and Rb/Sr ratio of 0.57 & 0.40, indicate that the Anambra Basin sediments are matured. TiO2/AL2O3 binary plots, Th/Co Vs La/Sc crossplots, Th-Sc-Zr triplots and Cr, Ni concentration suggest mixed provenance of felsic to mafic source rocks for these sediments. From the log (K2O/Na2O) Vs SiO2 crossplots, a passive margin tectonic setting was determined for these sediments.
本文利用标准地球化学技术对阿南布拉盆地页岩进行了研究，以确定沉积物的物源和成熟度。对阿南布拉盆地马木组和恩波罗组页岩层序中12个具有代表性的样品进行了研究，确定了沉积物源、古环境、成岩条件、成熟度和构造背景。为了详细考虑并确定主要矿物、微量元素和稀土元素的固有成分，采用了电感耦合等离子体质谱(ICP-MS)分析技术。Nkporo组和Mamu组的碎屑矿物分别为Al2O3(18.27%和21.16%)、TiO2(1.73%和1.63%)和Fe2O3(2.78%和2.85%)。化学蚀变指数(CIA)分别为93.54和39.55,Rb/Sr比值为0.57和0.40,SiO2、Al2O3和TiO2的富集程度分别为1.14、1.94和3.67，表明阿南布拉盆地的沉积物已经成熟。TiO2/AL2O3二元图、Th/Co Vs La/Sc交叉图、Th-Sc- zr三角图和Cr、Ni浓度显示沉积物源岩为长英质-基性混合物源岩。根据测井(K2O/Na2O) Vs SiO2交会图，确定了这些沉积物的被动边缘构造背景。
{"title":"Geochemical Characteristics of the Campano-Maastrictian Sediments of the Anambra Basin, Southeastern Nigeria - Implication For Provenance, Paleodepositional Environment, Maturity and Tectonic Setting","authors":"M. E. Okiotor, E. D. Ogueh","doi":"10.2118/207170-ms","DOIUrl":"https://doi.org/10.2118/207170-ms","url":null,"abstract":"\u0000 The present study investigates the Anambra Basin shales to determine the provenance and maturity of the sediments using standard geochemical techniques. Twelve (12) representative samples recovered from shale sequences of The Mamu Formation and Nkporo Group of The Anambra Basin were studied to determine the sediment provenance, paleoenvironment, diagenetic conditions, maturity as well as the tectonic setting.\u0000 To consider in detail and establish the inherent constituents of the Major minerals, Trace and Rare Earth elements, Inductively Coupled Plasma Mass Spectrometry (ICP-MS) analyses techniques was employed. The detrital minerals determined are Al2O3 (18.27% and 21.16%), TiO2 (1.73% and 1.63%) and Fe2O3 (2.78% and 2.85%), for Nkporo Group and Mamu Formation respectively. The enrichment of SiO2, Al2O3 and TiO2 (1.14, 1.94, 3.67 respectively) supported by Chemical Index of Alteration (CIA) of 93.54 & 39.55 and Rb/Sr ratio of 0.57 & 0.40, indicate that the Anambra Basin sediments are matured. TiO2/AL2O3 binary plots, Th/Co Vs La/Sc crossplots, Th-Sc-Zr triplots and Cr, Ni concentration suggest mixed provenance of felsic to mafic source rocks for these sediments. From the log (K2O/Na2O) Vs SiO2 crossplots, a passive margin tectonic setting was determined for these sediments.","PeriodicalId":10899,"journal":{"name":"Day 2 Tue, August 03, 2021","volume":"62 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-02","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75092436","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}
Oil price is primarily determined by global supply and demand forces as well as governments policies and action or inaction of institutions like OPEC. However, in recent times, it has become evident that public health is a vital factor influencing demand and in turn oil price. In US, oil price reached a negative value for the first time in history by April 2020. Personnel and public health have been shown to have profound effect on operational expenditure (OPEX) of organizations, this in turn affecting the profitability of such organizations. Extra measures involving cost, had to be taken by organizations all over the world to ensure health and safety of their personnel in their sites. In Nigeria, effect of covid-19 measures for companies were, shut in of production, declaration of force majeure on ongoing contracts, slashing of costs, suspension on evaluation of future projects, profile assets for sale, remote/tele working, etc. Huge costs were also incurred as a part of corporate social responsibility for host communities/states where they operate. The consequential outcome is that there are reports of lower than planned profitability and liquidity positions. This paper examines action taken during this covid crisis and their impact on the financial status of their organizations. Using a quantitative and descriptive research design, an online survey has been used to gather information from respondents from different oil and gas companies of cost incurred by them. Secondary data was also obtained from quarterly reports of some companies of the oil majors to show their profitability comparing Q1-Q4 of 2019 and 2020. The paper also appraises action and inaction by corporate/government bodies to stimulate economic growth and help its personnel/citizenry. An attempt is also made to glean experience and lessons from organization that lived through the periods being examined.
