Mohd Uzair Zakaria, Wan Mahsuri Wan Hashim, Nik Fauziah Nik Omar, Rohaizad M Norpiah, M. A. Abu Bakar, Wan Amni Wan Mohamad
A gas field located offshore Malaysia will be developed with carbon capture technology which will recover the remaining amount of hydrocarbon from CO2 rich permeate stream and subsequently concentrate the amount of CO2 to higher purity. The separated high concentration CO2 will be compressed, transported to storage site and injected to store the CO2 safely in a sub-surface geological formation which is a depleted gas field. One of the key success criteria for the CCS development is to be able to inject the CO2 to the reservoir for permanent storage from early to end of injection life. Typically, the battery limit of interface between the subsurface and surface engineer is the surface ITHP whereby the initial prediction was based on stand-alone sub-surface well modelling. A validation exercise was conducted using surface well modelling, including a sensitivity of three main Equation of State (EOS) being considered i.e., GERG-2008, PR 1978 and Advanced PR 1978, to allow the range of pressure drop to be translated to the ITHP number to be quantified. It is acknowledged that impurities within the CO2 stream have strong effect on phase behaviour and physical property predictions. The CO2 composition under study is >95mol% with a mixture of impurities. In addition, ambient temperature has also been found to influence pressure drop prediction. A similar approach is extended for pipeline study. Subsequently, the result provides a clear picture to develop a basis for facility design pressure. The integrated approach of flow assurance between wells and pipeline is important as this was found to affect the CO2 source pressure and design of the surface facility. This paper explains how the study was conducted during conceptual engineering stage and can serve as a reference to other CCS projects.
{"title":"Case Study: The Importance of Integrated Flow Assurance Modelling for Carbon Capture and Storage CCS Project","authors":"Mohd Uzair Zakaria, Wan Mahsuri Wan Hashim, Nik Fauziah Nik Omar, Rohaizad M Norpiah, M. A. Abu Bakar, Wan Amni Wan Mohamad","doi":"10.4043/31536-ms","DOIUrl":"https://doi.org/10.4043/31536-ms","url":null,"abstract":"\u0000 A gas field located offshore Malaysia will be developed with carbon capture technology which will recover the remaining amount of hydrocarbon from CO2 rich permeate stream and subsequently concentrate the amount of CO2 to higher purity. The separated high concentration CO2 will be compressed, transported to storage site and injected to store the CO2 safely in a sub-surface geological formation which is a depleted gas field.\u0000 One of the key success criteria for the CCS development is to be able to inject the CO2 to the reservoir for permanent storage from early to end of injection life. Typically, the battery limit of interface between the subsurface and surface engineer is the surface ITHP whereby the initial prediction was based on stand-alone sub-surface well modelling. A validation exercise was conducted using surface well modelling, including a sensitivity of three main Equation of State (EOS) being considered i.e., GERG-2008, PR 1978 and Advanced PR 1978, to allow the range of pressure drop to be translated to the ITHP number to be quantified. It is acknowledged that impurities within the CO2 stream have strong effect on phase behaviour and physical property predictions. The CO2 composition under study is >95mol% with a mixture of impurities. In addition, ambient temperature has also been found to influence pressure drop prediction. A similar approach is extended for pipeline study. Subsequently, the result provides a clear picture to develop a basis for facility design pressure.\u0000 The integrated approach of flow assurance between wells and pipeline is important as this was found to affect the CO2 source pressure and design of the surface facility. This paper explains how the study was conducted during conceptual engineering stage and can serve as a reference to other CCS projects.","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"9 1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75175781","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}
Anas Khaled Alsheikh, N. Zawawi, M. S. Liew, L. E. Shawn, I. Toloue, K. U. Danyaro, Nurshazlyn M. Aszemi
In Malaysia, over 400 oil and gas platforms are in operation. In every life cycle of a platform, it undergoes decommissioning. The most used method is by relocating the asset to an onshore fabrication facility. The alternative to onshore decommissioning is by reefing structures in-situ or ex-situ basis. to achieve the environmental assurance of a successful decommissioning by reefing, two domains of parameters were overviewed. the study involved hydrodynamic simulation of platforms. The first domain is in relations to the site to determine its suitability against hosting marine life and thriving coral formulation (Site Suitability). the other domain is in relations to the structure's physical and hydrodynamic properties (structural viability). Site suitability is governed by water depth and current velocity. Structural viability is governed by two sub-domains, one is where dimensions and complexity of the structure are assessed using dimensionality analysis. And the other is its hydrodynamic properties (Vortex Shedding Frequency, Pressure, Wake Region indices).
