The industry is in constant research with consistent efforts to ensure that the no/less incidents occur during the course of operations. Notable and popular slogans/rules have been adopted among engineering and oil & gas organizations over the years in the industry to intimate the need for safe activities to be performed among staff. Slogans like Goal Zero, Golden Rule dictum, "Safe…Yes we can", Life Saving Rules, "No Wahala…Take 5" and many others have been used in recent times to inculcate the culture of safety and situational awareness in the mind of the work force. Tools like check cards, stickers, safety IDs and banners are also quick reminders of the environment being operated on. However while all these tools are fairly efficient, the need for proper risk assessment cannot be over-emphasized at all times before a job to be done can be certified safe. Worksite Tools like toolbox talk, last minute risk assessment (LMRA), Job Hazard Analysis (JHA) and post job debrief are veritable towards achieving this goal. But while risk assessment before the job commences is important, of equivalent or even much importance is the one conducted during the job and this is called dynamic risk assessment. This paper presents an approach and exposition of the risk assessment plan in the operations level in the oil and gas industry. It also discussed on the methods to be deployed a successful risk assessment and buttress further on static and dynamic risk assessment as it concerns operations in a gas process plant. A new conceptual risk assessment model has been developed. A case study was treated from Atabala Plant which is a gas processing facility in the south southern Nigeria.
{"title":"Dynamic Risk Assessment – A MacGyverism to Worksite Incidents","authors":"E. Umeh","doi":"10.2118/198779-MS","DOIUrl":"https://doi.org/10.2118/198779-MS","url":null,"abstract":"\u0000 The industry is in constant research with consistent efforts to ensure that the no/less incidents occur during the course of operations. Notable and popular slogans/rules have been adopted among engineering and oil & gas organizations over the years in the industry to intimate the need for safe activities to be performed among staff. Slogans like Goal Zero, Golden Rule dictum, \"Safe…Yes we can\", Life Saving Rules, \"No Wahala…Take 5\" and many others have been used in recent times to inculcate the culture of safety and situational awareness in the mind of the work force. Tools like check cards, stickers, safety IDs and banners are also quick reminders of the environment being operated on.\u0000 However while all these tools are fairly efficient, the need for proper risk assessment cannot be over-emphasized at all times before a job to be done can be certified safe. Worksite Tools like toolbox talk, last minute risk assessment (LMRA), Job Hazard Analysis (JHA) and post job debrief are veritable towards achieving this goal. But while risk assessment before the job commences is important, of equivalent or even much importance is the one conducted during the job and this is called dynamic risk assessment.\u0000 This paper presents an approach and exposition of the risk assessment plan in the operations level in the oil and gas industry. It also discussed on the methods to be deployed a successful risk assessment and buttress further on static and dynamic risk assessment as it concerns operations in a gas process plant. A new conceptual risk assessment model has been developed. A case study was treated from Atabala Plant which is a gas processing facility in the south southern Nigeria.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 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":"85529045","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}
Heavy metals are present in crude oil produced worldwide in varying concentration as impurities. Such metals are also exposed to the environment when oil spill occur. In this study, we applied the duckweed, Lemna paucicostata as an ecological based treatment method for the phytoremediation of heavy metals present in crude oil polluted waters. Duckweed was applied in an artificial constructed wetland mesocosm contaminated with crude oil to simulate a spill site. Heavy metals were analyzed following established guidelines using AAS for a 60-day period. The results showed that heavy metals reported in this study were above permissible limit. Initial cadmium, chromium, lead and vanadium decreased by 4.36, 7.06, 17.95 and 2.47% after 15 days respectively and then decreased further by 11.21, 19.94 and 32.4% for Cd; 13.15, 16.9 and 13.76% for Cr; 20.51, 30.77 and 41.03% for Pb; and 4.12, 15.66 and 26.37% for V after 30, 45 and 60 days respectively. There was no significant difference between the mean values of the metals across the duration. The result of this study showed that duckweed moderately removed heavy metals from crude oil polluted waters. Extending the duration of the study could increase the potentials of the plant to remove a higher amount of metals from the contaminated media. This result could be translated to real life application as an ecological base tool for the sustainable remediation of metals in crude oil polluted environment.
