Magnetic resonance (MR) is a very robust service that delivers several formation evaluation products. Both the wireline (WL) and logging-while-drilling (LWD) services deliver shale volume, porosity, permeability, viscosity, saturation and fluid typing. In addition to these, the WL service also delivers capillary pressure and grain size analysis. Although WL and LWD MR Services have different modes of acquisition, the result is usually the same. WL MR uses multiple frequencies, but LWD MR uses a single frequency. Multiple frequencies provide multiple magnetic field gradients that provide for more flexible hydrocarbon typing acquisition sequences, unlike the LWD MR single frequency that supplies a single hydrocarbon acquisition sequence. Dual Wait Time (DTW) analysis is the hydrocarbon typing technique for LWD MR, but the WL hydrocarbon typing has the flexibility to choose from a range of applications that includes two-dimensional MR mapping (2D MR), density multiple wait time (DMTW) analysis, multiple gradient inter-echo spacing (MGTE) analysis, simultaneous inversion of multiple echo trains (SIMET), and T1/T2 ratio (R-T2) analysis for gas reservoirs. Light hydrocarbons (gas) and Kaolinitic shales compromise the use of neutron-density and gamma ray models as bulk shale volume indicators. However, MR shale volume computation using clay-bound water (CBW), which is unaffected by the presence of gas or Kaolinitic shales. MR Logs can accurately determine porosity in complex lithologies and thin beds. Irreducible water saturation from MR is used to determine reservoir quality and productivity. In the industry today, MR logs are the most tolerant to environmental challenges. They are able to "say" the true state of the reservoir in the midst of environmental factors like the presence of gas, shales, and thin beds, which are known to adversely impact measurements from other conventional tools
{"title":"Magnetic Resonance: Says it as it is!","authors":"Stanley Oifoghe, Victor Okowi, Eziulo Ibe","doi":"10.2118/198739-MS","DOIUrl":"https://doi.org/10.2118/198739-MS","url":null,"abstract":"\u0000 Magnetic resonance (MR) is a very robust service that delivers several formation evaluation products. Both the wireline (WL) and logging-while-drilling (LWD) services deliver shale volume, porosity, permeability, viscosity, saturation and fluid typing. In addition to these, the WL service also delivers capillary pressure and grain size analysis.\u0000 Although WL and LWD MR Services have different modes of acquisition, the result is usually the same. WL MR uses multiple frequencies, but LWD MR uses a single frequency. Multiple frequencies provide multiple magnetic field gradients that provide for more flexible hydrocarbon typing acquisition sequences, unlike the LWD MR single frequency that supplies a single hydrocarbon acquisition sequence.\u0000 Dual Wait Time (DTW) analysis is the hydrocarbon typing technique for LWD MR, but the WL hydrocarbon typing has the flexibility to choose from a range of applications that includes two-dimensional MR mapping (2D MR), density multiple wait time (DMTW) analysis, multiple gradient inter-echo spacing (MGTE) analysis, simultaneous inversion of multiple echo trains (SIMET), and T1/T2 ratio (R-T2) analysis for gas reservoirs.\u0000 Light hydrocarbons (gas) and Kaolinitic shales compromise the use of neutron-density and gamma ray models as bulk shale volume indicators. However, MR shale volume computation using clay-bound water (CBW), which is unaffected by the presence of gas or Kaolinitic shales. MR Logs can accurately determine porosity in complex lithologies and thin beds. Irreducible water saturation from MR is used to determine reservoir quality and productivity.\u0000 In the industry today, MR logs are the most tolerant to environmental challenges. They are able to \"say\" the true state of the reservoir in the midst of environmental factors like the presence of gas, shales, and thin beds, which are known to adversely impact measurements from other conventional tools","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":"84297596","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
O. Erivwo, J. Ochai, Victor Agbaroji, Oluwatobi Oke
