Oil & gas (O&G) operators are increasingly focused on decarbonization and reaching net-zero carbon emissions. The O&G industry seeks to minimise methane emissions. Verification of estimated emissions using top down measurement methods represents a critical component of this effort. A novel approach to operationalizing top-down emissions surveys was developed and demonstrated, leveraging expertise in unmanned vehicle application, innovative methane emissions measurement technology, and an O&G industry collaborator. The inspection technique utilizes a fixed-wing unmanned aircraft to perform a remote offshore asset inspection while safely launching and recovering onshore. This method enables the collection of many tens of thousands individual point methane concentration measurements and affords the ability to resolve facility-level methane emissions and in conjunction with appropriate environmental conditions information, derive an accurate emission rate for an individual asset, while accounting for background fluctuation and potential upwind sources.The unmanned aircraft does not require any crew or equipment to be taken offshore or make modifications to the asset, thus allowing inspections to be performed with minimum impact to facility operations. This work overcame significant regulatory hurdles to fly long distance unmanned aircraft in congested airspace, developed detailed operational procedures and demonstrated the safety of the technique to both the O&G and aviation community, and the effectiveness of the measurement technology. The work demonstrated the suitability of the technique for operationalisation for routine measurement programmes.
{"title":"Application of Long Endurance UAS for Top-Down Methane Emission Measurements of Oil and Gas Facilities in an Offshore Environment","authors":"Charles Tavner, Daniel F. Touzel, Brendan Smith","doi":"10.2118/205467-ms","DOIUrl":"https://doi.org/10.2118/205467-ms","url":null,"abstract":"\u0000 Oil & gas (O&G) operators are increasingly focused on decarbonization and reaching net-zero carbon emissions. The O&G industry seeks to minimise methane emissions. Verification of estimated emissions using top down measurement methods represents a critical component of this effort.\u0000 A novel approach to operationalizing top-down emissions surveys was developed and demonstrated, leveraging expertise in unmanned vehicle application, innovative methane emissions measurement technology, and an O&G industry collaborator. The inspection technique utilizes a fixed-wing unmanned aircraft to perform a remote offshore asset inspection while safely launching and recovering onshore. This method enables the collection of many tens of thousands individual point methane concentration measurements and affords the ability to resolve facility-level methane emissions and in conjunction with appropriate environmental conditions information, derive an accurate emission rate for an individual asset, while accounting for background fluctuation and potential upwind sources.The unmanned aircraft does not require any crew or equipment to be taken offshore or make modifications to the asset, thus allowing inspections to be performed with minimum impact to facility operations. This work overcame significant regulatory hurdles to fly long distance unmanned aircraft in congested airspace, developed detailed operational procedures and demonstrated the safety of the technique to both the O&G and aviation community, and the effectiveness of the measurement technology. The work demonstrated the suitability of the technique for operationalisation for routine measurement programmes.","PeriodicalId":277521,"journal":{"name":"Day 2 Wed, September 08, 2021","volume":"56 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2021-09-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114564972","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The design and method of operation of Autonomous Inflow Control Devices are reviewed, including single-phase and multi-phase flow performance. Next, the multi-phase flow of fluids in the annular space between circular conduits is examined based on published information and flow pattern maps. This information is brought together in a thought experiment describing how AICDs and well performance will react to the segregation of fluids upstream of the flow control device, and the potential impact that the degree of restrictiveness on unwanted effluents can affect the flow performance of the reservoir and well. Finally, the impact on well flow performance is quantified by computer modelling of the reservoir inflow performance, annular flow performance, and AICD performance. The sensitivity of well productivity is assessed for multiple flow scenarios adjusting several model parameters, including type and number of AICDs per zone, GOR, water cut, flow rate, and well completion size. Although the concept of an AICD that completely shuts off gas and/or water production sounds appealing to those wishing to eliminate the production of unwanted effluents, a full understanding of the dynamics of inflow from the reservoir and phase segregation in the wellbore is necessary to evaluate the impact of highly restrictive AICDs on well productivity. With annular separation, even small water cuts or limited amounts of free gas flowing into the wellbore can cause most of the highly restrictive AICDs in a multiple device zone to shut, greatly impacting the oil productivity of the zone and the well. Using AICDs that are not as restrictive of the unwanted effluents allows the operator to continue to produce oil at significant rates when associated with low water cuts or reduced free-gas GORs. A workflow for determining the optimum degree of restrictiveness is proposed and demonstrated.
