O. Emeka, Y. Adeeyo, A. Etim, Opeyemi Oluwalade, Onyema Ohabuike, Uzoamaka Okene, Leziga Bakor, I. Ukauku, Niyi Afolabi, Jolomi Esimaje
With global Oil prices still recovering from the down cycle and coupled with high cost of drilling new wells, EROTON E & P has devised strategies to manage declining oil production, increase oil production from her existing assets and add new reserves through team integration and improved subsurface data management by using fit-for-purpose technology (cement packer) and other collaborative tools. Cement packer technology is a relatively fast-to-deploy and cost-effective rig-less intervention technique that allows easy access to hydrocarbon reserves behind pipe which are located above and between production packers in wells where the existing completion intervals have reached their economic limit. This technology can be used to separate a new zone earmarked for completion from other intervals including non-hydrocarbon zones. The cement plug is pumped into the allocated space to serve as an effective production packer. This becomes viable and economic option when the interval is above an existing parker. Cement packer activity can be carried out using a rigless unit with the benefit of significant cost savings while achieving seamless isolation of the production intervals. One example from the strings of successful cement parker operation, among a few others, is the CAAK-040 well in CAAK field. The well was drilled in 1988 and completed on X3050B and Y4050B reservoirs. Both intervals quit in 2001 at BSW above 80%. After the integrated subsurface evaluation using all available data including CO logging acquired across the existing and proposed completion intervals, CAAK-040 was proposed for a zone change. A rigless workover intervention of the well was executed and the production interval switched from Y4050B to C8000B reservoir on the new short string using cement packer technology to isolate Y4050B completion and recomplete in the new target sand. CAAK-040 did not flow after the cement packer and perforation operations were successfully executed and the well had to be lifted to production using a temporary gaslift system. Currently, the well is performing above the planned potential of 1500bopd from C8000B reservoir. This paper will discuss the lessons learnt and best practices from the cement packer and re-perforation of CAAK-040 using a rigless workover unit. There is continuous monitoring to ensure all approved company procedures and minimum standards are strictly adhered to. To date, we have a total of five (5) wells that have been recompleted and reserve added using cement packer. This activity has accelerated the production system unlocking of short-term oil generation (STOG) production of over 5,000 b/d of oil in one-year target. The average total cost of this operation is about 20-30% of a conventional workover. Thereby saving the company over $20m with added rewards of reactivating shut-in wells and producing reserves that were previously sub-economical and inaccessible.
{"title":"Rigless Recompletion Using Cement Packer – EROTON E & P Experience","authors":"O. Emeka, Y. Adeeyo, A. Etim, Opeyemi Oluwalade, Onyema Ohabuike, Uzoamaka Okene, Leziga Bakor, I. Ukauku, Niyi Afolabi, Jolomi Esimaje","doi":"10.2118/198769-MS","DOIUrl":"https://doi.org/10.2118/198769-MS","url":null,"abstract":"\u0000 With global Oil prices still recovering from the down cycle and coupled with high cost of drilling new wells, EROTON E & P has devised strategies to manage declining oil production, increase oil production from her existing assets and add new reserves through team integration and improved subsurface data management by using fit-for-purpose technology (cement packer) and other collaborative tools.