ADNOC LNG on Das Island facility consists of three process trains. Each train contains one Sulphur Recovery Unit (SRU) which comprises a three-stage Claus unit followed by a SUPERCLAUS® unit. In the past 5 years, average Reliability of these SRUs is 85.7%, much below 98% of the LNG group benchmark value. The calculated Sulphur recovery efficiency in Clause mode is between 92% to 96% which is well below the target value of 97.5%. The SRU reliability and efficiency continue to have a negative impact on Sulphur production loss as well as flaring and emissions. This paper describes corrective actions taken by ADNOC LNG to address these issues in order to improve SRU reliability and efficiency and to minimize production losses and flaring. The implementation of these corrective actions has resulted in 8% improvement on SRU reliability. Sulphur recovery efficiency under Clause mode increased by 3.1%, leading to a significant reduction on flaring and emission, as well as increase on Sulphur production.
{"title":"Improving Sulphur Plant Reliability and Efficiency","authors":"Zhenhai Liu, M. Agung, Jan Kiebert","doi":"10.2118/197242-ms","DOIUrl":"https://doi.org/10.2118/197242-ms","url":null,"abstract":"\u0000 ADNOC LNG on Das Island facility consists of three process trains. Each train contains one Sulphur Recovery Unit (SRU) which comprises a three-stage Claus unit followed by a SUPERCLAUS® unit. In the past 5 years, average Reliability of these SRUs is 85.7%, much below 98% of the LNG group benchmark value. The calculated Sulphur recovery efficiency in Clause mode is between 92% to 96% which is well below the target value of 97.5%. The SRU reliability and efficiency continue to have a negative impact on Sulphur production loss as well as flaring and emissions.\u0000 This paper describes corrective actions taken by ADNOC LNG to address these issues in order to improve SRU reliability and efficiency and to minimize production losses and flaring. The implementation of these corrective actions has resulted in 8% improvement on SRU reliability. Sulphur recovery efficiency under Clause mode increased by 3.1%, leading to a significant reduction on flaring and emission, as well as increase on Sulphur production.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"49 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80139836","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}
Well testing equipment for unconventional onshore applications generally comprises a sand removal unit (Desander), a dual choke manifold, a test separator with metering, various types of tanks for temporary storage and in some cases a flare. This equipment is typically interconnected through high pressure temporary flowline generally referred to as flow-iron, which is made up from modular components that are joined by quick connect hammer unions. Installation of the equipment and the well testing itself is labor intensive. Personnel is on location 24 hours a day, working on or near high pressure piping and climbing onto open top tanks during well testing. This results in significant labor costs and exposes personnel to numerous health and safety risks. This paper starts with introducing a modularized Automated Well Testing system (AWT) which has been developed to rig-in and out faster, minimize personnel exposure to health and safety risks, minimize transport cost, reduce footprint and eliminate greenhouse gas emissions to operate the unit. A first unit has been built and applied at various shale plays across North America during the past two years. Learnings and conclusions from these applications are summarized and used to evaluate the design.
