Deposits of heavy oil and natural bitumen have been long-discovered in the Dahomey basin south-western Nigeria. However, inconsistency in estimates of volumes of hydrocarbon contained in these deposits has inhibited commercial interest in the deposits. The inconsistency is attributable to the little or no consideration for spatial variability in those studies. This work is therefore motivated by the need for spatially-coherent geomodels leading to reliable volumetric estimates. An existing database of porosity, depth-to-top and thickness attributes of a section of the deposits located at Agbabu is the subject of this work. This work conducted exploratory spatial data analysis (ESDA) as well as empirical variogram estimation, interpretation and modeling of the attributes. Here, the estimation and interpretation of empirical variogram faced a number of challenges with potentials to render the estimates uninterpretable, unstable and inconsistent with geologic information. These include presence of spatial outlier data, clusteredness of variogram clouds, data paucity, and irregular distribution of point-pairs on variogram clouds. Spatial outliers were either removed or correlated with existing geologic information. The clusteredness issues were resolved using a machine-learning – aided variogram estimation technique recently proposed. Variogram cloud binning approach was deployed to handle irregular distribution of point-pairs. In attempting to deploy an automatic fitting algorithm, cases of insufficient empirical points leading to lack of convergence were encountered. Such cases were resolved by adopting a combination of manual and automatic fitting approaches. Ultimately, this work presents a three-dimensional anisotropic (zonal) porosity variogram model and two-dimensional anisotropic (geometric) models for the depth-to-top and thickness variograms. These models are suitable inputs to spatial interpolation algorithms in generating maps of these volumetric attributes.
{"title":"Estimating and Modeling of Spatial Variability of Volumetric Attributes of a Nigerian Heavy Oil and Bitumen Deposit","authors":"O. Mosobalaje, O. Orodu, D. Ogbe","doi":"10.2118/198859-MS","DOIUrl":"https://doi.org/10.2118/198859-MS","url":null,"abstract":"\u0000 Deposits of heavy oil and natural bitumen have been long-discovered in the Dahomey basin south-western Nigeria. However, inconsistency in estimates of volumes of hydrocarbon contained in these deposits has inhibited commercial interest in the deposits. The inconsistency is attributable to the little or no consideration for spatial variability in those studies. This work is therefore motivated by the need for spatially-coherent geomodels leading to reliable volumetric estimates. An existing database of porosity, depth-to-top and thickness attributes of a section of the deposits located at Agbabu is the subject of this work.\u0000 This work conducted exploratory spatial data analysis (ESDA) as well as empirical variogram estimation, interpretation and modeling of the attributes. Here, the estimation and interpretation of empirical variogram faced a number of challenges with potentials to render the estimates uninterpretable, unstable and inconsistent with geologic information. These include presence of spatial outlier data, clusteredness of variogram clouds, data paucity, and irregular distribution of point-pairs on variogram clouds. Spatial outliers were either removed or correlated with existing geologic information. The clusteredness issues were resolved using a machine-learning – aided variogram estimation technique recently proposed. Variogram cloud binning approach was deployed to handle irregular distribution of point-pairs. In attempting to deploy an automatic fitting algorithm, cases of insufficient empirical points leading to lack of convergence were encountered. Such cases were resolved by adopting a combination of manual and automatic fitting approaches.\u0000 Ultimately, this work presents a three-dimensional anisotropic (zonal) porosity variogram model and two-dimensional anisotropic (geometric) models for the depth-to-top and thickness variograms. These models are suitable inputs to spatial interpolation algorithms in generating maps of these volumetric attributes.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"42 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81121237","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 oil and gas industry require technologies to prevent mineral scale formation and deposition in reservoirs and production systems. One commonly used method to achieve this is the scale inhibitor squeeze treatment. The challenge addressed here using modelling is to prolong the squeeze treatment lifetime in heterogeneous reservoirs, thus, reduce the cost per barrel of oil produced, especially in deep offshore and remote locations. Key to squeeze life extension is ensuring optimum scale inhibitor retention on rock matrix. Therefore, the inhibitor must contact the reservoir rocks and be distributed amongst the layers in proportion to the expected water production rates per layer, which will be determined by reservoir heterogeneity, system geometry and gravitational effects. These effects are studied for an offshore water flooded reservoir by means of a reservoir simulation model. The study reveals that reservoir heterogeneity generally improves inhibitor squeeze treatment performance as measured at surface for the entire well, with more inhibitor being placed in the zones with high permeability-thickness product (kh). However, downhole pressure differentials can result in higher pressure layers being unprotected for longer periods before the inhibitor concentrations for the entire well goes below the Minimum Inhibitor Concentration (MIC). The use of diversion techniques is shown by simulation work to improve placement and thus help achieve a successful inhibitor squeeze treatment in all the reservoir layers. However, inhibitor concentrations may remain relatively high in layers that do not produce much water, resulting in some wastage of inhibitor as a penalty for delaying the time before re-squeezing is required. The modelling helps understand where scale could occur and the best management strategy for scale prevention or control; identifying the impact of scale; giving insight into the best inhibitor squeeze treatment options and expected performance; and providing input needed for the economic model required for good reservoir scale management.