{"title":"Annular Phase Separation with AICD Completions – The Impact on Well Flow Performance and Control of Unwanted Effluents","authors":"M. Konopczynski, M. Moradi","doi":"10.2118/205407-ms","DOIUrl":"https://doi.org/10.2118/205407-ms","url":null,"abstract":"\u0000 The design and method of operation of Autonomous Inflow Control Devices are reviewed, including single-phase and multi-phase flow performance. Next, the multi-phase flow of fluids in the annular space between circular conduits is examined based on published information and flow pattern maps. This information is brought together in a thought experiment describing how AICDs and well performance will react to the segregation of fluids upstream of the flow control device, and the potential impact that the degree of restrictiveness on unwanted effluents can affect the flow performance of the reservoir and well. Finally, the impact on well flow performance is quantified by computer modelling of the reservoir inflow performance, annular flow performance, and AICD performance. The sensitivity of well productivity is assessed for multiple flow scenarios adjusting several model parameters, including type and number of AICDs per zone, GOR, water cut, flow rate, and well completion size.\u0000 Although the concept of an AICD that completely shuts off gas and/or water production sounds appealing to those wishing to eliminate the production of unwanted effluents, a full understanding of the dynamics of inflow from the reservoir and phase segregation in the wellbore is necessary to evaluate the impact of highly restrictive AICDs on well productivity. With annular separation, even small water cuts or limited amounts of free gas flowing into the wellbore can cause most of the highly restrictive AICDs in a multiple device zone to shut, greatly impacting the oil productivity of the zone and the well. Using AICDs that are not as restrictive of the unwanted effluents allows the operator to continue to produce oil at significant rates when associated with low water cuts or reduced free-gas GORs. A workflow for determining the optimum degree of restrictiveness is proposed and demonstrated.","PeriodicalId":277521,"journal":{"name":"Day 2 Wed, September 08, 2021","volume":"274 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2021-09-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129476643","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}
M. Nazeri, Hooman Haghighi, Craig Mckay, D. Erickson, Suling Zhai
The presence of impurities in captured CO2 plays a vital role in the safe and effective CO2 transport and storage in the CCUS chain. Impurities can significantly increase the cost of processing, transport, and storage and moreover add additional challenges to the design, operation, health and safety and integrity aspects. The effects of various impurities on the aforementioned challenges have been addressed in this work. Despite the importance of this area, there are still some knowledge gaps in terms of assessing the impact of CO2 specification on CCUS design and operations. International standards address different elements of the CCS chain, but none cover the full chain or consider the full chain economics. There are also differences between industry and leading CO2 authorities regarding the potential issues and challenges of implementing those standards. This paper reviews available standards and references which provide specifications/limitations for impurities for the purpose of transport and storage. In this work, the modified cubic EoSs and GERG EoS have been used to predict the thermodynamic properties and tuned viscosity models have been used for the prediction of transport properties. The required specifications for the quality of CO2 streams have been investigated using the above methodology for fluid properties, followed by the use of commercial software packages for thermohydraulic analysis of CO2 pipelines. Additionally, the storage capacity and geochemistry of fluids under high-pressure and high-temperature (HPHT) storage conditions were investigated. The impact of impurities has been assessed based on various CO2 sources using commercial capturing technologies. The assessment considered the impact of impurities on thermodynamic, thermohydraulic, integrity and operation of CO2 transport, injection, and storage system. This would include the effects of various types of components and their typical concentrations, e.g., water content, non-condensable gases (N2, O2, CH4, Ar, H2and CO), toxic gases (H2S and SO2), and hydrocarbons, on the thermophysical properties including density, viscosity, phase envelope and hydraulic parameters. A comparison of modelling results against the available experimental data measured at elevated pressure and temperature conditions have also been presented. This paper has mainly focused on the lessons learned from past CO2 transport design and operational experiences in order to identify the areas where it could lead to an optimised system in terms of design, costs, and operation. Additionally, past experience in the design of CO2 pipelines and operation of CO2 injection has been used to identify opportunities where CO2 specifications and guidelines could potentially be modified in order to achieve an optimised and cost-effective CO2 transport and injection system. Keywords: CO2 Specification; CO2 Transport Pipelines; Design and Operation Challenges; CO2 impurities; CCUS;