{"title":"Optimizing Automated Well Testing for the Unconventional Oil Field using a Modular Approach","authors":"S. Baaren, Ryan Malone","doi":"10.2118/197826-ms","DOIUrl":"https://doi.org/10.2118/197826-ms","url":null,"abstract":"\u0000 Well testing equipment for unconventional onshore applications generally comprises a sand removal unit (Desander), a dual choke manifold, a test separator with metering, various types of tanks for temporary storage and in some cases a flare. This equipment is typically interconnected through high pressure temporary flowline generally referred to as flow-iron, which is made up from modular components that are joined by quick connect hammer unions. Installation of the equipment and the well testing itself is labor intensive. Personnel is on location 24 hours a day, working on or near high pressure piping and climbing onto open top tanks during well testing. This results in significant labor costs and exposes personnel to numerous health and safety risks.\u0000 This paper starts with introducing a modularized Automated Well Testing system (AWT) which has been developed to rig-in and out faster, minimize personnel exposure to health and safety risks, minimize transport cost, reduce footprint and eliminate greenhouse gas emissions to operate the unit. A first unit has been built and applied at various shale plays across North America during the past two years. Learnings and conclusions from these applications are summarized and used to evaluate the design.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"455 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82943321","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 autonomous outflow control device is developed to choke back the injection fluid into natural/induced fractures and mitigate the disproportional injection of fluid into the thief zone and potentially creating short-circuit to the nearby producer wells. This paper will present an overview of the flow loop performance testing, and demonstrates the design consideration and integration with completion design and its benefit by reservoir modelling. The bi-stable devices should be installed in several compartments in the wells and operate as normal outflow control valves initially. When the injected flowrate flowing through a bi-stable valve exceeds a designed threshold, the bi-stable valve will autonomously move to another position to choke back the injection of fluid at that specific compartment. This allows the denied fluid to be distributed among the valves installed at neighbouring compartments. This performance enables the operator to minimise the impacts of natural fractures on the injected fluid conformance and to control the growth of thermal fractures while improving the efficiency of the injection well systems. The flow performance of the bi-stable valve has been validated and the flow behaviour can be simulated in the reservoir model. Static flow modelling has been used to establish the valve setting and packer placement in the well section and to demonstrate an improved distribution of the water injection and the effect of restricting water to the thief zone on the nearby producer oil recovery. A reservoir modelling method has been established to evaluate the bi-stable device performance in reservoir environments and compared with outflow control devices (OCDs) and open hole completions. Due to the uncertainty of heterogeneous reservoirs and the potential for dynamic changes of injection properties, the simulation study showed that with a lower pressure drop compared to OCDs, the fluid front can be managed more efficiently to achieve the desired sweep and maximised ultimate recovery. The first autonomous injection valve that restricts water into dilated/propagated fractures is developed. This device removes most of the deficiencies of OCDs and eliminates the requirements of running PLT and the prescribed well interventions e.g. closing/opening of sliding sleeves. Instead, it provides operators with a tool that enables the optimised completion to deliver optimum water injection techniques autonomously.
{"title":"A Game Changer for Injection Wells Outflow Control Devices to Efficiently Control the Injection Fluid Conformance","authors":"I. M. Ismail, M. Konopczynski, M. Moradi","doi":"10.2118/197612-ms","DOIUrl":"https://doi.org/10.2118/197612-ms","url":null,"abstract":"\u0000 A new autonomous outflow control device is developed to choke back the injection fluid into natural/induced fractures and mitigate the disproportional injection of fluid into the thief zone and potentially creating short-circuit to the nearby producer wells. This paper will present an overview of the flow loop performance testing, and demonstrates the design consideration and integration with completion design and its benefit by reservoir modelling.\u0000 The bi-stable devices should be installed in several compartments in the wells and operate as normal outflow control valves initially. When the injected flowrate flowing through a bi-stable valve exceeds a designed threshold, the bi-stable valve will autonomously move to another position to choke back the injection of fluid at that specific compartment. This allows the denied fluid to be distributed among the valves installed at neighbouring compartments. This performance enables the operator to minimise the impacts of natural fractures on the injected fluid conformance and to control the growth of thermal fractures while improving the efficiency of the injection well systems.\u0000 The flow performance of the bi-stable valve has been validated and the flow behaviour can be simulated in the reservoir model. Static flow modelling has been used to establish the valve setting and packer placement in the well section and to demonstrate an improved distribution of the water injection and the effect of restricting water to the thief zone on the nearby producer oil recovery.\u0000 A reservoir modelling method has been established to evaluate the bi-stable device performance in reservoir environments and compared with outflow control devices (OCDs) and open hole completions. Due to the uncertainty of heterogeneous reservoirs and the potential for dynamic changes of injection properties, the simulation study showed that with a lower pressure drop compared to OCDs, the fluid front can be managed more efficiently to achieve the desired sweep and maximised ultimate recovery.\u0000 The first autonomous injection valve that restricts water into dilated/propagated fractures is developed. This device removes most of the deficiencies of OCDs and eliminates the requirements of running PLT and the prescribed well interventions e.g. closing/opening of sliding sleeves. Instead, it provides operators with a tool that enables the optimised completion to deliver optimum water injection techniques autonomously.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"9 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82462037","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}
Zanussi Mohd Zain, E. Fontaine, Saifulbahari Abdul Hamid
This paper reviews the current industry practice for the design of Mid-Water-Arch (MWA) including the guidance from International Standards, requirements from Class, engineering (EPC) installation (OIC) practices. Best industry practice has been developed by MISC Berhad based on the past experiences and leasons learnt , to ensure the continuity of operations and prevent production loss through immediate mitigation actions, efficient repair strategy and minimum requirements for new design. The benefits of establishing of a minimum size of tether chain and the implementation of backup tether interventions are emphasized. The information provided in this paper may provenly useful for Class to amend mooring guidance to account for specific technical requirements for MWA long term requirement.