{"title":"Impact of Public Health on Oil Production Operation Expenditure – Case Study: Covid-19 Era Expenses in Nigeria Oil & Gas Industry","authors":"J. Ugolo","doi":"10.2118/208229-ms","DOIUrl":"https://doi.org/10.2118/208229-ms","url":null,"abstract":"\u0000 Oil price is primarily determined by global supply and demand forces as well as governments policies and action or inaction of institutions like OPEC. However, in recent times, it has become evident that public health is a vital factor influencing demand and in turn oil price. In US, oil price reached a negative value for the first time in history by April 2020.\u0000 Personnel and public health have been shown to have profound effect on operational expenditure (OPEX) of organizations, this in turn affecting the profitability of such organizations. Extra measures involving cost, had to be taken by organizations all over the world to ensure health and safety of their personnel in their sites. In Nigeria, effect of covid-19 measures for companies were, shut in of production, declaration of force majeure on ongoing contracts, slashing of costs, suspension on evaluation of future projects, profile assets for sale, remote/tele working, etc. Huge costs were also incurred as a part of corporate social responsibility for host communities/states where they operate. The consequential outcome is that there are reports of lower than planned profitability and liquidity positions.\u0000 This paper examines action taken during this covid crisis and their impact on the financial status of their organizations. Using a quantitative and descriptive research design, an online survey has been used to gather information from respondents from different oil and gas companies of cost incurred by them. Secondary data was also obtained from quarterly reports of some companies of the oil majors to show their profitability comparing Q1-Q4 of 2019 and 2020. The paper also appraises action and inaction by corporate/government bodies to stimulate economic growth and help its personnel/citizenry. An attempt is also made to glean experience and lessons from organization that lived through the periods being examined.","PeriodicalId":10899,"journal":{"name":"Day 2 Tue, August 03, 2021","volume":"123 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-02","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85258306","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}
Virtue Urunwo Elechi, S. S. Ikiensikimama, J. Ajienka, O. Akaranta, O. Okon
Gas hydrates are impediments to flow of gas and oil and its avoidance and mitigation is key to oil and gas operators. Mitigation via chemical controls is more suitable for marine environments. The effectiveness of 2wt% of an extract from the plant order, Zingiberales has been compared to that of Mono-Ethylene Glycol in a simulated offshore laboratory mini flow loop of 0.5-inch ID. The results from final pressure shows the value of ZE to be 107 psi while that of the MEG was 99 psi. The ∆P for ZE was 43 psi while that of MEG was 51 psi. The difference in ∆P was 8psi more than that of MEG. The Inhibition Capacity (%) values showed ZE to have performed better with a value of 62.28% while that of MEG was 55.26%. ZE had an Inhibition Capacity that was 7.02% more than that of MEG which is mostly imported and is termed a toxic alcohol, meaning that it is both human and environmentally hazardous. ZE therefore should be considered for development as a gas hydrate inhibitor.
