In this paper, review findings from past literature on development of thin oil rim reservoirs are presented. The review entailed going through several papers written in the subject with a view to identifying possible research gaps with opportunity of proffering solutions. The review areas that require attention include; proper definition of thin oil rim reservoir, inadequacy of the current classification of factors that affect oil rim development by non-consideration of strategic, commercial and stakeholder aspects. Other areas include; non- application of a combined depletion and flooding scheme under critical flow conditions in the Niger Delta and non-focus on controllable factors in the use of engineering design in the evaluation of thin oil rim reservoir development options. Hence in this paper we proffer thoughts on a rational definition of a "Thin oil rim reservoir", highlight some development schemes termed "novel" in this study and propose such applications in evaluation of thin oil rim reservoirs especially in the Niger Delta. The evaluation of these options suffixes as evidence that due diligence has been made in a bid to ensure a robust development plan. Finally, the paper presents discussion on recovery factor from thin oil rim reservoir developments with the objective of providing guidance on applicable ranges and highlight the opportunities in giving more focused attention and priority to the development of a thin oil rim reservoir.
{"title":"Exploitation of Thin Oil Rim with Large Gas Cap, a Critical Review","authors":"Obidike Peter, M. Onyekonwu, C. Ubani","doi":"10.2118/198724-MS","DOIUrl":"https://doi.org/10.2118/198724-MS","url":null,"abstract":"\u0000 In this paper, review findings from past literature on development of thin oil rim reservoirs are presented. The review entailed going through several papers written in the subject with a view to identifying possible research gaps with opportunity of proffering solutions.\u0000 The review areas that require attention include; proper definition of thin oil rim reservoir, inadequacy of the current classification of factors that affect oil rim development by non-consideration of strategic, commercial and stakeholder aspects. Other areas include; non- application of a combined depletion and flooding scheme under critical flow conditions in the Niger Delta and non-focus on controllable factors in the use of engineering design in the evaluation of thin oil rim reservoir development options.\u0000 Hence in this paper we proffer thoughts on a rational definition of a \"Thin oil rim reservoir\", highlight some development schemes termed \"novel\" in this study and propose such applications in evaluation of thin oil rim reservoirs especially in the Niger Delta. The evaluation of these options suffixes as evidence that due diligence has been made in a bid to ensure a robust development plan.\u0000 Finally, the paper presents discussion on recovery factor from thin oil rim reservoir developments with the objective of providing guidance on applicable ranges and highlight the opportunities in giving more focused attention and priority to the development of a thin oil rim reservoir.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"9 14 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90248563","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 presence of paraffin wax precipitation and deposition in tubing surfaces during production is one of the all-encompassing nuisances in oil and gas industry operations worldwide and it causes major production problems. The study aimed at acquiring novel insights into the bacterial community diversity capable of utilizing paraffin wax. Samples were collected from crude oil-polluted site in Gio Community, Tai Local Government Area, Niger Delta, Nigeria at depth of 0-0.5m (surface polluted soil [SPS]), 1m (sub surface polluted soil [SPSS]). GPS coordinate points for the North, South, East and West were N40 41′ 39″; N40 41′ 38″; N40 41′ 38″ and N40 41′ 37″ for latitudes respectively. Longitudes for the coordinates were E70 13′ 49″; E70 13′54″; E70 13′ 53″ and E70 13′ 54″ for North, respectively and unpolluted soil (UPS) taken 80m away from polluted site as control. All samples were transported to the laboratory within 6h at 4°C for analyses. Biodegradation screening was carried out using 2, 6-dichlorophenol indophenol (DCPIP) (redox potential +0.217 V) indicator to evaluate the biodegradation of hexadecane, paraffin oil and crude oil by axenic cultures of the bacteria isolated. GC-FID analysis for total petroleum hydrocarbons (TPH) were 22,146.65ppm for (surface polluted soil [SPS]), 14,087.80ppm (sub surface [SPSS]) and control soil (UPS) 479.67ppm respectively. Polycyclic aromatic hydrocarbons (PAHs) were 12,209.3ppm for SPS, 3,248.75ppm for SPSS and 22.72ppm for UPS. Total cultivable hydrocarbon utilizing bacterial count (TCHUB) for SPS, SPSS and UPS were 8.4 × 105cfu/g, 8.0 × 105cfu/g and 3.96 × 104cfu/g respectively. Pseudomonas spp., Bacillus spp., Acinetobacter sp. and Serratia sp. demonstrated higher biodegradability of paraffin wax than other 62 TCHUB isolated. These bacteria may probably represent an alternative green method for scale removal in the oil and gas sector.