\u0000 Cement packer technology is a relatively fast-to-deploy and cost-effective rig-less intervention technique that allows easy access to hydrocarbon reserves behind pipe which are located above and between production packers in wells where the existing completion intervals have reached their economic limit. This technology can be used to separate a new zone earmarked for completion from other intervals including non-hydrocarbon zones. The cement plug is pumped into the allocated space to serve as an effective production packer. This becomes viable and economic option when the interval is above an existing parker. Cement packer activity can be carried out using a rigless unit with the benefit of significant cost savings while achieving seamless isolation of the production intervals.\u0000 One example from the strings of successful cement parker operation, among a few others, is the CAAK-040 well in CAAK field. The well was drilled in 1988 and completed on X3050B and Y4050B reservoirs. Both intervals quit in 2001 at BSW above 80%. After the integrated subsurface evaluation using all available data including CO logging acquired across the existing and proposed completion intervals, CAAK-040 was proposed for a zone change. A rigless workover intervention of the well was executed and the production interval switched from Y4050B to C8000B reservoir on the new short string using cement packer technology to isolate Y4050B completion and recomplete in the new target sand. CAAK-040 did not flow after the cement packer and perforation operations were successfully executed and the well had to be lifted to production using a temporary gaslift system.\u0000 Currently, the well is performing above the planned potential of 1500bopd from C8000B reservoir. This paper will discuss the lessons learnt and best practices from the cement packer and re-perforation of CAAK-040 using a rigless workover unit.\u0000 There is continuous monitoring to ensure all approved company procedures and minimum standards are strictly adhered to.\u0000 To date, we have a total of five (5) wells that have been recompleted and reserve added using cement packer. This activity has accelerated the production system unlocking of short-term oil generation (STOG) production of over 5,000 b/d of oil in one-year target. The average total cost of this operation is about 20-30% of a conventional workover. Thereby saving the company over $20m with added rewards of reactivating shut-in wells and producing reserves that were previously sub-economical and inaccessible.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"14 2 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88058325","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. Adebayo, Olugbenga Daodu, Eric Ezenobi, Olayinka David, A. Laoye, G. Komolafe, L. Dennar, Somto Nwandu, C. Chidiebere, Suleiman Ahmed, Ime E. Uyouko
Well integrity is a key focus area in any oil and gas development. There have been several cases of well integrity issues which have resulted in scenarios of blowout, loss of lives, assets, and reputation, including costs spent for clean-up and environmental remediation, amongst others. These and more have made the energy industry put a keen focus to making sure all hydrocarbon production and processing facilities are integral, with newer technologies still being developed to aid the diagnosis of well integrity problems. Well integrity considerations cut across the entire life cycle of the well, from well conceptualization/planning through to drilling, completion, production and abandonment. This case study presents a high-pressure, high temperature gas well with sustained annulus pressure in the early production phase of the well. Well X is a gas well completed in an elevated pressure and temperature reservoir on a land terrain. The reservoir is about 13000ftss deep, with a temperature of 219°F and a reservoir pressure of 9300psi. The well was completed, cleaned up and brought to production about a year ago and annular pressures were observed. This paper details the different approaches used in diagnosing the sustained annular pressures – separating thermal effect from sustained pressure due to leak. It shows the different scenarios of leak paths identified and how these were streamlined. The paper also highlights the integration of data acquired during the investigation. Some of the data acquired include well annuli pressures, high precision temperature logs, spectral noise logs and electromagnetic corrosion logs.