{"title":"The Impact of Reservoir Heterogeneity in the Modelling of Scale Inhibitor Squeeze Treatments","authors":"F. Uzoigwe, E. Mackay, O. Vazquez","doi":"10.2118/198844-MS","DOIUrl":"https://doi.org/10.2118/198844-MS","url":null,"abstract":"\u0000 The oil and gas industry require technologies to prevent mineral scale formation and deposition in reservoirs and production systems. One commonly used method to achieve this is the scale inhibitor squeeze treatment. The challenge addressed here using modelling is to prolong the squeeze treatment lifetime in heterogeneous reservoirs, thus, reduce the cost per barrel of oil produced, especially in deep offshore and remote locations.\u0000 Key to squeeze life extension is ensuring optimum scale inhibitor retention on rock matrix. Therefore, the inhibitor must contact the reservoir rocks and be distributed amongst the layers in proportion to the expected water production rates per layer, which will be determined by reservoir heterogeneity, system geometry and gravitational effects. These effects are studied for an offshore water flooded reservoir by means of a reservoir simulation model.\u0000 The study reveals that reservoir heterogeneity generally improves inhibitor squeeze treatment performance as measured at surface for the entire well, with more inhibitor being placed in the zones with high permeability-thickness product (kh). However, downhole pressure differentials can result in higher pressure layers being unprotected for longer periods before the inhibitor concentrations for the entire well goes below the Minimum Inhibitor Concentration (MIC).\u0000 The use of diversion techniques is shown by simulation work to improve placement and thus help achieve a successful inhibitor squeeze treatment in all the reservoir layers. However, inhibitor concentrations may remain relatively high in layers that do not produce much water, resulting in some wastage of inhibitor as a penalty for delaying the time before re-squeezing is required.\u0000 The modelling helps understand where scale could occur and the best management strategy for scale prevention or control; identifying the impact of scale; giving insight into the best inhibitor squeeze treatment options and expected performance; and providing input needed for the economic model required for good reservoir scale management.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"23 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84667999","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}
Oluwaseun E. Ajayi, K. Lawal, C. Ukaonu, Tunde Alabi, O. Okoh, Obianuju Igbokwe
Drilling fluids are vital elements in the safe, efficient and effective construction of wells. Their key functions include transporting drill cuttings to the surface, cooling and lubrication of drill string, cleaning build-up deposits on drill bits and tools, as well as stabilisation of the borehole and pressure control. Because they are often a complex mixture of different solids and fluids, the rheology of drilling fluids is usually complicated. As a result, they typically exhibit non-Newtonian flow behaviours. While the traditional practice is to use critical velocity to describe the flow regimes of drilling fluids by discriminating between laminar and turbulent conditions, this paper explores the applicability of Reynolds numlber (NRe), which is a more robust and universal dimensionless quantity to characterise flow regimes. Models to estimate NRe of drilling fluids are explored for Bingham and power-law types of drilling fluids, including development of models for other non-Newtonian behaviours such as shear-thinning and shear-thickening. More important, the models provide a veritable basis to compare the hydraulic characteristics of a drilling-fluid mixture against its Newtonian counterparts under similar conditions. In addition, these models would facilitate the exploitation of the concept of dynamic similarity to improve the design and benchmarking of the flow characteristics of different drilling fluids in different systems and under diverse conditions. Examples are provided that show the robustness of using NRe as against critical velocity, to identify flow regimes of drilling fluids. The applicability of the proposed models and ideas are not limited to drilling fluid hydraulics. The findings are relevant in other areas of transporting non-Newtonian fluids such as polymer for enhanced-oil recovery and multiphase mixtures such as emulsions, waxy crudes and general pipeline transport. Additionally, the principles and insights should be of interest to other industries such as food processing and chemical manufacturing.