{"title":"Impact of CO2 Specifications on Design and Operation Challenges of CO2 Transport and Storage Systems in CCUS","authors":"M. Nazeri, Hooman Haghighi, Craig Mckay, D. Erickson, Suling Zhai","doi":"10.2118/205472-ms","DOIUrl":"https://doi.org/10.2118/205472-ms","url":null,"abstract":"\u0000 The presence of impurities in captured CO2 plays a vital role in the safe and effective CO2 transport and storage in the CCUS chain. Impurities can significantly increase the cost of processing, transport, and storage and moreover add additional challenges to the design, operation, health and safety and integrity aspects. The effects of various impurities on the aforementioned challenges have been addressed in this work.\u0000 Despite the importance of this area, there are still some knowledge gaps in terms of assessing the impact of CO2 specification on CCUS design and operations. International standards address different elements of the CCS chain, but none cover the full chain or consider the full chain economics. There are also differences between industry and leading CO2 authorities regarding the potential issues and challenges of implementing those standards. This paper reviews available standards and references which provide specifications/limitations for impurities for the purpose of transport and storage.\u0000 In this work, the modified cubic EoSs and GERG EoS have been used to predict the thermodynamic properties and tuned viscosity models have been used for the prediction of transport properties. The required specifications for the quality of CO2 streams have been investigated using the above methodology for fluid properties, followed by the use of commercial software packages for thermohydraulic analysis of CO2 pipelines. Additionally, the storage capacity and geochemistry of fluids under high-pressure and high-temperature (HPHT) storage conditions were investigated.\u0000 The impact of impurities has been assessed based on various CO2 sources using commercial capturing technologies. The assessment considered the impact of impurities on thermodynamic, thermohydraulic, integrity and operation of CO2 transport, injection, and storage system. This would include the effects of various types of components and their typical concentrations, e.g., water content, non-condensable gases (N2, O2, CH4, Ar, H2and CO), toxic gases (H2S and SO2), and hydrocarbons, on the thermophysical properties including density, viscosity, phase envelope and hydraulic parameters. A comparison of modelling results against the available experimental data measured at elevated pressure and temperature conditions have also been presented.\u0000 This paper has mainly focused on the lessons learned from past CO2 transport design and operational experiences in order to identify the areas where it could lead to an optimised system in terms of design, costs, and operation. Additionally, past experience in the design of CO2 pipelines and operation of CO2 injection has been used to identify opportunities where CO2 specifications and guidelines could potentially be modified in order to achieve an optimised and cost-effective CO2 transport and injection system.\u0000 Keywords: CO2 Specification; CO2 Transport Pipelines; Design and Operation Challenges; CO2 impurities; CCUS;","PeriodicalId":277521,"journal":{"name":"Day 2 Wed, September 08, 2021","volume":"6 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2021-09-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127759425","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}
Barry Ritchie, Eyad Mohamed Elhassan, T. Jørgensen, Kristian Solhaug
A new development well in the Halfdan Field, well HBB-05, was selected as a candidate for the first Multilateral Completion Stimulation Technology (MCST) installation in the Danish sector of the North Sea. Placed in a thinner part of the Ekofisk formation it was important that the well didn't communicate with the underlying Tor formation, which would reduce the recovery from both reservoirs. An alternative completion was sought that would enhance reservoir contact, while protecting reserves. Halfdan is a laterally extensive field and comprises a high porosity (25% - 35%), low permeability (0.5 mD – 5 mD) chalk reservoir of Maastrichtian (Upper Cretaceous) and Danian (0.1-1mD) (Lower Paleocene) age. The main field, located within the Maastrichtian Tor formation, is developed with long horizontal wells of 10,000 ft - 15,000 ft reservoir sections drilled in a parallel pattern of alternating oil production and