{"title":"Ecological Remediation of Heavy Metals in Crude Oil Polluted Waters Using Duckweed","authors":"A. Ekperusi, F. Sikoki, E. Nwachukwu","doi":"10.2118/198773-MS","DOIUrl":"https://doi.org/10.2118/198773-MS","url":null,"abstract":"\u0000 Heavy metals are present in crude oil produced worldwide in varying concentration as impurities. Such metals are also exposed to the environment when oil spill occur. In this study, we applied the duckweed, Lemna paucicostata as an ecological based treatment method for the phytoremediation of heavy metals present in crude oil polluted waters. Duckweed was applied in an artificial constructed wetland mesocosm contaminated with crude oil to simulate a spill site. Heavy metals were analyzed following established guidelines using AAS for a 60-day period. The results showed that heavy metals reported in this study were above permissible limit. Initial cadmium, chromium, lead and vanadium decreased by 4.36, 7.06, 17.95 and 2.47% after 15 days respectively and then decreased further by 11.21, 19.94 and 32.4% for Cd; 13.15, 16.9 and 13.76% for Cr; 20.51, 30.77 and 41.03% for Pb; and 4.12, 15.66 and 26.37% for V after 30, 45 and 60 days respectively. There was no significant difference between the mean values of the metals across the duration. The result of this study showed that duckweed moderately removed heavy metals from crude oil polluted waters. Extending the duration of the study could increase the potentials of the plant to remove a higher amount of metals from the contaminated media. This result could be translated to real life application as an ecological base tool for the sustainable remediation of metals in crude oil polluted environment.","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":"85864121","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}
Reservoir_B7 is one of the top reservoirs in Adobe field and was considered for further development in a multi-year drilling campaign. The initial opportunity identification and new drill forecasts for this reservoir were done using an old simulation model. Over the years, the challenge with this model had been the prediction water production from existing producers which necessitated the introduction of local permeability barriers in the model. However, to validate this opportunity and ensure reliability of production forecasts, a new simulation study was commissioned. A systematic approach was employed during the new study which involved continuous engagement between Earth Modeler and Simulation Engineer. This led to identification of a low-quality facies which had not been properly characterized. Recharacterization of these facies led to an improvement in history match with an overall good pressure and saturation matches on both well-by-well and reservoir levels. The latest history matched model was used to validate the proposed opportunity and indicated a sub-economic incremental recovery. This led to elimination of hitherto top opportunity from the drilling program and preventing a bad investment by the company.
{"title":"Resolution of a Perennial Water-Cut History Match Challenge Helps to Optimize Drilling Program","authors":"N. Yusuf, P. Andrew, Lynn Silpngarmlers","doi":"10.2118/198851-MS","DOIUrl":"https://doi.org/10.2118/198851-MS","url":null,"abstract":"\u0000 Reservoir_B7 is one of the top reservoirs in Adobe field and was considered for further development in a multi-year drilling campaign. The initial opportunity identification and new drill forecasts for this reservoir were done using an old simulation model. Over the years, the challenge with this model had been the prediction water production from existing producers which necessitated the introduction of local permeability barriers in the model. However, to validate this opportunity and ensure reliability of production forecasts, a new simulation study was commissioned.\u0000 A systematic approach was employed during the new study which involved continuous engagement between Earth Modeler and Simulation Engineer. This led to identification of a low-quality facies which had not been properly characterized. Recharacterization of these facies led to an improvement in history match with an overall good pressure and saturation matches on both well-by-well and reservoir levels. The latest history matched model was used to validate the proposed opportunity and indicated a sub-economic incremental recovery. This led to elimination of hitherto top opportunity from the drilling program and preventing a bad investment by the company.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"26 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82428771","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}
Drilling fluid is one of the major substances used when drilling a well, as it serves numerous purposes such as lubrication and cooling of the drilling bit, cuttings removal to mention a few. And one of its major constituent is the bentonite, clay that serves as the dispersed phase. The cost of procuring the bentonite clay for the production of drilling fluid is expensive because of its importation into the country hereby increasing the overall cost of drilling a well. This paper investigated the suitability of suspected clay from Uwheru and Otor-Udu village in Delta State, Nigeria for the production of water based drilling fluid. The mud was formulated using 21.0g of each clay local sample and 350ml of fresh water. Different concentrations of pH and viscosity chemical additives were used. Comparative analysis was made on the drilling mud sample formulated from clay obtained from the study areas namely (Uwheru and Otor-Udu) to determine their suitability for the formulation of drilling fluids and to determine if it meets the API standard. The properties tested for include the mud density, pH, sand content and rheological properties. After laboratory work was conducted, the two formulated mud samples had same mud weight of 8.5ppg which was slightly below the API standard for bentonite clay of 8.65minimum and 9.60maximum. A pH control additive (NaOH) and Viscosifier additive (CMC) were added. In conclusion, analysis was made on the experimental values of Uwheru which had values of 3cp for 2cp for the 600rpm and 300rpm rheological readings respectively, pH of 5, sand content of 0.1ml and density of 8.5ppg while that of Otor-Udu had values of 3cp and 2cp for the 600rpm and 300rpm rheological readings respectively, pH of 5, sand content of 0.05ml and density of 8.5ppg. From the analysis made between the local clay formulated drilling fluid samples and the standard API values for bentonite using graphs and charts, the local clay can be improvised for bentonite.