Horizontal wells are susceptible to early water breakthrough (EWBT) due to reservoir heterogeneity and "the heel-toe effect", caused by frictional pressure losses along the well that lead to a non-uniform production profile. Also, with heavy oil reservoirs, early water breakthrough can occur because of viscous fingering due to an unfavorable mobility ratio caused by a difference in the viscosity of heavy oil and water. This ratio leads to a high inflow of water into the wellbore. EWBT is undesirable as it brings with it negative implications; from low oil productivity to corrosion in the wellbore and water disposal challenges. There are different industry solutions to managing early water breakthrough including reservoir based improved oil recovery (IOR) or enhanced oil recovery (EOR) methods such as thermal EOR (steam flooding, cyclic steam injection), chemical EOR (polymer or alkaline flooding) or miscible EOR (with methane or ethane to reduce capillary resistance). These methods are however complex and broad field-based applications with varying experiences in the outcomes of the field implementation. There are also mechanical well specific solutions for mitigating EWBT and in this paper, we present the considerations and plans for the application of Autonomous Inflow Control Devices (AICDs) for the mitigation of EWBT in the Niger Delta. AICDs are relatively new and are known for autonomous selective choking of fluid phases. They restrict the flow of less viscous phases like water while allowing more viscous phases like heavy oil to pass through, with minimum pressure drop. The paper examines the different causes of EWBT in Ogini field and the different solution options available. It presents the cost/benefit analysis and modeling considerations resulting in the selection of AICDs for EWBT mitigation. The paper concludes with the technology implementation plan developed for its successful deployment in the upcoming drilling campaign.
{"title":"Considerations for Mitigating Early Water Breakthrough in Horizontal Wells in Heavy Oil Reservoirs in the Niger Delta - Ogini Field Case Study","authors":"O. Erivwo, J. Ochai, Victor Agbaroji, Oluwatobi Oke","doi":"10.2118/198828-MS","DOIUrl":"https://doi.org/10.2118/198828-MS","url":null,"abstract":"\u0000 Horizontal wells are susceptible to early water breakthrough (EWBT) due to reservoir heterogeneity and \"the heel-toe effect\", caused by frictional pressure losses along the well that lead to a non-uniform production profile. Also, with heavy oil reservoirs, early water breakthrough can occur because of viscous fingering due to an unfavorable mobility ratio caused by a difference in the viscosity of heavy oil and water. This ratio leads to a high inflow of water into the wellbore.\u0000 EWBT is undesirable as it brings with it negative implications; from low oil productivity to corrosion in the wellbore and water disposal challenges. There are different industry solutions to managing early water breakthrough including reservoir based improved oil recovery (IOR) or enhanced oil recovery (EOR) methods such as thermal EOR (steam flooding, cyclic steam injection), chemical EOR (polymer or alkaline flooding) or miscible EOR (with methane or ethane to reduce capillary resistance). These methods are however complex and broad field-based applications with varying experiences in the outcomes of the field implementation. There are also mechanical well specific solutions for mitigating EWBT and in this paper, we present the considerations and plans for the application of Autonomous Inflow Control Devices (AICDs) for the mitigation of EWBT in the Niger Delta. AICDs are relatively new and are known for autonomous selective choking of fluid phases. They restrict the flow of less viscous phases like water while allowing more viscous phases like heavy oil to pass through, with minimum pressure drop.\u0000 The paper examines the different causes of EWBT in Ogini field and the different solution options available. It presents the cost/benefit analysis and modeling considerations resulting in the selection of AICDs for EWBT mitigation. The paper concludes with the technology implementation plan developed for its successful deployment in the upcoming drilling campaign.","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":"82572449","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 Well A14 was drilled in 2004 with dual completion and flowed for about 7 years. The well was shut-in due to high water cut and sand production. In December 2011, the well was re-completed single with 7’’ Cased Hole Gravel Pack and ESP + YTool. The well was later sidetracked and deviated to a tie-in point in order to encounter the target at optimal structural positions and provide additional drainage points on the target level to optimize hydrocarbon recovery from the field. The flowed for a period of 2 ½ years and stopped flowing as a result of electric fault on the ESP. Following this and the unfavorable price of crude oil at the time, there was need