{"title":"Field Experience on the Design and Operation of Mid-Water Arch MWA in South China Sea","authors":"Zanussi Mohd Zain, E. Fontaine, Saifulbahari Abdul Hamid","doi":"10.2118/197619-ms","DOIUrl":"https://doi.org/10.2118/197619-ms","url":null,"abstract":"\u0000 This paper reviews the current industry practice for the design of Mid-Water-Arch (MWA) including the guidance from International Standards, requirements from Class, engineering (EPC) installation (OIC) practices. Best industry practice has been developed by MISC Berhad based on the past experiences and leasons learnt , to ensure the continuity of operations and prevent production loss through immediate mitigation actions, efficient repair strategy and minimum requirements for new design. The benefits of establishing of a minimum size of tether chain and the implementation of backup tether interventions are emphasized. The information provided in this paper may provenly useful for Class to amend mooring guidance to account for specific technical requirements for MWA long term requirement.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"42 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82468652","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}
To explore the opportunity for maximum utilization for one of gas processing facilities in line with ADNOC strategy to enhance profitability and asset utilization. A Technical study was conducted to increase the processing capacity up to 115% of its design limit. This was to identify the potential bottlenecks in the facility and suggest debottlenecking options with a reasonable investment. The Technical study covers the following activities: Rigorous process simulation including the licensor units of NGL & AGRU.Line sizing adequacy check and detailed hydraulic evaluation of the major piping.Equipment adequacy check.Relief & blowdown and flare system adequacy check.Proprietary equipment/design evaluation of licensed units.Adequacy check for In-line instruments like control valves, flow elements/transmitters, ThermowellsRotating equipment adequacy checks performed with the concurrence from OEMs.Obtained Endorsement of NGL licenser (Ortloff) for the methodology of 115% adequacy check, with a recommendation to gradually increase the plant rate in 1% at a time and monitor the performance until achieving the required targetRisk assessment was conducted before the capacity testActual plant capacity test run to verify the study findings. The study has concluded the following observations for processing 115% of the design capacity: High flow alarms set points need to be changed at some locations due to increase gas flow rates.550 oo 1133 of thermowell are not adequate based on new design CODE. These thermowells are to be replaced for the continuous operation.6 Filters to be upgraded with required capacity. A Successful two days Test-run was conducted in June 2018 and there are no additional limitations identified other than identified in the study. Following are the outcome. Reduction of the C2 recovery by 1.2 % with no significant change in C3 recovery level.Increase in Residue Gas by 30 MMSCFD per trainIncrease in NGL by 235 TPD per trainIncrease in condensate by 2100 BPD per train Overall Product wise revenue per train was identified at a sum of 62.5 MMUSD/Y.