{"title":"Formulation of Water Based Drilling Fluid Using Local Mud Uwheru & Otor-Udu Clay","authors":"Aihie John Odion","doi":"10.2118/198737-MS","DOIUrl":"https://doi.org/10.2118/198737-MS","url":null,"abstract":"\u0000 Drilling fluid is one of the major substances used when drilling a well, as it serves numerous purposes such as lubrication and cooling of the drilling bit, cuttings removal to mention a few. And one of its major constituent is the bentonite, clay that serves as the dispersed phase. The cost of procuring the bentonite clay for the production of drilling fluid is expensive because of its importation into the country hereby increasing the overall cost of drilling a well.\u0000 This paper investigated the suitability of suspected clay from Uwheru and Otor-Udu village in Delta State, Nigeria for the production of water based drilling fluid. The mud was formulated using 21.0g of each clay local sample and 350ml of fresh water. Different concentrations of pH and viscosity chemical additives were used. Comparative analysis was made on the drilling mud sample formulated from clay obtained from the study areas namely (Uwheru and Otor-Udu) to determine their suitability for the formulation of drilling fluids and to determine if it meets the API standard. The properties tested for include the mud density, pH, sand content and rheological properties.\u0000 After laboratory work was conducted, the two formulated mud samples had same mud weight of 8.5ppg which was slightly below the API standard for bentonite clay of 8.65minimum and 9.60maximum. A pH control additive (NaOH) and Viscosifier additive (CMC) were added.\u0000 In conclusion, analysis was made on the experimental values of Uwheru which had values of 3cp for 2cp for the 600rpm and 300rpm rheological readings respectively, pH of 5, sand content of 0.1ml and density of 8.5ppg while that of Otor-Udu had values of 3cp and 2cp for the 600rpm and 300rpm rheological readings respectively, pH of 5, sand content of 0.05ml and density of 8.5ppg. From the analysis made between the local clay formulated drilling fluid samples and the standard API values for bentonite using graphs and charts, the local clay can be improvised for bentonite.","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":"80022779","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}
Virtue Urunwo Elechi, S. S. Ikiensikimama, J. Ajienka, O. Akaranta, M. Onyekonwu, O. Okon
This present study emphasizes the inhibition capacity of a local inhibitor, Plant Extract (PE) on structure I (sI) gas hydrate. The Plant Extract (PE) was screened using a mini flow loop made of 316 stainless steel of internal diameter of 0.5-inch encased in a 4-inch PVC pipe skid mounted on a metal frame work fitted with pressure and temperature gauges, mixer vessel, pumps and control switches. Pressure and Temperature readings were recorded for 120 minutes. Plots of Pressure and Temperature versus Time for 1, 2 and 3wt% of the local inhibitor alongside Pressure versus Time plot of PE and MEG were done as a way of comparison. Calculations for Inhibition Efficiency (IE) for local inhibitor PE and MEG was also done. 1wt% of the plant extract (PE) had a high inhibition efficiency of 84.21% while 2 and 3wt% had inhibition efficiency of 60.53% and 73.68% respectively. The overall inhibition efficiency of Plant Extract (PE) was higher than that of MEG for 1wt% (60.53%) and 2wt% (55.26%) but had the same efficiency at 3wt% (73.68%). The optimum weight percentage for PE is 1wt% because of its high efficiency. It is clearly shown that Plant Extract (PE) is a better gas hydrate inhibitor which is gotten from nature and is environmentally friendly unlike Mono Ethylene Glycol (MEG) which is synthetic and toxic to both human and aquatic life. It is therefore recommended for field trial.