{"title":"On the Characterisation of the Flow Regimes of Drilling Fluids","authors":"Oluwaseun E. Ajayi, K. Lawal, C. Ukaonu, Tunde Alabi, O. Okoh, Obianuju Igbokwe","doi":"10.2118/198742-MS","DOIUrl":"https://doi.org/10.2118/198742-MS","url":null,"abstract":"\u0000 Drilling fluids are vital elements in the safe, efficient and effective construction of wells. Their key functions include transporting drill cuttings to the surface, cooling and lubrication of drill string, cleaning build-up deposits on drill bits and tools, as well as stabilisation of the borehole and pressure control. Because they are often a complex mixture of different solids and fluids, the rheology of drilling fluids is usually complicated. As a result, they typically exhibit non-Newtonian flow behaviours. While the traditional practice is to use critical velocity to describe the flow regimes of drilling fluids by discriminating between laminar and turbulent conditions, this paper explores the applicability of Reynolds numlber (NRe), which is a more robust and universal dimensionless quantity to characterise flow regimes.\u0000 Models to estimate NRe of drilling fluids are explored for Bingham and power-law types of drilling fluids, including development of models for other non-Newtonian behaviours such as shear-thinning and shear-thickening. More important, the models provide a veritable basis to compare the hydraulic characteristics of a drilling-fluid mixture against its Newtonian counterparts under similar conditions. In addition, these models would facilitate the exploitation of the concept of dynamic similarity to improve the design and benchmarking of the flow characteristics of different drilling fluids in different systems and under diverse conditions. Examples are provided that show the robustness of using NRe as against critical velocity, to identify flow regimes of drilling fluids.\u0000 The applicability of the proposed models and ideas are not limited to drilling fluid hydraulics. The findings are relevant in other areas of transporting non-Newtonian fluids such as polymer for enhanced-oil recovery and multiphase mixtures such as emulsions, waxy crudes and general pipeline transport. Additionally, the principles and insights should be of interest to other industries such as food processing and chemical manufacturing.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"14 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73328311","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}
Moradeyo Adesanwo, O. Bello, David Zhu, Barthemeaus Owen, B. Ogu, Jennifer Chimuanya Ossai, G. Iwo
Increasing need for improved efficiency, service life and cost reduction using downhole real-time streaming sensor data is making electrical submersible pump (ESP) well operation management one of the most important issues in production optimization and improved oil recovery. Expanding the benefit of the downhole sensors is currently driving the need for embracing dynamic data-driven application systems (artificial intelligence, machine learning and deep learning) and big data tools by Oil and Gas industry to gain competitive advantage. One of the shortcomings for conventional data driven approach is that artificial intelligence (machine and/or deep learning) algorithms are totally decoupled from physics based modeling due to the lack of domain knowledge. As OEM for ESP, we have an industry proven ESP system simulator that can be used to generate training dataset for scalable data driven monitoring of ESP systems. Correct interpretation of temperature and pressure data can lead to improved accuracy of continuous downhole flow performance characteristics and reservoir properties such as static reservoir pressure and productivity index, which are key information to control and optimize ESP-based well production. In this work, a physics-based data driven model and inversion-based methods for model calibration and updating are developed for ESP well monitoring. The model is used as a forward engine and an inversion procedure is then added to interpret the measured data to estimate reservoir pressure, productivity index, downhole multiphase flow rates, and perform production allocation to improve hydrocarbon recovery and mitigate water/gas breakthrough risk. The new modeling framework introduces a fast and accurate forward model that incorporates specific measurements response functions for the physics-based data driven simulation model of permanent downhole gauge data in the ESP wells. Multiple inversion methods are used to interpret the downhole-measured data. Under the assumption of a subsurface multiphase flow model, the inversion approaches estimate well rates, back flow allocation, productivity index and reservoir pressure response specific to a given measurement domain by numerically reproducing the available measurements. The model and estimation techniques are evaluated with field data obtained from multiple wells located in a producing field. Many estimation simulations are performed using various sampling rates of the ESP AutographPC software. The satisfactory predictive accuracy of the physics-based data driven model makes the determination of multiphase flow and reservoir parameters computationally inexpensive, adaptive to operational changes, and suitable for online real-time system implementation.