{"title":"A Literature Review on Site Suitability and Structural Hydrodynamic Viability for Artificial Reefs Purposes","authors":"Anas Khaled Alsheikh, N. Zawawi, M. S. Liew, L. E. Shawn, I. Toloue, K. U. Danyaro, Nurshazlyn M. Aszemi","doi":"10.4043/31494-ms","DOIUrl":"https://doi.org/10.4043/31494-ms","url":null,"abstract":"\u0000 In Malaysia, over 400 oil and gas platforms are in operation. In every life cycle of a platform, it undergoes decommissioning. The most used method is by relocating the asset to an onshore fabrication facility. The alternative to onshore decommissioning is by reefing structures in-situ or ex-situ basis. to achieve the environmental assurance of a successful decommissioning by reefing, two domains of parameters were overviewed. the study involved hydrodynamic simulation of platforms. The first domain is in relations to the site to determine its suitability against hosting marine life and thriving coral formulation (Site Suitability). the other domain is in relations to the structure's physical and hydrodynamic properties (structural viability). Site suitability is governed by water depth and current velocity. Structural viability is governed by two sub-domains, one is where dimensions and complexity of the structure are assessed using dimensionality analysis. And the other is its hydrodynamic properties (Vortex Shedding Frequency, Pressure, Wake Region indices).","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76048757","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}
Hydrates have been a constant threat to subsea deepwater operations. Partial or total hydrate blockages usually occur after shutdown of a host facility, which invariably affects the resumption of production. The complexities of subsea production systems and extensiveness of deepwater fields present challenges in implementing hydrate management strategies. In the past, erroneous and ad-hoc strategies were implemented due to a lack of flow assurance (FA) awareness and understanding, resulting in production deferment caused by frequent hydrate formation/ blockages. Hydrate inhibition based on Mono-Ethylene Glycol (MEG) and Methanol (MeOH), if not properly understood and managed may lead to significant increases in a field's annual operating expenditure (OPEX). PETRONAS has gained a fair amount of experience in dealing with hydrates. The approaches taken in mitigating hydrate related issues in subsea developments have been exemplary and it is beneficial to be shared across the fraternities. These approaches will be discussed in detail throughout the article based on case studies from two subsea field developments: Field D Deepwater Gas Development and BG Gas Flowline at Field C
{"title":"Integrated Approach in Implementing Hydrate Management Strategies in Deepwater Gas Developments","authors":"A. Anuar, Rohaizad M Norpiah","doi":"10.4043/31582-ms","DOIUrl":"https://doi.org/10.4043/31582-ms","url":null,"abstract":"\u0000 Hydrates have been a constant threat to subsea deepwater operations. Partial or total hydrate blockages usually occur after shutdown of a host facility, which invariably affects the resumption of production. The complexities of subsea production systems and extensiveness of deepwater fields present challenges in implementing hydrate management strategies. In the past, erroneous and ad-hoc strategies were implemented due to a lack of flow assurance (FA) awareness and understanding, resulting in production deferment caused by frequent hydrate formation/ blockages. Hydrate inhibition based on Mono-Ethylene Glycol (MEG) and Methanol (MeOH), if not properly understood and managed may lead to significant increases in a field's annual operating expenditure (OPEX). PETRONAS has gained a fair amount of experience in dealing with hydrates. The approaches taken in mitigating hydrate related issues in subsea developments have been exemplary and it is beneficial to be shared across the fraternities. These approaches will be discussed in detail throughout the article based on case studies from two subsea field developments: Field D Deepwater Gas Development and BG Gas Flowline at Field C","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"72 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85835320","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}
Field X produces dry gas from a carbonate reservoir with moderate aquifer support consisting of 16 wells most of which were drilled between 1986 to 1987. Up until 2021, these wells would have been in service for approximately 35 years, past its theoretical design life. Based on production forecast, the field is expected to continue producing for another 10 to 18 years. In view of the prolonged life extension, there is a need to review the integrity status of the well to ensure safe production until the end of field life. Wellhead preventive maintenance are conducted on a six-monthly basis to assure safety critical equipment (SCE) functionality and performance. Maintenance data collected since 2008 provides a good view on surface and subsurface valve integrity. In recent years, observations on external corrosion have received some attention. At the same time, there were efforts in determining and verifying the corrosion rates for production tubing, wellhead and x-mas tree. For well tubing and production casing, load based assumptions were used to estimate the minimum allowable tubular thickness to establish a basis for remaining life estimates. To verify the remaining life estimates, in 2019, a multi-finger caliper log was ran across the tubing of Well B to measure actual metal loss around the pipe. A magnetic log was also run in Well B in the same year to obtain quantitative measurement of remaining metal thickness in 13-3/8", 9-5/8" and 7" tubing. The observations from these exercises indicate that calculated estimates are more conservative as they do not account for the impact of the highly dynamic conditions downhole. While logging provided an independent view of the condition of the tubing and casing, no inspection of the x-mas tree cavity was carried out. An opportunity to close this gap and obtain information on the internal condition of the x-mas tree body is presented to Field X with the abandonment campaign on two idle wells in quarter three of 2021. The x-mas tree was retrieved, and internal inspection was conducted. The same is done for retrieved tubing from the abandoned wells. This study and its findings will enhance understanding on well design life, especially for vintage wells of over 30 years and provide assurance that wells are safe to produce.