for an optimized means of intervention; several factors were considered and a HWO intervention using HWPU was selected. This paper addresses the contingent challenges faced and how these were overcome in the course of this 2nd W/O to recover the existing completion and run-in with a new design of ESP and accessories. During POOH the old completion after laying down the D-ESP packer on surface, the well kicked as a result of poor circulation during the killing operation. This resulted in a loss of control and fluid influx spilling to the environment. This challenge was addressed in compliance with the best standards. The W/O was resumed and the entire completion string and ESP assembly + Ytool retrieved. Subsequently during the final installation of the new ESP, the string parted at the threaded connection and the entire ESP completion assembly was lost in hole. This second incident was carefully reviewed by the team involved prior mobilization of fishing equipment and eventual recovery of the lost-in-hole in a single attempt. The entire completion containing the lost-in- hole, on about 2000m of 3 ½" Tubing completion was recovered; the new assemblies were prepared and RIH successfully. The well was eventually completed and currently flowing (≈2000bopd). The responsible team reviewed the incidents, identified lapses and proposed future procedures in order to forestall reoccurrence.
{"title":"Lessons Learnt During Hydraulic Workover for ESP Replacement","authors":"Mohammed Othman, Choja Ojanomare","doi":"10.2118/198870-MS","DOIUrl":"https://doi.org/10.2118/198870-MS","url":null,"abstract":"\u0000 The Well A14 was drilled in 2004 with dual completion and flowed for about 7 years. The well was shut-in due to high water cut and sand production. In December 2011, the well was re-completed single with 7’’ Cased Hole Gravel Pack and ESP + YTool. The well was later sidetracked and deviated to a tie-in point in order to encounter the target at optimal structural positions and provide additional drainage points on the target level to optimize hydrocarbon recovery from the field. The flowed for a period of 2 ½ years and stopped flowing as a result of electric fault on the ESP. Following this and the unfavorable price of crude oil at the time, there was need for an optimized means of intervention; several factors were considered and a HWO intervention using HWPU was selected. This paper addresses the contingent challenges faced and how these were overcome in the course of this 2nd W/O to recover the existing completion and run-in with a new design of ESP and accessories. During POOH the old completion after laying down the D-ESP packer on surface, the well kicked as a result of poor circulation during the killing operation. This resulted in a loss of control and fluid influx spilling to the environment. This challenge was addressed in compliance with the best standards. The W/O was resumed and the entire completion string and ESP assembly + Ytool retrieved. Subsequently during the final installation of the new ESP, the string parted at the threaded connection and the entire ESP completion assembly was lost in hole. This second incident was carefully reviewed by the team involved prior mobilization of fishing equipment and eventual recovery of the lost-in-hole in a single attempt. The entire completion containing the lost-in- hole, on about 2000m of 3 ½\" Tubing completion was recovered; the new assemblies were prepared and RIH successfully. The well was eventually completed and currently flowing (≈2000bopd). The responsible team reviewed the incidents, identified lapses and proposed future procedures in order to forestall reoccurrence.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"58 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86688810","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}
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}
C. Okpalla, V. Chaloupka, Romain Djenani, Victor Okengwu, T. Akinniyi, B. Orluwosu, Kenneth Johnson
A service company was challenged to deliver best-in-class upper and lower completions by leveraging deep water completion experiences throughout West Africa with the operator and service company's global best practices and lessons learned. An operator reduced lower completion times, standalone screens, and openhole gravel packs by 60% between the 1st and 24th well while reducing upper completion times by 40% for the same wells. Well construction durations, including drilling and completion, currently averages 24 days per well, with lower and upper completion operating efficiencies and run reliabilities exceeding 97%.
