Hashil Nasser Said Al Naabi, A. A. Hinai, Anwar Adawi, H. Kiyumi, Mohammed Ali Khalfan Al Aghbari, M. Abri, Ibrahim Hamed Ali Al Suleimani, Naser Mohammed Nasser Al Busaidi, Mahmood Ahmed Nasser Al Humaimi, H. Youssef
This paper discusses the continuous improvement in Khulud field, the most challenging field in Sultanate of Oman in terms of high pressure and high temperature. A paper (SPE-188629-MS) was published in 2017 under the title of " Achieving a Step Change in Well Duration and Cost in a HPHT Tight Gas Field" which explained many improvements in different areas including (10k cemented completion and degraded mud, operational optimization and efficiency, slim design). However, in this paper, the focus will be on 15k cemented completion, which was a challenge in that time for both designs (fat and slim). Thus, the new improvement is mainly in well design, which led to significant reduction in well delivery cost and time for 15k wells. Drilling and completing very tight HPHT deep Gas well can be very challenging. The risk of losing the well is real due to challenges related to liner hanger system failures that have been experienced several times within the field. In addition, stuck pipe risk of cleanout assembly prior to running liner top completion is another serious challenge that had led to abandoning a few wells in the past. Cemented completion for 15K well is one of the challenges mentioned in the SPE-188629-MS paper in Khulud field. Production casing is not strong enough to handle hot kill load in case completion tubing leaks and as well is not designed for full gas displacement. In addition, many failures were encountered with liner hanger system, which compromises well delivery in some cases. To overcome such challenges and reduce well delivery time and cost, PDO initiated new well designs to cater for 15k cemented completion for both fat and slim applications. Advantages and disadvantages of cemented completion for both designs will be discussed in this paper. In fat design, production casing was upgraded to higher weight and grade. 7 in casing was eliminated as the new production casing is good enough to handle hot kill load in case tubing leak happens. In slim design, ECD and high surface pressure are the main concerns. The team managed to simulate, optimize ECD for different scenarios and mitigate high surface pressure. All Risks and associated consequences were captured. A mitigation plan was developed. Future improved design has been evaluated but not approved yet which will drive cost reduction and operational efficiency.
{"title":"New PDO Improved Well Design 15K Cemented Completion to Successfully Deliver Faster and Cheaper Complex Deep Gas HPHT Wells","authors":"Hashil Nasser Said Al Naabi, A. A. Hinai, Anwar Adawi, H. Kiyumi, Mohammed Ali Khalfan Al Aghbari, M. Abri, Ibrahim Hamed Ali Al Suleimani, Naser Mohammed Nasser Al Busaidi, Mahmood Ahmed Nasser Al Humaimi, H. Youssef","doi":"10.2118/197207-ms","DOIUrl":"https://doi.org/10.2118/197207-ms","url":null,"abstract":"\u0000 This paper discusses the continuous improvement in Khulud field, the most challenging field in Sultanate of Oman in terms of high pressure and high temperature. A paper (SPE-188629-MS) was published in 2017 under the title of \" Achieving a Step Change in Well Duration and Cost in a HPHT Tight Gas Field\" which explained many improvements in different areas including (10k cemented completion and degraded mud, operational optimization and efficiency, slim design). However, in this paper, the focus will be on 15k cemented completion, which was a challenge in that time for both designs (fat and slim). Thus, the new improvement is mainly in well design, which led to significant reduction in well delivery cost and time for 15k wells.\u0000 Drilling and completing very tight HPHT deep Gas well can be very challenging. The risk of losing the well is real due to challenges related to liner hanger system failures that have been experienced several times within the field. In addition, stuck pipe risk of cleanout assembly prior to running liner top completion is another serious challenge that had led to abandoning a few wells in the past.\u0000 Cemented completion for 15K well is one of the challenges mentioned in the SPE-188629-MS paper in Khulud field. Production casing is not strong enough to handle hot kill load in case completion tubing leaks and as well is not designed for full gas displacement. In addition, many failures were encountered with liner hanger system, which compromises well delivery in some cases. To overcome such challenges and reduce well delivery time and cost, PDO initiated new well designs to cater for 15k cemented completion for both fat and slim applications. Advantages and disadvantages of cemented completion for both designs will be discussed in this paper.