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}
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 ‘JEB’ oilfield has been in operation since 1992 with 24 oil producing Wells, 8 water injection Wells and no gas injection. From inception, the field was producing at the rate of 27 MSTB/D. The gas produced was 34,333.7 SCF/D which was being flared but later supplied to the Nigeria Liquefied Natural Gas (NLNG) for export. The field had very weak aquifer support and therefore had been water-flooded from early days of its production. With high water cut, it was necessary to find ways of reducing water production and increasing oil production. The study involved field data gathering, history matching of the field data and prediction of future production. Production rates from the different production schemes were simulated for fourteen years. The cumulative oil production of gas injection, water alternating gas (WAG) injection and gas alternating water (GAW) injection schemes were 4.28 MMMSTB, 3.29 MMMSTB and 3.15 MMMSTB respectively representing an incremental recovery of 38%, 6%, and 1%. The cumulative water production of gas injection, WAG injection and GAW injection were 2.65 MMMSTB, 6.52 MMMSTB and 6.90 MMMSTB respectively, which represent 64%, 10% and 5% reduction in produced water. The economic analysis showed gas injection as the best alternative injection scheme for the field with internal rate of return (IRR) of 19.26 %, while the IRR of WAG and GAW injection schemes were 12.09 % and 11.22 % respectively. Also, at 15% discount rate, the gas injection scheme had the best result with a Profitability Index (PI) greater than 1, a positive Net Present Value (NPV) while all other injection schemes had negative NPV and PI was less than one. The possibility of changing a field from water injection to gas injection has been explored, hence, before embarking on any enhanced oil recovery scheme, other alternatives should be evaluated.
{"title":"Switching from Water Injection Scheme to Gas Injection Scheme for Improved Oil Recovery in a Niger Delta Oilfield","authors":"J. Akpabio, B. E. Jackson, Celestine A. Udie","doi":"10.2118/198835-MS","DOIUrl":"https://doi.org/10.2118/198835-MS","url":null,"abstract":"\u0000 The ‘JEB’ oilfield has been in operation since 1992 with 24 oil producing Wells, 8 water injection Wells and no gas injection. From inception, the field was producing at the rate of 27 MSTB/D. The gas produced was 34,333.7 SCF/D which was being flared but later supplied to the Nigeria Liquefied Natural Gas (NLNG) for export. The field had very weak aquifer support and therefore had been water-flooded from early days of its production. With high water cut, it was necessary to find ways of reducing water production and increasing oil production. The study involved field data gathering, history matching of the field data and prediction of future production. Production rates from the different production schemes were simulated for fourteen years. The cumulative oil production of gas injection, water alternating gas (WAG) injection and gas alternating water (GAW) injection schemes were 4.28 MMMSTB, 3.29 MMMSTB and 3.15 MMMSTB respectively representing an incremental recovery of 38%, 6%, and 1%. The cumulative water production of gas injection, WAG injection and GAW injection were 2.65 MMMSTB, 6.52 MMMSTB and 6.90 MMMSTB respectively, which represent 64%, 10% and 5% reduction in produced water. The economic analysis showed gas injection as the best alternative injection scheme for the field with internal rate of return (IRR) of 19.26 %, while the IRR of WAG and GAW injection schemes were 12.09 % and 11.22 % respectively. Also, at 15% discount rate, the gas injection scheme had the best result with a Profitability Index (PI) greater than 1, a positive Net Present Value (NPV) while all other injection schemes had negative NPV and PI was less than one. The possibility of changing a field from water injection to gas injection has been explored, hence, before embarking on any enhanced oil recovery scheme, other alternatives should be evaluated.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"43 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76921524","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}
Loretta Umeonaku, Philip Adegboye, Emmanuel Ubadigha, Hamza Ibrahim, Francis Anwana, Gabriel Omale
Formation Pressure data is a key parameter for in-depth characterization of a reservoir's potential and capacity to produce hydrocarbon. Pressure data are analyzed to confirm fluid interface, fluid type as well as to understand reservoir connectivity/isolation and compartmentalization if any, needed to finalise on the completion strategy to be utilized for optimal production. Acquisition of this data while drilling provides early and reliable information for decision making in optimising the drilling process. This paper demonstrates the use of Formation Pressure While Drilling (FPWD) tool to acquire formation pressure data. It examines the successful wellsite execution of FPWD service deployed in 3 deepwater wells in the Gulf of Guinea. It discusses operational sequence, quality of the results and how the operator utilized acquired data. In Well A, the test objective was to establish reservoir connectivity between a producer and an injector. For Well B, acquired pressure data was crucial in finalizing completion strategy. Well C shows how the direct pressure measurements were utilized to update the mud program in real time while drilling. Finally, this paper reemphasizes the value of FPWD by outlining how acquired pressure data met clients objectives by providing valuable quality data which provided great insight in reservoir characterization and safely drilling the wells to Total Depth.