{"title":"A Case Study of Sustained Annulus Pressure Diagnosis in a Newly Drilled High-Pressure Gas Well in SPDC","authors":"A. Adebayo, Olugbenga Daodu, Eric Ezenobi, Olayinka David, A. Laoye, G. Komolafe, L. Dennar, Somto Nwandu, C. Chidiebere, Suleiman Ahmed, Ime E. Uyouko","doi":"10.2118/198856-MS","DOIUrl":"https://doi.org/10.2118/198856-MS","url":null,"abstract":"\u0000 Well integrity is a key focus area in any oil and gas development. There have been several cases of well integrity issues which have resulted in scenarios of blowout, loss of lives, assets, and reputation, including costs spent for clean-up and environmental remediation, amongst others. These and more have made the energy industry put a keen focus to making sure all hydrocarbon production and processing facilities are integral, with newer technologies still being developed to aid the diagnosis of well integrity problems.\u0000 Well integrity considerations cut across the entire life cycle of the well, from well conceptualization/planning through to drilling, completion, production and abandonment. This case study presents a high-pressure, high temperature gas well with sustained annulus pressure in the early production phase of the well.\u0000 Well X is a gas well completed in an elevated pressure and temperature reservoir on a land terrain. The reservoir is about 13000ftss deep, with a temperature of 219°F and a reservoir pressure of 9300psi. The well was completed, cleaned up and brought to production about a year ago and annular pressures were observed.\u0000 This paper details the different approaches used in diagnosing the sustained annular pressures – separating thermal effect from sustained pressure due to leak. It shows the different scenarios of leak paths identified and how these were streamlined.\u0000 The paper also highlights the integration of data acquired during the investigation. Some of the data acquired include well annuli pressures, high precision temperature logs, spectral noise logs and electromagnetic corrosion logs.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"39 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90874547","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}
Structural complexities are concerns frequently encountered as peculiar features in most hydrocarbon provinces which various attempts has been made to resolve using conventional spatial images of the subsurface as continuous seismic reflections. These structural patterns are either tectonic or sedimentonic in origin and confers anisotropy and heterogeneity in subsurface formations thereby increasing the uncertainty associated with exploring hydrocarbon locked in their pores. Diffraction imaging has been used in various instances to delineate subtle discontinuities that synthesize diffraction waves in hydrocarbon formations, in tandem with reflection seismic and other invasive geophysical logs and core, in comparatively understanding fracture orientations and establishing relationships with the temporal data that are often regarded as most reliable. These data points have been used to infer structural relationship between the naturally fractured clastic formations in an oil and gas field with success. Rock elastic properties and signal anisotropy derived from core and logs resulted in structural attributes that correlated well with seismic diffraction volume inferred properties, giving credence to the relationships established and usefulness of the diffraction volume for characterizing and emphasizing small scale features hitherto classed as sub-seismic.
{"title":"Delineating Fracture Patterns from Seismic and Well Derived Multi-Attributes Data","authors":"Rotimi Oluwatosin John, Yao Liang, Zhenli Wang","doi":"10.2118/198763-MS","DOIUrl":"https://doi.org/10.2118/198763-MS","url":null,"abstract":"\u0000 Structural complexities are concerns frequently encountered as peculiar features in most hydrocarbon provinces which various attempts has been made to resolve using conventional spatial images of the subsurface as continuous seismic reflections. These structural patterns are either tectonic or sedimentonic in origin and confers anisotropy and heterogeneity in subsurface formations thereby increasing the uncertainty associated with exploring hydrocarbon locked in their pores. Diffraction imaging has been used in various instances to delineate subtle discontinuities that synthesize diffraction waves in hydrocarbon formations, in tandem with reflection seismic and other invasive geophysical logs and core, in comparatively understanding fracture orientations and establishing relationships with the temporal data that are often regarded as most reliable. These data points have been used to infer structural relationship between the naturally fractured clastic formations in an oil and gas field with success. Rock elastic properties and signal anisotropy derived from core and logs resulted in structural attributes that correlated well with seismic diffraction volume inferred properties, giving credence to the relationships established and usefulness of the diffraction volume for characterizing and emphasizing small scale features hitherto classed as sub-seismic.