\u0000 In fat design, production casing was upgraded to higher weight and grade. 7 in casing was eliminated as the new production casing is good enough to handle hot kill load in case tubing leak happens.\u0000 In slim design, ECD and high surface pressure are the main concerns. The team managed to simulate, optimize ECD for different scenarios and mitigate high surface pressure. All Risks and associated consequences were captured. A mitigation plan was developed. Future improved design has been evaluated but not approved yet which will drive cost reduction and operational efficiency.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"28 3 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88063752","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. Hassan, Ahmed Rashed Alaleeli, Ahmedagha Hamidzada, A. J. D. Barros, Yousif Al Katheeri, Fatima Bin Tarsh, G. Aliyeva
It is common to be faced with severe losses prior to cementing the 9 5-8 in. intermediate casing in an offshore field in UAE. Intermediate casing covers weak zones and as a results there is always a high risk of formation breakdown and induced losses while running the casing and before it reaches intended setting point. The average losses experienced during drilling the 12 1-4 in. hole may exceed 100 BPH. The main challenge in the case reviewed in this paper was that the formation was fracturing during casing running, compromising ability to achieve proper zonal isolation and successful cement job execution. To address the challenge a special LCM Spacer system was proposed, designed to minimize or eliminate the losses during the primary cement job by offering superior sealing capabilities. This LCM Spacer system can easily mitigate loss circulation while cementing, based on ultra-low invasion technology forming a barrier across loss zones. It creates a film across formation walls and reduces the loss circulation ranging from partial to total losses on permeable, fragile, weak formation, natural fractures and depleted reservoirs. It also improves wellbore stability and ECD’s along the wellbore and expected loss zones. The LCM Spacer system was designed and implemented based on the well conditions, design guidelines and previously recorded global success of the system applied in similar applications.
{"title":"Advanced Loss Circulation Spacer System in UAE Enables Successful Cementation of 9 5/8\" Casing and Required Zonal Isolation during Severe Losses","authors":"A. Hassan, Ahmed Rashed Alaleeli, Ahmedagha Hamidzada, A. J. D. Barros, Yousif Al Katheeri, Fatima Bin Tarsh, G. Aliyeva","doi":"10.2118/197618-ms","DOIUrl":"https://doi.org/10.2118/197618-ms","url":null,"abstract":"\u0000 It is common to be faced with severe losses prior to cementing the 9 5-8 in. intermediate casing in an offshore field in UAE. Intermediate casing covers weak zones and as a results there is always a high risk of formation breakdown and induced losses while running the casing and before it reaches intended setting point. The average losses experienced during drilling the 12 1-4 in. hole may exceed 100 BPH.\u0000 The main challenge in the case reviewed in this paper was that the formation was fracturing during casing running, compromising ability to achieve proper zonal isolation and successful cement job execution.\u0000 To address the challenge a special LCM Spacer system was proposed, designed to minimize or eliminate the losses during the primary cement job by offering superior sealing capabilities. This LCM Spacer system can easily mitigate loss circulation while cementing, based on ultra-low invasion technology forming a barrier across loss zones. It creates a film across formation walls and reduces the loss circulation ranging from partial to total losses on permeable, fragile, weak formation, natural fractures and depleted reservoirs. It also improves wellbore stability and ECD’s along the wellbore and expected loss zones.\u0000 The LCM Spacer system was designed and implemented based on the well conditions, design guidelines and previously recorded global success of the system applied in similar applications.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"31 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84621512","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}
Mubashir Ahmad Mubashir, Fawad Zain Yousfi, M. Albadi, M. Baslaib, O. A. Jeelani, Amna Yaaqob Khamis Salem Aladsani, S. Alhouqani, Salah Al Qallabi, I. Bankole, Fawzi Omar Al Jaberi, Ashim Dutta, A. Shahat, Jose Alejandro Aranda, Rami Jibreel, Ghada Matar Ali, Anubhav Agarwal, Yohannes Fisher Pangestu, Rahul Kumar, A. Jaiyeola, A. Yugay, G. Pimenta, R. Masoud, Rohit V. Deshmukh, Hessa Al Shehhi, Fares Al Belooshi, Viswasri Pendyala, C. Mandal