{"title":"Interpreting Downhole Pressure and Temperature Data from ESP Wells by Use of Inversion-Based Methods in Samabri Biseni Field","authors":"Moradeyo Adesanwo, O. Bello, David Zhu, Barthemeaus Owen, B. Ogu, Jennifer Chimuanya Ossai, G. Iwo","doi":"10.2118/198872-MS","DOIUrl":"https://doi.org/10.2118/198872-MS","url":null,"abstract":"\u0000 Increasing need for improved efficiency, service life and cost reduction using downhole real-time streaming sensor data is making electrical submersible pump (ESP) well operation management one of the most important issues in production optimization and improved oil recovery. Expanding the benefit of the downhole sensors is currently driving the need for embracing dynamic data-driven application systems (artificial intelligence, machine learning and deep learning) and big data tools by Oil and Gas industry to gain competitive advantage. One of the shortcomings for conventional data driven approach is that artificial intelligence (machine and/or deep learning) algorithms are totally decoupled from physics based modeling due to the lack of domain knowledge. As OEM for ESP, we have an industry proven ESP system simulator that can be used to generate training dataset for scalable data driven monitoring of ESP systems. Correct interpretation of temperature and pressure data can lead to improved accuracy of continuous downhole flow performance characteristics and reservoir properties such as static reservoir pressure and productivity index, which are key information to control and optimize ESP-based well production. In this work, a physics-based data driven model and inversion-based methods for model calibration and updating are developed for ESP well monitoring. The model is used as a forward engine and an inversion procedure is then added to interpret the measured data to estimate reservoir pressure, productivity index, downhole multiphase flow rates, and perform production allocation to improve hydrocarbon recovery and mitigate water/gas breakthrough risk. The new modeling framework introduces a fast and accurate forward model that incorporates specific measurements response functions for the physics-based data driven simulation model of permanent downhole gauge data in the ESP wells. Multiple inversion methods are used to interpret the downhole-measured data. Under the assumption of a subsurface multiphase flow model, the inversion approaches estimate well rates, back flow allocation, productivity index and reservoir pressure response specific to a given measurement domain by numerically reproducing the available measurements. The model and estimation techniques are evaluated with field data obtained from multiple wells located in a producing field. Many estimation simulations are performed using various sampling rates of the ESP AutographPC software. The satisfactory predictive accuracy of the physics-based data driven model makes the determination of multiphase flow and reservoir parameters computationally inexpensive, adaptive to operational changes, and suitable for online real-time system implementation.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"50 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87507600","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 conventional method for DCA for a solution-gas drive reservoir is the Arp's Approach. Another approach, an improved approach, is the Fetkovich Type Curve Approach which involves the combination of rate equation and material balance equation for finite systems to obtain rate-time equations for solution-gas drive reservoir using backpressure exponent(n) in place of Arp's decline exponent(b). This improved approach, however, has a number of limitations. First, it is difficult to judge which type curve production data match. It has a lower resolution. Also, the developed cumulative-rate model for the material balance equation form: PR2is linear with Np, tends to give inaccurate result. This paper, first, presents a cumulative-rate model using a mathematical approach. Then, the Fetkovich rate-time relationships for both the material balance equation forms: PR2is linear with Np, PR is linear with Np, are transferred into linear relationships(in a log-log plot) by finding the derivative of the natural logarithm of the dimensionless rate(qDd) with respect to the dimensionless time(tDd). Consequently, the type lines are generated and upon about fifty (50) trials, conditions required for optimum workability are presented. The developed cumulative-rate model was validated with field data from a reservoir in the Niger Delta. The correlation between forecasted cumulative production and actual production data is 0.99988. Thus, indicating high positive correlation. Also, the linearized models were validated with production data from Arbuckle Lime, Kansas. The correlation too, is as high as 0.99988. Thereafter, a user-friendly Microsoft Excel spreadsheet application for computing cumulative production given rate is created using Excel VBA.