{"title":"Enhance the Operating Capacity - Maximize the Revenue","authors":"Murali Muthukrishnan, Fatima H. Alraeesi","doi":"10.2118/197898-ms","DOIUrl":"https://doi.org/10.2118/197898-ms","url":null,"abstract":"\u0000 To explore the opportunity for maximum utilization for one of gas processing facilities in line with ADNOC strategy to enhance profitability and asset utilization. A Technical study was conducted to increase the processing capacity up to 115% of its design limit. This was to identify the potential bottlenecks in the facility and suggest debottlenecking options with a reasonable investment.\u0000 The Technical study covers the following activities: Rigorous process simulation including the licensor units of NGL & AGRU.Line sizing adequacy check and detailed hydraulic evaluation of the major piping.Equipment adequacy check.Relief & blowdown and flare system adequacy check.Proprietary equipment/design evaluation of licensed units.Adequacy check for In-line instruments like control valves, flow elements/transmitters, ThermowellsRotating equipment adequacy checks performed with the concurrence from OEMs.Obtained Endorsement of NGL licenser (Ortloff) for the methodology of 115% adequacy check, with a recommendation to gradually increase the plant rate in 1% at a time and monitor the performance until achieving the required targetRisk assessment was conducted before the capacity testActual plant capacity test run to verify the study findings.\u0000 The study has concluded the following observations for processing 115% of the design capacity: High flow alarms set points need to be changed at some locations due to increase gas flow rates.550 oo 1133 of thermowell are not adequate based on new design CODE. These thermowells are to be replaced for the continuous operation.6 Filters to be upgraded with required capacity.\u0000 A Successful two days Test-run was conducted in June 2018 and there are no additional limitations identified other than identified in the study. Following are the outcome. Reduction of the C2 recovery by 1.2 % with no significant change in C3 recovery level.Increase in Residue Gas by 30 MMSCFD per trainIncrease in NGL by 235 TPD per trainIncrease in condensate by 2100 BPD per train\u0000 Overall Product wise revenue per train was identified at a sum of 62.5 MMUSD/Y.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"28 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78942537","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 key management guideline for water-driven, naturally fractured reservoirs (NFR) is to minimize water production. Water breakthrough is undesirable as it reduces oil production rate and lowers oil recovery. Managing these reservoirs involves delaying water breakthrough and mitigating its effects. This paper describes a cross-disciplinary workflow, which serves such purposes by making use of downhole pressure gauges (DHG) pressure data-based well models along with a dynamically validated fracture model. The data-based well model is developed from our DHG pressure-production database. It has been field tested for forecasting water breakthrough, predicting water level in wells and planning for counteractive actions. The data-based well model is combined with a detailed fracture model whose elements were derived from the systemic integration of fracture types, genetic context and interaction with the carbonate host rock during diagenesis. The resulting workflow enables the well and reservoir management team (WRM) to put the well back in production after water-breakthrough in a way that maximizes oil re-saturation from tributary fractures into the main conductive features connected to the wellbore. A field case illustrating the application of this workflow is discussed. The outcome of the application of this workflow is compared with the performance of other wells in which water breakthrough was dealt with by merely reducing their liquid rates till water cut became manageable. A complete set of relevant measured data, including downhole pressure gauge and a post breakthrough production logging tool (PLT), is discussed in the paper. Well performance puts in evidence that the workflow discussed in this paper allows for higher oil production rates and significantly lower water production rates following water breakthrough compared against more traditional approaches for handling wells after water breakthrough. The workflow was developed through frequent iterations between near-wellbore flow performance data-based modeling and multi-scale fracture characterization, aimed to address the impact of the main conductive features and tributary fractures on well productivity. It is of interest to anyone involved in managing NFR, especially those engaged in preserving the sustainability of the oil potential of the well (both duration and rate).