ADNOC onshore tested HPHT sour gas reservoirs with 30% H2S, 10% CO2 to evaluate the reservoir and well potential as part of the efforts in supplying additional gas for meeting country's growing energy needs. Developing these massive HPHT sour gas reservoirs is essential for providing a sustainable source of energy for years to come. This critical project serves the broader national strategy and country aspirations in fulfilling the gas demand over the next few decades to come. Few HPHT sour wells were drilled but only one well could be tested successfully. The other two wells had to be suspended due to HSE /environmental and operational reason as elemental Sulphur was detected. Based on the previous well test and reservoir data, it was decided to use one of the existing well and sidetrack in the Sour reservoir to gain experience about drilling a long horizontal section in the High pressure, high temperature sour condition. A specialized drilling Rig capable of drilling the long horizontal well was selected. Due to nature of the reservoir, specialized sour service drilling tools were selected considered the long departure and long open hole horizontal length of 10000+ ft. Selection of the downhole material for these conditions was itself a challenge as very few vendors or IOC (Internatioanl oil companies) have experience of developing and producing from +30% H2S and +10% CO2. Due to the location of the well, stringent HSE measurements were adapter to ensure zero tolerance for the safety violation in accordance with 100% HSE. The testing of the HPHT sour gas was challenging due to not only HSE issues but also from the environment part too as flaring needed to be minimized in the brown field. Hence, it was decided to Tie-in the well to the nearby facilities. The challenge was that the existing facilities were not design to accept the sour gas. This was overcome by blending the sour gas with sweet gas to meet the existing facilities specs and capacities. After the well was drilled, the +10000 ft. open hole was flowed to clean to ensure all the drilling fluid lost was recovered to test to access well potential and obtain representative data for full field development plan. Drilling, testing and producing the highly sour HPHT gas reservoirs with more than 30% H2S and 10% CO2 along with temperature ranging up to 300 deg F is itself a huge challenge. Over the last few years, ADNOC Onshore have developed considerable expertise in testing the sour wells considering all the safety and environmental aspects. This paper highlights the work progress and the lessons learned during each step of the operation from planning phase to drilling, tie-in the well to the existing facilities after dilution during testing. All the proposed mitigation plans considering 100% HSE while dealing with these appraisal wells in the Arab sour reservoir having +30% H2S and 10 % CO2 were developed and implemented sucessfully.
{"title":"Sour Gas Well Testing Challenges-A Successful Case Study","authors":"Mubashir Ahmad Mubashir, Fawad Zain Yousfi, M. Albadi, M. Baslaib, O. A. Jeelani, Amna Yaaqob Khamis Salem Aladsani, S. Alhouqani, Salah Al Qallabi, I. Bankole, Fawzi Omar Al Jaberi, Ashim Dutta, A. Shahat, Jose Alejandro Aranda, Rami Jibreel, Ghada Matar Ali, Anubhav Agarwal, Yohannes Fisher Pangestu, Rahul Kumar, A. Jaiyeola, A. Yugay, G. Pimenta, R. Masoud, Rohit V. Deshmukh, Hessa Al Shehhi, Fares Al Belooshi, Viswasri Pendyala, C. Mandal","doi":"10.2118/197482-ms","DOIUrl":"https://doi.org/10.2118/197482-ms","url":null,"abstract":"\u0000 ADNOC onshore tested HPHT sour gas reservoirs with 30% H2S, 10% CO2 to evaluate the reservoir and well potential as part of the efforts in supplying additional gas for meeting country's growing energy needs. Developing these massive HPHT sour gas reservoirs is essential for providing a sustainable source of energy for years to come.\u0000 This critical project serves the broader national strategy and country aspirations in fulfilling the gas demand over the next few decades to come.\u0000 Few HPHT sour wells were drilled but only one well could be tested successfully. The other two wells had to be suspended due to HSE /environmental and operational reason as elemental Sulphur was detected.