water injection wells spaced 600 ft apart. A multizone MCST was placed in a thin, layered chalk aiming for an increased effective well bore radius. The well consisted of a 4-½" liner with a new record number of subs placed in one well; 56 MCST subs. Each sub contained four needles at 90 degrees phasing capable of penetrating up to 40 ft. into the reservoir. The subs were placed in the distal 3,000ft horizontal section, beyond the reach of coiled tubing. The liner was installed on a work string starting at 16,820 ft. First time usage of MCST offshore Denmark creates a potential game changer for carbonate reservoir productivity enhancement. Production improvement over conventional stimulation methods where the following challenges may be addressed: –Thin, layered chalk–Need for increased wellbore radius–Extended reach reservoir sections–Beyond the reach of coiled tubing
{"title":"North Sea Horizontal Well with Multi-Zone Completion Sets World Record Using Acid Jetting Technology","authors":"Barry Ritchie, Eyad Mohamed Elhassan, T. Jørgensen, Kristian Solhaug","doi":"10.2118/205417-ms","DOIUrl":"https://doi.org/10.2118/205417-ms","url":null,"abstract":"\u0000 A new development well in the Halfdan Field, well HBB-05, was selected as a candidate for the first Multilateral Completion Stimulation Technology (MCST) installation in the Danish sector of the North Sea. Placed in a thinner part of the Ekofisk formation it was important that the well didn't communicate with the underlying Tor formation, which would reduce the recovery from both reservoirs. An alternative completion was sought that would enhance reservoir contact, while protecting reserves.\u0000 Halfdan is a laterally extensive field and comprises a high porosity (25% - 35%), low permeability (0.5 mD – 5 mD) chalk reservoir of Maastrichtian (Upper Cretaceous) and Danian (0.1-1mD) (Lower Paleocene) age. The main field, located within the Maastrichtian Tor formation, is developed with long horizontal wells of 10,000 ft - 15,000 ft reservoir sections drilled in a parallel pattern of alternating oil production and water injection wells spaced 600 ft apart.\u0000 A multizone MCST was placed in a thin, layered chalk aiming for an increased effective well bore radius. The well consisted of a 4-½\" liner with a new record number of subs placed in one well; 56 MCST subs. Each sub contained four needles at 90 degrees phasing capable of penetrating up to 40 ft. into the reservoir. The subs were placed in the distal 3,000ft horizontal section, beyond the reach of coiled tubing. The liner was installed on a work string starting at 16,820 ft.\u0000 First time usage of MCST offshore Denmark creates a potential game changer for carbonate reservoir productivity enhancement. Production improvement over conventional stimulation methods where the following challenges may be addressed: –Thin, layered chalk–Need for increased wellbore radius–Extended reach reservoir sections–Beyond the reach of coiled tubing","PeriodicalId":277521,"journal":{"name":"Day 2 Wed, September 08, 2021","volume":"58 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2021-09-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132199497","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}
Bilal Hakim, Brandon Thibodeaux, C. Brinkman, J. Gomes, Kevin Smith, Ryan Cone, Tom Messonnier
Waterflooding in deepwater reservoirs typically involves injecting seawater or produced water from the surface via pumps into injection wells. This technique is often cost-prohibitive for many reservoirs and poses significant mechanical/operational risks. This paper discusses how one Gulf of Mexico (GOM) operator overcame all these challenges using smart well technology to implement the first controlled dumpflood in deepwater GOM and boosted the injection rate, reservoir pressure, and recovery from a reservoir at a depth of 20,000 ft. In a typical dumpflood project, uncontrolled water production from the aquifer and subsequent injection into the target zone occurs downhole within the same wellbore. Therefore, typical surface and downhole complexities associated with conventional waterflood projects can be avoided. In this first deepwater GOM controlled dumpflood well, the controlled water flow (≥20,000 bbl/d) is directed from the source aquifer to the target oil zone via inflow control valves (ICV). The ICV, downhole permanent pressure gauges, and the downhole flowmeter provide complete surveillance and control of the injection operation to achieve reservoir management and optimize the waterflood objectives. A world-class Pliocene oil reservoir in the deepwater GOM underwent significant pressure depletion due to a weak water-drive mechanism. Extensive subsurface studies and modeling suggested great rock quality and reservoir connectivity, favorable oil-water mobility ratios, and significant upside potential making this reservoir a perfect candidate for waterflooding. Given topsides facility space constraints, a topsides injection