{"title":"Egina Deep Water Development Completion Success: One Team Working Together Setting New Performance Standards","authors":"C. Okpalla, V. Chaloupka, Romain Djenani, Victor Okengwu, T. Akinniyi, B. Orluwosu, Kenneth Johnson","doi":"10.2118/198869-MS","DOIUrl":"https://doi.org/10.2118/198869-MS","url":null,"abstract":"\u0000 A service company was challenged to deliver best-in-class upper and lower completions by leveraging deep water completion experiences throughout West Africa with the operator and service company's global best practices and lessons learned. An operator reduced lower completion times, standalone screens, and openhole gravel packs by 60% between the 1st and 24th well while reducing upper completion times by 40% for the same wells. Well construction durations, including drilling and completion, currently averages 24 days per well, with lower and upper completion operating efficiencies and run reliabilities exceeding 97%.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"34 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79325655","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. Sherif, Omisore Adenike, Eremiokhale Obehi, A. Funso, Blankson Eyituoyo
Electrical Submersible Pump (ESP) failures cause disruptions that lead to production deferement besides the cost of interventions/workovers post failure. The service life of an ESP is difficult to predict as it is affected by several factors which include reservoir characteristics, pump operating conditions and even the installation procedure. Measurement and monitoring of both dynamic and static ESP parameters play a critical role in extending the run-life. However, due to the complex nature of ESP failures, it can be difficult to identify anomalies by simply trending data. Notable progress has been made in the past years with respect to the development of systems for monitoring but most operators are yet to fully leverage on a system that will allow for proactive ESP health condition monitoring. In this paper, generalized machine-learning techniques and information acquired through real-time streaming was used to predict impending failures. This study applies Principal Component Analysis (PCA) on ESP intallations for a marginal field in the Niger Delta where production optimization and cost reduction are key to sustenance. Python was used for the data processing/statistical analysis and the algorithm development. The major objective of the PCA was to identify correlations in the dynamic ESP parameters: Intake Pressure, Intake Temperature, Discharge Pressure, Vibrations, Motor Temperature, Motor Current, Systems Current and Frequency recorded by the Variable Speed Drive (VSD) at regular intervals. Once the correlation/pattern was identified, the PCA approach found the directions of maximum variance in the high-dimensional data (in this study eight-dimensional) and projected it onto a smaller dimensional subspace while retaining most of the information. For each installation, a stable region for the operating frequency was identified and failed ESPs showed a clear drift from the stable region months before the failure occured, which was not apparent in the recorded parameters from the VSD. The paper describes how to use Machine Learning (ML) algorithms to predict an ESP's runlife bringing the industry a step closer to proactive ESP monitoring as opposed to the current reactive methods.
{"title":"Predictive Data Analytics for Effective Electric Submersible Pump Management","authors":"S. Sherif, Omisore Adenike, Eremiokhale Obehi, A. Funso, Blankson Eyituoyo","doi":"10.2118/198759-MS","DOIUrl":"https://doi.org/10.2118/198759-MS","url":null,"abstract":"\u0000 Electrical Submersible Pump (ESP) failures cause disruptions that lead to production deferement besides the cost of interventions/workovers post failure. The service life of an ESP is difficult to predict as it is affected by several factors which include reservoir characteristics, pump operating conditions and even the installation procedure. Measurement and monitoring of both dynamic and static ESP parameters play a critical role in extending the run-life. However, due to the complex nature of ESP failures, it can be difficult to identify anomalies by simply trending data.\u0000 Notable progress has been made in the past years with respect to the development of systems for monitoring but most operators are yet to fully leverage on a system that will allow for proactive ESP health condition monitoring.