{"title":"Understanding the Impact of Corrosion on Gas Wells Past its Design Life","authors":"Hanani Zaidil, Sim-Siong Wong","doi":"10.4043/31456-ms","DOIUrl":"https://doi.org/10.4043/31456-ms","url":null,"abstract":"\u0000 Field X produces dry gas from a carbonate reservoir with moderate aquifer support consisting of 16 wells most of which were drilled between 1986 to 1987. Up until 2021, these wells would have been in service for approximately 35 years, past its theoretical design life. Based on production forecast, the field is expected to continue producing for another 10 to 18 years. In view of the prolonged life extension, there is a need to review the integrity status of the well to ensure safe production until the end of field life. Wellhead preventive maintenance are conducted on a six-monthly basis to assure safety critical equipment (SCE) functionality and performance. Maintenance data collected since 2008 provides a good view on surface and subsurface valve integrity.\u0000 In recent years, observations on external corrosion have received some attention. At the same time, there were efforts in determining and verifying the corrosion rates for production tubing, wellhead and x-mas tree. For well tubing and production casing, load based assumptions were used to estimate the minimum allowable tubular thickness to establish a basis for remaining life estimates. To verify the remaining life estimates, in 2019, a multi-finger caliper log was ran across the tubing of Well B to measure actual metal loss around the pipe. A magnetic log was also run in Well B in the same year to obtain quantitative measurement of remaining metal thickness in 13-3/8\", 9-5/8\" and 7\" tubing. The observations from these exercises indicate that calculated estimates are more conservative as they do not account for the impact of the highly dynamic conditions downhole. While logging provided an independent view of the condition of the tubing and casing, no inspection of the x-mas tree cavity was carried out. An opportunity to close this gap and obtain information on the internal condition of the x-mas tree body is presented to Field X with the abandonment campaign on two idle wells in quarter three of 2021. The x-mas tree was retrieved, and internal inspection was conducted. The same is done for retrieved tubing from the abandoned wells.\u0000 This study and its findings will enhance understanding on well design life, especially for vintage wells of over 30 years and provide assurance that wells are safe to produce.","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"34 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88879177","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}
P. Chongrueanglap, W. Siriwattanakajorn, M. K. Hamdan, K. Poret, Thanutpong Soontornnateepat, Sirichai Mahamat, Khuananong Wongpaet, Y. P. Cheong
This paper focuses on the challenges in building representative 3D static models under all subsurface uncertainties for a green field. The case study is based on a giant carbonate gas field, appraised with a few partially penetrated wells in Central Luconia province, offshore Sarawak, Malaysia. With very limited hard data for reservoir characterization, knowledge from Central Luconia literature and nearby field analogues had to be used together with the 3D seismic data. Standard geostatistical methodology was used to integrate the subsurface interpretations and to capture the identified subsurface uncertainties, i.e., structural framework, fluid contacts, facies distribution, petrophysical interpretations, saturation function, permeability prediction etc. Some of the key challenges, findings and results are listed below; How to quantify a long list of subsurface uncertainties with a manageable number of 3D static models? Full factorial design was used together with expert knowledge to limit the total number of uncertainties. How to quantify the structural uncertainty and the challenge in building geocellular grid for carbonate platform and pinnacle buildup? Even with very limited core data, the lithofacies interpretation was completed and incorporate 3D seismic data as representative 3D trend for distributing the expected carbonate facies. It is a massive challenge in characterizing the petrophysical properties for carbonate reservoirs, as heterogeneity (both primary and secondary processes) can be difficult to predict. Similar porosity seen in seismic inversion might have different flow behavior in permeability. Sub-seismic geological features like flooding surfaces might be acting as vertical baffles, which must be modelled as an important element of the geostatistical models. Reservoir characterization and uncertainty quantification will allow an improved understanding of the reservoir, and the results will guide the data acquisition program in subsequent appraisal campaign. This case study will enrich the knowledge within the Central Luconia carbonate province, and a discovery in a mature basin is still a massive challenge for reservoir characterization under uncertainties.