{"title":"Realtime Aaquisition of Formation Pressure Data For Reservoir Characterization and Safe Drilling","authors":"Loretta Umeonaku, Philip Adegboye, Emmanuel Ubadigha, Hamza Ibrahim, Francis Anwana, Gabriel Omale","doi":"10.2118/198771-MS","DOIUrl":"https://doi.org/10.2118/198771-MS","url":null,"abstract":"\u0000 Formation Pressure data is a key parameter for in-depth characterization of a reservoir's potential and capacity to produce hydrocarbon. Pressure data are analyzed to confirm fluid interface, fluid type as well as to understand reservoir connectivity/isolation and compartmentalization if any, needed to finalise on the completion strategy to be utilized for optimal production. Acquisition of this data while drilling provides early and reliable information for decision making in optimising the drilling process.\u0000 This paper demonstrates the use of Formation Pressure While Drilling (FPWD) tool to acquire formation pressure data. It examines the successful wellsite execution of FPWD service deployed in 3 deepwater wells in the Gulf of Guinea. It discusses operational sequence, quality of the results and how the operator utilized acquired data. In Well A, the test objective was to establish reservoir connectivity between a producer and an injector. For Well B, acquired pressure data was crucial in finalizing completion strategy. Well C shows how the direct pressure measurements were utilized to update the mud program in real time while drilling.\u0000 Finally, this paper reemphasizes the value of FPWD by outlining how acquired pressure data met clients objectives by providing valuable quality data which provided great insight in reservoir characterization and safely drilling the wells to Total Depth.","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":"77028315","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. Ndokwu, K. Amadi, Oluwaseun Toyobo, Victor Okowi, I. Ajisafe, A. Inenemo
Due to the low oil price, Exploration and Production (E&P) companies are driven to reduce the cost per barrel of oil equivalent (BOE). The application of reservoir navigation services, in the placement of high angle and horizontal (HAHZ) wells in the sweet spot of reservoirs, has aided in meeting this economic need of the E&P, while also improving hydrocarbon recovery. Reservoir navigation services (RNS) can be regarded as another tool for improving the odds of success while drilling of HAHZ wells. This service involves the integration of real-time data (deep-reading azimuthal resistivity, gamma-ray, density image, resistivity image logs, near bit inclination and a fit for purpose rotary steerable system) to accurately position the well-bore relative to specific subsurface targets, while remaining within the constraints of the drilling and completion program. RNS also require a software package capable of pre-well modeling, displaying the acquired real-time data and interactively adapting the model to the real-time data. Geosteering in Njaba field involved a comprehensive pre-well planning, discussions, documentation and management approved decision-tree. Using three wells for this study, this paper describes the challenges, procedures and results of geosteering in Njaba Field located on-shore Niger-Delta. From different entry points, wells NJX1, NJX2, and NJX3 were planned to drain the same reservoir and optimize hydrocarbon recovery within the reservoir. Some of the challenges encountered includes geosteering the wellbore above a pre-determined production TVD hardline while simultaneously avoiding drilling into an overlying undulating shale cap rock, vertical seismic uncertainty and undulating formation boundaries.