{"title":"Decline Line Analysis DLA: A Method for Forecasting Cumulative Production for Solution-Gas Drive Reservoirs Based on Fetkovich Type Curve Approach","authors":"Omaga Sumaila","doi":"10.2118/198734-MS","DOIUrl":"https://doi.org/10.2118/198734-MS","url":null,"abstract":"\u0000 A conventional method for DCA for a solution-gas drive reservoir is the Arp's Approach. Another approach, an improved approach, is the Fetkovich Type Curve Approach which involves the combination of rate equation and material balance equation for finite systems to obtain rate-time equations for solution-gas drive reservoir using backpressure exponent(n) in place of Arp's decline exponent(b). This improved approach, however, has a number of limitations. First, it is difficult to judge which type curve production data match. It has a lower resolution. Also, the developed cumulative-rate model for the material balance equation form: PR2is linear with Np, tends to give inaccurate result.\u0000 This paper, first, presents a cumulative-rate model using a mathematical approach. Then, the Fetkovich rate-time relationships for both the material balance equation forms: PR2is linear with Np, PR is linear with Np, are transferred into linear relationships(in a log-log plot) by finding the derivative of the natural logarithm of the dimensionless rate(qDd) with respect to the dimensionless time(tDd). Consequently, the type lines are generated and upon about fifty (50) trials, conditions required for optimum workability are presented.\u0000 The developed cumulative-rate model was validated with field data from a reservoir in the Niger Delta. The correlation between forecasted cumulative production and actual production data is 0.99988. Thus, indicating high positive correlation. Also, the linearized models were validated with production data from Arbuckle Lime, Kansas. The correlation too, is as high as 0.99988. Thereafter, a user-friendly Microsoft Excel spreadsheet application for computing cumulative production given rate is created using Excel VBA.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"4 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82776928","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}
L. Nosike, G. Uwerikowe, V. Biu, A. Adeyemi, M. Usman
Regional studies are known to show major compartmentalization in an oil field, while observations during development and production often highlight local structural connectivity issues that require fault characterization at field-scale to mitigate uncertainty in reserve or stakes. The Akpo field, located in the deep offshore Niger Delta, exemplifies a maturing field where these structural connectivity issues are dominant and play significant roles in field development. Structural discrepancies in the crest and flanks of the anticline result in varying water contacts and overpressure differences, affecting connected volumes and sweep efficiency. Qualitative fault throw analysis, aided by 4-D monitoring results, show that same faults may be sealing and communicating at difference areas, across reservoir fairways in the deep offshore turbiditic channel complexes, delineated as architectural elements. Shale Gouge Ratio (SGR) helps in further constraining the sealing/leaking impact of fault gouge at a log-scale, such that adjacent well data can be used quantitatively to assess preferential flow paths across and within faults zones. This revealed an along-fault, up-fault and across-fault connectivity anisotropy. This work addresses how the fault characterization was used to assess the following: Reservoir compartmentalization, leading to panel separated as fault blocks.Communication across fault, shown by throw map and SGR.The varying water contacts, which tend to result from upwelling of fluid within panel.Sweep across panels, from injectors to producers.The well in real-time operational situation, where well trajectory traverses a fault. The study resulted in an improved infill well planning and placement, targeting unswept hydrocarbon, where well trajectories were determined by knowledge of fault compartmentalization, initial static connectivity shown by virgin pressures and present dynamic communication across injector-producer pairs. Post-mortem analysis of these infill wells was helpful in understanding the dynamic role of the crestal-collapse faults offsetting the reservoirs in the Akpo anticline, leading to optimization and increased productivity.