{"title":"Characterization of Potential Paraffin Wax Removing Bacteria for Sustainable Biotechnological Application","authors":"A. U. Okoye, C. Chikere, G. Okpokwasili","doi":"10.2118/198799-MS","DOIUrl":"https://doi.org/10.2118/198799-MS","url":null,"abstract":"\u0000 The presence of paraffin wax precipitation and deposition in tubing surfaces during production is one of the all-encompassing nuisances in oil and gas industry operations worldwide and it causes major production problems. The study aimed at acquiring novel insights into the bacterial community diversity capable of utilizing paraffin wax. Samples were collected from crude oil-polluted site in Gio Community, Tai Local Government Area, Niger Delta, Nigeria at depth of 0-0.5m (surface polluted soil [SPS]), 1m (sub surface polluted soil [SPSS]). GPS coordinate points for the North, South, East and West were N40 41′ 39″; N40 41′ 38″; N40 41′ 38″ and N40 41′ 37″ for latitudes respectively. Longitudes for the coordinates were E70 13′ 49″; E70 13′54″; E70 13′ 53″ and E70 13′ 54″ for North, respectively and unpolluted soil (UPS) taken 80m away from polluted site as control. All samples were transported to the laboratory within 6h at 4°C for analyses. Biodegradation screening was carried out using 2, 6-dichlorophenol indophenol (DCPIP) (redox potential +0.217 V) indicator to evaluate the biodegradation of hexadecane, paraffin oil and crude oil by axenic cultures of the bacteria isolated. GC-FID analysis for total petroleum hydrocarbons (TPH) were 22,146.65ppm for (surface polluted soil [SPS]), 14,087.80ppm (sub surface [SPSS]) and control soil (UPS) 479.67ppm respectively. Polycyclic aromatic hydrocarbons (PAHs) were 12,209.3ppm for SPS, 3,248.75ppm for SPSS and 22.72ppm for UPS. Total cultivable hydrocarbon utilizing bacterial count (TCHUB) for SPS, SPSS and UPS were 8.4 × 105cfu/g, 8.0 × 105cfu/g and 3.96 × 104cfu/g respectively. Pseudomonas spp., Bacillus spp., Acinetobacter sp. and Serratia sp. demonstrated higher biodegradability of paraffin wax than other 62 TCHUB isolated. These bacteria may probably represent an alternative green method for scale removal in the oil and gas sector.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"21 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87383035","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}
K. Lawal, O. Okoh, Asekhame U. Yadua, Mathilda I. Ovuru, S. Eyitayo, S. Ramaswamy
Given sufficient performance and other data, material balance (MB) is a common method of determining the hydrocarbons initially in-place (HCIIP) in a reservoir. The application of this method requires, as a minimum, historic cumulative production (including injection) and average reservoir pressure. However, determination of historic average reservoir pressures would require shut-in of wells, hence production deferments. As an improvement to the classical MB, the dynamic material balance (DMB) method was developed by Mattar and Anderson (2005). Unlike the MB method, direct measurements of average reservoir pressure are not critical to DMB. In its basic form, the implementation of DMB requires historic production rates, flowing bottomhole pressures and cumulative production, thereby eliminating associated deferments. Although DMB has performed satisfactorily in some applications, its overall robustness remains to be fully explored. This paper conducts rigorous sensitivity checks on selected DMB models. Based on insights gained, their relative strengths and weaknesses are highlighted. To keep the problem tractable, detailed simulations are performed on different three-dimensional (3D) multiphase homogenous reservoir models of known HCIIP. Different cases are simulated, generating relevant performance datasets to evaluate DMB. The parametric tests conducted on this undersaturated compressible oil reservoir include (i) constant vs. variable production rates; (ii) rate hysteresis; (iii) vertical vs. horizontal well; (iv) single vs. multiple wells; (v) healthy vs. damaged well; and (vi) variable skin factors, with hysteresis. Within the parameter space examined, simulation results show that DMB performance (e.g. HCIIP) is sensitive to some of the parameters and subsurface realisations investigated. Against this background, some improvements and guidelines are proposed to enhance the capability and performance of DMB as a technique for reservoir surveillance.