{"title":"Reservoir Navigation in Njaba Field – Challenges, Procedure and Results","authors":"C. Ndokwu, K. Amadi, Oluwaseun Toyobo, Victor Okowi, I. Ajisafe, A. Inenemo","doi":"10.2118/198786-MS","DOIUrl":"https://doi.org/10.2118/198786-MS","url":null,"abstract":"\u0000 Due to the low oil price, Exploration and Production (E&P) companies are driven to reduce the cost per barrel of oil equivalent (BOE). The application of reservoir navigation services, in the placement of high angle and horizontal (HAHZ) wells in the sweet spot of reservoirs, has aided in meeting this economic need of the E&P, while also improving hydrocarbon recovery.\u0000 Reservoir navigation services (RNS) can be regarded as another tool for improving the odds of success while drilling of HAHZ wells. This service involves the integration of real-time data (deep-reading azimuthal resistivity, gamma-ray, density image, resistivity image logs, near bit inclination and a fit for purpose rotary steerable system) to accurately position the well-bore relative to specific subsurface targets, while remaining within the constraints of the drilling and completion program. RNS also require a software package capable of pre-well modeling, displaying the acquired real-time data and interactively adapting the model to the real-time data.\u0000 Geosteering in Njaba field involved a comprehensive pre-well planning, discussions, documentation and management approved decision-tree. Using three wells for this study, this paper describes the challenges, procedures and results of geosteering in Njaba Field located on-shore Niger-Delta. From different entry points, wells NJX1, NJX2, and NJX3 were planned to drain the same reservoir and optimize hydrocarbon recovery within the reservoir. Some of the challenges encountered includes geosteering the wellbore above a pre-determined production TVD hardline while simultaneously avoiding drilling into an overlying undulating shale cap rock, vertical seismic uncertainty and undulating formation boundaries.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"130 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79239227","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}
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. 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}
One of the cruel environmental quagmires confronting the Petroleum industry is the high organic pollutant levels in the bio-treatment unit of its refinery wastewater treatment plants which is not in line with the design specification. High level of organic pollutants in discharged non-compliant effluents from petroleum refineries leads to varied environmental hazards. Wastewaters discharged from petroleum refineries are characterized by the presence of toxic pollutants like phenols, polycyclic aromatic hydrocarbons (PAHs), metal derivatives, etc. Numerous enzymes from plants, fungi and bacteria have been reported to be involved in the degradation of toxic organic pollutants but with limited field trials. The present study focuses on production and characterization of enzyme, tyrosinase expressed by native microorganisms in refinery wastewater and its application in the removal of organic pollutants from petroleum refinery effluents. A total of 10 microbial strains were identified and isolated from refinery wastewater and screened for expression of tyrosinase using standard microbiological methods. Among 10 isolates, 4 isolates; Bacilus subtilis, Verticillium sp., Penicillium sp. and Aspergillus flavus were selected for enzyme characterization and production based on the magnitude of the zone of clearance they produced. Tyrosinase was produced in broth and partially purified by ammonium sulfate precipitation, dialysis and Sephadex G-75. The purified enzyme was immobilized in sodium alginate and was used for the treatment of petroleum refinery wastewater. Results revealed that the immobilized enzyme significantly removed phenol and PAHs present in the wastewater by 95 %, and 89 % respectively. These findings highlight the viability of enzyme, tyrosinase, for the degradation of organic pollutants in petroleum-derived effluents.
