An offshore field is producing oil from multiple reservoirs with peripheral water injection scheme. Seawater is injected through a subsea network and wellhead towers located along the original reservoir edge. However, because its OWC has moved upward, wells from wellhead towers are too remote to inject seawater effectively, with some portion going to the aquifer rather than oil pool. Therefore, it is planned to migrate injection strategy from peripheral to mid-dip pattern. An expected risk is scaling by mixing incompatible seawater and formation water. Such risk and mitigation measures were evaluated. To achieve the objective, the following methodology was applied: 1. Scale modelling based on water chemical analysis. 2. Define scale risk envelope with three risk categories 3. Tracer dynamic reservoir simulation to track formation water, connate water, dump flood water, injection seawater and treated seawater. 4. Review the past field scale history data 5. Coreflood experiment to observe actual phenomena inside the reservoir with various parameters such as water mixing ratio, sulphate concentration, temperature and chemical inhibitor 6. Consolidate all study results, conclude field scale risk and impact of mitigation measures. Scale prediction modelling, verified by coreflood tests, found that mixing reservoir formation water and injection seawater causes a sulphate scale risk, with risk severity depending on mixing ratio and sulphate concentration. Reservoir temperature was also found to correlate strongly with scale risk. Therefore, each reservoir should have different water management strategy. Scale impact is limited in the shallower wide reservoir with cooler reservoir temperature. Such reservoir should therefore have mid-dip pattern water injection to avoid low water injection efficiency with possible scale inhibitor squeezing as a contingency option. On the other hand, deeper reservoir has higher risk of scaling due to its higher temperature, causing scale plugging easily in reservoir pores and production wells. For such reservoir, peripheral aquifer water injection, treated low-sulphate seawater with sulphate-removal system, or no water injection development concept should be selected. By using modelling and experiment to quantify the scale risk over a range of conditions, the field operator has identified opportunities to optimize the water injection strategy. The temperature dependence of the scale risk means, in principal, that different injection strategy for each reservoir can minimize flow assurance challenges and maximize return on investment in scale mitigation measures.
{"title":"Water Compatibility and Scale Risk Evaluation by Integrating Scale Prediction of Fluid Modelling, Reservoir Simulation and Laboratory Coreflood Experiment for a Giant Oil Field in Offshore Abu Dhabi","authors":"Y. Nomura, M. Almarzooqi, K. Makishima, Jon Tuck","doi":"10.2118/207319-ms","DOIUrl":"https://doi.org/10.2118/207319-ms","url":null,"abstract":"\u0000 An offshore field is producing oil from multiple reservoirs with peripheral water injection scheme. Seawater is injected through a subsea network and wellhead towers located along the original reservoir edge. However, because its OWC has moved upward, wells from wellhead towers are too remote to inject seawater effectively, with some portion going to the aquifer rather than oil pool. Therefore, it is planned to migrate injection strategy from peripheral to mid-dip pattern. An expected risk is scaling by mixing incompatible seawater and formation water. Such risk and mitigation measures were evaluated.\u0000 To achieve the objective, the following methodology was applied: 1. Scale modelling based on water chemical analysis. 2. Define scale risk envelope with three risk categories 3. Tracer dynamic reservoir simulation to track formation water, connate water, dump flood water, injection seawater and treated seawater. 4. Review the past field scale history data 5. Coreflood experiment to observe actual phenomena inside the reservoir with various parameters such as water mixing ratio, sulphate concentration, temperature and chemical inhibitor 6. Consolidate all study results, conclude field scale risk and impact of mitigation measures.\u0000 Scale prediction modelling, verified by coreflood tests, found that mixing reservoir formation water and injection seawater causes a sulphate scale risk, with risk severity depending on mixing ratio and sulphate concentration. Reservoir temperature was also found to correlate strongly with scale risk. Therefore, each reservoir should have different water management strategy. Scale impact is limited in the shallower wide reservoir with cooler reservoir temperature. Such reservoir should therefore have mid-dip pattern water injection to avoid low water injection efficiency with possible scale inhibitor squeezing as a contingency option. On the other hand, deeper reservoir has higher risk of scaling due to its higher temperature, causing scale plugging easily in reservoir pores and production wells. For such reservoir, peripheral aquifer water injection, treated low-sulphate seawater with sulphate-removal system, or no water injection development concept should be selected.\u0000 By using modelling and experiment to quantify the scale risk over a range of conditions, the field operator has identified opportunities to optimize the water injection strategy. The temperature dependence of the scale risk means, in principal, that different injection strategy for each reservoir can minimize flow assurance challenges and maximize return on investment in scale mitigation measures.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"61 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74406504","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}
Varghese Mangalathu John, Jose Selvaraj Edwin, Prakash Madhukar Nandwalkar, Raju Paul, F. Kamal
Many of the well-established practices and procedures those were followed in the execution of Oil & Gas Industry Projects were seeing a shift towards digital transformation in recent years, which got accelerated due to the Covid-19 pandemic. Digital transformation is the adoption of digital technologies whereby the existing business processes are modified or new ones are created. This process of redefining the conventional procedures, culture and customer experience to meet the changing requirements benefit the overall business function. Redefining the process of business in the digital age is digital transformation. Digital transformation in Oil & Gas Industry is embracing of technology to reshape how oil and gas companies manage and operate their assets. The digitally-enabled and data-centric approach leads to improved productivity, higher efficiency and increased cost savings. One of the Process Transformation example in Oil & Gas sector is to conduct the Factory Inspection and Acceptance Tests remotely utilizing various digital tools available in this digital age instead of the conventional way of physical participation in the testing. Many industries were already exploring the possibilities of non-conventional work practices such as Work from Home (remotely, away from office), conducting virtual meetings with remotely located participants. These practices were still not accepted in all the industries prior to 2020. However the outbreak of Covid-19 pandemic worldwide created a need to accept these non-conventional practices of remote or virtual work. Post Covid (2020), these are widely accepted in most of the industries including Oil & Gas sector. The concept of Virtual Remote Factory Acceptance Test (FAT) is explored to overcome the unforeseen situation arose due to worldwide Covid-19 outbreak. Travel restrictions were imposed worldwide to curb the covid-19 spread, which made a halt to the normal work practices followed till then. Virtual Remote FAT is a successful alternative to the conventional way of conducting the FAT and was utilized during Covid-19 outbreak. Virtual remote FAT is successfully completed in some of the recently executed projects and this can be pursued even after the Covid crisis.