\u0000 In this paper, generalized machine-learning techniques and information acquired through real-time streaming was used to predict impending failures. This study applies Principal Component Analysis (PCA) on ESP intallations for a marginal field in the Niger Delta where production optimization and cost reduction are key to sustenance. Python was used for the data processing/statistical analysis and the algorithm development. The major objective of the PCA was to identify correlations in the dynamic ESP parameters: Intake Pressure, Intake Temperature, Discharge Pressure, Vibrations, Motor Temperature, Motor Current, Systems Current and Frequency recorded by the Variable Speed Drive (VSD) at regular intervals. Once the correlation/pattern was identified, the PCA approach found the directions of maximum variance in the high-dimensional data (in this study eight-dimensional) and projected it onto a smaller dimensional subspace while retaining most of the information. For each installation, a stable region for the operating frequency was identified and failed ESPs showed a clear drift from the stable region months before the failure occured, which was not apparent in the recorded parameters from the VSD.\u0000 The paper describes how to use Machine Learning (ML) algorithms to predict an ESP's runlife bringing the industry a step closer to proactive ESP monitoring as opposed to the current reactive methods.","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":"84359466","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}
P. Oviawele, S. Onwukwe, N. Nwachukwu, I. Onyejekwe
Disposal of condensate produced from stranded gas field have been a major concern to producing companies due to unavailability of nearby oil flow stations to receive the condensate, which have resulted to abandonment of such fields. This work seek to improve the thermodynamic properties (Heat Capacity, Heating Value, Specific Heat capacity, Heat of Vaporization and Enthalpy) of the export gas through condensate spiking. This was carried out by simulating a natural gas plant, consisting of condensate line and spiking mixer. The simulation was done using Aspen HYSYS, to include the point at which the condensate stream was spiked into the high-pressure dry natural gas stream. Phase envelope and hydrate formation curve for the streams (dry natural gas and the mixture after spiking) were obtained. Case study in HYSYS was used to carry out Sensitivity analysis, to determine the effect of temperature, pressure and flow rate of the condensate on the mixture (export gas). Economic analysis of the project was carried out. Results obtained from the thermodynamic analysis shows that the thermodynamic properties of the export gas after spiking improves, such that the heating value and enthalpy of the export gas increases. The phase envelops shows that hydrate will not form in the export gas streams. Through the sensitivity analyses, the effect of variation in the parameters of the condensate shows that the vapour fraction of the export gas increases as the temperature increase and decrease as the pressure increases. The maximum condensate flow rate was obtained to be 12,500 bbl/day, at a dry gas flow rate of 382.2 MMScfd, for a maximum vapour fraction of 0.953, with this operating parameters, flow assurance problem of hydrate formation, liquid holdup and high pressure drops along the pipeline with be eliminated. Hydrocarbon dew point of −13.41°C was obtained showing that liquid hydrocarbon will not condense out of the gas during transportation. Economic analysis shows that the NPV and IRR are $432.778 million and 33%, indicating that the project is viable for investment. Therefore, it is possible to spike condensate into treated export gas without causing flow assurance problems, and helps mitigate against risk associated with environmental pollution.
{"title":"Improving the Thermodynamic Properties of Export Gas Through Condensate Spiking","authors":"P. Oviawele, S. Onwukwe, N. Nwachukwu, I. Onyejekwe","doi":"10.2118/198805-MS","DOIUrl":"https://doi.org/10.2118/198805-MS","url":null,"abstract":"\u0000 Disposal of condensate produced from stranded gas field have been a major concern to producing companies due to unavailability of nearby oil flow stations to receive the condensate, which have resulted to abandonment of such fields. This work seek to improve the thermodynamic properties (Heat Capacity, Heating Value, Specific Heat capacity, Heat of Vaporization and Enthalpy) of the export gas through condensate spiking. This was carried out by simulating a natural gas plant, consisting of condensate line and spiking mixer. The simulation was done using Aspen HYSYS, to include the point at which the condensate stream was spiked into the high-pressure dry natural gas stream. Phase envelope and hydrate formation curve for the streams (dry natural gas and the mixture after spiking) were obtained. Case study in HYSYS was used to carry out Sensitivity analysis, to determine the effect of temperature, pressure and flow rate of the condensate on the mixture (export gas). Economic analysis of the project was carried out. Results obtained from the thermodynamic analysis shows that the thermodynamic properties of the export gas after spiking improves, such that the heating value and enthalpy of the export gas increases. The phase envelops shows that hydrate will not form in the export gas streams. Through the sensitivity analyses, the effect of variation in the parameters of the condensate shows that the