{"title":"Challenges on Building Representative 3D Static Models under Subsurface Uncertainties for a Giant Carbonate Field in Central Luconia, Offshore Sarawak","authors":"P. Chongrueanglap, W. Siriwattanakajorn, M. K. Hamdan, K. Poret, Thanutpong Soontornnateepat, Sirichai Mahamat, Khuananong Wongpaet, Y. P. Cheong","doi":"10.4043/31341-ms","DOIUrl":"https://doi.org/10.4043/31341-ms","url":null,"abstract":"\u0000 This paper focuses on the challenges in building representative 3D static models under all subsurface uncertainties for a green field. The case study is based on a giant carbonate gas field, appraised with a few partially penetrated wells in Central Luconia province, offshore Sarawak, Malaysia. With very limited hard data for reservoir characterization, knowledge from Central Luconia literature and nearby field analogues had to be used together with the 3D seismic data. Standard geostatistical methodology was used to integrate the subsurface interpretations and to capture the identified subsurface uncertainties, i.e., structural framework, fluid contacts, facies distribution, petrophysical interpretations, saturation function, permeability prediction etc.\u0000 Some of the key challenges, findings and results are listed below;\u0000 How to quantify a long list of subsurface uncertainties with a manageable number of 3D static models? Full factorial design was used together with expert knowledge to limit the total number of uncertainties. How to quantify the structural uncertainty and the challenge in building geocellular grid for carbonate platform and pinnacle buildup? Even with very limited core data, the lithofacies interpretation was completed and incorporate 3D seismic data as representative 3D trend for distributing the expected carbonate facies. It is a massive challenge in characterizing the petrophysical properties for carbonate reservoirs, as heterogeneity (both primary and secondary processes) can be difficult to predict. Similar porosity seen in seismic inversion might have different flow behavior in permeability. Sub-seismic geological features like flooding surfaces might be acting as vertical baffles, which must be modelled as an important element of the geostatistical models. Reservoir characterization and uncertainty quantification will allow an improved understanding of the reservoir, and the results will guide the data acquisition program in subsequent appraisal campaign.\u0000 This case study will enrich the knowledge within the Central Luconia carbonate province, and a discovery in a mature basin is still a massive challenge for reservoir characterization under uncertainties.","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"55 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83891026","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}
Nicholas Moses, E. Ismayilov, Edwin Newn, Emmanuel Mogga, Chunlei Zou, Jeremie Poizat, Gordon Milne, I. Sanni, Stewart Thomson, Blayne Haubrich
The operator of field S initiated a project with a key objective to unlock and increase oil recovery while maximizing the economical oil ultimate recovery and maintaining a daily production with a ceiling unit development cost. The targeted sandstone reservoirs are shallow with unconsolidated formation which require active sand control. To achieve the objectives, a Single Trip Sand Control and Cementing System was developed by the service provider utilizing existing proven technology which was adapted to be a fit for purpose solution. The main driver in developing the single trip system was operational simplicity. The high-level procedure of the system is: Drill open hole from surface to target depth in a single run. Make up lower completion assembly and production casing and run to target depth. In the same trip, set production packer and release service string. Gravel pack the lower completion or install as a stand-alone screens completion and cement the production casing in place before pulling out of hole. Once the single trip system was designed and developed, a detailed system integration testing was carried out to ensure that the technology performed as expected. The turnaround time from design to execution was reduced tremendously by utilizing existing proven technology with minimal modification required. From there, 2 wells were identified for a pilot technology trial where this novel system was implemented. The execution of these 2 wells was successful with the expected learning curve of implementing a new system. One of the key findings were the robustness of the system as it was applied in a well with higher than normal doglegs, highly deviated shallow reservoir and the sand screens were run through extended open hole shale sections which would have been cased off in a conventional completion approach. Additionally, the single trip approach allows for further optimization with multi-skilling personnel, and this led to an improved operational efficiency. Post well completion, the 2 wells have been successfully put on production and are producing sand free. This unconventional approach can unlock more marginal reserves that were previously not feasible to be developed economically.