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"88 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89015582","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 selection of appropriate candidate wells for a stimulation operation is the most vital step for the economic success of the process. The selection criteria include assessing the well damage and choosing the appropriate approach to stimulate it. Most selection approaches consider the effects of damage and their corresponding treatment methods neglecting the economic influence of the process. This research, therefore, presents a detailed approach to candidate well selection for matrix stimulation using Vogel’s Inflow Performance Relationship (IPR) curve analysis. A non-linear mathematical optimisation model was developed in Microsoft Excel using this analysis. This model requires certain input parameters for each well in order to generate results which could be analysed for the right decision. To validate the model, data from four wells on the Nero Field were used as input parameters. The results show that Well N3 has the highest total post-stimulation production of 12 833 886 barrels of oil and therefore should be considered for the stimulation operation. Sensitivity analysis was also conducted on Well N3 to see the performance of the well when certain independent variables such as price of oil, discount rate, and stimulation time are varied. The results show that the post-stimulation well performance is positively influenced by oil price, increasing as the oil price increase. The post-stimulation well performance, however, show a negative influence from both the discount rate and stimulation time, decreasing as those two parameters increase
{"title":"Optimising Candidate Well Selection for Matrix Stimulation-IPR Approach","authors":"E. M. Amarfio, P. T. Adusu","doi":"10.2118/198707-MS","DOIUrl":"https://doi.org/10.2118/198707-MS","url":null,"abstract":"\u0000 The selection of appropriate candidate wells for a stimulation operation is the most vital step for the economic success of the process. The selection criteria include assessing the well damage and choosing the appropriate approach to stimulate it. Most selection approaches consider the effects of damage and their corresponding treatment methods neglecting the economic influence of the process. This research, therefore, presents a detailed approach to candidate well selection for matrix stimulation using Vogel’s Inflow Performance Relationship (IPR) curve analysis. A non-linear mathematical optimisation model was developed in Microsoft Excel using this analysis. This model requires certain input parameters for each well in order to generate results which could be analysed for the right decision. To validate the model, data from four wells on the Nero Field were used as input parameters. The results show that Well N3 has the highest total post-stimulation production of 12 833 886 barrels of oil and therefore should be considered for the stimulation operation. Sensitivity analysis was also conducted on Well N3 to see the performance of the well when certain independent variables such as price of oil, discount rate, and stimulation time are varied. The results show that the post-stimulation well performance is positively influenced by oil price, increasing as the oil price increase. The post-stimulation well performance, however, show a negative influence from both the discount rate and stimulation time, decreasing as those two parameters increase","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"39 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79101896","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. Fajemidupe, A. Aliyu, Y. Baba, A. Archibong, N. E. Okeke, A. Ehinmowo, H. Yeung
Producing sand during oil and gas production is unavoidable. Sand is produced along with oil and gas and its deposition in pipelines is a significant risk as it can cause pipe corrosion and flow assurance difficulties. It is therefore key that flow conditions are sustained to guarantee lack of deposition of sand particles. The minimum combination of mixture velocities that guarantee continuous sand motion is known as the minimum transport condition (MTC). Here, we investigate the effect both of sand concentration and particle diameter on MTC in a horizontal pipeline in the stratified flow regime. Non-intrusive conductivity probes were utilised for the detection of sand. These sensors are commonly used for the measurement of film thickness in gas and liquid flows, but we demonstrate their use here for sand detection after suitable calibration. It was observed that at the ultra-low sand concentrations of our experiments, MTC increases with both sand particle diameter and concentration. We developed a new correlation based on Thomas's lower model but included a sand concentration correction term that also applies at low particle concentrations. The correlation's predictions compared favourably with our measurements at MTC as well as data obtained from the open literature at medium concentrations.