was ruled out. Seawater injection via subsea pumping was deemed risky and marginally economical given the high cost and low commodity prices. The asset team then brainstormed ways to minimize the cost and overcome the associated risks and challenges. The asset team envisioned a dumpflood scenario would overcome all the challenges, but a dumpflood had not previously been implemented in the deepwater GOM. From a technical standpoint, all the known risks were identified and addressed, and a low risk factor was determined for this project. After a complex well completion job, the injection rate was ramped-up to ≥20,000 bwpd water via the ICV. An immediate uptick in reservoir pressure and production rate was observed in the producer well 3,000 ft away. Continuous injection has resulted in reservoir pressure and flowrate increases by at least 1,000 psi and 4,000 bopd, respectively, consistent with reservoir modeling estimates. The operator was successful in implementing an existing technology in a unique way in the deepwater environment. A naturally occurring water source at a depth of 19,000 ft was efficiently harvested to increase recovery from a reservoir at a fraction of the cost of a conventional deepwater waterflood project. Great interdisciplinary collaboration and forward thinking enabled the success of this uniq
{"title":"First Successful Controlled Dumpflood in Deepwater Gulf of Mexico Results in Promising Incremental Rate and Recovery","authors":"Bilal Hakim, Brandon Thibodeaux, C. Brinkman, J. Gomes, Kevin Smith, Ryan Cone, Tom Messonnier","doi":"10.2118/205449-ms","DOIUrl":"https://doi.org/10.2118/205449-ms","url":null,"abstract":"\u0000 Waterflooding in deepwater reservoirs typically involves injecting seawater or produced water from the surface via pumps into injection wells. This technique is often cost-prohibitive for many reservoirs and poses significant mechanical/operational risks. This paper discusses how one Gulf of Mexico (GOM) operator overcame all these challenges using smart well technology to implement the first controlled dumpflood in deepwater GOM and boosted the injection rate, reservoir pressure, and recovery from a reservoir at a depth of 20,000 ft.\u0000 In a typical dumpflood project, uncontrolled water production from the aquifer and subsequent injection into the target zone occurs downhole within the same wellbore. Therefore, typical surface and downhole complexities associated with conventional waterflood projects can be avoided. In this first deepwater GOM controlled dumpflood well, the controlled water flow (≥20,000 bbl/d) is directed from the source aquifer to the target oil zone via inflow control valves (ICV). The ICV, downhole permanent pressure gauges, and the downhole flowmeter provide complete surveillance and control of the injection operation to achieve reservoir management and optimize the waterflood objectives.\u0000 A world-class Pliocene oil reservoir in the deepwater GOM underwent significant pressure depletion due to a weak water-drive mechanism. Extensive subsurface studies and modeling suggested great rock quality and reservoir connectivity, favorable oil-water mobility ratios, and significant upside potential making this reservoir a perfect candidate for waterflooding. Given topsides facility space constraints, a topsides injection was ruled out. Seawater injection via subsea pumping was deemed risky and marginally economical given the high cost and low commodity prices. The asset team then brainstormed ways to minimize the cost and overcome the associated risks and challenges. The asset team envisioned a dumpflood scenario would overcome all the challenges, but a dumpflood had not previously been implemented in the deepwater GOM. From a technical standpoint, all the known risks were identified and addressed, and a low risk factor was determined for this project.\u0000 After a complex well completion job, the injection rate was ramped-up to ≥20,000 bwpd water via the ICV. An immediate uptick in reservoir pressure and production rate was observed in the producer well 3,000 ft away. Continuous injection has resulted in reservoir pressure and flowrate increases by at least 1,000 psi and 4,000 bopd, respectively, consistent with reservoir modeling estimates.\u0000 The operator was successful in implementing an existing technology in a unique way in the deepwater environment. A naturally occurring water source at a depth of 19,000 ft was efficiently harvested to increase recovery from a reservoir at a fraction of the cost of a conventional deepwater waterflood project. Great interdisciplinary collaboration and forward thinking enabled the success of this uniq","PeriodicalId":277521,"journal":{"name":"Day 2 Wed, September 08, 2021","volume":"35 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2021-09-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127882275","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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