{"title":"Evaluation of the Inhibition Efficiency of Plant Extract PE as Gas Hydrate Inhibitor in a Simulated Offshore Environment","authors":"Virtue Urunwo Elechi, S. S. Ikiensikimama, J. Ajienka, O. Akaranta, M. Onyekonwu, O. Okon","doi":"10.2118/198781-MS","DOIUrl":"https://doi.org/10.2118/198781-MS","url":null,"abstract":"\u0000 This present study emphasizes the inhibition capacity of a local inhibitor, Plant Extract (PE) on structure I (sI) gas hydrate. The Plant Extract (PE) was screened using a mini flow loop made of 316 stainless steel of internal diameter of 0.5-inch encased in a 4-inch PVC pipe skid mounted on a metal frame work fitted with pressure and temperature gauges, mixer vessel, pumps and control switches. Pressure and Temperature readings were recorded for 120 minutes. Plots of Pressure and Temperature versus Time for 1, 2 and 3wt% of the local inhibitor alongside Pressure versus Time plot of PE and MEG were done as a way of comparison. Calculations for Inhibition Efficiency (IE) for local inhibitor PE and MEG was also done. 1wt% of the plant extract (PE) had a high inhibition efficiency of 84.21% while 2 and 3wt% had inhibition efficiency of 60.53% and 73.68% respectively. The overall inhibition efficiency of Plant Extract (PE) was higher than that of MEG for 1wt% (60.53%) and 2wt% (55.26%) but had the same efficiency at 3wt% (73.68%). The optimum weight percentage for PE is 1wt% because of its high efficiency. It is clearly shown that Plant Extract (PE) is a better gas hydrate inhibitor which is gotten from nature and is environmentally friendly unlike Mono Ethylene Glycol (MEG) which is synthetic and toxic to both human and aquatic life. It is therefore recommended for field trial.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"94 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85384166","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}
Reservoir connectivity remains a critical and growing area of research and application in the petroleum industry, as most discoveries go through development to maturity. This becomes highly imperative for reservoir management decisions in highly fractured compartments or stacked reservoirs with faults across them. In most field cases and especially for a highly faulted region like the Niger Delta, there are some uncertainties around connectivity primarily due to seismic data and resolutions as regards the technology available at acquisition. The primary aim of this work is to use dynamic modelling to ascertain connectivity in mature reservoirs. This work applied the standard workflow for Reservoir Connectivity Analysis (RCA) in evaluating four (4) stacked reservoirs in the RAINBOW field, onshore Niger-Delta using dynamic modelling of the MBAL multi-tank option. Various scenarios were analyzed with the integrated data – geology, production and reservoir pressure history, fluid and rock properties to select the most likely scenario. For this analysis, a new diagnostic plot was introduced for evaluating transmissibility, which improved the clarity in decision making. Using the prevalent economic parameters, a quick evaluation was done to understand the impacts of the reservoir management decisions on the viability of this approach. From the results, two of the four reservoirs are observed to be dynamically connected. The analysis shows that a new perforation extension opportunity is a quick return decision that can yield considerable returns, while new infill opportunities as the optimal decision. Also, the effects of transmissibility on the reservoirs affect the Net Present Values of the decisions. Therefore, this improved workflow approach can be recommended as a quick win when sufficient time and resources are not available for opportunity maturation. Further work is also required to integrate this understanding to build a simulation model for robust benchmarking.