{"title":"A Novel Approach in Handling Water Breakthrough in Fractured Carbonate Reservoir Through Dynamically Integrated Fracture Characterization: A Case Study","authors":"L. F. Rodríguez, Erich Funk","doi":"10.2118/197540-ms","DOIUrl":"https://doi.org/10.2118/197540-ms","url":null,"abstract":"\u0000 A key management guideline for water-driven, naturally fractured reservoirs (NFR) is to minimize water production. Water breakthrough is undesirable as it reduces oil production rate and lowers oil recovery. Managing these reservoirs involves delaying water breakthrough and mitigating its effects. This paper describes a cross-disciplinary workflow, which serves such purposes by making use of downhole pressure gauges (DHG) pressure data-based well models along with a dynamically validated fracture model.\u0000 The data-based well model is developed from our DHG pressure-production database. It has been field tested for forecasting water breakthrough, predicting water level in wells and planning for counteractive actions. The data-based well model is combined with a detailed fracture model whose elements were derived from the systemic integration of fracture types, genetic context and interaction with the carbonate host rock during diagenesis. The resulting workflow enables the well and reservoir management team (WRM) to put the well back in production after water-breakthrough in a way that maximizes oil re-saturation from tributary fractures into the main conductive features connected to the wellbore.\u0000 A field case illustrating the application of this workflow is discussed. The outcome of the application of this workflow is compared with the performance of other wells in which water breakthrough was dealt with by merely reducing their liquid rates till water cut became manageable. A complete set of relevant measured data, including downhole pressure gauge and a post breakthrough production logging tool (PLT), is discussed in the paper. Well performance puts in evidence that the workflow discussed in this paper allows for higher oil production rates and significantly lower water production rates following water breakthrough compared against more traditional approaches for handling wells after water breakthrough.\u0000 The workflow was developed through frequent iterations between near-wellbore flow performance data-based modeling and multi-scale fracture characterization, aimed to address the impact of the main conductive features and tributary fractures on well productivity. It is of interest to anyone involved in managing NFR, especially those engaged in preserving the sustainability of the oil potential of the well (both duration and rate).","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"40 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79339374","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. Moiseenkov, Dmitrii Smirnov, S. Mahajan, A. Hadhrami, I. Azizi, Hilal Shabibi, Y. Balushi, Mahmood Omairi, M. Rashdi
There have been many oil and gas field discoveries in the Cambrian Ara Group intra-salt carbonate rocks in the South Oman Salt Basin. These carbonates represent self-charging petroleum system with over-pressured hydrocarbon accumulation in dolomitized rock encased in the salt. Drilling and completion wells going through salt is challenging. Salt creeping behavior results in issues of stuck pipe during drilling operations, casings deformation and collapse that have led to well suspension and abandonment. The full set of the available historical data analyzed to identify magnitude and history of the problem. The study conducted to estimate of salt creep magnitude, to assess the effect of the salt creep on cement quality, drilling and completion risks. The risk of salt creep on the drilling, completion and long-term well integrity was evaluated with multi-disciplinary integration of geological, geomechanical, petrophysical and well engineering aspects to minimize and mitigate the salt creeping risks. In addition to identify root cause for completion failure and providing recommendations to drilling practices, cementation and completion design that can improve well delivery process. Salt creep behavior presents drilling challenges associated with excessive torque, stuck pipe, casing deformation, and poor cementing job. Salt creep associated risks to drilling and well integrity should be managed and mitigated. Key study findings captured for wells designs were: Salt creep rate increases with depth, salt thickness and differential stress (function of MW)Non uniform loading decreases the collapse rating of the casing and results in casing deformationNon-uniform loading likely due to poor cementing, interface between rigid carbonate intervals and salt, and irregular open hole quality. Studied casing collapse cases could likely be attributed to several factors or combinations of factors such as salt mobility behavior, drilling with low MW, poor cement jobs and loss of internal hydrostatic support for the casing after cement job between liners lap. The improved multi-disciplinary understanding of salt creep is vital to reduce drilling and completion costs, unnecessary well abandonment and achieve good life cycle well integrity i.e. avoid extra side-track and workover cost due to integrity issues. The best practices and conclusions summarized in the study for drilling and completion design expected to benefit the exploration and development projects for the salt encased carbonate reservoirs around the globe.