{"title":"Implication of Structural Analysis in the Development and Management of a Maturing Field – The Akpo Case Study","authors":"L. Nosike, G. Uwerikowe, V. Biu, A. Adeyemi, M. Usman","doi":"10.2118/198865-MS","DOIUrl":"https://doi.org/10.2118/198865-MS","url":null,"abstract":"\u0000 Regional studies are known to show major compartmentalization in an oil field, while observations during development and production often highlight local structural connectivity issues that require fault characterization at field-scale to mitigate uncertainty in reserve or stakes. The Akpo field, located in the deep offshore Niger Delta, exemplifies a maturing field where these structural connectivity issues are dominant and play significant roles in field development. Structural discrepancies in the crest and flanks of the anticline result in varying water contacts and overpressure differences, affecting connected volumes and sweep efficiency.\u0000 Qualitative fault throw analysis, aided by 4-D monitoring results, show that same faults may be sealing and communicating at difference areas, across reservoir fairways in the deep offshore turbiditic channel complexes, delineated as architectural elements. Shale Gouge Ratio (SGR) helps in further constraining the sealing/leaking impact of fault gouge at a log-scale, such that adjacent well data can be used quantitatively to assess preferential flow paths across and within faults zones. This revealed an along-fault, up-fault and across-fault connectivity anisotropy.\u0000 This work addresses how the fault characterization was used to assess the following: Reservoir compartmentalization, leading to panel separated as fault blocks.Communication across fault, shown by throw map and SGR.The varying water contacts, which tend to result from upwelling of fluid within panel.Sweep across panels, from injectors to producers.The well in real-time operational situation, where well trajectory traverses a fault.\u0000 The study resulted in an improved infill well planning and placement, targeting unswept hydrocarbon, where well trajectories were determined by knowledge of fault compartmentalization, initial static connectivity shown by virgin pressures and present dynamic communication across injector-producer pairs. Post-mortem analysis of these infill wells was helpful in understanding the dynamic role of the crestal-collapse faults offsetting the reservoirs in the Akpo anticline, leading to optimization and increased productivity.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 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":"82133997","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 Niger Delta is a prolific oil and gas province with almost 160 oilfields and 1,500 wells put on production since the 1960s. Many of these wells have been producing for decades and now find themselves in hands of new operating companies of limited resources. There are strong commercial drivers to keep these wells in production through rapidly planned workover operations. The historical records for these wells are poor and in many instances nonexistent, often being no more than a very simplistic A4 completion diagram lacking in details and summary. The basis for design and the history of numerous interventions has long been lost and the focus of new operators is often on only the production casing and the tubing strings. However, it is imperative to consider the full well architecture and construction history because some were design optimized with minimal casing setting 13 3/8" shallow and completing in 9 5/8". Worst case consequence of this design approach is well blowout and cratering if the production casing fails with a gas column to surface. A generic case is presented to emphasize the reality of this risk. The risks of extending well life, compounded by change of use in late life are discussed in the context of design validation. The causes and challenge of poor well engineering data are reviewed, to establish the historical norms in not only the Niger Delta but globally. The importance of tracking down data in the well Intervention planning process is emphasized. It is further proposed that controlled, as-built drawings of all wells, which do not omit casing details, lithology, and critical component features such as wellheads casing hanger seals and Xmas tree should be electronically created, cloud stored and used as a basis for well bore integrity analysis prior to undertaking interventions/workovers. An example from a North Sea Development Project is presented. Such a system should also be used to establish which critical barriers exist during the intervention, how they will be validated, and how is evidence captured in order to address the typical human factors which are fundamental in many blowouts. Critically the system should produce accurate well integrity reports during operations to track compliance with the plan. A generic example for a typical Niger delta dual bore completion well is presented.
{"title":"Using Cloud Based Well Engineering Data and Wellbore Integrity Analysis to Reduce Risk in Niger Delta Workovers","authors":"K. P. Seymour, C. Stuart","doi":"10.2118/198735-MS","DOIUrl":"https://doi.org/10.2118/198735-MS","url":null,"abstract":"\u0000 The Niger Delta is a prolific oil and gas province with almost 160 oilfields and 1,500 wells put on production since the 1960s. Many of these wells have been producing for decades and now find themselves in hands of new operating companies of limited resources. There are strong commercial drivers to keep these wells in production through rapidly planned workover operations. The historical records for these wells are poor and in many instances nonexistent, often being no more than a very simplistic A4 completion diagram lacking in details and summary. The basis for design and the history of numerous interventions has long been lost and the focus of new operators is often on only the production casing and the tubing strings. However, it is imperative to consider the full well architecture and construction history because some