{"title":"Virtual Remote Factory Acceptance Test","authors":"Varghese Mangalathu John, Jose Selvaraj Edwin, Prakash Madhukar Nandwalkar, Raju Paul, F. Kamal","doi":"10.2118/208167-ms","DOIUrl":"https://doi.org/10.2118/208167-ms","url":null,"abstract":"\u0000 Many of the well-established practices and procedures those were followed in the execution of Oil & Gas Industry Projects were seeing a shift towards digital transformation in recent years, which got accelerated due to the Covid-19 pandemic.\u0000 Digital transformation is the adoption of digital technologies whereby the existing business processes are modified or new ones are created. This process of redefining the conventional procedures, culture and customer experience to meet the changing requirements benefit the overall business function. Redefining the process of business in the digital age is digital transformation.\u0000 Digital transformation in Oil & Gas Industry is embracing of technology to reshape how oil and gas companies manage and operate their assets. The digitally-enabled and data-centric approach leads to improved productivity, higher efficiency and increased cost savings.\u0000 One of the Process Transformation example in Oil & Gas sector is to conduct the Factory Inspection and Acceptance Tests remotely utilizing various digital tools available in this digital age instead of the conventional way of physical participation in the testing.\u0000 Many industries were already exploring the possibilities of non-conventional work practices such as Work from Home (remotely, away from office), conducting virtual meetings with remotely located participants. These practices were still not accepted in all the industries prior to 2020. However the outbreak of Covid-19 pandemic worldwide created a need to accept these non-conventional practices of remote or virtual work. Post Covid (2020), these are widely accepted in most of the industries including Oil & Gas sector.\u0000 The concept of Virtual Remote Factory Acceptance Test (FAT) is explored to overcome the unforeseen situation arose due to worldwide Covid-19 outbreak. Travel restrictions were imposed worldwide to curb the covid-19 spread, which made a halt to the normal work practices followed till then.\u0000 Virtual Remote FAT is a successful alternative to the conventional way of conducting the FAT and was utilized during Covid-19 outbreak. Virtual remote FAT is successfully completed in some of the recently executed projects and this can be pursued even after the Covid crisis.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"9 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81421670","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}
Philippe Guilbaud, Tanios Matta, Tamadher Al Bashr, Imtiaz Ali
A method consisting in an optimal combination of conventional topography from a terrestrial acquisition and satellite derived topography is presented. The solution recently implemented in the UAE for the engineering and the construction of a gas export pipeline allows significant cost reduction, time saving, and safety hazard reduction as fewer terrestrial operations are needed. The survey area is split into 2 sub-areas: area with infrastructures requiring a high accuracy is surveyed with terrestrial topographical acquisition methods such as GNSS receivers, the other one with desert conditions is mapped from satellite stereoscopic imagery. Stereoscopic mode refers to when the satellite sensor acquires two images of the same location taken from different angles. Using photogrammetric techniques, it produces a 3D elevation model of the area. The native satellite imagery allows a mapping of the surface features as well. Terrestrial and satellite datasets are finally merged and adjusted to provide engineering and construction contractors with a unique survey dataset. Terrestrial survey methods provide generally 5-10cm horizontal and vertical accuracies whereas satellite topography has accuracy of a few meters, so satellite topography must be controlled and adjusted from terrestrial ground control points which allow to reach an average 50cm absolute accuracy. This is good enough in desert areas with neither particular ground feature nor steep relief requiring complex design. Satellite acquisition has limitations: vegetation masking the ground, steep slopes and dense infrastructures. It is therefore necessary to combine conventional and satellite topography to meet engineering requirements. This is considered when defining the satellite and terrestrial survey areas. Beyond these limitations, this solution has strong advantages. Satellite grid resolution can be better (1-2m versus 5-10m for GNSS surveys). Acquisition and processing are faster (about 2 weeks versus a few weeks or months), and costs are from 10 to 100 times cheaper than conventional methods. No need for personnel and equipment on site, no management of logistics and permitting as well. Finally, it reduces safety hazards such as car accident, harsh weather, manual handling, etc. In addition, limiting the area to be surveyed with conventional equipment may avoid the need to mobilize Airborne photogrammetry or lidar systems usually operated by foreign companies. This limits complex Call for Tender, permitting management and give more opportunity to contract local companies. Satellite topography is widely used for preliminary studies, but the innovation here consists in an optimal combination of terrestrial and satellite datasets for engineering and construction purposes. This solution has however some limitations as it requires suitable conditions for satellite optical imagery acquisitions: no vegetation, limited cloud cover, smooth topography, and limited infrastructures. This is