{"title":"Improvements to the Dynamic Material-Balance Method of Reservoir Surveillance","authors":"K. Lawal, O. Okoh, Asekhame U. Yadua, Mathilda I. Ovuru, S. Eyitayo, S. Ramaswamy","doi":"10.2118/198741-MS","DOIUrl":"https://doi.org/10.2118/198741-MS","url":null,"abstract":"\u0000 Given sufficient performance and other data, material balance (MB) is a common method of determining the hydrocarbons initially in-place (HCIIP) in a reservoir. The application of this method requires, as a minimum, historic cumulative production (including injection) and average reservoir pressure. However, determination of historic average reservoir pressures would require shut-in of wells, hence production deferments. As an improvement to the classical MB, the dynamic material balance (DMB) method was developed by Mattar and Anderson (2005). Unlike the MB method, direct measurements of average reservoir pressure are not critical to DMB. In its basic form, the implementation of DMB requires historic production rates, flowing bottomhole pressures and cumulative production, thereby eliminating associated deferments. Although DMB has performed satisfactorily in some applications, its overall robustness remains to be fully explored.\u0000 This paper conducts rigorous sensitivity checks on selected DMB models. Based on insights gained, their relative strengths and weaknesses are highlighted. To keep the problem tractable, detailed simulations are performed on different three-dimensional (3D) multiphase homogenous reservoir models of known HCIIP. Different cases are simulated, generating relevant performance datasets to evaluate DMB. The parametric tests conducted on this undersaturated compressible oil reservoir include (i) constant vs. variable production rates; (ii) rate hysteresis; (iii) vertical vs. horizontal well; (iv) single vs. multiple wells; (v) healthy vs. damaged well; and (vi) variable skin factors, with hysteresis.\u0000 Within the parameter space examined, simulation results show that DMB performance (e.g. HCIIP) is sensitive to some of the parameters and subsurface realisations investigated. Against this background, some improvements and guidelines are proposed to enhance the capability and performance of DMB as a technique for reservoir surveillance.","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":"79581457","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}
Digital rock special core analysis has been used in recent times as an alternative to laboratory special core analysis (SCAL) but has failed to deliver the level of accuracy required by service companies. Current research suggests the dominant role of capillary pressure heterogeneity in flow characterization compared to viscous and gravity forces. However, the irreversible changes in relative permeability (hysteresis) during strategies for hydrocarbon recovery, have not been integrated. Hence, capillary heterogeneity and hysteresis were incorporated in numerical corefloods of primary waterflooding. Heterogeneity in the Bentheimer and Berea cores used for this study, were defined by a 3D spatial variation in capillary entry pressure obtained from experiments. Steady state Decane drainage preceded waterflooding. Capillary numbers were obtained across a range of rates depicting capillary to viscous dominated flow regimes, controlled by rock heterogeneity and distance from the well. Simulation results showed a dominance of heterogeneity in lowering oil production especially in the Berea-characterized by increased capillary strength-than the corresponding Bentheimer case. Hysteresis accelerated but decreased ultimate oil recovery, with greater impact in viscous (higher rates) than capillary dominated conditions (lower rates). Capillary number increased nonlinearly with flow rate. Also, residual oil saturation increased from low to high rates until a considerable decline ensued beyond threshold rates for which viscous pressure drop exceeded 60–3 times the highest capillary entry pressure in the Bentheimer and Berea cores respectively. Thus, the significant influence of capillary heterogeneity on oil production and the use of digital cores to estimate the irreversible oil trapping effects of hysteresis within heterogeneous rock sections is highlighted. This gives insight into effective enhanced oil recovery strategy to capture capillary trapped oil across core to field scales.
{"title":"Digital Rock Core Simulation of Waterflooding, Showing the Impact of Rock Heterogeneity on Oil Production","authors":"Oluwakemi Olofinnika","doi":"10.2118/198846-MS","DOIUrl":"https://doi.org/10.2118/198846-MS","url":null,"abstract":"\u0000 Digital rock special core analysis has been used in recent times as an alternative to laboratory special core analysis (SCAL) but has failed to deliver the level of accuracy required by service companies. Current research suggests the dominant role of capillary pressure heterogeneity in flow characterization compared to viscous and gravity forces. However, the irreversible changes in relative permeability (hysteresis) during strategies for hydrocarbon recovery, have not been integrated.\u0000 Hence, capillary heterogeneity and hysteresis were incorporated in numerical corefloods of primary waterflooding. Heterogeneity in the Bentheimer and Berea cores used for this study, were defined by a 3D spatial variation in capillary entry pressure obtained from experiments. Steady state Decane drainage preceded waterflooding. Capillary numbers were obtained across a range of rates depicting capillary to viscous dominated flow regimes, controlled by rock heterogeneity and distance from the well.\u0000 Simulation results showed a dominance of heterogeneity in lowering oil production especially in the Berea-characterized by increased capillary strength-than the corresponding Bentheimer case. Hysteresis accelerated but decreased ultimate oil recovery, with greater impact in viscous (higher rates) than capillary dominated conditions (lower rates). Capillary number increased nonlinearly with flow rate. Also, residual oil saturation increased from low to high rates until a considerable decline ensued beyond threshold rates for which viscous pressure drop exceeded 60–3 times the highest capillary entry pressure in the Bentheimer and Berea cores respectively.\u0000 Thus, the significant influence of capillary heterogeneity on oil production and the use of digital cores to estimate the irreversible oil trapping effects of hysteresis within heterogeneous rock sections is highlighted. This gives insight into effective enhanced oil recovery strategy to capture capillary trapped oil across core to field scales.","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":"82660909","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. Chudi, J. Iwegbu, Gerard Tetegan, Obinna Ikwueze, O. Effiom, Uruh Oke-oghene, B. Ayodeji, Stephen Opatewa, Titi Oladipo, T. Afolayan, Amba-Ambaiowei Tonyi, F. Osayande, Oladipo Falade, M. Kanu, Austin Anaevune, J. Emakpor, C. Afulukwe, Sophie Pokima