{"title":"Zingiberales Extract ZE: A Locally Sourced Natural Compound as Gas Hydrate Inhibitor","authors":"Virtue Urunwo Elechi, S. S. Ikiensikimama, J. Ajienka, O. Akaranta, O. Okon","doi":"10.2118/207154-ms","DOIUrl":"https://doi.org/10.2118/207154-ms","url":null,"abstract":"\u0000 Gas hydrates are impediments to flow of gas and oil and its avoidance and mitigation is key to oil and gas operators. Mitigation via chemical controls is more suitable for marine environments. The effectiveness of 2wt% of an extract from the plant order, Zingiberales has been compared to that of Mono-Ethylene Glycol in a simulated offshore laboratory mini flow loop of 0.5-inch ID. The results from final pressure shows the value of ZE to be 107 psi while that of the MEG was 99 psi. The ∆P for ZE was 43 psi while that of MEG was 51 psi. The difference in ∆P was 8psi more than that of MEG. The Inhibition Capacity (%) values showed ZE to have performed better with a value of 62.28% while that of MEG was 55.26%. ZE had an Inhibition Capacity that was 7.02% more than that of MEG which is mostly imported and is termed a toxic alcohol, meaning that it is both human and environmentally hazardous. ZE therefore should be considered for development as a gas hydrate inhibitor.","PeriodicalId":10899,"journal":{"name":"Day 2 Tue, August 03, 2021","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-02","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91146196","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}
There are a good numbers of brown hydrocarbon reservoirs, with a substantial amount of bypassed oil. These reservoirs are said to be brown, because a huge chunk of its recoverable oil have been produced. Since a significant number of prominent oil fields are matured and the number of new discoveries is declining, it is imperative to assess performances of waterflooding in such reservoirs; taking an undersaturated reservoir as a case study. It should be recalled that Waterflooding is widely accepted and used as a means of secondary oil recovery method, sometimes after depletion of primary energy sources. The effects of permeability distribution on flood performances is of concerns in this study. The presence of high permeability streaks could lead to an early water breakthrough at the producers, thus reducing the sweep efficiency in the field. A solution approach adopted in this study was reserve water injection. A reverse approach because, a producing well is converted to water injector while water injector well is converted to oil producing well. This optimization method was applied to a waterflood process carried out on a reservoir field developed by a two - spot recovery design in the Niger Delta area of Nigeria that is being used as a case study. Simulation runs were carried out with a commercial reservoir oil simulator. The result showed an increase in oil production with a significant reduction in water-cut. The Net Present Value, NPV, of the project was re-evaluated with present oil production. The results of the waterflood optimization revealed that an increase in the net present value of up to 20% and an increase in cumulative production of up to 27% from the base case was achieved. The cost of produced water treatment for re-injection and rated higher water pump had little impact on the overall project economy. Therefore, it can conclude that changes in well status in wells status in an heterogenous hydrocarbon reservoir will increase oil production.
{"title":"Undersaturated Hydrocarbon Reservoir Waterflooding: A simulation Approach to Performance Assessment","authors":"A. Adeniyi, Miracle Imwonsa Osatemple, A. Giwa","doi":"10.2118/207148-ms","DOIUrl":"https://doi.org/10.2118/207148-ms","url":null,"abstract":"\u0000 There are a good numbers of brown hydrocarbon reservoirs, with a substantial amount of bypassed oil. These reservoirs are said to be brown, because a huge chunk of its recoverable oil have been produced. Since a significant number of prominent oil fields are matured and the number of new discoveries is declining, it is imperative to assess performances of waterflooding in such reservoirs; taking an undersaturated reservoir as a case study. It should be recalled that Waterflooding is widely accepted and used as a means of secondary oil recovery method, sometimes after depletion of primary energy sources. The effects of permeability distribution on flood performances is of concerns in this study. The presence of high permeability streaks could lead to an early water breakthrough at the producers, thus reducing the sweep efficiency in the field. A solution approach adopted in this study was reserve water injection. A reverse approach because, a producing well is converted to water injector while water injector well is converted to oil producing well. This optimization method was applied to a waterflood process carried out on a reservoir field developed by a two - spot recovery design in the Niger Delta area of Nigeria that is being used as a case study. Simulation runs were carried out with a commercial reservoir oil simulator. The