{"title":"Salt Creeping Effect on Borehole Collapse and Well Completion Design, Based on South Oman Field Experience","authors":"A. Moiseenkov, Dmitrii Smirnov, S. Mahajan, A. Hadhrami, I. Azizi, Hilal Shabibi, Y. Balushi, Mahmood Omairi, M. Rashdi","doi":"10.2118/197692-ms","DOIUrl":"https://doi.org/10.2118/197692-ms","url":null,"abstract":"\u0000 There have been many oil and gas field discoveries in the Cambrian Ara Group intra-salt carbonate rocks in the South Oman Salt Basin. These carbonates represent self-charging petroleum system with over-pressured hydrocarbon accumulation in dolomitized rock encased in the salt. Drilling and completion wells going through salt is challenging. Salt creeping behavior results in issues of stuck pipe during drilling operations, casings deformation and collapse that have led to well suspension and abandonment.\u0000 The full set of the available historical data analyzed to identify magnitude and history of the problem. The study conducted to estimate of salt creep magnitude, to assess the effect of the salt creep on cement quality, drilling and completion risks. The risk of salt creep on the drilling, completion and long-term well integrity was evaluated with multi-disciplinary integration of geological, geomechanical, petrophysical and well engineering aspects to minimize and mitigate the salt creeping risks. In addition to identify root cause for completion failure and providing recommendations to drilling practices, cementation and completion design that can improve well delivery process.\u0000 Salt creep behavior presents drilling challenges associated with excessive torque, stuck pipe, casing deformation, and poor cementing job. Salt creep associated risks to drilling and well integrity should be managed and mitigated. Key study findings captured for wells designs were: Salt creep rate increases with depth, salt thickness and differential stress (function of MW)Non uniform loading decreases the collapse rating of the casing and results in casing deformationNon-uniform loading likely due to poor cementing, interface between rigid carbonate intervals and salt, and irregular open hole quality.\u0000 Studied casing collapse cases could likely be attributed to several factors or combinations of factors such as salt mobility behavior, drilling with low MW, poor cement jobs and loss of internal hydrostatic support for the casing after cement job between liners lap. The improved multi-disciplinary understanding of salt creep is vital to reduce drilling and completion costs, unnecessary well abandonment and achieve good life cycle well integrity i.e. avoid extra side-track and workover cost due to integrity issues. The best practices and conclusions summarized in the study for drilling and completion design expected to benefit the exploration and development projects for the salt encased carbonate reservoirs around the globe.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"35 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88086026","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}
There are many types of equipment failures encountered during the operation of oil-flooded twin screw natural gas compressors. Defining the failure modes of gas compressors mining sour gas is of primary importance for improving reliability. The failure modes for compressors operating with hydrodymanic journal bearings are different from compressors operating with rolling element bearings. Gas compressors operating in corrosive environments easily succumb to failures such as corrosion-pitting, hydrogen-assisted fatigue and chemical attack. Some common failure modes will be defined for each type of bearings used in rotary screw compressors. Identifying these failure modes assists in defining the problem so that new lubricants can be designed to extend the working life of the compressor. The failure modes of roller bearing equipped compressors operating in sour and acid gases are primarily due to premature spall formation from hydrogen-assisted fatigue (i.e. hydrogen embrittlement) and sulfide stress corrosion. We have found that hydrodynamic journal bearings equipped compressors operating in sour gases will fail due to sulfide corrosion attack of the hydrodynamic bearings. A new additive system was developed to inhibit both types of failure modes. Laboratory corrosion tests were used to compare corrosion inhibition of new additive system to well-established compressor lubricants. When levels of corrosion inhibition were established, the experimental lubricants were field tested. Field tests of this experimental lubricant were carried out in compressors operating with both hydrodynamic bearings and rolling element bearings. The testing in this difficult natural gas field, demonstrated that CPI’s new experimental fluids have extended the operating time to failure, for compressors operating with both type of bearing systems, from about 2,000 hours to well over 10,000 hours. CPI has developed lubricant solutions that improve the reliability by extending the time to failure for oil-flooded twin screw compressors mining water-saturated natural gas streams with both acid gas and sour gas elements.