{"title":"Single Trip Sand Control and Cementing System","authors":"Nicholas Moses, E. Ismayilov, Edwin Newn, Emmanuel Mogga, Chunlei Zou, Jeremie Poizat, Gordon Milne, I. Sanni, Stewart Thomson, Blayne Haubrich","doi":"10.4043/31431-ms","DOIUrl":"https://doi.org/10.4043/31431-ms","url":null,"abstract":"\u0000 The operator of field S initiated a project with a key objective to unlock and increase oil recovery while maximizing the economical oil ultimate recovery and maintaining a daily production with a ceiling unit development cost. The targeted sandstone reservoirs are shallow with unconsolidated formation which require active sand control. To achieve the objectives, a Single Trip Sand Control and Cementing System was developed by the service provider utilizing existing proven technology which was adapted to be a fit for purpose solution. The main driver in developing the single trip system was operational simplicity. The high-level procedure of the system is:\u0000 Drill open hole from surface to target depth in a single run. Make up lower completion assembly and production casing and run to target depth. In the same trip, set production packer and release service string. Gravel pack the lower completion or install as a stand-alone screens completion and cement the production casing in place before pulling out of hole.\u0000 Once the single trip system was designed and developed, a detailed system integration testing was carried out to ensure that the technology performed as expected. The turnaround time from design to execution was reduced tremendously by utilizing existing proven technology with minimal modification required. From there, 2 wells were identified for a pilot technology trial where this novel system was implemented. The execution of these 2 wells was successful with the expected learning curve of implementing a new system. One of the key findings were the robustness of the system as it was applied in a well with higher than normal doglegs, highly deviated shallow reservoir and the sand screens were run through extended open hole shale sections which would have been cased off in a conventional completion approach. Additionally, the single trip approach allows for further optimization with multi-skilling personnel, and this led to an improved operational efficiency. Post well completion, the 2 wells have been successfully put on production and are producing sand free. This unconventional approach can unlock more marginal reserves that were previously not feasible to be developed economically.","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"225 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74638702","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. R. Farrell, Andrew C. Ewing, D. Frigo, G. Graham
It is widely accepted that live crude oil samples provide the most field representative fluids when investigating asphaltenes and paraffin wax problems in laboratory testing. However, this approach is limited by availability of live samples and the potential that samples collected during drilling will be insufficiently representative due to contamination. This paper demonstrates that re-livened oil comprising dead oil and just 1 or 2 solvents can be an acceptable replacement where live oil of sufficient quality is not available. We outline a best-of-both approach: using readily available dead oil but replacing the volatile ends with components that reproduce much of the solvating and phase behaviour of live oil, and where they differ from it, they do so in a predictable manner, which can be readily modelled using an equation of state (EoS) simulator. This avoids the expense and time required to restore the oil to a precise replica of live fluid while still generating laboratory data to increase confidence in predictions for the actual live oil composition generated by the EoS software. Illustrative examples are given to demonstrate different ways in which re-livened oil can be designed to mimic key features of live oil behaviour, and any differences can be modelled. Wax appearance measurements were made for re-livened oil and used to calibrate an EoS model. When used to simulate data for a live oil, the calibrated model gave excellent agreement with field data. Subsequently, deposition tests were carried out with re-livened oil and used to qualify a wax inhibitor for subsea application. Measurement of the Asphaltenes Onset Pressure (AOP) for re-livened oil was used to tune the EoS model for the analogous live oil, yielding predictions of the asphaltenes precipitation envelope (APE) that were consistent with those obtained using the live oil. This illustrates that live oil may not always be necessary to obtain a reliable APE, especially when the only live oil samples are of questionable quality. Solubility theory was applied to the selection of conditions for asphaltenes flow-loop deposition, wherein a precipitant is added to dead oil to induce deposition. This approach can determine both the identity and correct proportion of a suitable precipitant to simulate conditions close to the bubble point where deposition commonly occurs. Our work shows how experimental results (both laboratory and field) were used to validate the methodology presented here. The findings of our work will lead to significant cost-savings in performing both flow assurance risk assessments and inhibitor qualification. Rather than going to the significant expense and operational difficulty and risk of collecting and transporting live samples, such screenings can be performed on re-livened fluids that are both field representative and cost-effective.