{"title":"Dynamic Modelling for Reservoir Connectivity Analysis in Mature Fields","authors":"O. Ajayi, Sunday Ikienskimama, Emmanuel Mogbolu","doi":"10.2118/198752-MS","DOIUrl":"https://doi.org/10.2118/198752-MS","url":null,"abstract":"\u0000 Reservoir connectivity remains a critical and growing area of research and application in the petroleum industry, as most discoveries go through development to maturity. This becomes highly imperative for reservoir management decisions in highly fractured compartments or stacked reservoirs with faults across them. In most field cases and especially for a highly faulted region like the Niger Delta, there are some uncertainties around connectivity primarily due to seismic data and resolutions as regards the technology available at acquisition. The primary aim of this work is to use dynamic modelling to ascertain connectivity in mature reservoirs. This work applied the standard workflow for Reservoir Connectivity Analysis (RCA) in evaluating four (4) stacked reservoirs in the RAINBOW field, onshore Niger-Delta using dynamic modelling of the MBAL multi-tank option. Various scenarios were analyzed with the integrated data – geology, production and reservoir pressure history, fluid and rock properties to select the most likely scenario. For this analysis, a new diagnostic plot was introduced for evaluating transmissibility, which improved the clarity in decision making. Using the prevalent economic parameters, a quick evaluation was done to understand the impacts of the reservoir management decisions on the viability of this approach. From the results, two of the four reservoirs are observed to be dynamically connected. The analysis shows that a new perforation extension opportunity is a quick return decision that can yield considerable returns, while new infill opportunities as the optimal decision. Also, the effects of transmissibility on the reservoirs affect the Net Present Values of the decisions. Therefore, this improved workflow approach can be recommended as a quick win when sufficient time and resources are not available for opportunity maturation. Further work is also required to integrate this understanding to build a simulation model for robust benchmarking.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":" 4","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91412975","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 machine learning approach to shear sonic log prediction is demonstrated. The results of this approach were compared to that of an approach based on the Greenberg-Castagna empirical method. This approach is based on supervised machine learning and is implemented in MATLAB. While the Greenberg-Castagna method is an empirical method that attempts to predict shear velocity log from compressional velocity log for various pure and composite lithologies, this approach uses, in addition to compressional velocity log as the main predictor, several other logging measurements as predictors including gamma ray, bulk density, neutron, resistivity, porosity and water saturation logs. A dataset which includes wells with recorded shear velocity logs is used to train and validate the machine learning model. A feature selection process is performed to highlight which of the logs would be good predictors of shear velocity (VS). Various regression models are then trained, and the predicted values compared to the actual for the various models by their root-mean-square errors (RMSE), and the model with the smallest RMSE is chosen. Predictions are then carried out on another well within the dataset, which serves as the validation set. The results show improvement in the accuracy of the predictions over the linear regression model based on the Greenberg-Castagna method, as measured by the RMSE. The case study also demonstrates the potential of carrying out shear sonic log prediction in hydrocarbon-bearing intervals, which is a limitation of the Greenberg-Castagna method which only works in brine-saturated rocks. This approach would provide improved accuracy where shear sonic logs are absent and need to be predicted for geomechanics, rock physics and other applications. This is particularly important in older fields where shear sonic logs were never acquired in the older wells.
{"title":"A Machine Learning Approach to Shear Sonic Log Prediction","authors":"I. Bukar, M. B. Adamu, U. Hassan","doi":"10.2118/198764-MS","DOIUrl":"https://doi.org/10.2118/198764-MS","url":null,"abstract":"\u0000 A machine learning approach to shear sonic log prediction is demonstrated. The results of this approach were compared to that of an approach based on the Greenberg-Castagna empirical method. This approach is based on supervised machine learning and is implemented in MATLAB. While the Greenberg-Castagna method is an empirical method that attempts to predict shear velocity log from compressional velocity log for various pure and composite lithologies, this approach uses, in addition to compressional velocity log as the main predictor, several other logging measurements as predictors including gamma ray, bulk density, neutron, resistivity, porosity and water saturation logs. A dataset which includes wells with recorded shear velocity logs is used to train and validate the machine learning model. A feature selection process is performed to highlight which of the logs would be good predictors of shear velocity (VS). Various regression models are then trained, and the predicted values compared to the actual for the various models by their root-mean-square errors (RMSE), and the model with the smallest RMSE is chosen. Predictions are then carried out on another well within the dataset, which serves as the validation set. The results show improvement in the accuracy of the predictions over the linear regression model based on the Greenberg-Castagna method, as measured by the RMSE. The case study also demonstrates the potential of carrying out shear sonic log prediction in hydrocarbon-bearing intervals, which is a limitation of the Greenberg-Castagna method which only works in brine-saturated rocks. This approach would provide improved accuracy where shear sonic logs are absent and need to be predicted for geomechanics, rock physics and other applications. This is particularly important in older fields where shear sonic logs were never acquired in the older wells.