{"title":"Minimum Sand Transport Conditions in Gas-Solid-Liquid Three-Phase Stratified Flow in Horizontal Pipelines","authors":"O. Fajemidupe, A. Aliyu, Y. Baba, A. Archibong, N. E. Okeke, A. Ehinmowo, H. Yeung","doi":"10.2118/198726-MS","DOIUrl":"https://doi.org/10.2118/198726-MS","url":null,"abstract":"\u0000 Producing sand during oil and gas production is unavoidable. Sand is produced along with oil and gas and its deposition in pipelines is a significant risk as it can cause pipe corrosion and flow assurance difficulties. It is therefore key that flow conditions are sustained to guarantee lack of deposition of sand particles. The minimum combination of mixture velocities that guarantee continuous sand motion is known as the minimum transport condition (MTC). Here, we investigate the effect both of sand concentration and particle diameter on MTC in a horizontal pipeline in the stratified flow regime. Non-intrusive conductivity probes were utilised for the detection of sand. These sensors are commonly used for the measurement of film thickness in gas and liquid flows, but we demonstrate their use here for sand detection after suitable calibration. It was observed that at the ultra-low sand concentrations of our experiments, MTC increases with both sand particle diameter and concentration. We developed a new correlation based on Thomas's lower model but included a sand concentration correction term that also applies at low particle concentrations. The correlation's predictions compared favourably with our measurements at MTC as well as data obtained from the open literature at medium concentrations.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"75 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80650132","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}
W. I. Eke, O. Achugasim, S. E. Ofordile, J. Ajienka, O. Akaranta
Use of chemical additives for the control of wax formation and to improve flow properties of waxy crude oil is increasingly being adopted by oil industry operators. Most of these additives, such as pour point depressants, wax crystal modifiers or wax inhibitors are synthetic polymeric compounds, with poly acrylates and methacrylates, poly(alkylmaleate-co-α-olefin), poly(styrene-co-alkylmaleamide) and poly(ethylene-co-vinyl acetate) constituting the dominant chemistry. The high specificity of pour point depressant formulations to oil wells and the considerable expense incurred by industry operators on chemical injections continue to increase the interest for the development of better and cheaper chemical solutions to the wax formation problem. The present work reports the application of natural Cashew Nut Shell Liquid (CNSL) as a flow improver for waxy crude oils and its potential as a veritable resource for the development of new pour point depressants for waxy crude oils. CNSL was solvent-extracted from the shells of Cashew Nut (Anacardium Occidentale L.) using a soxhlet extractor. The physico-chemical properties of CNSL were determined. Functional group characterization was carried out by Fourier Transform Infrared Spectroscopy (FTIR). Rheological evaluation of CNSL at temperatures ranging from 10°C to 60°C using a coaxial cylinder rotational viscometer showed Newtonian behavior. Two Niger-Delta waxy crude oils were characterized to determine their API gravity, water content, kinematic and dynamic viscosity, pour point, Wax Appearance Temperature, wax content, asphaltene content and paraffin carbon number distribution. Wax formation in neat and CNSL-dosed crude oil was studied using cross-polarized microscopy. The pour point of a test crude oil dosed with CNSL at 4000ppm was depressed by 6°C. CNSL reduced the viscosity of the two waxy crude oils by 60% and 35% respectively during couette flow at a temperature of 10°C. CNSL can function as a pour point depressant and viscosity reducer for waxy crude oils and holds promise as a renewable chemical feedstock for the production of pour point depressants and other oilfield chemicals.
{"title":"Performance Evaluation of Cashew Nut Shell Liquid CNSL as Flow Improver for Waxy Crude Oils","authors":"W. I. Eke, O. Achugasim, S. E. Ofordile, J. Ajienka, O. Akaranta","doi":"10.2118/198721-MS","DOIUrl":"https://doi.org/10.2118/198721-MS","url":null,"abstract":"\u0000 Use of chemical additives for the control of wax formation and to improve flow properties of waxy crude oil is increasingly being adopted by oil industry operators. Most of these additives, such as pour point depressants, wax crystal modifiers or wax inhibitors are synthetic polymeric compounds, with poly acrylates and methacrylates, poly(alkylmaleate-co-α-olefin), poly(styrene-co-alkylmaleamide) and poly(ethylene-co-vinyl acetate) constituting the dominant chemistry. The high specificity of pour point depressant formulations to oil wells and the considerable expense incurred by industry operators on chemical injections continue to increase the interest for the development of better and cheaper chemical solutions to the wax formation problem. The present work reports the application of natural Cashew Nut Shell Liquid (CNSL) as a flow improver for waxy crude oils and its potential as a veritable resource for the development of new pour point depressants for waxy crude oils. CNSL was solvent-extracted from the shells of Cashew Nut (Anacardium Occidentale L.) using a soxhlet extractor. The physico-chemical properties of CNSL were determined. Functional group characterization was carried out by Fourier Transform Infrared Spectroscopy (FTIR). Rheological evaluation of CNSL at temperatures ranging from 10°C to 60°C using a coaxial cylinder rotational viscometer showed Newtonian behavior. Two Niger-Delta waxy crude oils were characterized to determine their API gravity, water content, kinematic and dynamic viscosity, pour point, Wax Appearance Temperature, wax content, asphaltene content and paraffin carbon number distribution. Wax formation in neat and CNSL-dosed crude oil was studied using cross-polarized microscopy. The pour point of a test crude oil dosed with CNSL at 4000ppm was depressed by 6°C. CNSL reduced the viscosity of the two waxy crude oils by 60% and 35% respectively during couette flow at a temperature of 10°C. CNSL can function as a pour point depressant and viscosity reducer for waxy crude oils and holds promise as a renewable chemical feedstock for the production of pour point depressants and other oilfield chemicals.