{"title":"Flow Assurance Testing with Re-Livened Oil: A Cost-Effective Analogue for Live Oil","authors":"A. R. Farrell, Andrew C. Ewing, D. Frigo, G. Graham","doi":"10.4043/31416-ms","DOIUrl":"https://doi.org/10.4043/31416-ms","url":null,"abstract":"\u0000 It is widely accepted that live crude oil samples provide the most field representative fluids when investigating asphaltenes and paraffin wax problems in laboratory testing. However, this approach is limited by availability of live samples and the potential that samples collected during drilling will be insufficiently representative due to contamination. This paper demonstrates that re-livened oil comprising dead oil and just 1 or 2 solvents can be an acceptable replacement where live oil of sufficient quality is not available.\u0000 We outline a best-of-both approach: using readily available dead oil but replacing the volatile ends with components that reproduce much of the solvating and phase behaviour of live oil, and where they differ from it, they do so in a predictable manner, which can be readily modelled using an equation of state (EoS) simulator. This avoids the expense and time required to restore the oil to a precise replica of live fluid while still generating laboratory data to increase confidence in predictions for the actual live oil composition generated by the EoS software.\u0000 Illustrative examples are given to demonstrate different ways in which re-livened oil can be designed to mimic key features of live oil behaviour, and any differences can be modelled. Wax appearance measurements were made for re-livened oil and used to calibrate an EoS model. When used to simulate data for a live oil, the calibrated model gave excellent agreement with field data. Subsequently, deposition tests were carried out with re-livened oil and used to qualify a wax inhibitor for subsea application. Measurement of the Asphaltenes Onset Pressure (AOP) for re-livened oil was used to tune the EoS model for the analogous live oil, yielding predictions of the asphaltenes precipitation envelope (APE) that were consistent with those obtained using the live oil. This illustrates that live oil may not always be necessary to obtain a reliable APE, especially when the only live oil samples are of questionable quality. Solubility theory was applied to the selection of conditions for asphaltenes flow-loop deposition, wherein a precipitant is added to dead oil to induce deposition. This approach can determine both the identity and correct proportion of a suitable precipitant to simulate conditions close to the bubble point where deposition commonly occurs.\u0000 Our work shows how experimental results (both laboratory and field) were used to validate the methodology presented here. The findings of our work will lead to significant cost-savings in performing both flow assurance risk assessments and inhibitor qualification. Rather than going to the significant expense and operational difficulty and risk of collecting and transporting live samples, such screenings can be performed on re-livened fluids that are both field representative and cost-effective.","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78169880","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}
Siva Kumaran Chidambram, Jinyong Tan, Mohd Amaluddin Yusoff, June Janesby Roy Jihok
The current gas turbine performance monitoring infrastructure in Shell Malaysia yields inaccuracies of ±15% with no links towards emissions and fuel economics. This has resulted in severe limitations towards the ability to improve greenhouse gas (GHG) performance and generate value. This paper describes a novel, data centric approach to derive meaningful insights and economics/carbon savings from existing data on Plant Information (PI) and SMART CONNECT, a Shell in house performance management IT tool. This project applies advanced analytics techniques based on historical data, supplemented by engineering performance models to derive robust outcomes. First, gas turbine and compressor modelling principles are programmed in Python and validated with engineering software such as UNISIM based on available operating data via PI. This yields a multivariate dataset tabulating the historical efficiency, power and fuel gas consumption of the fleet. The model is then utilized in a mathematical optimization algorithm and the optimized data used for training and validation of a Random Forest Regressor model. The performance model in Python is able to achieve accuracies of <1% absolute error when validated with UMSFM on the key performance parameters. Through parametric optimization, the Mean Squared Error (MSE) of the gas turbine and compressor powers is reduced to 0.55MW2 from its original 4.94MW2. The Heat Rate, Shaft Power, and gas generator exit pressures are also identified as the variables most correlated with efficiency. Lastly, the trained machine learning model demonstrated agreement with the dataset during testing, with a R2 value of 0.86 reflecting a strong correlation. With a predictive digital model in place, production programmers can accurately identify the key levers to optimize the machine operating point for optimum fuel gas consumption. Optimizing Gumusut Kakap's high pressure compressors can yield 62,400 USD in savings per annum from increased sales gas and and 880 tCO2e per annum of reduction in GHG emissions, for every 1% increase in efficiency. This approach is a novel concept, leveraging on expertise from both engineering and data science to enhance equipment performance, and can be replicated towards other types of equipment to achieve efficiency, economic and emissions improvements at scale.