\u0000 Based on the previous well test and reservoir data, it was decided to use one of the existing well and sidetrack in the Sour reservoir to gain experience about drilling a long horizontal section in the High pressure, high temperature sour condition. A specialized drilling Rig capable of drilling the long horizontal well was selected. Due to nature of the reservoir, specialized sour service drilling tools were selected considered the long departure and long open hole horizontal length of 10000+ ft. Selection of the downhole material for these conditions was itself a challenge as very few vendors or IOC (Internatioanl oil companies) have experience of developing and producing from +30% H2S and +10% CO2.\u0000 Due to the location of the well, stringent HSE measurements were adapter to ensure zero tolerance for the safety violation in accordance with 100% HSE.\u0000 The testing of the HPHT sour gas was challenging due to not only HSE issues but also from the environment part too as flaring needed to be minimized in the brown field. Hence, it was decided to Tie-in the well to the nearby facilities. The challenge was that the existing facilities were not design to accept the sour gas. This was overcome by blending the sour gas with sweet gas to meet the existing facilities specs and capacities.\u0000 After the well was drilled, the +10000 ft. open hole was flowed to clean to ensure all the drilling fluid lost was recovered to test to access well potential and obtain representative data for full field development plan.\u0000 Drilling, testing and producing the highly sour HPHT gas reservoirs with more than 30% H2S and 10% CO2 along with temperature ranging up to 300 deg F is itself a huge challenge.\u0000 Over the last few years, ADNOC Onshore have developed considerable expertise in testing the sour wells considering all the safety and environmental aspects.\u0000 This paper highlights the work progress and the lessons learned during each step of the operation from planning phase to drilling, tie-in the well to the existing facilities after dilution during testing. All the proposed mitigation plans considering 100% HSE while dealing with these appraisal wells in the Arab sour reservoir having +30% H2S and 10 % CO2 were developed and implemented sucessfully.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"19 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88634042","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. Yugay, Mubashir Ahmad, I. Bankole, S. Alhouqani, Salah Al Qallabi, G. Pimenta
As a part of Country strategy to fulfill growing demand in gas energy in the country, development of Arab formations started. This paper shares the actual case history of successfully completed evaluation of Arab formation in one of the Company fields. High temperature (300F), high H2S concentrations (up to 37% H2S) and presence of elemental Sulphur dictated usage of very exotic downhole corrosion resistant alloy (CRA) material. Tightness of carbonate formation (less than 1 mD) pushed to drill 10,000’ horizontal section to meet project objectives. High reservoir pressure reaching 5,700 psi in combination with all conditions above resulted in high level of risk during initial project evaluation and required very robust HSE and Integrity systems in place with no chance to failure. Arab formation evaluation project started in 2014 and was performed in several steps, with gradual increase of the complexity of the each next stage: from vertical well to horizontal, from sampling to longer duration testing, from carbon steel completion to fit-for-purpose inhibition and high grade CRA materials. Efficient collaboration among multidisciplinary teams, continuous management support and clear communication channels between all stakeholders proved to be a key to success for this challenging project. The project included involvement of high capacity rig to fulfill extended reach depth (ERD) well requirements, specific well intervention techniques while drilling and testing, usage of special inhibitor for high sour wells and finally inspection of the recovered completion. All Company available best practices and technical competencies applied in this project allowed to overcome all the challenges and achieve appreciable sustainable gas rates, meeting all set objectives with no HSE incidents and failures. Findings and lessons learned received are used to tailor next stage of the project to ensure most efficient scenario of field development to support country strategy in increasing energy potential. The content of the paper gives a good understanding to the readers on the key aspects and main challenges that they may face during initial evaluation stage of the tight gas high pressure high temperature (HPHT) carbonate formations with high H2S content. The document could be used as a local considering current government strategy of massive attraction of new business partners for the exploration of new gas and gas condensate blocks in the region.