were design optimized with minimal casing setting 13 3/8\" shallow and completing in 9 5/8\". Worst case consequence of this design approach is well blowout and cratering if the production casing fails with a gas column to surface. A generic case is presented to emphasize the reality of this risk. The risks of extending well life, compounded by change of use in late life are discussed in the context of design validation. The causes and challenge of poor well engineering data are reviewed, to establish the historical norms in not only the Niger Delta but globally. The importance of tracking down data in the well Intervention planning process is emphasized. It is further proposed that controlled, as-built drawings of all wells, which do not omit casing details, lithology, and critical component features such as wellheads casing hanger seals and Xmas tree should be electronically created, cloud stored and used as a basis for well bore integrity analysis prior to undertaking interventions/workovers. An example from a North Sea Development Project is presented. Such a system should also be used to establish which critical barriers exist during the intervention, how they will be validated, and how is evidence captured in order to address the typical human factors which are fundamental in many blowouts. Critically the system should produce accurate well integrity reports during operations to track compliance with the plan. A generic example for a typical Niger delta dual bore completion well is presented.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"9 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80516579","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
I. Ayuba, S. Isehunwa, M. B. Adamu, A. Usman, M. N. Bello
This investigation demonstrates the use of acentric factor as the third parameter in a corresponding states correlation for compressibility factors and a discussion of their application to three different types of gas reservoir. A correlation is presented which provides compressibility factors based on Hall – Yarborough equation of states for use in both two – phase and single-phase hydrocarbon systems. The modified Hall - Yarborough equation employs the acentric factor as an additional parameter to improve its accuracy. This modified equation is as simple as the original form, yet achieves substantially better prediction accuracy, especially at higher pressure. The correlation is based on hydrocarbon compressibility determinations from twenty-two hydrocarbon samples taken from three different types of reservoir systems. Out of the data used 67 percent were from dew point or retrograde gas condensate and bubble point or dissolved gas reservoir, 33 percent were from single phase gas reservoir. Results from the modified Hall – Yarborough equation, the original Hall – Yarborough equation and practically obtained were compared with natural gas components data for three different reservoirs to demonstrate its accuracy and increased application range. The improvement of the modified equation, over the original Hall – Yarborough equation ranges from 0.98% to 7.017% on the average.
{"title":"Modification of Hall-Yarborough Equation of State For Predicting Gas Compressibility Factors","authors":"I. Ayuba, S. Isehunwa, M. B. Adamu, A. Usman, M. N. Bello","doi":"10.2118/198715-MS","DOIUrl":"https://doi.org/10.2118/198715-MS","url":null,"abstract":"This investigation demonstrates the use of acentric factor as the third parameter in a corresponding states correlation for compressibility factors and a discussion of their application to three different types of gas reservoir. A correlation is presented which provides compressibility factors based on Hall – Yarborough equation of states for use in both two – phase and single-phase hydrocarbon systems. The modified Hall - Yarborough equation employs the acentric factor as an additional parameter to improve its accuracy. This modified equation is as simple as the original form, yet achieves substantially better prediction accuracy, especially at higher pressure. The correlation is based on hydrocarbon compressibility determinations from twenty-two hydrocarbon samples taken from three different types of reservoir systems. Out of the data used 67 percent were from dew point or retrograde gas condensate and bubble point or dissolved gas reservoir, 33 percent were from single phase gas reservoir. Results from the modified Hall – Yarborough equation, the original Hall – Yarborough equation and practically obtained were compared with natural gas components data for three different reservoirs to demonstrate its accuracy and increased application range. The improvement of the modified equation, over the original Hall – Yarborough equation ranges from 0.98% to 7.017% on the average.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"33 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74892701","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}
J. Adesun, Olanike Olajide, C. Ekesiobi, A. Ogunjobi, K. Ishola
A quantitative seismic interpretation (QSI) approach in assessing reservoir properties of a near-field exploration discovery is presented. This approach demonstrates the integration of rock physics model and seismic inversion to determine the lateral extent of the reservoir complex, improve the understanding of geometry and connectivity of the reservoir sands encountered in this field; and improve confidence in estimates of the resource base. An integrated interpretation approach that incorporates seismic and well log data sets, together with available relevant reports is adopted to reduce interpretation risk inherent with the study location. The hydrocarbon bearing reservoir sands were characterized, based on their elastic rock properties responses, to predict reservoir parameters for reservoir architectural delineation from seismic data volume. The results provide insight to address subsurface uncertainties associated with reservoir connectivity, and future infill well count determination for production optimization and possible reserves addition.