result showed an increase in oil production with a significant reduction in water-cut. The Net Present Value, NPV, of the project was re-evaluated with present oil production. The results of the waterflood optimization revealed that an increase in the net present value of up to 20% and an increase in cumulative production of up to 27% from the base case was achieved. The cost of produced water treatment for re-injection and rated higher water pump had little impact on the overall project economy. Therefore, it can conclude that changes in well status in wells status in an heterogenous hydrocarbon reservoir will increase oil production.","PeriodicalId":10899,"journal":{"name":"Day 2 Tue, August 03, 2021","volume":"16 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-02","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86351813","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}
Ayobami Ezekiel, Prince Oduh, E. Okoh, C. Onah, M. Ojah, S. Adewole
In this study, a simpler numerical model for calculating inter-well distance was developed. This model was developed as an alternative to the Ei-function used for computing pressure drops. The mainobjective of developing this model is tomake resolution of pilfering issues easyto resolve. With the developed model, calculations relating to pressure drops and more specifically, inter-well distance, can be done with greater ease and accuracy. In developing this model, the integral equation of the Eifunction in the pressure drop equation was solved numerically. The numerical solution reduced thepressure drop equation to a polynomial equation which is much easier to solve. The developed model was used to solve real problems. Results generated from it were compared with those obtained using previous approaches. Important informationsuch as well configuration, region of the reservoir, and transient history wherethe work is valid are stated. The development of the correlations and tables forthe range of validity and values of the Ei-function is a major quantum leap in well testing and analysis. It will be quite cumbersome to resolve integrals with unknowns, hence, methods of trials and errors have been resorted to over the years. However, this new approach resolved the pressure drop equation into a systemof polynomials which is much easier to solve. Consequently, the distance betweenpossibly interfering wells (which is an important variable during interference test) can now be gotten with ease. The developed model is valid within the range of validity of the Ei-function. Without doubt, this work will help redefine the pressure drop equation into a polynomial equation which can easily be resolved using any of the known approaches to solving problems involving polynomials. More so, getting the correct distance betweenthe two wells in question is pivotal to the test. With the model developed in this work, getting inter-well distance is now easier and more accurate.
{"title":"Numerical Method of Estimating Distance Between Wells","authors":"Ayobami Ezekiel, Prince Oduh, E. Okoh, C. Onah, M. Ojah, S. Adewole","doi":"10.2118/207159-ms","DOIUrl":"https://doi.org/10.2118/207159-ms","url":null,"abstract":"\u0000 In this study, a simpler numerical model for calculating inter-well distance was developed. This model was developed as an alternative to the Ei-function used for computing pressure drops. The mainobjective of developing this model is tomake resolution of pilfering issues easyto resolve. With the developed model, calculations relating to pressure drops and more specifically, inter-well distance, can be done with greater ease and accuracy. In developing this model, the integral equation of the Eifunction in the pressure drop equation was solved numerically. The numerical solution reduced thepressure drop equation to a polynomial equation which is much easier to solve. The developed model was used to solve real problems. Results generated from it were compared with those obtained using previous approaches. Important informationsuch as well configuration, region of the reservoir, and transient history wherethe work is valid are stated. The development of the correlations and tables forthe range of validity and values of the Ei-function is a major quantum leap in well testing and analysis. It will be quite cumbersome to resolve integrals with unknowns, hence, methods of trials and errors have been resorted to over the years. However, this new approach resolved the pressure drop equation into a systemof polynomials which is much easier to solve. Consequently, the distance betweenpossibly interfering wells (which is an important variable during interference test) can now be gotten with ease. The developed model is valid within the range of validity of the Ei-function. Without doubt, this work will help redefine the pressure drop equation into a polynomial equation which can easily be resolved using any of the known approaches to solving problems involving polynomials. More so, getting the correct distance betweenthe two wells in question is pivotal to the test. With the model developed