{"title":"Successful Evaluation of Tight Gas HPHT Carbonate Formation with Extremely High Sour Content and Elemental Sulphur Presence","authors":"A. Yugay, Mubashir Ahmad, I. Bankole, S. Alhouqani, Salah Al Qallabi, G. Pimenta","doi":"10.2118/197657-ms","DOIUrl":"https://doi.org/10.2118/197657-ms","url":null,"abstract":"\u0000 As a part of Country strategy to fulfill growing demand in gas energy in the country, development of Arab formations started. This paper shares the actual case history of successfully completed evaluation of Arab formation in one of the Company fields. High temperature (300F), high H2S concentrations (up to 37% H2S) and presence of elemental Sulphur dictated usage of very exotic downhole corrosion resistant alloy (CRA) material. Tightness of carbonate formation (less than 1 mD) pushed to drill 10,000’ horizontal section to meet project objectives. High reservoir pressure reaching 5,700 psi in combination with all conditions above resulted in high level of risk during initial project evaluation and required very robust HSE and Integrity systems in place with no chance to failure.\u0000 Arab formation evaluation project started in 2014 and was performed in several steps, with gradual increase of the complexity of the each next stage: from vertical well to horizontal, from sampling to longer duration testing, from carbon steel completion to fit-for-purpose inhibition and high grade CRA materials. Efficient collaboration among multidisciplinary teams, continuous management support and clear communication channels between all stakeholders proved to be a key to success for this challenging project. The project included involvement of high capacity rig to fulfill extended reach depth (ERD) well requirements, specific well intervention techniques while drilling and testing, usage of special inhibitor for high sour wells and finally inspection of the recovered completion. All Company available best practices and technical competencies applied in this project allowed to overcome all the challenges and achieve appreciable sustainable gas rates, meeting all set objectives with no HSE incidents and failures. Findings and lessons learned received are used to tailor next stage of the project to ensure most efficient scenario of field development to support country strategy in increasing energy potential.\u0000 The content of the paper gives a good understanding to the readers on the key aspects and main challenges that they may face during initial evaluation stage of the tight gas high pressure high temperature (HPHT) carbonate formations with high H2S content. The document could be used as a local considering current government strategy of massive attraction of new business partners for the exploration of new gas and gas condensate blocks in the region.","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":"90561304","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}
Natural Gas Liquefaction (NGL) plant Acid Gas Removal (AGR) unit successfully switched from silicon based to polyglycol based antifoam. Changing the type of antifoam was to eliminate the repetitive foaming occurrences in the AGR amine absorber, and to avoid the side effects of the excessive silicon deposits in the circulated amine. The polyglycol based antifoam was found to be more effective and required at lower concentration. The AGR unit experienced repetitive amine absorber foaming since the plant commissioning. The foaming events are due to feed quality challenges in the form of liquid hydrocarbon carryover, and suspended solids entrainment. The repetitive foaming led to frequently disturbing the plant operation, reducing the unit throughput and impacting the product quality. To decrease the foaming occurrences the mode of operation for the antifoam injection was changed from intermittent injection to continues injection. However, the unit was so sensitive to the antifoam flow interruptions. The required concentration of the silicon based antifoam was high (110 – 130 PPM compared to 20-25 PPM for the polyglycol based antifoam). This led to the side effects of the excessive silicon deposits in the system, such as the fouling of heating equipment (heat exchangers, reboilers and air coolers), the frequent amine filters clogging, and increasing the circulated amine total suspended solids. The main objective for switching the type of antifoam is to eliminate the foaming events while minimizing the side effects of the silicon deposits. The polyglycol based antifoam was found more effective for continuous injection with concentration of 20-25 PPM. Furthermore, in the case of minor foaming in the amine absorber, increasing the antifoam concentration to 500 PPM was found to be effective in stabilizing the absorber foaming in less than 5 minutes. In addition, the minor antifoam flow interruptions did not result in foaming events unlike the silicon antifoam.