{"title":"Assessment of Reservoir Properties using Applied Rock Physics & Seismic Inversion for Near-Field Exploration in a Niger Delta Field","authors":"J. Adesun, Olanike Olajide, C. Ekesiobi, A. Ogunjobi, K. Ishola","doi":"10.2118/198806-MS","DOIUrl":"https://doi.org/10.2118/198806-MS","url":null,"abstract":"\u0000 A quantitative seismic interpretation (QSI) approach in assessing reservoir properties of a near-field exploration discovery is presented.\u0000 This approach demonstrates the integration of rock physics model and seismic inversion to determine the lateral extent of the reservoir complex, improve the understanding of geometry and connectivity of the reservoir sands encountered in this field; and improve confidence in estimates of the resource base.\u0000 An integrated interpretation approach that incorporates seismic and well log data sets, together with available relevant reports is adopted to reduce interpretation risk inherent with the study location. The hydrocarbon bearing reservoir sands were characterized, based on their elastic rock properties responses, to predict reservoir parameters for reservoir architectural delineation from seismic data volume. The results provide insight to address subsurface uncertainties associated with reservoir connectivity, and future infill well count determination for production optimization and possible reserves addition.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"15 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81055321","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}
Based on the Field Development Plan (FDP), AKPO Reservoir ST was developed with two crestal producers (ST-P2 and ST-P1) and two water injectors at the periphery (ST-W2 on the eastern flank and ST-W1 on the western flank). However, the results of a time lapse seismic monitor (4D M-2) in addition to dynamic simulation showed that the attic oil of S-Reservoir would be bypassed at the end of Field life. The time lapse seismic monitor (4D M-2) results also showed that the main producer in the S-Reservoir; ST-P2 was risking early water breakthrough from the ST-W2 water injector at the toe. Hence, the need for an infill well to mitigate these identified risks. This paper presents the maturation & drilling strategy, well results and the production performance of the first infill well of the AKPO Field. The infill maturation strategy involved the update of the geological model with recent well/ 4D seismic information, evaluation of the present static uncertainties on in-place volumes, history matching of the dynamic model in line with current field behaviour and the evaluation of the incremental production and economic value of the infill well. S-P3 trajectory was designed as a sub-horizontal drain to target and produce the attic oil in the S-Reservoir up-dip of producer ST-P2. It was completed across two fault blocks to ensure drainage of the southern panel as fault behaviour remains one of the main uncertainty. The well trajectory was placed as far up-dip as possible, with its toe set higher than the shallowest completion of ST-P2 in the S-reservoir. The final well result for S-P3, drilled in Q4 2016, was outstanding, thanks to excellent integration of seismic, geological and dynamic data. The main results included: Optimal well placement, as a result of real time adjustments of the well trajectory aided by reservoir navigation toolsMore attic oil found as a result of shallower top of S-ReservoirIncremental production of 15 kboepd over 2 years and an incremental reserves of ∼10 Mboe.
{"title":"The Use of 4D & Dynamic Synthesis in Brown Field Development: A Case Study of S-P3 Infill Well Maturation, Preparation and Drilling","authors":"G. Uwerikowe, O. Oshewa, P. Wantong, M. Usman","doi":"10.2118/198745-MS","DOIUrl":"https://doi.org/10.2118/198745-MS","url":null,"abstract":"\u0000 Based on the Field Development Plan (FDP), AKPO Reservoir ST was developed with two crestal producers (ST-P2 and ST-P1) and two water injectors at the periphery (ST-W2 on the eastern flank and ST-W1 on the western flank). However, the results of a time lapse seismic monitor (4D M-2) in addition to dynamic simulation showed that the attic oil of S-Reservoir would be bypassed at the end of Field life. The time lapse seismic monitor (4D M-2) results also showed that the main producer in the S-Reservoir; ST-P2 was risking early water breakthrough from the ST-W2 water injector at the toe. Hence, the need for an infill well to mitigate these identified risks. This paper presents the maturation & drilling strategy, well results and the production performance of the first infill well of the AKPO Field.\u0000 The infill maturation strategy involved the update of the geological model with recent well/ 4D seismic information, evaluation of the present static uncertainties on in-place volumes, history matching of the dynamic model in line with current field behaviour and the evaluation of the incremental production and economic value of the infill well.\u0000 S-P3 trajectory was designed as a sub-horizontal drain to target and produce the attic oil in the S-Reservoir up-dip of producer ST-P2. It was completed across two fault blocks to ensure drainage of the southern panel as fault behaviour remains one of the main uncertainty. The well trajectory was placed as far up-dip as possible, with its toe set higher than the shallowest completion of ST-P2 in the S-reservoir.\u0000 The final well result for S-P3, drilled in Q4 2016, was outstanding, thanks to excellent integration of seismic, geological and dynamic data. The main results included: Optimal well placement, as a result of real time adjustments of the well trajectory aided by reservoir navigation toolsMore attic oil found as a result of shallower top of S-ReservoirIncremental production of 15 kboepd over 2 years and an incremental reserves of ∼10 Mboe.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"199 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73137853","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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