in this work, getting inter-well distance is now easier and more accurate.","PeriodicalId":10899,"journal":{"name":"Day 2 Tue, August 03, 2021","volume":"58 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-02","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83934361","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 most common challenge in horizontal drilling is depth uncertainty which can be due to poor seismic data or interpretation. It is arguable that a successful landing of the wellbore in the reservoir optimally and within the desired zone is the most challenging in most geosteering operation. The presence of fluid contacts such as oil-water-contact (OWC) and gas-oil-contact (GOC) complicates the whole drilling process, most especially if these fluid contacts are not well defined or known. Additionally, the ability to map the boundaries of the reservoir as the BHA drills the lateral section is an added advantage to remaining within the desired reservoir section. The success of any reservoir navigation service where seismic uncertainty at the reservoir top is high will rely largely on how effective the geosteering system is and how the geosteering engineer is able to react promptly to changes while landing the well in the reservoir and drilling the lateral section with without exiting the reservoir. Reservoir Navigation Service (RNS) provides the means for the drilling near horizontal or horizontal wells for the purpose of increasing hydrocarbon extraction from the earth's subsurface. This involves the use of a pre-defined bottom hole assembly (BHA) with inbuilt downhole logging while drilling (LWD) and measurement while drilling (MWD) sensors. The measurements from these downhole sensors are uplinked to the surface of the wellbore where they are converted to meaningful petrophysical data. The goal is to use the downhole petrophysical data such as gamma ray, propagation resistivity and so on, to update an existing pre-well geological model of a section of the earth in such a way that the final result depicts the true model picture of the earth subsurface. This paper focuses on using well CBH-44L to showcase how the use of real-time distance-to-boundary (D2B) measurement from a deep reading azimuthal propagation resistivity tool is use to correct for depth uncertainty in seismic, thereby, improving the chance of successfully landing and drilling a horizontal well.
{"title":"Correcting Subsurface Seismic Depth Uncertainty in Real-Time Using Reservoir Navigation Distance-to-Bed Mapping","authors":"Victor Imomoh, K. Amadi, J. Onyeji","doi":"10.2118/208239-ms","DOIUrl":"https://doi.org/10.2118/208239-ms","url":null,"abstract":"\u0000 The most common challenge in horizontal drilling is depth uncertainty which can be due to poor seismic data or interpretation. It is arguable that a successful landing of the wellbore in the reservoir optimally and within the desired zone is the most challenging in most geosteering operation. The presence of fluid contacts such as oil-water-contact (OWC) and gas-oil-contact (GOC) complicates the whole drilling process, most especially if these fluid contacts are not well defined or known. Additionally, the ability to map the boundaries of the reservoir as the BHA drills the lateral section is an added advantage to remaining within the desired reservoir section.\u0000 The success of any reservoir navigation service where seismic uncertainty at the reservoir top is high will rely largely on how effective the geosteering system is and how the geosteering engineer is able to react promptly to changes while landing the well in the reservoir and drilling the lateral section with without exiting the reservoir.\u0000 Reservoir Navigation Service (RNS) provides the means for the drilling near horizontal or horizontal wells for the purpose of increasing hydrocarbon extraction from the earth's subsurface. This involves the use of a pre-defined bottom hole assembly (BHA) with inbuilt downhole logging while drilling (LWD) and measurement while drilling (MWD) sensors. The measurements from these downhole sensors are uplinked to the surface of the wellbore where they are converted to meaningful petrophysical data. The goal is to use the downhole petrophysical data such as gamma ray, propagation resistivity and so on, to update an existing pre-well geological model of a section of the earth in such a way that the final result depicts the true model picture of the earth subsurface.\u0000 This paper focuses on using well CBH-44L to showcase how the use of real-time distance-to-boundary (D2B) measurement from a deep reading azimuthal propagation resistivity tool is use to correct for depth uncertainty in seismic, thereby, improving the chance of successfully landing and drilling a horizontal well.","PeriodicalId":10899,"journal":{"name":"Day 2 Tue, August 03, 2021","volume":"36 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-02","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88438937","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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