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"33 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80769644","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The oil and gas industry require technologies to prevent mineral scale formation and deposition in reservoirs and production systems. One commonly used method to achieve this is the scale inhibitor squeeze treatment. The challenge addressed here using modelling is to prolong the squeeze treatment lifetime in heterogeneous reservoirs, thus, reduce the cost per barrel of oil produced, especially in deep offshore and remote locations. Key to squeeze life extension is ensuring optimum scale inhibitor retention on rock matrix. Therefore, the inhibitor must contact the reservoir rocks and be distributed amongst the layers in proportion to the expected water production rates per layer, which will be determined by reservoir heterogeneity, system geometry and gravitational effects. These effects are studied for an offshore water flooded reservoir by means of a reservoir simulation model. The study reveals that reservoir heterogeneity generally improves inhibitor squeeze treatment performance as measured at surface for the entire well, with more inhibitor being placed in the zones with high permeability-thickness product (kh). However, downhole pressure differentials can result in higher pressure layers being unprotected for longer periods before the inhibitor concentrations for the entire well goes below the Minimum Inhibitor Concentration (MIC). The use of diversion techniques is shown by simulation work to improve placement and thus help achieve a successful inhibitor squeeze treatment in all the reservoir layers. However, inhibitor concentrations may remain relatively high in layers that do not produce much water, resulting in some wastage of inhibitor as a penalty for delaying the time before re-squeezing is required. The modelling helps understand where scale could occur and the best management strategy for scale prevention or control; identifying the impact of scale; giving insight into the best inhibitor squeeze treatment options and expected performance; and providing input needed for the economic model required for good reservoir scale management.
{"title":"The Impact of Reservoir Heterogeneity in the Modelling of Scale Inhibitor Squeeze Treatments","authors":"F. Uzoigwe, E. Mackay, O. Vazquez","doi":"10.2118/198844-MS","DOIUrl":"https://doi.org/10.2118/198844-MS","url":null,"abstract":"\u0000 The oil and gas industry require technologies to prevent mineral scale formation and deposition in reservoirs and production systems. One commonly used method to achieve this is the scale inhibitor squeeze treatment. The challenge addressed here using modelling is to prolong the squeeze treatment lifetime in heterogeneous reservoirs, thus, reduce the cost per barrel of oil produced, especially in deep offshore and remote locations.\u0000 Key to squeeze life extension is ensuring optimum scale inhibitor retention on rock matrix. Therefore, the inhibitor must contact the reservoir rocks and be distributed amongst the layers in proportion to the expected water production rates per layer, which will be determined by reservoir heterogeneity, system geometry and gravitational effects. These effects are studied for an offshore water flooded reservoir by means of a reservoir simulation model.\u0000 The study reveals that reservoir heterogeneity generally improves inhibitor squeeze treatment performance as measured at surface for the entire well, with more inhibitor being placed in the zones with high permeability-thickness product (kh). However, downhole pressure differentials can result in higher pressure layers being unprotected for longer periods before the inhibitor concentrations for the entire well goes below the Minimum Inhibitor Concentration (MIC).\u0000 The use of diversion techniques is shown by simulation work to improve placement and thus help achieve a successful inhibitor squeeze treatment in all the reservoir layers. However, inhibitor concentrations may remain relatively high in layers that do not produce much water, resulting in some wastage of inhibitor as a penalty for delaying the time before re-squeezing is required.\u0000 The modelling helps understand where scale could occur and the best management strategy for scale prevention or control; identifying the impact of scale; giving insight into the best inhibitor squeeze treatment options and expected performance; and providing input needed for the economic model required for good reservoir scale management.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"23 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84667999","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A new high-pressure high temperature (HP-HT) lab-scale rig involving microbial cultivation of pure bacteria strain under reservoir conditions of up to 200 bar and 200°C has been developed. This was accompanied by an extensive laboratory investigation to establish the mechanisms associated with the production and screening of Lipopeptide from pure Bacillus mojavensis NCIMB 13391 strain for the purpose of enhanced oil recovery (EOR) processes. We report for the first time, thermodynamic standard Gibbs free energy required for the Lipopeptide environment friendly biosurfactant (EFBS) formation (ΔGf°) as -2135.1 J.mol−1, and very low brine salinity water (VLBSW) molarity of 0.5096 mg.l− 1. The produced Lipopeptide biomaterial under anaerobic batch cultivation technique generated CMC values of 2.8 mg.l−1 and 2.7 mg.l−1 in deionised water and VLBSW respectively. The dimensionless molecular weight of the produced Lipopeptide biomaterial is 1423.69 and high spontaneity nature of the biomaterial resulting from a more negative ΔGf° value aided the interfacial tension (IFT) reduction of the heavy crude oil and VLBSW system from 15.71 mN.m−1 to 0.04 mN.m−1 at critical micellisation concentration (CMC) of 2.7 mg.l−1 and 65°C under reservoir confined environment, and 1.76 mN.m−1 at 25°C temperature and 55 bar pressure conditions. However, 2.7 mg.l−1 solution molarity, 65°C temperature and 55 bar pressure are recommended as the optimum recovery pilot molarity, temperature and pressure of the screened heavy crude oil material in low-salinity EOR processes.