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"13 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73448649","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 prohibitive costs & risks associated with performing PLT and potentially the isolation of the water producing zone through WSO in deepwater fields such as Akpo renders these operations economically unattractive. This paper addresses the application of analytical method including the use of 4D monitor results to replace conventional PLT to identify, screen and select viable successful water shut off candidates. Prior to executing water shut-off treatment programs, a combination of 4D seismic interpretation, production history review as well as the collection of completion and reservoir information were thoroughly performed to ensure that the wells are properly selected. Well's diagnostic plot (WOR and WOR′) must be consistent with the type of water coning or channeling problem identified from the 4D time lapse seismic and also the depth of possible mechanical plug must be around or above estimated current oil-water contact (COWC). Two candidate wells having 6-5/8″ SAS Slot 10 in 8.5″ open hole, at approximately 4,000 meter TD, and 82 deg C reservoir temperature were selected. The water cut values were 55% in one well and 60% in the other. This paper presents below the significant upside for WSO attributed to the use of analytical method and integration of 4D seismic data by eliminating the need to run a traditional PLT. The operation was technically & economically successful on one well with a decrease of watercut from 55% to 16% resulting in the well incremental oil production of ~3kbopd. Operation is planned mid 2019 for the second well
{"title":"Application of the Combined Analytical Methods & Time Lapse Seismic 4D as a Veritable Tool for Water Shut Off WSO Operations – Deepwater Akpo Field","authors":"M. Usman, V. Biu, Jed Oukmal, A. Adeyemi","doi":"10.2118/198814-MS","DOIUrl":"https://doi.org/10.2118/198814-MS","url":null,"abstract":"\u0000 The prohibitive costs & risks associated with performing PLT and potentially the isolation of the water producing zone through WSO in deepwater fields such as Akpo renders these operations economically unattractive.\u0000 This paper addresses the application of analytical method including the use of 4D monitor results to replace conventional PLT to identify, screen and select viable successful water shut off candidates.\u0000 Prior to executing water shut-off treatment programs, a combination of 4D seismic interpretation, production history review as well as the collection of completion and reservoir information were thoroughly performed to ensure that the wells are properly selected.\u0000 Well's diagnostic plot (WOR and WOR′) must be consistent with the type of water coning or channeling problem identified from the 4D time lapse seismic and also the depth of possible mechanical plug must be around or above estimated current oil-water contact (COWC).\u0000 Two candidate wells having 6-5/8″ SAS Slot 10 in 8.5″ open hole, at approximately 4,000 meter TD, and 82 deg C reservoir temperature were selected. The water cut values were 55% in one well and 60% in the other.\u0000 This paper presents below the significant upside for WSO attributed to the use of analytical method and integration of 4D seismic data by eliminating the need to run a traditional PLT. The operation was technically & economically successful on one well with a decrease of watercut from 55% to 16% resulting in the well incremental oil production of ~3kbopd. Operation is planned mid 2019 for the second well","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"28 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86560951","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 effect of temperature and brine composition on Crude-Oil-Rock-Brine (CORB) interactions during controlled salinity brine and biosurfactant injection process were investigated and reported in this study. Comprehensive core flooding experiments were carried out using formation brine, controlled salinity brine and combined controlled salinity biosurfactant brine injection in carbonate core samples at 23 °C and 70 °C. Effluent analyses and oil recovery from each flooding experiment were used to interpret the temperature and brine composition effect on the CORB interactions. The results of this study show that increased temperature makes no significant impact on CORB interactions during high salinity brine flooding. Increased temperature however, enhances CORB interactions through increased reactivity during controlled salinity brine and controlled salinity biosurfactant brine flooding thereby, resulting in increased oil production. Furthermore, the results of this study demonstrated the enhanced oil recovery potential of combined controlled salinity brine and biosurfactant application in condition relevant to hydrocarbon reservoirs.