{"title":"Predictive Analytics for Gas Turbine Driven Trains to Achieve Optimum Performance, Economics and Greenhouse Gas Emissions","authors":"Siva Kumaran Chidambram, Jinyong Tan, Mohd Amaluddin Yusoff, June Janesby Roy Jihok","doi":"10.4043/31489-ms","DOIUrl":"https://doi.org/10.4043/31489-ms","url":null,"abstract":"\u0000 The current gas turbine performance monitoring infrastructure in Shell Malaysia yields inaccuracies of ±15% with no links towards emissions and fuel economics. This has resulted in severe limitations towards the ability to improve greenhouse gas (GHG) performance and generate value. This paper describes a novel, data centric approach to derive meaningful insights and economics/carbon savings from existing data on Plant Information (PI) and SMART CONNECT, a Shell in house performance management IT tool.\u0000 This project applies advanced analytics techniques based on historical data, supplemented by engineering performance models to derive robust outcomes. First, gas turbine and compressor modelling principles are programmed in Python and validated with engineering software such as UNISIM based on available operating data via PI. This yields a multivariate dataset tabulating the historical efficiency, power and fuel gas consumption of the fleet. The model is then utilized in a mathematical optimization algorithm and the optimized data used for training and validation of a Random Forest Regressor model.\u0000 The performance model in Python is able to achieve accuracies of <1% absolute error when validated with UMSFM on the key performance parameters. Through parametric optimization, the Mean Squared Error (MSE) of the gas turbine and compressor powers is reduced to 0.55MW2 from its original 4.94MW2. The Heat Rate, Shaft Power, and gas generator exit pressures are also identified as the variables most correlated with efficiency. Lastly, the trained machine learning model demonstrated agreement with the dataset during testing, with a R2 value of 0.86 reflecting a strong correlation.\u0000 With a predictive digital model in place, production programmers can accurately identify the key levers to optimize the machine operating point for optimum fuel gas consumption. Optimizing Gumusut Kakap's high pressure compressors can yield 62,400 USD in savings per annum from increased sales gas and and 880 tCO2e per annum of reduction in GHG emissions, for every 1% increase in efficiency. This approach is a novel concept, leveraging on expertise from both engineering and data science to enhance equipment performance, and can be replicated towards other types of equipment to achieve efficiency, economic and emissions improvements at scale.","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"61 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80605350","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
K. Poret, A. Saller, P. Henglai, K. Laitrakull, P. Chongrueanglap, W. Siriwattanakajorn, Platt Chris
Miocene carbonates have been producing gas in Central Luconia for more than 30 years (Warrlich et al., 2019). Approximately 65 TCF of recoverable gas have been discovered to date in these build-ups (Scherer, 1980; Mahmud and Saleh, 1999; Khazali et al., 2013; Kosa et al., 2015; Warrlich et al., 2019). One of the most recent carbonate discoveries in this region, Field X, is in its early-stage of reservoir characterization. Depositional and facies models have been created with newly acquired data from LL-C appraisal well. Tectonics, accommodation, and sea level contributed to the overall shape and deposition of the carbonate buildup. One appraisal well, LL-C was drilled and penetrated a thick carbonate section on the structure. With the available data, facies and conceptual depositional models were created using well logs, sidewall cores, conventional cores, cuttings, seismic, and an extensive literature review. At the time of this study, core laboratory analyses were not yet completed. The reservoir is separated into five zones based on well log, core, and seismic data. A precursory facies model was completed using only photographs from the sidewall cores acquired in all five zones of the structure and photographs from conventional core acquired in the upper reservoir interval. Five facies were identified: Coral, Packstone, Wackestone, Mudstone, and Cemented Margin. The data acquired in LL-C illustrates the complexity of carbonate reservoirs and the need to acquire core early in the appraisal of carbonate reservoirs.
中新世碳酸盐已经在中央卢科尼亚生产了30多年的天然气(Warrlich et al.， 2019)。迄今为止，在这些堆积中已发现约65万亿立方英尺的可采天然气(Scherer, 1980;Mahmud and Saleh, 1999;Khazali et al.， 2013;Kosa et al.， 2015;Warrlich et al.， 2019)。该地区最近发现的碳酸盐岩之一X油田正处于储层表征的早期阶段。利用LL-C评价井新获得的资料建立了沉积相模型。构造、调节和海平面对碳酸盐堆积的整体形状和沉积有影响。其中一口评价井LL-C在该构造上钻穿了一层较厚的碳酸盐岩剖面。根据现有数据，通过测井、侧壁岩心、常规岩心、岩屑、地震和广泛的文献回顾，建立了相和概念沉积模型。在本研究进行时，核心实验室分析尚未完成。根据测井、岩心和地震数据，将储层划分为五个区域。仅使用在该构造的所有五个区域获得的侧壁岩心照片和在上部储层段获得的常规岩心照片，就完成了前兆相模型。确定了五种相:珊瑚相、包岩相、瓦克岩相、泥岩相和胶结边缘相。LL-C储层获得的数据说明了碳酸盐岩储层的复杂性以及在碳酸盐岩储层评价中早期获取岩心的必要性。
{"title":"Field X, Central Luconia, Offshore Sarawak, Malaysia, Early Appraisal Stage Reservoir Characterization","authors":"K. Poret, A. Saller, P. Henglai, K. Laitrakull, P. Chongrueanglap, W. Siriwattanakajorn, Platt Chris","doi":"10.4043/31515-ms","DOIUrl":"https://doi.org/10.4043/31515-ms","url":null,"abstract":"\u0000 Miocene carbonates have been producing gas in Central Luconia for more than 30 years (Warrlich et al., 2019). Approximately 65 TCF of recoverable gas have been discovered to date in these build-ups (Scherer, 1980; Mahmud and Saleh, 1999; Khazali et al., 2013; Kosa et al., 2015; Warrlich et al., 2019). One of the most recent carbonate discoveries in this region, Field X, is in its early-stage of reservoir characterization. Depositional and facies models have been created with newly acquired data from LL-C appraisal well.\u0000 Tectonics, accommodation, and sea level contributed to the overall shape and deposition of the carbonate buildup. One appraisal well, LL-C was drilled and penetrated a thick carbonate section on the structure. With the available data, facies and conceptual depositional models were created using well logs, sidewall cores, conventional cores, cuttings, seismic, and an extensive literature review. At the time of this study, core laboratory analyses were not yet completed. The reservoir is separated into five zones based on well log, core, and seismic data. A precursory facies model was completed using only photographs from the sidewall cores acquired in all five zones of the structure and photographs from conventional core acquired in the upper reservoir interval. Five facies were identified: Coral, Packstone, Wackestone, Mudstone, and Cemented Margin. The data acquired in LL-C illustrates the complexity of carbonate reservoirs and the need to acquire core early in the appraisal of carbonate reservoirs.","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"12 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80251053","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}