{"title":"Combination of Terrestrial and Satellite Topography for Pipeline Engineering and Construction","authors":"Philippe Guilbaud, Tanios Matta, Tamadher Al Bashr, Imtiaz Ali","doi":"10.2118/207362-ms","DOIUrl":"https://doi.org/10.2118/207362-ms","url":null,"abstract":"\u0000 A method consisting in an optimal combination of conventional topography from a terrestrial acquisition and satellite derived topography is presented. The solution recently implemented in the UAE for the engineering and the construction of a gas export pipeline allows significant cost reduction, time saving, and safety hazard reduction as fewer terrestrial operations are needed.\u0000 The survey area is split into 2 sub-areas: area with infrastructures requiring a high accuracy is surveyed with terrestrial topographical acquisition methods such as GNSS receivers, the other one with desert conditions is mapped from satellite stereoscopic imagery. Stereoscopic mode refers to when the satellite sensor acquires two images of the same location taken from different angles. Using photogrammetric techniques, it produces a 3D elevation model of the area. The native satellite imagery allows a mapping of the surface features as well.\u0000 Terrestrial and satellite datasets are finally merged and adjusted to provide engineering and construction contractors with a unique survey dataset.\u0000 Terrestrial survey methods provide generally 5-10cm horizontal and vertical accuracies whereas satellite topography has accuracy of a few meters, so satellite topography must be controlled and adjusted from terrestrial ground control points which allow to reach an average 50cm absolute accuracy. This is good enough in desert areas with neither particular ground feature nor steep relief requiring complex design.\u0000 Satellite acquisition has limitations: vegetation masking the ground, steep slopes and dense infrastructures. It is therefore necessary to combine conventional and satellite topography to meet engineering requirements. This is considered when defining the satellite and terrestrial survey areas.\u0000 Beyond these limitations, this solution has strong advantages. Satellite grid resolution can be better (1-2m versus 5-10m for GNSS surveys). Acquisition and processing are faster (about 2 weeks versus a few weeks or months), and costs are from 10 to 100 times cheaper than conventional methods. No need for personnel and equipment on site, no management of logistics and permitting as well. Finally, it reduces safety hazards such as car accident, harsh weather, manual handling, etc.\u0000 In addition, limiting the area to be surveyed with conventional equipment may avoid the need to mobilize Airborne photogrammetry or lidar systems usually operated by foreign companies. This limits complex Call for Tender, permitting management and give more opportunity to contract local companies.\u0000 Satellite topography is widely used for preliminary studies, but the innovation here consists in an optimal combination of terrestrial and satellite datasets for engineering and construction purposes.\u0000 This solution has however some limitations as it requires suitable conditions for satellite optical imagery acquisitions: no vegetation, limited cloud cover, smooth topography, and limited infrastructures. This is ","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"24 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77356900","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}
Sludge formation could significantly impair well productivity if deposited in the wellbore or surface flow lines. In a field where sludge formation is not common, an oil production well showed a sudden deterioration in well productivity. Thorough investigation of abnormal well performance, from surface and sub-surface perspective, indicated that the deposition of a thick layer of a tight emulsion across the surface choke has resulted in ceasing the oil flow to the gas oil separation plant. Extensive lab analysis indicated that the obstruction material was a sludge deposition promoted by the presence of asphaltene, high amount of iron and low pH brine. It is noteworthy to mention that the analytical results of lab prepared emulsion samples elucidate the rule of low pH aqueous solution, asphaltene and iron ions in inducing tight emulsion formation which helps to understand the root causes of sludge deposition. To come up with a cost-effective remedial treatment considering health, safety and environment (HSE), different emulsion breaking formulations, including different de-emulsifiers and anti-sludge agents, were examined in this study. An effective diesel-based formulation including proper de-emulsifier and anti-sludging agent was used during the execution of the field job. The design of the field job took into consideration a minimal footprint to the environment through the flowback of the well to the neighboring gas oil separation plant. This paper summarizes the joint efforts by production engineers and lab scientists to systemically tackle such major flow assurance issues which could significantly jeopardize wells productivity. The systemic approach starts with problem detection through well intervention and sample collection. It also includes the lab work which was carried out to identify the type and composition of deposition and evaluate/optimize a proper formulation for sludge deposition removal. The paper discusses in detail the design and execution of a successful field treatment, which has resulted in restoring and maintaining the well potential.