vapour fraction of the export gas increases as the temperature increase and decrease as the pressure increases. The maximum condensate flow rate was obtained to be 12,500 bbl/day, at a dry gas flow rate of 382.2 MMScfd, for a maximum vapour fraction of 0.953, with this operating parameters, flow assurance problem of hydrate formation, liquid holdup and high pressure drops along the pipeline with be eliminated. Hydrocarbon dew point of −13.41°C was obtained showing that liquid hydrocarbon will not condense out of the gas during transportation. Economic analysis shows that the NPV and IRR are $432.778 million and 33%, indicating that the project is viable for investment. Therefore, it is possible to spike condensate into treated export gas without causing flow assurance problems, and helps mitigate against risk associated with environmental pollution.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"15 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90713953","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
O. Numbere, Prince Aigbedion, U. Okoli, Eleanor Okubor, Babatunde Olugbesan, Greg Ntiwunka
In a regime of volatile oil prices, it has become increasingly important to plan and deliver cost effective wells safely. Typically, this is achieved by optimizing technical details in planning and execution phase; however, an often-overlooked area of optimization is the management of rental tool inventory and the associated logistics. This area is usually subject to cost overruns due to insufficient tracking of equipment from mobilization through its use at the rigsite, resulting in late demobilization and incurring of additional cost by operators. To completely eliminate these unwanted costs, a web/intranet based, equipment tracking solution which interfaced with the existing enterprise resource planning (ERP) platform (for contracting and procurement information) was designed and implemented by Addax Petroleum Nigeria to track and monitor the movement of rented equipment between service providers, logistics base and operations base. It ensured the effective tracking of rented equipment upon mobilization up till demobilization; this helped to prevent cost overruns for rented equipment during the drilling campaign. Daily reports and notifications were also provided to all key personnel on rented equipment status and it ensured a collaborative workspace for drilling team members to manage rented equipment movement internally. The rentals inventory tracking application (RITA™) software was deployed during a six-month drilling campaign in 2017/2018. It provided comprehensive tracking for equipment mobilized to the rig, eliminating cost overruns on rental equipment throughout the project and cost savings of circa $1,000,000 during the six-month drilling campaign.
{"title":"Reducing Drilling Operations Cost Through Rental Inventory Management - A Case Study","authors":"O. Numbere, Prince Aigbedion, U. Okoli, Eleanor Okubor, Babatunde Olugbesan, Greg Ntiwunka","doi":"10.2118/198804-MS","DOIUrl":"https://doi.org/10.2118/198804-MS","url":null,"abstract":"\u0000 In a regime of volatile oil prices, it has become increasingly important to plan and deliver cost effective wells safely. Typically, this is achieved by optimizing technical details in planning and execution phase; however, an often-overlooked area of optimization is the management of rental tool inventory and the associated logistics. This area is usually subject to cost overruns due to insufficient tracking of equipment from mobilization through its use at the rigsite, resulting in late demobilization and incurring of additional cost by operators.\u0000 To completely eliminate these unwanted costs, a web/intranet based, equipment tracking solution which interfaced with the existing enterprise resource planning (ERP) platform (for contracting and procurement information) was designed and implemented by Addax Petroleum Nigeria to track and monitor the movement of rented equipment between service providers, logistics base and operations base. It ensured the effective tracking of rented equipment upon mobilization up till demobilization; this helped to prevent cost overruns for rented equipment during the drilling campaign. Daily reports and notifications were also provided to all key personnel on rented equipment status and it ensured a collaborative workspace for drilling team members to manage rented equipment movement internally.\u0000 The rentals inventory tracking application (RITA™) software was deployed during a six-month drilling campaign in 2017/2018. It provided comprehensive tracking for equipment mobilized to the rig, eliminating cost overruns on rental equipment throughout the project and cost savings of circa $1,000,000 during the six-month drilling campaign.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"87 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78304210","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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