This study highlights a technique adopted for predicting and mapping net-to-gross (NTG) away from well locations through a combination of rock physics and seismic inversion applied in the Baza Field. The Baza field is located offshore Nigeria, with reservoirs poorly to mildly consolidated that were originally deposited in a deep-water submarine canyon system. The field is a partially appraised green field with three well penetrations encountereing amalgamated channels and lobes within the canyon system of tuiditic origin. Of the three wells drilled to date, only one well penetrated the key reservoir of interest- the B4 sands. The paucity of well penetration posses a challenge for accurate reservoir property assessment, particularly net-to-gross that has direct impact on hydrocarbon volume computation and ultimately on field development. Net-to-gross was predicted from seismic data based on a linear relationship observed from log derived P-impedance-AI (density × compressional velocity logs) and S-impedance-SI (density × shear velocity). Both properties when integrated can descrimate between sands and shales, and therefore serves as a proxy for calculating NTG. The linear relationship was applied to AI and SI seismic volumes built from simultaneous inversion of three sub-stack seismic data – the near (0-18), median (12-24) and far (24-45). The seismically derived net-to gross computed from simultaneous inversion compares favorably with log derived net-to-gross at well locations. The net-to-gross model resulted in a robust static and dynamic model that ultimately formed the basis for selecting optimal locations for future development wells for the B4 reservoir.
{"title":"Integration of Rock Physics and Seismic Inversion for Net-To-Gross Estimation: Implication for Reservoir Modelling and Field Development in Offshore Niger Delta","authors":"O. Chudi, J. Iwegbu, Gerard Tetegan, Obinna Ikwueze, O. Effiom, Uruh Oke-oghene, B. Ayodeji, Stephen Opatewa, Titi Oladipo, T. Afolayan, Amba-Ambaiowei Tonyi, F. Osayande, Oladipo Falade, M. Kanu, Austin Anaevune, J. Emakpor, C. Afulukwe, Sophie Pokima","doi":"10.2118/198765-MS","DOIUrl":"https://doi.org/10.2118/198765-MS","url":null,"abstract":"\u0000 This study highlights a technique adopted for predicting and mapping net-to-gross (NTG) away from well locations through a combination of rock physics and seismic inversion applied in the Baza Field. The Baza field is located offshore Nigeria, with reservoirs poorly to mildly consolidated that were originally deposited in a deep-water submarine canyon system. The field is a partially appraised green field with three well penetrations encountereing amalgamated channels and lobes within the canyon system of tuiditic origin. Of the three wells drilled to date, only one well penetrated the key reservoir of interest- the B4 sands. The paucity of well penetration posses a challenge for accurate reservoir property assessment, particularly net-to-gross that has direct impact on hydrocarbon volume computation and ultimately on field development.\u0000 Net-to-gross was predicted from seismic data based on a linear relationship observed from log derived P-impedance-AI (density × compressional velocity logs) and S-impedance-SI (density × shear velocity). Both properties when integrated can descrimate between sands and shales, and therefore serves as a proxy for calculating NTG. The linear relationship was applied to AI and SI seismic volumes built from simultaneous inversion of three sub-stack seismic data – the near (0-18), median (12-24) and far (24-45).\u0000 The seismically derived net-to gross computed from simultaneous inversion compares favorably with log derived net-to-gross at well locations. The net-to-gross model resulted in a robust static and dynamic model that ultimately formed the basis for selecting optimal locations for future development wells for the B4 reservoir.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"96 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86045659","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}
Rachel Johnson, Djamel Zerari, P. Salicante, P. Midolo
Continuous circulation technology is a form of managed pressure drilling (MPD) where the constant circulation of drilling fluid is maintained by allowing the rig pumps to remain on while adding and removing stands of drillpipe. Using continuous circulation, many drilling challenges are solved through continuous hole cleaning and solids transport, including maintaining constant bottomhole pressure (BHP), reducing the loading of solids and cuttings bed formation resulting from a pumps-off state, mitigating stuck pipe incidents, reducing ballooning effects, providing continuous cooling of bottomhole assembly (BHA) components, and improving formation integrity. Continuous circulation technology was used extensively for its hole-cleaning benefits during a 17-month development, gas drilling, and oil drilling campaign on a deepwater drillship in offshore West Africa from 2015-2016. Operations restarted in 2018 and are ongoing in 2019. Deepwater drilling using continuous circulation in this field provided a solution for significantly helping improve the rate of penetration (ROP) through continuous hole cleaning when drilling one stand per hour or faster. With constant circulation during the drillpipe connection process, the operator was able to significantly decrease