{"title":"Restoring Well Productivity Through a Fit-for-Purpose Sludge Cleanout Job","authors":"Muhammad A Al Huraifi, A. Al-Taq, M. A. Hajri","doi":"10.2118/208111-ms","DOIUrl":"https://doi.org/10.2118/208111-ms","url":null,"abstract":"\u0000 Sludge formation could significantly impair well productivity if deposited in the wellbore or surface flow lines. In a field where sludge formation is not common, an oil production well showed a sudden deterioration in well productivity. Thorough investigation of abnormal well performance, from surface and sub-surface perspective, indicated that the deposition of a thick layer of a tight emulsion across the surface choke has resulted in ceasing the oil flow to the gas oil separation plant. Extensive lab analysis indicated that the obstruction material was a sludge deposition promoted by the presence of asphaltene, high amount of iron and low pH brine. It is noteworthy to mention that the analytical results of lab prepared emulsion samples elucidate the rule of low pH aqueous solution, asphaltene and iron ions in inducing tight emulsion formation which helps to understand the root causes of sludge deposition. To come up with a cost-effective remedial treatment considering health, safety and environment (HSE), different emulsion breaking formulations, including different de-emulsifiers and anti-sludge agents, were examined in this study. An effective diesel-based formulation including proper de-emulsifier and anti-sludging agent was used during the execution of the field job. The design of the field job took into consideration a minimal footprint to the environment through the flowback of the well to the neighboring gas oil separation plant. This paper summarizes the joint efforts by production engineers and lab scientists to systemically tackle such major flow assurance issues which could significantly jeopardize wells productivity. The systemic approach starts with problem detection through well intervention and sample collection. It also includes the lab work which was carried out to identify the type and composition of deposition and evaluate/optimize a proper formulation for sludge deposition removal. The paper discusses in detail the design and execution of a successful field treatment, which has resulted in restoring and maintaining the well potential.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"35 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85457367","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}
Isothermal Storage Tanks (IST) contains tens thousands tons of the liquefied gases (propane, ethane, ethylene, etc.) at very low temperatures. These are the most dangerous industrial objects. In the report the Integrated Structural Health Monitoring (ISHM) Systems for the management of the integrity of these tanks in real time is considered. The structure of the ISHM Systems, NDT methods, technical characteristics, data verification procedures, a decision-making algorithm and practical results are described.
{"title":"Safety 4.0 for the Most Dangerous Industrial Objects","authors":"I. Razuvaev","doi":"10.2118/207762-ms","DOIUrl":"https://doi.org/10.2118/207762-ms","url":null,"abstract":"\u0000 Isothermal Storage Tanks (IST) contains tens thousands tons of the liquefied gases (propane, ethane, ethylene, etc.) at very low temperatures. These are the most dangerous industrial objects. In the report the Integrated Structural Health Monitoring (ISHM) Systems for the management of the integrity of these tanks in real time is considered. The structure of the ISHM Systems, NDT methods, technical characteristics, data verification procedures, a decision-making algorithm and practical results are described.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"260 ","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91449755","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}
Donatella Stocchi, Giacomo Zinzani, A. Lazzari, G. Leo, P. Pasquali, Davide Flamminio, F. Iolli
During the last years, the total number of subsea wells considerably increased thanks to growing investments in the development of deep and ultra-deep water fields. At the end of their producing life, all these wells will need to be decommissioned and permanently plugged and abandoned, so the demand for technologies that will allow to fulfil this task in the respect of the regulations and at the minimum cost gained a lot of momentum. This paper describes a permanent P&A strategy of subsea wells to be carried out with Well Intervention vessel. The study first goes through the operation sequence and available technologies, defining an abandonment approach which is in line with international standards. Identified strategy results into a significant time and cost reduction comparing with traditional subsea wells decommissioning works performed by a floater rig, even maintaining the same level of safety and effectiveness. The study shows that the overall time reduction estimated by using an intervention vessel ranges from 40 to 55%, compared to a conventional rig-based approach, leading the wells abandonment expenditure savings up to 70%. For all those wells where the implementation of an intervention vessel is not guaranteed, there is still room to get time and cost savings of about 5-15% by combining the same riserless technologies with a conventional floater rig.