{"title":"Common Failure Modes in Oil Flooded Rotary Screw Sour Gas Compressors","authors":"D. Pallister, P. Ong","doi":"10.2118/197591-ms","DOIUrl":"https://doi.org/10.2118/197591-ms","url":null,"abstract":"\u0000 There are many types of equipment failures encountered during the operation of oil-flooded twin screw natural gas compressors. Defining the failure modes of gas compressors mining sour gas is of primary importance for improving reliability. The failure modes for compressors operating with hydrodymanic journal bearings are different from compressors operating with rolling element bearings. Gas compressors operating in corrosive environments easily succumb to failures such as corrosion-pitting, hydrogen-assisted fatigue and chemical attack. Some common failure modes will be defined for each type of bearings used in rotary screw compressors. Identifying these failure modes assists in defining the problem so that new lubricants can be designed to extend the working life of the compressor.\u0000 The failure modes of roller bearing equipped compressors operating in sour and acid gases are primarily due to premature spall formation from hydrogen-assisted fatigue (i.e. hydrogen embrittlement) and sulfide stress corrosion. We have found that hydrodynamic journal bearings equipped compressors operating in sour gases will fail due to sulfide corrosion attack of the hydrodynamic bearings. A new additive system was developed to inhibit both types of failure modes. Laboratory corrosion tests were used to compare corrosion inhibition of new additive system to well-established compressor lubricants. When levels of corrosion inhibition were established, the experimental lubricants were field tested. Field tests of this experimental lubricant were carried out in compressors operating with both hydrodynamic bearings and rolling element bearings. The testing in this difficult natural gas field, demonstrated that CPI’s new experimental fluids have extended the operating time to failure, for compressors operating with both type of bearing systems, from about 2,000 hours to well over 10,000 hours. CPI has developed lubricant solutions that improve the reliability by extending the time to failure for oil-flooded twin screw compressors mining water-saturated natural gas streams with both acid gas and sour gas elements.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"11 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89485136","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}
Haitham Al Kalbani, Faheem Al Marhoobi, Hamed Al Siyabi, Saleh Al Shabibi, Amran Al Kiyumi
The intensity of global warming has increased in recent years and reduction of greenhouse gases become a necessity. The Paris Agreement's recently signed by 196 countries long-term goal is to mitigate the global average temperature to well below 2 °C above pre-industrial levels (Wikipedia, 2018); and to limit the increase to 1.5 °C, as this will results in controlling the risks and effects of climate change. Governments are going towards stringent regulations and implementation of carbon credits. In oil and gas industry, gas is produced with oil and it is mostly treated and transported for various industrial uses. However, a significant portion of this gas is used in the facilities for power generation and other uses. Tanks for example, are usually blanketed by fuel gas. During the operation of the tanks gases are lost due flashing, level variation and thermal variation. The gases are usually collected in a header and then flared through atmospheric gas flares. The flaring will result in higher CO2 emission. Inefficient flares will also result in incomplete combustion of hydrocarbon and consequently the emission of methane and other gases. Currently, there are various technologies used to recover the gas, compress it and reuse it. Ejector, Eductor or compressors are mainly used for such application. Depending on the available resources, utilities, operational and maintenance experience and the return on investment any of these technologies can be selected. Daleel Petroleum LLC, who are operating a field in Oman, set a target of zero flaring by initially installing a gas treatment and compression plant to recover associated gas which was successfully commissioned in 2018. The next step is to recover the gas from the tanks, compress it and send to the gas treatment plant for further processing. This study covers Daleel petroleum LLC's approach in selecting the optimum technology for AP gas recovery and utilization. The study focused on setting the selection criteria and return on investment. A selection criteria will provide other operators with a holistic approach to take decision towards zero flaring and it will set a clear path on how to achieve it.
{"title":"Achieving Zero Flaring through Oil Tanks Gas Recovery: Case Study from Oman","authors":"Haitham Al Kalbani, Faheem Al Marhoobi, Hamed Al Siyabi, Saleh Al Shabibi, Amran Al Kiyumi","doi":"10.2118/197673-ms","DOIUrl":"https://doi.org/10.2118/197673-ms","url":null,"abstract":"\u0000 The intensity of global warming has increased in recent years and reduction of greenhouse gases become a necessity. The Paris Agreement's recently signed by 196 countries long-term goal is to mitigate the global average temperature to well below 2 °C above pre-industrial levels (Wikipedia, 2018); and to limit the increase to 1.5 °C, as this will results in controlling the risks and effects of climate change. Governments are going towards stringent regulations and implementation of carbon credits.\u0000 In oil and gas industry, gas is produced with oil and it is mostly treated and transported for various industrial uses. However, a significant portion of this gas is used in the facilities for power generation and other uses. Tanks for example, are usually blanketed by fuel gas. During the operation of the tanks gases are lost due flashing, level variation and thermal variation. The gases are usually collected in a header and then flared through atmospheric gas flares. The flaring will result in higher CO2 emission. Inefficient flares will also result in incomplete combustion of hydrocarbon and consequently the emission of methane and other gases.