the amount of time spent on hole-cleaning activities after a stand was drilled down in both oil-based mud (OBM) and water-based mud (WBM) applications. The enhanced hole cleaning provided by continuous circulation also helped improve cuttings transport efficiency, mitigate stuck pipe incidents, and enhanced the ability to drill a clean hole. This continuous circulation system was used on a deepwater drillship in offshore West Africa on 16 wells from 2015-2016, following two wells drilled without this technology, and four wells after the restart in 2018. Overall, more than 535 operating days and more than 1230 successful continuous circulation drillpipe connections were performed during both drilling and tripping operations. Because of the increased ROP provided by continuous hole cleaning with the system, approximately five drilling days were saved per well, totaling to an approximate 85 drilling day reduction over the planned drilling campaign from 2015-2016, resulting in a significant cost savings to the operator and to obtain first production much sooner than anticipated. Continuous circulation technology has proven to reduce overall nonproductive time (NPT) and total drilling days. During a long-term drilling campaign, additional improvements were recognized with superior prewell planning and front-end engineering design to minimize interference with rig operations and equipment and improve understanding and communication between the service company and operator. A newer generation, dual-activity rig helped prevent downtime by providing a platform for continuous repair and maintenance activities while drilling.
{"title":"Continuous Circulation Technology to Reduce Drilling Days in Offshore West Africa: Case Study","authors":"Rachel Johnson, Djamel Zerari, P. Salicante, P. Midolo","doi":"10.2118/198864-MS","DOIUrl":"https://doi.org/10.2118/198864-MS","url":null,"abstract":"\u0000 Continuous circulation technology is a form of managed pressure drilling (MPD) where the constant circulation of drilling fluid is maintained by allowing the rig pumps to remain on while adding and removing stands of drillpipe. Using continuous circulation, many drilling challenges are solved through continuous hole cleaning and solids transport, including maintaining constant bottomhole pressure (BHP), reducing the loading of solids and cuttings bed formation resulting from a pumps-off state, mitigating stuck pipe incidents, reducing ballooning effects, providing continuous cooling of bottomhole assembly (BHA) components, and improving formation integrity. Continuous circulation technology was used extensively for its hole-cleaning benefits during a 17-month development, gas drilling, and oil drilling campaign on a deepwater drillship in offshore West Africa from 2015-2016. Operations restarted in 2018 and are ongoing in 2019.\u0000 Deepwater drilling using continuous circulation in this field provided a solution for significantly helping improve the rate of penetration (ROP) through continuous hole cleaning when drilling one stand per hour or faster. With constant circulation during the drillpipe connection process, the operator was able to significantly decrease the amount of time spent on hole-cleaning activities after a stand was drilled down in both oil-based mud (OBM) and water-based mud (WBM) applications. The enhanced hole cleaning provided by continuous circulation also helped improve cuttings transport efficiency, mitigate stuck pipe incidents, and enhanced the ability to drill a clean hole.\u0000 This continuous circulation system was used on a deepwater drillship in offshore West Africa on 16 wells from 2015-2016, following two wells drilled without this technology, and four wells after the restart in 2018. Overall, more than 535 operating days and more than 1230 successful continuous circulation drillpipe connections were performed during both drilling and tripping operations. Because of the increased ROP provided by continuous hole cleaning with the system, approximately five drilling days were saved per well, totaling to an approximate 85 drilling day reduction over the planned drilling campaign from 2015-2016, resulting in a significant cost savings to the operator and to obtain first production much sooner than anticipated.\u0000 Continuous circulation technology has proven to reduce overall nonproductive time (NPT) and total drilling days. During a long-term drilling campaign, additional improvements were recognized with superior prewell planning and front-end engineering design to minimize interference with rig operations and equipment and improve understanding and communication between the service company and operator. A newer generation, dual-activity rig helped prevent downtime by providing a platform for continuous repair and maintenance activities while drilling.","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":"78795058","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}
Anindya Das, C. Anijekwu, K. Maguire, Mark Wood, Segun Akinrolabu, Olaniyi Adenaiye, O. Iyowu, Omolara Duvbiama, Uchechukwu Ozoemene, Kefe Amrasa
Permeability is one of the most important parameters of reservoir rocks; it defines the capacity of rocks to transmit fluids in pore spaces. Permeability prediction is of extreme importance in deciding the field development strategy for green reservoirs. The reservoir rocks are made up of grains, cement and pore network. The pore network is made up of larger spaces, referred to as pores, which are connected by small spaces referred to as throats. The pore spaces control the amount of porosity, while the pore throats control the movement of fluids and the quantity of rock permeability. Generally, the sources of permeability measurements in green field are from core data, well test data and Nuclear Magnetic Resonance (NMR) data. However, core information, well test information and NMR information are usually very limited due to high cost of acquisition making justification usually difficult. The consequence is that we have very low ratio of cored to the total reservoirs in the Niger Delta. This paper discusses a methodology for accurately estimating permeability using analogue fields/reservoirs core