{"title":"Effects of Temperature on Crude-Oil-Rock-Brine Interactions During Controlled Salinity Biosurfactant Flooding","authors":"Tinuola Udoh, J. Vinogradov","doi":"10.2118/198761-MS","DOIUrl":"https://doi.org/10.2118/198761-MS","url":null,"abstract":"\u0000 The effect of temperature and brine composition on Crude-Oil-Rock-Brine (CORB) interactions during controlled salinity brine and biosurfactant injection process were investigated and reported in this study. Comprehensive core flooding experiments were carried out using formation brine, controlled salinity brine and combined controlled salinity biosurfactant brine injection in carbonate core samples at 23 °C and 70 °C. Effluent analyses and oil recovery from each flooding experiment were used to interpret the temperature and brine composition effect on the CORB interactions. The results of this study show that increased temperature makes no significant impact on CORB interactions during high salinity brine flooding. Increased temperature however, enhances CORB interactions through increased reactivity during controlled salinity brine and controlled salinity biosurfactant brine flooding thereby, resulting in increased oil production. Furthermore, the results of this study demonstrated the enhanced oil recovery potential of combined controlled salinity brine and biosurfactant application in condition relevant to hydrocarbon reservoirs.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"77 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88152359","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}
B. Anyanwu, A. Ezejiofor, I. Nwaogazie, O. Orisakwe
The craze for technological development has given rise to environmental safety concerns. Various human activities such as artisanal mining, illegal refining, use of leaded petrol, illegal disposal and burning of toxic waste, absorption of production industries in inhabited areas have led to high contamination and pollution associated with heavy metals. The research was done to explore the effect of low dose exposure to heavy metal mixture using male albino rats as experimental animals. The experimental rats were separated into two equal groups; (i) control receiving only deionized water, (ii) combination of metals (PbCl2+ CdCl2 + HgCl2). Treatment was carried out through oral gavage. Induced low dose heavy metal mixture substantially decreased the follicle stimulating hormone, luteinizing hormone and testosterone levels and significantly increased the prolactin level. It also resulted to hepatotoxicity by significantly increasing the liver enzymes and bilirubin level, thereby reducing the total protein and albumin levels. The lipid profile was also investigated to check the risk associated with the cardiovascular system. The result showed a considerable increase (P<0.05) in triglycerides, total cholesterol, low density lipoprotein and very low density lipoprotein and a significant reduction in high density lipoprotein when compared with the control group. Furthermore, low dose heavy metal mixture induced histopathological changes to the liver. Collectively, our findings clearly highlight that environmental and occupational exposure to heavy metals resulted to hepatotoxicity, risk to the cardiovascular system and changes to the hormonal system.