{"title":"Development of a New High-Pressure High-Temperature Technology for Advanced Screening of Biosurfactants and Injection of Microbes in Porous Rocks during Low-Salinity EOR Processes","authors":"C. C. Onyemara, Lateef T. Akanji, R. Ebel","doi":"10.2118/198878-MS","DOIUrl":"https://doi.org/10.2118/198878-MS","url":null,"abstract":"\u0000 A new high-pressure high temperature (HP-HT) lab-scale rig involving microbial cultivation of pure bacteria strain under reservoir conditions of up to 200 bar and 200°C has been developed. This was accompanied by an extensive laboratory investigation to establish the mechanisms associated with the production and screening of Lipopeptide from pure Bacillus mojavensis NCIMB 13391 strain for the purpose of enhanced oil recovery (EOR) processes. We report for the first time, thermodynamic standard Gibbs free energy required for the Lipopeptide environment friendly biosurfactant (EFBS) formation (ΔGf°) as -2135.1 J.mol−1, and very low brine salinity water (VLBSW) molarity of 0.5096 mg.l− 1. The produced Lipopeptide biomaterial under anaerobic batch cultivation technique generated CMC values of 2.8 mg.l−1 and 2.7 mg.l−1 in deionised water and VLBSW respectively. The dimensionless molecular weight of the produced Lipopeptide biomaterial is 1423.69 and high spontaneity nature of the biomaterial resulting from a more negative ΔGf° value aided the interfacial tension (IFT) reduction of the heavy crude oil and VLBSW system from 15.71 mN.m−1 to 0.04 mN.m−1 at critical micellisation concentration (CMC) of 2.7 mg.l−1 and 65°C under reservoir confined environment, and 1.76 mN.m−1 at 25°C temperature and 55 bar pressure conditions. However, 2.7 mg.l−1 solution molarity, 65°C temperature and 55 bar pressure are recommended as the optimum recovery pilot molarity, temperature and pressure of the screened heavy crude oil material in low-salinity EOR processes.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"15 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87008096","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}
During fit for service or corrosion risk assessments of oil and gas facility systems, a key parameter required to design and implement an effective risk management strategy is visual inspection. This paper explains how using state of the art computer vision and deep learning techniques could address such challenges. We used majorly the python programming language, Tensorflow Application Programming Interface, Resnet deep learning architecture, GPU machines and cloud computing technologies to achieve this. Beyond the challenges of obtaining sufficient corrosion defects data, our final solution is a systematic method that would assist field personnel, facility engineers, service companies and management more accurately detect corrosion defect types and failure modes unbiasedly. This leads to more cost effective and quicker recommendation of preventive or corrective measures.
{"title":"Using Deep Learning and Computer Vision Techniques to Improve Facility Corrosion Risk Management Systems 2.0","authors":"C. Ejimuda, C. Ejimuda","doi":"10.2118/198863-MS","DOIUrl":"https://doi.org/10.2118/198863-MS","url":null,"abstract":"\u0000 During fit for service or corrosion risk assessments of oil and gas facility systems, a key parameter required to design and implement an effective risk management strategy is visual inspection. This paper explains how using state of the art computer vision and deep learning techniques could address such challenges. We used majorly the python programming language, Tensorflow Application Programming Interface, Resnet deep learning architecture, GPU machines and cloud computing technologies to achieve this. Beyond the challenges of obtaining sufficient corrosion defects data, our final solution is a systematic method that would assist field personnel, facility engineers, service companies and management more accurately detect corrosion defect types and failure modes unbiasedly. This leads to more cost effective and quicker recommendation of preventive or corrective measures.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"80 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81116990","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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