data in green reservoirs. The main factors to consider in choosing a suitable analogue includes Facies classification, relative depth of the reservoirs, average porosity and histogram of the Gamma ray values between the subject and analogue reservoirs. This selection is usually an integrated effort between the teams Geologist and Petrophysicist. In this study, two fields were selected where permeability prediction was based on analogue core data. A robust Niger delta wide analogue selection process was applied first to identify the analogue field where core data exists. After selection of the analogue field, facies-wise poroperm transform was built. This poroperm transforms were then validated in one of the fields where real core measurements were available post study. This blind test with real core permeability data indicated an excellent match with analogue based permeability model. In the other field, the analogue based permeability was validated against NMR and mobility data acquired in some of the reservoirs. This workflow establishes the robustness of using existing analogue data to reduce the subsurface uncertainty and justify an integrated workflow of estimating permeability in the green field rather than acquiring a new data to support development decision.
{"title":"Estimation of Reservoir Permeability Using Analogue Core Data for Green Field: Case Studies from Niger Delta","authors":"Anindya Das, C. Anijekwu, K. Maguire, Mark Wood, Segun Akinrolabu, Olaniyi Adenaiye, O. Iyowu, Omolara Duvbiama, Uchechukwu Ozoemene, Kefe Amrasa","doi":"10.2118/198751-MS","DOIUrl":"https://doi.org/10.2118/198751-MS","url":null,"abstract":"\u0000 Permeability is one of the most important parameters of reservoir rocks; it defines the capacity of rocks to transmit fluids in pore spaces. Permeability prediction is of extreme importance in deciding the field development strategy for green reservoirs. The reservoir rocks are made up of grains, cement and pore network. The pore network is made up of larger spaces, referred to as pores, which are connected by small spaces referred to as throats. The pore spaces control the amount of porosity, while the pore throats control the movement of fluids and the quantity of rock permeability. Generally, the sources of permeability measurements in green field are from core data, well test data and Nuclear Magnetic Resonance (NMR) data. However, core information, well test information and NMR information are usually very limited due to high cost of acquisition making justification usually difficult. The consequence is that we have very low ratio of cored to the total reservoirs in the Niger Delta.\u0000 This paper discusses a methodology for accurately estimating permeability using analogue fields/reservoirs core data in green reservoirs. The main factors to consider in choosing a suitable analogue includes Facies classification, relative depth of the reservoirs, average porosity and histogram of the Gamma ray values between the subject and analogue reservoirs. This selection is usually an integrated effort between the teams Geologist and Petrophysicist.\u0000 In this study, two fields were selected where permeability prediction was based on analogue core data.\u0000 A robust Niger delta wide analogue selection process was applied first to identify the analogue field where core data exists. After selection of the analogue field, facies-wise poroperm transform was built. This poroperm transforms were then validated in one of the fields where real core measurements were available post study. This blind test with real core permeability data indicated an excellent match with analogue based permeability model. In the other field, the analogue based permeability was validated against NMR and mobility data acquired in some of the reservoirs.\u0000 This workflow establishes the robustness of using existing analogue data to reduce the subsurface uncertainty and justify an integrated workflow of estimating permeability in the green field rather than acquiring a new data to support development decision.","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":"78814810","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 addition of natural and synthetic surfactants during chemical flooding recovers oil originally trapped by capillary forces through the reduction of the interfacial (adhesive) tension between the aqueous and oleic phases. As the interfacial tension reduces, the trapped oil droplets are mobilized forming a continuous oil bank thereby reducing the amount of residual oil saturation. The objective of phase behaviour is to determine the optimum salinity and to select the best compatible chemical composition for a specific application that can effectively enhance oil recovery. This study seeks to assess chemical compatibilities between alkaline –surfactant systems in the presence of calcium and magnesium ions; analyse synergy between alkali-surfactant slugs and crude oil to enable us to design an optimal low-cost, environmental friendly alkaline and surfactant floods for enhanced oil recovery. This is based on an understanding of fluid-fluid interactions. We conducted phase behaviour tests on selected local surfactants (AlkaSurf X, Moringa), bio-ethanol, local alkali (potash) and simulated formation brine. Aqueous stability and salinity scan experiments were conducted to determine the compatibility of the Alkaline–Surfactant systems with brine. Solutions free of precipitation were used for the interfacial-tension and phase behaviour analysis. Salinity scan results were used to calculate the solubilisation ratio and optimal salinity. Results indicate that the local Alkaline-Surfactant systems are highly tolerant of divalent ions. Also, results from pipette test showed that AlkaSurf X and Moringa alone attained a Type II (-) microemulsion, however, the addition of potash and co-surfactant at a controlled pH and concentration exhibited optimal salinity and a Type III microemulsion. This study shows that certain local alkali and surfactant can enhance oil recovery, even under harsh conditions, thus eliminating the use of harmful chemicals and need for brine softening processes which adds to the overall cost.