{"title":"Effect of Environmental and Occupational Exposures to Heavy Metals: The Health Implications","authors":"B. Anyanwu, A. Ezejiofor, I. Nwaogazie, O. Orisakwe","doi":"10.2118/198740-MS","DOIUrl":"https://doi.org/10.2118/198740-MS","url":null,"abstract":"\u0000 The craze for technological development has given rise to environmental safety concerns. Various human activities such as artisanal mining, illegal refining, use of leaded petrol, illegal disposal and burning of toxic waste, absorption of production industries in inhabited areas have led to high contamination and pollution associated with heavy metals. The research was done to explore the effect of low dose exposure to heavy metal mixture using male albino rats as experimental animals. The experimental rats were separated into two equal groups; (i) control receiving only deionized water, (ii) combination of metals (PbCl2+ CdCl2 + HgCl2). Treatment was carried out through oral gavage. Induced low dose heavy metal mixture substantially decreased the follicle stimulating hormone, luteinizing hormone and testosterone levels and significantly increased the prolactin level. It also resulted to hepatotoxicity by significantly increasing the liver enzymes and bilirubin level, thereby reducing the total protein and albumin levels. The lipid profile was also investigated to check the risk associated with the cardiovascular system. The result showed a considerable increase (P<0.05) in triglycerides, total cholesterol, low density lipoprotein and very low density lipoprotein and a significant reduction in high density lipoprotein when compared with the control group. Furthermore, low dose heavy metal mixture induced histopathological changes to the liver. Collectively, our findings clearly highlight that environmental and occupational exposure to heavy metals resulted to hepatotoxicity, risk to the cardiovascular system and changes to the hormonal system.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"62 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85223820","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}
H. K. Abdulfatah, Okafor Ikechukwu Stanley, P. Nzerem, K. Jakada
A reservoir development plan provides the necessary guidance and information for establishing whether or not a project is economically viable considering possible development project options, risks and uncertainties in order to define the most optimal development concept that will increase oil production and reduce production costs. The aim of this project was to determine the optimum way to develop and produce an offshore oil field in a manner that considers risks and uncertainties and values stakeholders’ interest. A stochastic multi-tank reservoir model was created using MBAL and it consist of various producers and water injection wells. Sensitivity analysis was carried out on Seven development scenarios with a view to examine effect of maintaining reservoir pressure, sustaining well productivity and injectivity, optimize well counts and improving well delivery- timing, cost and well performance. The economic viability of each of the development scenarios was carried out to determine the net present value, incremental project cash flow, unit technical cost, unit development cost and breakeven price BEP of each of the scenarios. The optimal development strategy was then selected based on the production performance and key economic indicators. The project provided an opportunity to develop an additional 396MMbbls of recoverable oil from 32 new wells both producers and injector wells (P+WI).
{"title":"Defining the Optimal Development Strategy to Maximize Recovery and Production Rate from an Integrated Offshore Water-Flood Project","authors":"H. K. Abdulfatah, Okafor Ikechukwu Stanley, P. Nzerem, K. Jakada","doi":"10.2118/198843-MS","DOIUrl":"https://doi.org/10.2118/198843-MS","url":null,"abstract":"\u0000 A reservoir development plan provides the necessary guidance and information for establishing whether or not a project is economically viable considering possible development project options, risks and uncertainties in order to define the most optimal development concept that will increase oil production and reduce production costs. The aim of this project was to determine the optimum way to develop and produce an offshore oil field in a manner that considers risks and uncertainties and values stakeholders’ interest. A stochastic multi-tank reservoir model was created using MBAL and it consist of various producers and water injection wells. Sensitivity analysis was carried out on Seven development scenarios with a view to examine effect of maintaining reservoir pressure, sustaining well productivity and injectivity, optimize well counts and improving well delivery- timing, cost and well performance. The economic viability of each of the development scenarios was carried out to determine the net present value, incremental project cash flow, unit technical cost, unit development cost and breakeven price BEP of each of the scenarios. The optimal development strategy was then selected based on the production performance and key economic indicators. The project provided an opportunity to develop an additional 396MMbbls of recoverable oil from 32 new wells both producers and injector wells (P+WI).","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"52 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82945740","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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