{"title":"The Evolution of Subsea Wells Plug and Abandon by the Use of Intervention Vessel","authors":"Donatella Stocchi, Giacomo Zinzani, A. Lazzari, G. Leo, P. Pasquali, Davide Flamminio, F. Iolli","doi":"10.2118/207285-ms","DOIUrl":"https://doi.org/10.2118/207285-ms","url":null,"abstract":"\u0000 During the last years, the total number of subsea wells considerably increased thanks to growing investments in the development of deep and ultra-deep water fields. At the end of their producing life, all these wells will need to be decommissioned and permanently plugged and abandoned, so the demand for technologies that will allow to fulfil this task in the respect of the regulations and at the minimum cost gained a lot of momentum.\u0000 This paper describes a permanent P&A strategy of subsea wells to be carried out with Well Intervention vessel. The study first goes through the operation sequence and available technologies, defining an abandonment approach which is in line with international standards. Identified strategy results into a significant time and cost reduction comparing with traditional subsea wells decommissioning works performed by a floater rig, even maintaining the same level of safety and effectiveness.\u0000 The study shows that the overall time reduction estimated by using an intervention vessel ranges from 40 to 55%, compared to a conventional rig-based approach, leading the wells abandonment expenditure savings up to 70%.\u0000 For all those wells where the implementation of an intervention vessel is not guaranteed, there is still room to get time and cost savings of about 5-15% by combining the same riserless technologies with a conventional floater rig.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"32 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81314776","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}
Satyadileep Dara, S. Ibrahim, A. Raj, I. Khan, Eisa Salem Al Jenaibi
The oxidation of Benzene, Toluene, Ethylbenzene, and Xylenes (BTEX) in the furnace of SRUs at high temperature is an effective solution to prevent Claus catalyst deactivation in the downstream catalytic converters. However, the existing SRUs do not have the means to monitor BTEX emissions from Claus furnace due to lack of commercial online analyzers in the market. This often leads to excessive temperatures up to 1150 °C in the furnace to ensure BTEX destruction. Such high temperatures increase fuel gas consumption and CO emission and reduce sulfur recovery efficiency. To obtain continuous BTEX indication at the furnace exit, an online BTEX soft sensor model is developed to predict BTEX concentration at furnace exit. Subsequently, this soft sensor will be implemented in one of the SRUs of ADNOC Gas Processing. The BTEX soft sensor has been developed by constructing a compact kinetic model for aromatics destruction in the furnace based on the understanding of BTEX oxidation mechanisms derived using a detailed and well validated kinetic model developed previously. The kinetic model, including its rate parameters were incorporated into Hysys/Sulsim software, where both the reaction furnace and catalytic converters were simulated. The BTEX soft sensor has been validated with plant data from different ADNOC Gas Processing SRU trains under a wide range of feed conditions (particularly, with varying relative concentrations of H2S, CO2, and hydrocarbons in acid gas feed) in order to ensure its robustness and versatile predictive accuracy. The model predicts BTEX emissions from the reaction furnace under a wide range of operating conditions in the furnace with deviation not exceeding +/- 5 ppm. It also predicts the reaction furnace temperature (with a deviation of +/- 5%) and species composition from the furnace exit within a reasonable error margin. Presently, the model is in the process of being deployed in one of the SRUs of ADNO Gas Processing as an online soft sensor, where it can read the feed conditions, predict the BTEX exit concentration and write this value to the DCS. Thus, plant operators can monitor BTEX exit concentration on continuous basis and use it as a reliable basis to lower fuel gas co-firing rate in the furnace to achieve optimum furnace temperature that provide efficient BTEX destruction and low CO emission. The online soft analyzer, when deployed in SRU, will continuously predict BTEX emission from SRU furnace with high accuracy, which cannot be done experimentally in the plant or reliably using most of the existing commercial software. This approach can be used to seek favorable means of optimizing BTEX destruction to enhance sulfur recovery, while decreasing fuel gas consumption and carbon footprint in sulfur recovery units to reduce operating cost.
{"title":"Development of an Online Soft Analyzer for the Continuous Analysis of BTEX Emissions from the Furnace of Sulfur Recovery Units","authors":"Satyadileep Dara, S. Ibrahim, A. Raj, I. Khan, Eisa Salem Al Jenaibi","doi":"10.2118/207476-ms","DOIUrl":"https://doi.org/10.2118/207476-ms","url":null,"abstract":"\u0000 The oxidation of Benzene, Toluene, Ethylbenzene, and Xylenes (BTEX) in the furnace of SRUs at high temperature is an effective solution to prevent Claus catalyst deactivation in the downstream catalytic converters. However, the existing SRUs do not have the means to monitor BTEX emissions from Claus furnace due to lack of commercial online analyzers in the market. This often leads to excessive temperatures up to 1150 °C in the furnace to ensure BTEX destruction. Such high temperatures increase fuel gas consumption and CO emission and reduce sulfur recovery efficiency. To obtain continuous BTEX indication at the furnace exit, an online BTEX soft sensor model is developed to predict BTEX concentration at furnace exit. Subsequently, this soft sensor will be implemented in one of the SRUs of ADNOC Gas Processing. The BTEX soft sensor has been developed by constructing a compact kinetic model for aromatics destruction in the furnace based on the understanding of BTEX oxidation mechanisms derived using a detailed and well validated kinetic model developed previously. The kinetic model, including its rate parameters were incorporated into Hysys/Sulsim software, where both the reaction furnace and catalytic converters were simulated. The BTEX soft sensor has been validated with plant data from different ADNOC Gas Processing SRU trains under a wide range of feed conditions (particularly, with varying relative concentrations of H2S, CO2, and hydrocarbons in acid gas feed) in order to