{"title":"Phase Behaviour of Local Alkaline and Surfactants During Flooding","authors":"A. Obuebite, M. Onyekonwu, O. Akaranta, C. Ubani","doi":"10.2118/198772-MS","DOIUrl":"https://doi.org/10.2118/198772-MS","url":null,"abstract":"\u0000 The addition of natural and synthetic surfactants during chemical flooding recovers oil originally trapped by capillary forces through the reduction of the interfacial (adhesive) tension between the aqueous and oleic phases. As the interfacial tension reduces, the trapped oil droplets are mobilized forming a continuous oil bank thereby reducing the amount of residual oil saturation. The objective of phase behaviour is to determine the optimum salinity and to select the best compatible chemical composition for a specific application that can effectively enhance oil recovery. This study seeks to assess chemical compatibilities between alkaline –surfactant systems in the presence of calcium and magnesium ions; analyse synergy between alkali-surfactant slugs and crude oil to enable us to design an optimal low-cost, environmental friendly alkaline and surfactant floods for enhanced oil recovery. This is based on an understanding of fluid-fluid interactions. We conducted phase behaviour tests on selected local surfactants (AlkaSurf X, Moringa), bio-ethanol, local alkali (potash) and simulated formation brine. Aqueous stability and salinity scan experiments were conducted to determine the compatibility of the Alkaline–Surfactant systems with brine. Solutions free of precipitation were used for the interfacial-tension and phase behaviour analysis. Salinity scan results were used to calculate the solubilisation ratio and optimal salinity. Results indicate that the local Alkaline-Surfactant systems are highly tolerant of divalent ions. Also, results from pipette test showed that AlkaSurf X and Moringa alone attained a Type II (-) microemulsion, however, the addition of potash and co-surfactant at a controlled pH and concentration exhibited optimal salinity and a Type III microemulsion. This study shows that certain local alkali and surfactant can enhance oil recovery, even under harsh conditions, thus eliminating the use of harmful chemicals and need for brine softening processes which adds to the overall cost.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"16 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89432202","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
I. Eiroboyi, S. S. Ikiensikimama, B. Oriji, I. Okoye
In enhancing oil recovery through polymer flooding, the application of polymers have been basically structured around the use of commercial polymers like xanthan gum, scleroglucan, Hydroxyl ethyl cellulose, Polyacrylamide, Hydrolysed Polyacrylamide and its derivatives. The use of some of these polymer has led to negative environmental issues and also increased treatment cost prior to discharge. The cost of some of the polymers is another reason, their applicability have not been appreciated so much in the oil and gas industry. The adoption of the principles of green chemistry in the synthesis of chemicals is a sure way of ensuring pollution prevention rather pollution control. Analysis carried on these polymers showed good rheology especially at higher concentrations. The displacement efficiency of Locust bean gum (LBG) and Gum arabic were evaluated using 0.2wt% and 0.5wt% in hard brine to recover trapped oil after water flooding, the results reflected significant incremental recoveries from both the use of LBG and Gum Arabic which also correlated with rheological characterisation carried out under different saline conditions. This analysis was extended by carrying a comparative study with commercial Locust bean gum and Xanthan gum. The efficiency of locally sourced LBG and Gum Arabic revealed that they are both candidates for polymer flooding.