{"title":"Acid Gas Removal Unit Successful Switch from Silicon to Polyglycol Antifoam to Eliminate Foaming","authors":"Mohammed Al Rumaih","doi":"10.2118/197204-ms","DOIUrl":"https://doi.org/10.2118/197204-ms","url":null,"abstract":"\u0000 Natural Gas Liquefaction (NGL) plant Acid Gas Removal (AGR) unit successfully switched from silicon based to polyglycol based antifoam. Changing the type of antifoam was to eliminate the repetitive foaming occurrences in the AGR amine absorber, and to avoid the side effects of the excessive silicon deposits in the circulated amine. The polyglycol based antifoam was found to be more effective and required at lower concentration.\u0000 The AGR unit experienced repetitive amine absorber foaming since the plant commissioning. The foaming events are due to feed quality challenges in the form of liquid hydrocarbon carryover, and suspended solids entrainment. The repetitive foaming led to frequently disturbing the plant operation, reducing the unit throughput and impacting the product quality. To decrease the foaming occurrences the mode of operation for the antifoam injection was changed from intermittent injection to continues injection. However, the unit was so sensitive to the antifoam flow interruptions.\u0000 The required concentration of the silicon based antifoam was high (110 – 130 PPM compared to 20-25 PPM for the polyglycol based antifoam). This led to the side effects of the excessive silicon deposits in the system, such as the fouling of heating equipment (heat exchangers, reboilers and air coolers), the frequent amine filters clogging, and increasing the circulated amine total suspended solids.\u0000 The main objective for switching the type of antifoam is to eliminate the foaming events while minimizing the side effects of the silicon deposits. The polyglycol based antifoam was found more effective for continuous injection with concentration of 20-25 PPM. Furthermore, in the case of minor foaming in the amine absorber, increasing the antifoam concentration to 500 PPM was found to be effective in stabilizing the absorber foaming in less than 5 minutes. In addition, the minor antifoam flow interruptions did not result in foaming events unlike the silicon antifoam.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"27 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76895164","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}
Giampiero Mulè, V. Luciano, A. Pastorello, A. Whymant
Coral Sul FLNG is designed to produce, liquefy, store and transfer LNG and condensates directly at the offshore reservoir. Over 430 meters long, Coral Sul will be the first FLNG ever built to operate in ultra-deep waters, its wells are located 2000 meters below sea level. The vessel is currently under construction by Technip, JGC, Samsung Consortium (TJS) in South Korea for a joint venture led by Eni as operator and partners (ExxonMobil, ENH, GALP, KOGAS and CNPC). The main safety challenges for the FLNG technology, relate to the management of cryogenic spills on board and the protection of people and assets in a very congested environment. FLNG technology is introducing a set of new safety rules for the industry which are still under development by main international certification bodies. Today, the lack of industry standards regarding FLNG technology, and the congested nature of the installation, make the Risk Based Approach an essential step to validate the design and identify fit for purpose reduction measures. Coral project carried out several actions for Cryogenic Risk Management with the aim to: ensure safety of all the Personnel on Boardminimize the potential for escalation and maintain asset integrity. This Paper describes the Risk Based Approach followed for Coral FLNG project and describes some of the most important design safety measures implemented on board to manage cryogenic spills: Design of Drainage System and Overboard dischargeDesigned against the Risk of Rapid Phase TransitionActive Protection Methods: Water Curtains to protect hull sideImproved Coating Materials (combined effect Cryogenic Spill Protection + Passive Fire Protection) Suitable design of drainage system is a key safety aspect for the design of the FLNG, since it is essential to minimize the vaporization which can create dangerous flammable gas clouds on board. The solution proposed for Coral Sul FLNG is a combination of open gutters, sloped open channels and vertical pipes which allow the quick discharge overboard of accidental spills, minimizing the vaporization in congested areas. In proximity of overboard spillage points, water curtains are implemented to protect the hull side, and the effect of discharge is evaluated for rapid phase transition. Steel decks and structures must be protected against fractures that can follow accidental cryogenic spillages and lead to structural failures which put at risk lives and assets. Specific coating materials have been developed for the protection of decks, piping and equipment to avoid the escalation of any incident. These coatings provide combined protection against embrittlement and fire. Application of coating is done used RBA approach. Design of drainage system and coatings have been identified as technical novelties. A technology validation program has been put in place for Coral Project in order to assess the maturity of the new technologies.