\u0000 Currently, there are various technologies used to recover the gas, compress it and reuse it. Ejector, Eductor or compressors are mainly used for such application. Depending on the available resources, utilities, operational and maintenance experience and the return on investment any of these technologies can be selected. Daleel Petroleum LLC, who are operating a field in Oman, set a target of zero flaring by initially installing a gas treatment and compression plant to recover associated gas which was successfully commissioned in 2018. The next step is to recover the gas from the tanks, compress it and send to the gas treatment plant for further processing.\u0000 This study covers Daleel petroleum LLC's approach in selecting the optimum technology for AP gas recovery and utilization. The study focused on setting the selection criteria and return on investment. A selection criteria will provide other operators with a holistic approach to take decision towards zero flaring and it will set a clear path on how to achieve it.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"862 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89944928","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}
With the increasing demand for hydrocarbons, unconventional reservoirs are gaining prominence and account for a large percentage of oil and gas production. However, these unconventional reservoirs inevitably include challenges that must be carefully managed while planning an extraction strategy to yield maximum recovery. This paper demonstrates the advantages of an integrated and automated well placement workflow to improve geosteering in complex unconventional reservoirs with maximum hydrocarbon recovery. Automated well placement technique is controlled by three primary components: (1) an integrated asset model; (2) availability of uninterrupted, real-time log data; and (3) appropriately selected well planning methods. Initially, a dynamically updatable model of subsurface geology is created that combines surface topography, and an initial well trajectory is planned. As the well progresses, new log data are added to the asset model, and an interpretation is made in real time. Incorporating real-time data helps to dynamically update the model and enable a comparison of planned vs. actual deviation surveys for course corrections. This procedure guides the geosteerer to update well plans, run feasibility analyses, and predict subsurface uncertainties ahead of drilling, thus, increasing the reservoir penetration and overall well productivity. Automated well placement while drilling is a relatively new concept and requires collaboration across various disciplines. Currently, such techniques are gaining importance among operators of unconventional resources as it enhances accuracy in well positioning and provides better production while reducing costs, drilling risks, and uncertainties. In addition, when targeting very thin, geologically complex reservoir layers, it provides a holistic view of the dynamically changing asset. The use of this approach will enable oil and gas operators to make collaborative, cross-domain decisions and streamline existing unconventional workflows.
{"title":"Role of Automated and Accurate Well Placement in Reducing Subsurface Complexities and Optimizing Geosteering – An Example from Complex Unconventional Reservoirs","authors":"Kalyan Saikia, Narayan H. Shanker","doi":"10.2118/197709-ms","DOIUrl":"https://doi.org/10.2118/197709-ms","url":null,"abstract":"\u0000 With the increasing demand for hydrocarbons, unconventional reservoirs are gaining prominence and account for a large percentage of oil and gas production. However, these unconventional reservoirs inevitably include challenges that must be carefully managed while planning an extraction strategy to yield maximum recovery. This paper demonstrates the advantages of an integrated and automated well placement workflow to improve geosteering in complex unconventional reservoirs with maximum hydrocarbon recovery.\u0000 Automated well placement technique is controlled by three primary components: (1) an integrated asset model; (2) availability of uninterrupted, real-time log data; and (3) appropriately selected well planning methods. Initially, a dynamically updatable model of subsurface geology is created that combines surface topography, and an initial well trajectory is planned. As the well progresses, new log data are added to the asset model, and an interpretation is made in real time. Incorporating real-time data helps to dynamically update the model and enable a comparison of planned vs. actual deviation surveys for course corrections. This procedure guides the geosteerer to update well plans, run feasibility analyses, and predict subsurface uncertainties ahead of drilling, thus, increasing the reservoir penetration and overall well productivity.\u0000 Automated well placement while drilling is a relatively new concept and requires collaboration across various disciplines. Currently, such techniques are gaining importance among operators of unconventional resources as it enhances accuracy in well positioning and provides better production while reducing costs, drilling risks, and uncertainties. In addition, when targeting very thin, geologically complex reservoir layers, it provides a holistic view of the dynamically changing asset. The use of this approach will enable oil and gas operators to make collaborative, cross-domain decisions and streamline existing unconventional workflows.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"26 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90209480","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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