{"title":"Production and Characterization of Tyrosinase Enzyme for Enhanced Treatment of Organic Pollutants in Petroleum Refinery Effluent","authors":"J. O. Osuoha, B. Abbey, E. Egwim, E. Nwaichi","doi":"10.2118/198791-MS","DOIUrl":"https://doi.org/10.2118/198791-MS","url":null,"abstract":"\u0000 One of the cruel environmental quagmires confronting the Petroleum industry is the high organic pollutant levels in the bio-treatment unit of its refinery wastewater treatment plants which is not in line with the design specification. High level of organic pollutants in discharged non-compliant effluents from petroleum refineries leads to varied environmental hazards. Wastewaters discharged from petroleum refineries are characterized by the presence of toxic pollutants like phenols, polycyclic aromatic hydrocarbons (PAHs), metal derivatives, etc. Numerous enzymes from plants, fungi and bacteria have been reported to be involved in the degradation of toxic organic pollutants but with limited field trials. The present study focuses on production and characterization of enzyme, tyrosinase expressed by native microorganisms in refinery wastewater and its application in the removal of organic pollutants from petroleum refinery effluents. A total of 10 microbial strains were identified and isolated from refinery wastewater and screened for expression of tyrosinase using standard microbiological methods. Among 10 isolates, 4 isolates; Bacilus subtilis, Verticillium sp., Penicillium sp. and Aspergillus flavus were selected for enzyme characterization and production based on the magnitude of the zone of clearance they produced. Tyrosinase was produced in broth and partially purified by ammonium sulfate precipitation, dialysis and Sephadex G-75. The purified enzyme was immobilized in sodium alginate and was used for the treatment of petroleum refinery wastewater. Results revealed that the immobilized enzyme significantly removed phenol and PAHs present in the wastewater by 95 %, and 89 % respectively. These findings highlight the viability of enzyme, tyrosinase, for the degradation of organic pollutants in petroleum-derived effluents.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86042686","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}
Jacob B. Neeka, Uche Ikoku, Ere Iyalla, O. Joel, S. S. Ikiensikimama
Liquefied Petroleum Gas (LPG), a product of natural gas processing is a mixture of hydrocarbon gases mainly propane, butane, butylene and impurities such as Sulphur compounds. The production of LPG depends largely on available natural gas. Fortunately, Nigeria has proven gas reserves of over 189.27 Trillion Cubit Feet (TCF). However, LPG production in the country and its distribution especially in an emerging economy appeared to have limited growth over the last three decades. In this study, a stochastic model is applied to secondary historical and predictive data from 1994 – 2020, essentially on the production, consumption and streamline distribution pattern for the country. Certain assumptions were made including changes in the various stages in the production value chains (production, storage, distribution, pipeline infrastructure, and supply chains in-country.). Linear regression and correlation approaches were adopted using the models which agreed favorably with the plots from established data. It indicated that LPG consumption increases rapidly from 2016 upward following increases in infrastructural surplus, investment and awareness enlightenment initiatives. The results obtained indicated a strong correlation between demand-supply bond driven by market forces in the urban and suburban cities in-country. These indicators are reliable parameters for sustainable strategic planning, policy development and implementation for rapid economic recovery.
{"title":"Predictive Models on Viable Options for Liquefied Petroleum Gas LPG Distribution: Case for a Small and Medium Scale Enterprise SME Commodity in Nigeria","authors":"Jacob B. Neeka, Uche Ikoku, Ere Iyalla, O. Joel, S. S. Ikiensikimama","doi":"10.2118/198871-MS","DOIUrl":"https://doi.org/10.2118/198871-MS","url":null,"abstract":"\u0000 Liquefied Petroleum Gas (LPG), a product of natural gas processing is a mixture of hydrocarbon gases mainly propane, butane, butylene and impurities such as Sulphur compounds. The production of LPG depends largely on available natural gas. Fortunately, Nigeria has proven gas reserves of over 189.27 Trillion Cubit Feet (TCF). However, LPG production in the country and its distribution especially in an emerging economy appeared to have limited growth over the last three decades. In this study, a stochastic model is applied to secondary historical and predictive data from 1994 – 2020, essentially on the production, consumption and streamline distribution pattern for the country. Certain assumptions were made including changes in the various stages in the production value chains (production, storage, distribution, pipeline infrastructure, and supply chains in-country.). Linear regression and correlation approaches were adopted using the models which agreed favorably with the plots from established data. It indicated that LPG consumption increases rapidly from 2016 upward following increases in infrastructural surplus, investment and awareness enlightenment initiatives. The results obtained indicated a strong correlation between demand-supply bond driven by market forces in the urban and suburban cities in-country. These indicators are reliable parameters for sustainable strategic planning, policy development and implementation for rapid economic recovery.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"71 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90330328","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
京公网安备 11010802042870号
京ICP备2023020795号-1
扫码关注我们
求助内容：
应助结果提醒方式：