Salu A. Samusideen, Mohammed Abdo Alwani, A. Kurdi
The objective of this paper is to show five innovative options of operating the hydrate inhibition system which aims to eliminate future wet natural gas production limitations and optimize capital and operation expenses during a 25-year life cycle period. Mono-Ethylene Glycol (MEG) is injected in wet natural gas trunk lines from an offshore gas field, as a means of hydrate inhibition during the winter season. The used MEG is supposed to be recovered in MEG Regeneration Unit (MRU) at onshore gas plant, where the wet natural gas is further processed. The MRU often faces challenges in producing to achieve specified MEG purity, which consequently results in injecting a diluted solution of MEG into the offshore systems, and thereby lowering the maximum allowable production capacity of wet natural gas. This paper describes the study in five different options. Option 1 represents the current operating scenario of maintaining the existing system with MRU in service, while option 2 explores shutting down MRU at onshore gas plant, and pumping fresh MEG during winter days from the gas plant to the offshore platforms. Option 3 explores shutting down MRU at the gas plant and pumping fresh MEG during winter days, but from a Beach Valve Station (BVS) at an onshore location. Option 4 explores maintaining the existing system with MRU in service and upgrade the storage tanks to address the unsteady state nature of rich MEG flow. Option 5 explores pumping lean MEG during winter days from the gas plant, storing rich MEG in tanks for MEG regeneration and reclaiming MEG through the existing system during the summer including storing lean MEG in tanks for winter usage. The evaluation has shown that options 2 and 3 can easily meet the required hydrate depression specification during winter period, at far lower MEG injection rates and at a substantially lower life cycle cost (LCC) compared to option 1. The evaluation also showed that options 4 and 5 will ensure MRU operation not interrupted due to low-low levels in MEG storage tanks and will maintain high purity MEG in the trunk lines, which is different from option 1. In conclusion, option 5 has the lowest LCC which is the most economically attractive option.
{"title":"Effective Mono Ethylene Glycol Meg Injection Optimisation at Offshore Gas Platform Facility: A Novel Case Study for Hydrate Control During Summer and Winter Operation","authors":"Salu A. Samusideen, Mohammed Abdo Alwani, A. Kurdi","doi":"10.4043/31393-ms","DOIUrl":"https://doi.org/10.4043/31393-ms","url":null,"abstract":"\u0000 The objective of this paper is to show five innovative options of operating the hydrate inhibition system which aims to eliminate future wet natural gas production limitations and optimize capital and operation expenses during a 25-year life cycle period.\u0000 Mono-Ethylene Glycol (MEG) is injected in wet natural gas trunk lines from an offshore gas field, as a means of hydrate inhibition during the winter season. The used MEG is supposed to be recovered in MEG Regeneration Unit (MRU) at onshore gas plant, where the wet natural gas is further processed. The MRU often faces challenges in producing to achieve specified MEG purity, which consequently results in injecting a diluted solution of MEG into the offshore systems, and thereby lowering the maximum allowable production capacity of wet natural gas.\u0000 This paper describes the study in five different options. Option 1 represents the current operating scenario of maintaining the existing system with MRU in service, while option 2 explores shutting down MRU at onshore gas plant, and pumping fresh MEG during winter days from the gas plant to the offshore platforms. Option 3 explores shutting down MRU at the gas plant and pumping fresh MEG during winter days, but from a Beach Valve Station (BVS) at an onshore location. Option 4 explores maintaining the existing system with MRU in service and upgrade the storage tanks to address the unsteady state nature of rich MEG flow. Option 5 explores pumping lean MEG during winter days from the gas plant, storing rich MEG in tanks for MEG regeneration and reclaiming MEG through the existing system during the summer including storing lean MEG in tanks for winter usage.\u0000 The evaluation has shown that options 2 and 3 can easily meet the required hydrate depression specification during winter period, at far lower MEG injection rates and at a substantially lower life cycle cost (LCC) compared to option 1. The evaluation also showed that options 4 and 5 will ensure MRU operation not interrupted due to low-low levels in MEG storage tanks and will maintain high purity MEG in the trunk lines, which is different from option 1. In conclusion, option 5 has the lowest LCC which is the most economically attractive option.","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"51 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78268491","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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