ensure its robustness and versatile predictive accuracy. The model predicts BTEX emissions from the reaction furnace under a wide range of operating conditions in the furnace with deviation not exceeding +/- 5 ppm. It also predicts the reaction furnace temperature (with a deviation of +/- 5%) and species composition from the furnace exit within a reasonable error margin. Presently, the model is in the process of being deployed in one of the SRUs of ADNO Gas Processing as an online soft sensor, where it can read the feed conditions, predict the BTEX exit concentration and write this value to the DCS. Thus, plant operators can monitor BTEX exit concentration on continuous basis and use it as a reliable basis to lower fuel gas co-firing rate in the furnace to achieve optimum furnace temperature that provide efficient BTEX destruction and low CO emission. The online soft analyzer, when deployed in SRU, will continuously predict BTEX emission from SRU furnace with high accuracy, which cannot be done experimentally in the plant or reliably using most of the existing commercial software. This approach can be used to seek favorable means of optimizing BTEX destruction to enhance sulfur recovery, while decreasing fuel gas consumption and carbon footprint in sulfur recovery units to reduce operating cost.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"25 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81580190","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. Alsaeedi, M. Elabrashy, M. Alzeyoudi, M. Albadi, Sandeep Soni, Jose Isambertt, Deepak Tripathi, Hamda Alkuwaiti
Asset engineers spend significant time in data validation on a daily basis by gathering data from multiple sources, manually collecting and analyzing these data points to deduce well behavior, and finally implementing the changes on the field. This paper proposes a closed-loop methodology that drastically reduces the time lost in low-efficiency activities, helps engineers to make faster decisions, and assists in efficiently implementing the changes in the field. This well performance evaluation starts with direct integration with the corporate database to feed the field data into a hydraulic model. Next, Pre-configured well performance limits such as reservoir parameters, well calibration parameters, and surface parameters are used to validate the input data and alert the end-user to trigger a well performance evaluation workflow. This workflow is based on a business intelligence tool that integrates statistical information with physics-based model information. Finally, after the engineer makes a holistic decision, an integrated action tracking mechanism assigns an actionable item to the field operator to close the workflow. This approach significantly reduces the time spent on data consolidation and analysis. Essentially this means more time for the engineers to focus on well behavior improvement strategies such as stimulation or re-perforation from more than three hundred strings with more than a thousand well data captured over a month. This approach is not entirely dependent on either static physics-based or statistical models; instead, this approach integrates both methods to enhance decision-making. Moreover, the dynamic behavior of the well is captured in the statistical model and validated against the estimated well behavior derived from the hydraulic model. Furthermore, the streamlined visualization tool helps engineers quickly identify well problems, such as lower productivity, reduced reservoir pressure, increased well scale, increased restrictions in the wellbore, etc. Another critical value addition of this closed-loop workflow is the actionable feedback that is well defined and stored within the system for common reference. For example, the asset engineers provide actionable feedback such as retesting requirement, well stimulation, artificial lift candidate, tubing clearance. Within the action tracking framework, field engineers can quickly filter the assigned action items to him or her for the day and take appropriate actions. This new integrated action-based closed-loop workflow significantly reduces the time spent on daily validation tasks and well performance evaluation tasks by combining the statistical and hydraulic models supported with visualization and action tracking capabilities.
{"title":"Closed-Loop Data & Business Intelligence Driven Approach of Well Performance Evaluation to Identify Changes in Well Behavior","authors":"A. Alsaeedi, M. Elabrashy, M. Alzeyoudi, M. Albadi, Sandeep Soni, Jose Isambertt, Deepak Tripathi, Hamda Alkuwaiti","doi":"10.2118/207214-ms","DOIUrl":"https://doi.org/10.2118/207214-ms","url":null,"abstract":"\u0000 Asset engineers spend significant time in data validation on a daily basis by gathering data from multiple sources, manually collecting and analyzing these data points to deduce well behavior, and finally implementing the changes on the field. This paper proposes a closed-loop methodology that drastically reduces the time lost in low-efficiency activities, helps engineers to make faster decisions, and assists in efficiently implementing the changes in the field.\u0000 This well performance evaluation starts with direct integration with the corporate database to feed the field data into a hydraulic model. Next, Pre-configured well performance limits such as reservoir parameters, well calibration parameters, and surface parameters are used to validate the input data and alert the end-user to trigger a well performance evaluation workflow. This workflow is based on a business intelligence tool that integrates statistical information with physics-based model information. Finally, after the engineer makes a holistic decision, an integrated action tracking mechanism assigns an actionable item to the field operator to close the workflow.\u0000 This approach significantly reduces the time spent on data consolidation and analysis. Essentially this means more time for the engineers to focus on well behavior improvement strategies such as stimulation or re-perforation from more than three hundred strings with more than a thousand well data captured over a month. This approach is not entirely dependent on either static physics-based or statistical models; instead, this approach integrates both methods to enhance decision-making. Moreover, the dynamic behavior of the well is captured in the statistical model and validated against the estimated well behavior derived from the hydraulic model. Furthermore, the streamlined visualization tool helps engineers quickly identify well problems, such as lower productivity, reduced reservoir pressure, increased well scale, increased restrictions in the wellbore, etc. Another critical value addition of this closed-loop workflow is the actionable feedback that is well defined and stored within the system for common reference. For example, the asset engineers provide actionable feedback such as retesting requirement, well stimulation, artificial lift candidate, tubing clearance. Within the action tracking framework, field engineers can quickly filter the assigned action items to him or her for the day and take appropriate actions.