{"title":"Experimental Investigation of the Macroscopic Displacement Efficiency of Locally Sourced Locust Bean Gum and Gum Arabic","authors":"I. Eiroboyi, S. S. Ikiensikimama, B. Oriji, I. Okoye","doi":"10.2118/198789-MS","DOIUrl":"https://doi.org/10.2118/198789-MS","url":null,"abstract":"\u0000 In enhancing oil recovery through polymer flooding, the application of polymers have been basically structured around the use of commercial polymers like xanthan gum, scleroglucan, Hydroxyl ethyl cellulose, Polyacrylamide, Hydrolysed Polyacrylamide and its derivatives. The use of some of these polymer has led to negative environmental issues and also increased treatment cost prior to discharge. The cost of some of the polymers is another reason, their applicability have not been appreciated so much in the oil and gas industry. The adoption of the principles of green chemistry in the synthesis of chemicals is a sure way of ensuring pollution prevention rather pollution control.\u0000 Analysis carried on these polymers showed good rheology especially at higher concentrations. The displacement efficiency of Locust bean gum (LBG) and Gum arabic were evaluated using 0.2wt% and 0.5wt% in hard brine to recover trapped oil after water flooding, the results reflected significant incremental recoveries from both the use of LBG and Gum Arabic which also correlated with rheological characterisation carried out under different saline conditions. This analysis was extended by carrying a comparative study with commercial Locust bean gum and Xanthan gum. The efficiency of locally sourced LBG and Gum Arabic revealed that they are both candidates for polymer flooding.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"150 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73711270","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 existing decline curve analysis (DCA) equations, some with valid theoretical justifications, cannot directly react to changes in operating conditions. Thus, they all assume constant operating conditions over the flowing life of a well. This however is an obvious oversimplification. This paper begins by briefly reviewing Gilbert's equation for flowrate prediction and then the C-curve and Logistic growth model DCA theories. The above review serves to identify well key flow indicators (KFI) and performance drivers. Subsequently, a forecasting approach which involves building artificial neural network (ANN) frameworks and training them on well KFI data is presented. Using trained ANNs, production forecasts were generated for three oil wells in the Niger-Delta producing from separate reservoirs under different flow regimes. The results were compared to forecasts from traditional DCA methods and material balance simulation, as well as with future production from the wells themselves. The results indicated that trained ANNs are capable of generating better performance curves than traditional DCA, with forecasts tying closely with results of material balance simulation and measured future well production rates. The ability of trained ANNs to evaluate the effect of changes in operating conditions (i.e. FTHP, GOR and water-cut) on production profiles and reserves drainable by wells, allows for scenario forecasting which is invaluable in field development planning. This is illustrated with field cases. This paper also presents a novel approach to evaluating the optimal hyperparameter configuration (i.e. the number of layers, neuron count per layer, dropout, batch size and the learning rate) required to minimize the loss function whilst training an ANN on any given dataset. This should prove invaluable to engineers and geoscientists integrating deep learning into sub-surface analyses.
{"title":"Dynamic Production Forecasting using Artificial Neural Networks customized to historical well Key Flow Indicators","authors":"David Nnamdi, Victor O. Adelaja","doi":"10.2118/198756-MS","DOIUrl":"https://doi.org/10.2118/198756-MS","url":null,"abstract":"\u0000 The existing decline curve analysis (DCA) equations, some with valid theoretical justifications, cannot directly react to changes in operating conditions. Thus, they all assume constant operating conditions over the flowing life of a well. This however is an obvious oversimplification.\u0000 This paper begins by briefly reviewing Gilbert's equation for flowrate prediction and then the C-curve and Logistic growth model DCA theories. The above review serves to identify well key flow indicators (KFI) and performance drivers. Subsequently, a forecasting approach which involves building artificial neural network (ANN) frameworks and training them on well KFI data is presented.\u0000 Using trained ANNs, production forecasts were generated for three oil wells in the Niger-Delta producing from separate reservoirs under different flow regimes. The results were compared to forecasts from traditional DCA methods and material balance simulation, as well as with future production from the wells themselves. The results indicated that trained ANNs are capable of generating better performance curves than traditional DCA, with forecasts tying closely with results of material balance simulation and measured future well production rates. The ability of trained ANNs to evaluate the effect of changes in operating conditions (i.e. FTHP, GOR and water-cut) on production profiles and reserves drainable by wells, allows for scenario forecasting which is invaluable in field development planning. This is illustrated with field cases.\u0000 This paper also presents a novel approach to evaluating the optimal hyperparameter configuration (i.e. the number of layers, neuron count per layer, dropout, batch size and the learning rate) required to minimize the loss function whilst training an ANN on any given dataset. This should prove invaluable to engineers and geoscientists integrating deep learning into sub-surface analyses.","PeriodicalId":11250,"journal":{"name":"Day 3 Wed, August 07, 2019","volume":"45 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74664912","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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