\u0000 This new integrated action-based closed-loop workflow significantly reduces the time spent on daily validation tasks and well performance evaluation tasks by combining the statistical and hydraulic models supported with visualization and action tracking capabilities.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"14 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87187606","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}
Armin Kueck, Vincent Kulke, Cord Schepelmann, Volker Peters, G. Ostermeyer, H. Reckmann
High Frequency Torsional Oscillations (HFTO) generate high torsional loads in the BHA causing cracks, damaged electronics or twist-offs. A new Torsional Vibration Isolator tool (TVI) protects the BHA by restricting vibrations to the tools between bit and TVI. Additional features have been added to the tool to automatically indicate torque overloading of the BHA and to increase torque resistance if required. This paper proves the functionality of the new features analytically, on a small-scale laboratory test and in multiple field deployments in the North Sea. New guidelines for field operations are provided. The new feature is a torsion limiter which automatically engages on reaching a critical torque threshold. The torque is then re-routed through more torque resistant BHA components. The engagement generates a characteristic signal indicating bit or BHA-overloading. The mechanical design of the new feature is presented. A criterion for engagement of the limiter and the signature indicating critical torque are analytically derived. They are experimentally validated on a scaled version of the TVI in a laboratory test. A prototype of the new tool is manufactured and deployed in multiple field operations in the North Sea previously heavily affected by HFTO. Two high-frequency measuring devices identify critical drilling situations on a scale of Milliseconds. A new guideline for utilization of this tool is developed including recommendations for BHA set-up and operational parameters. The TVI works as intended and protects the upper BHA from torsional loads generated by HFTO. The new feature engages at the predicted contact parameters. The signature indicating critical torque for the BHA was recorded and corresponds to the signature measured in the lab and predicted by the model. The TVI is best placed as close to the bit as possible, and a high-frequency measuring device in the BHA is recommended to record and transmit the contact indicators to surface. Based on field tests a parameter map for drilling torque and RPM is created that displays zones of safe operational parameters in a plain manner for field engineers. The map was validated in the field, and harmful drilling states were prevented by following the recommended drilling parameters. The next generation TVI protects BHAs from damage due to torsional vibrations. The new feature enables operations in stuck-pipe situations by increasing the torque when required. The overloading indicator prevents overstepping the torque limit of the bit and the BHA. The new parameter map and best-practice recommendations transport the learnings to the field in an easy-to-use manner.
{"title":"Next Generation Torsional Vibration Isolation Tool Increases BHA Reliability Proven by Field Operations in North Sea","authors":"Armin Kueck, Vincent Kulke, Cord Schepelmann, Volker Peters, G. Ostermeyer, H. Reckmann","doi":"10.2118/207739-ms","DOIUrl":"https://doi.org/10.2118/207739-ms","url":null,"abstract":"\u0000 High Frequency Torsional Oscillations (HFTO) generate high torsional loads in the BHA causing cracks, damaged electronics or twist-offs. A new Torsional Vibration Isolator tool (TVI) protects the BHA by restricting vibrations to the tools between bit and TVI. Additional features have been added to the tool to automatically indicate torque overloading of the BHA and to increase torque resistance if required. This paper proves the functionality of the new features analytically, on a small-scale laboratory test and in multiple field deployments in the North Sea. New guidelines for field operations are provided.\u0000 The new feature is a torsion limiter which automatically engages on reaching a critical torque threshold. The torque is then re-routed through more torque resistant BHA components. The engagement generates a characteristic signal indicating bit or BHA-overloading. The mechanical design of the new feature is presented. A criterion for engagement of the limiter and the signature indicating critical torque are analytically derived. They are experimentally validated on a scaled version of the TVI in a laboratory test. A prototype of the new tool is manufactured and deployed in multiple field operations in the North Sea previously heavily affected by HFTO. Two high-frequency measuring devices identify critical drilling situations on a scale of Milliseconds. A new guideline for utilization of this tool is developed including recommendations for BHA set-up and operational parameters.\u0000 The TVI works as intended and protects the upper BHA from torsional loads generated by HFTO. The new feature engages at the predicted contact parameters. The signature indicating critical torque for the BHA was recorded and corresponds to the signature measured in the lab and predicted by the model. The TVI is best placed as close to the bit as possible, and a high-frequency measuring device in the BHA is recommended to record and transmit the contact indicators to surface. Based on field tests a parameter map for drilling torque and RPM is created that displays zones of safe operational parameters in a plain manner for field engineers. The map was validated in the field, and harmful drilling states were prevented by following the recommended drilling parameters.\u0000 The next generation TVI protects BHAs from damage due to torsional vibrations. The new feature enables operations in stuck-pipe situations by increasing the torque when required. The overloading indicator prevents overstepping the torque limit of the bit and the BHA. The new parameter map and best-practice recommendations transport the learnings to the field in an easy-to-use manner.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"107 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89007405","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. Khanifar, Ibrahim Bin Subari, Mohd Razib Bin Abd Raub, Raj Deo Tewari, Mohd Faizal Bin Sedaralit
A major matured Malaysian offshore oilfield with more than 40 years of production history under a combination of moderate to strong aquifer support and moderate-size gas cap will be subjected to a unique enhanced oil recovery (EOR) scheme, the first of its kind offshore, called Gravity Assisted Simultaneous Water Alternating Gas (GASWAG) injection process. It is essentially a scheme which involves simultaneously injection of gas and water which involves injecting water up-dip and gas down-dip structurally in a depleted oil reservoir. This method takes the advantage of gravity drainage mechanism to maximize recovery from un-swept oil zones down-dip by aquifer influx and up-dip by gas cap expansion processes and it could be different than the conventional water alternating gas (WAG) method. This paper mostly presents the dynamic modelling and simulation work which has been established during this case study to obtain the GASWAG base case model and to conduct the optimization and sensitivity assessments on the major reservoir parameters. It also describes the main subsurface uncertainties and operational risks and their impact on incremental oil reserve and the results were used to design mitigation plans to help minimize impact on oil recovery volumes. Implementing the full field scale of this EOR scheme involves a detailed reservoir management plan (RMP) with many reactivations of idle wells, well workover plans, behind casing opportunities and adding perforation interval together with identified new infill wells to maximize the flood-front movement of the injected fluids. Obviously, good communication with field operational personnel is paramount to ensure these RMP are adhered to clear targets to successfully achieve the desired incremental recovery and will be elaborated in this paper. This paper describes the strategy and workflow to monitor and measure the two key success factors of this project which are production attainability and reserve attainability. The success of this project depends on continuous evaluation to check the actual performance against the anticipated behavior. As soon as new information obtains along implementation, it will be assessed against targets to steer the way to the main goal of additional reserve by the end of field life. Thus, it requires a comprehensive monitoring plan with detailed surveillance and data collection and, well testing to revisit and update the dynamic model accordingly. The results of this study show that GASWAG has emerged to be one of the most promising techniques with the highest incremental reserve for this field among various EOR techniques evaluated such as continuous gas injection, continuous water injection, conventional WAG, aquifer-assisted WAG, and double displacement.
{"title":"The World's First Offshore GASWAG EOR Full Field Implementation","authors":"A. Khanifar, Ibrahim Bin Subari, Mohd Razib Bin Abd Raub, Raj Deo Tewari, Mohd Faizal Bin Sedaralit","doi":"10.2118/208127-ms","DOIUrl":"https://doi.org/10.2118/208127-ms","url":null,"abstract":"\u0000 A major matured Malaysian offshore oilfield with more than 40 years of production history under a combination of moderate to strong aquifer support and moderate-size gas cap will be subjected to a unique enhanced oil recovery (EOR) scheme, the first of its kind offshore, called Gravity Assisted Simultaneous Water Alternating Gas (GASWAG) injection process. It is essentially a scheme which involves simultaneously injection of gas and water which involves injecting water up-dip and gas down-dip structurally in a depleted oil reservoir. This method takes the advantage of gravity drainage mechanism to maximize recovery from un-swept oil zones down-dip by aquifer influx and up-dip by gas cap expansion processes and it could be different than the conventional water alternating gas (WAG) method.\u0000 This paper mostly presents the dynamic modelling and simulation work which has been established during this case study to obtain the GASWAG base case model and to conduct the optimization and sensitivity assessments on the major reservoir parameters. It also describes the main subsurface uncertainties and operational risks and their impact on incremental oil reserve and the results were used to design mitigation plans to help minimize impact on oil recovery volumes. Implementing the full field scale of this EOR scheme involves a detailed reservoir management plan (RMP) with many reactivations of idle wells, well workover plans, behind casing opportunities and adding perforation interval together with identified new infill wells to maximize the flood-front movement of the injected fluids. Obviously, good communication with field operational personnel is paramount to ensure these RMP are adhered to clear targets to successfully achieve the desired incremental recovery and will be elaborated in this paper.\u0000 This paper describes the strategy and workflow to monitor and measure the two key success factors of this project which are production attainability and reserve attainability. The success of this project depends on continuous evaluation to check the actual performance against the anticipated behavior. As soon as new information obtains along implementation, it will be assessed against targets to steer the way to the main goal of additional reserve by the end of field life. Thus, it requires a comprehensive monitoring plan with detailed surveillance and data collection and, well testing to revisit and update the dynamic model accordingly.\u0000 The results of this study show that GASWAG has emerged to be one of the most promising techniques with the highest incremental reserve for this field among various EOR techniques evaluated such as continuous gas injection, continuous water injection, conventional WAG, aquifer-assisted WAG, and double displacement.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89725878","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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