Coral Sul FLNG旨在直接在海上储层生产、液化、储存和输送液化天然气和凝析油。Coral Sul长430米，将是有史以来第一个在超深水中运行的FLNG，其井位于海平面以下2000米。该船目前由Technip、JGC、Samsung Consortium (TJS)在韩国建造，由Eni领导的合资企业作为运营商和合作伙伴(ExxonMobil、ENH、GALP、KOGAS和CNPC)。FLNG技术面临的主要安全挑战涉及船上低温泄漏的管理以及在非常拥挤的环境中对人员和资产的保护。FLNG技术正在为行业引入一套新的安全规则，这些规则仍在主要国际认证机构的开发中。目前，FLNG技术缺乏行业标准，且安装的拥挤性，使得基于风险的方法成为验证设计和确定适合减少目的措施的重要步骤。Coral项目为低温风险管理开展了几项行动，目的是:确保船上所有人员的安全，最大限度地减少风险升级的可能性，并保持资产的完整性。本文描述了Coral FLNG项目所采用的基于风险的方法，并描述了船上实施的一些最重要的设计安全措施，以管理低温泄漏:排水系统和船外排放物的设计，旨在防止快速相变的风险主动保护方法:改进的涂层材料(低温泄漏防护+被动防火的综合作用)合适的排水系统设计是FLNG设计的一个关键安全方面，因为它至关重要，以尽量减少汽化，从而在船上产生危险的可燃气云。为Coral Sul FLNG提出的解决方案是开放式排水沟、倾斜的开放式通道和垂直管道的组合，这些管道可以快速将意外溢出物排出船外，最大限度地减少拥挤区域的蒸发。在靠近船外溢出点的地方，采用水帘保护船身侧，并对快速相变的排放效果进行了评估。钢甲板和结构必须防止意外低温泄漏引起的裂缝，并导致结构失效，危及生命和财产。为了保护甲板、管道和设备，已经开发了特殊的涂层材料，以避免任何事故的升级。这些涂层提供了抗脆化和防火的综合保护。采用RBA法涂覆涂层。排水系统和涂料的设计被认为是技术上的创新。为了评估新技术的成熟度，珊瑚项目已经实施了一项技术验证计划。
{"title":"Application of Cryogenic Spill Control Techniques in Floating LNG","authors":"Giampiero Mulè, V. Luciano, A. Pastorello, A. Whymant","doi":"10.2118/197245-ms","DOIUrl":"https://doi.org/10.2118/197245-ms","url":null,"abstract":"\u0000 Coral Sul FLNG is designed to produce, liquefy, store and transfer LNG and condensates directly at the offshore reservoir. Over 430 meters long, Coral Sul will be the first FLNG ever built to operate in ultra-deep waters, its wells are located 2000 meters below sea level. The vessel is currently under construction by Technip, JGC, Samsung Consortium (TJS) in South Korea for a joint venture led by Eni as operator and partners (ExxonMobil, ENH, GALP, KOGAS and CNPC).\u0000 The main safety challenges for the FLNG technology, relate to the management of cryogenic spills on board and the protection of people and assets in a very congested environment.\u0000 FLNG technology is introducing a set of new safety rules for the industry which are still under development by main international certification bodies. Today, the lack of industry standards regarding FLNG technology, and the congested nature of the installation, make the Risk Based Approach an essential step to validate the design and identify fit for purpose reduction measures.\u0000 Coral project carried out several actions for Cryogenic Risk Management with the aim to: ensure safety of all the Personnel on Boardminimize the potential for escalation and maintain asset integrity.\u0000 This Paper describes the Risk Based Approach followed for Coral FLNG project and describes some of the most important design safety measures implemented on board to manage cryogenic spills: Design of Drainage System and Overboard dischargeDesigned against the Risk of Rapid Phase TransitionActive Protection Methods: Water Curtains to protect hull sideImproved Coating Materials (combined effect Cryogenic Spill Protection + Passive Fire Protection)\u0000 Suitable design of drainage system is a key safety aspect for the design of the FLNG, since it is essential to minimize the vaporization which can create dangerous flammable gas clouds on board.\u0000 The solution proposed for Coral Sul FLNG is a combination of open gutters, sloped open channels and vertical pipes which allow the quick discharge overboard of accidental spills, minimizing the vaporization in congested areas. In proximity of overboard spillage points, water curtains are implemented to protect the hull side, and the effect of discharge is evaluated for rapid phase transition.\u0000 Steel decks and structures must be protected against fractures that can follow accidental cryogenic spillages and lead to structural failures which put at risk lives and assets. Specific coating materials have been developed for the protection of decks, piping and equipment to avoid the escalation of any incident. These coatings provide combined protection against embrittlement and fire. Application of coating is done used RBA approach.\u0000 Design of drainage system and coatings have been identified as technical novelties. A technology validation program has been put in place for Coral Project in order to assess the maturity of the new technologies.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"27 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84633562","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}
Naresh Kumar, Raju Paul, F. Kamal, Oussama Takieddine
The present trend is to use the umbilical for transmitting electrical power, instrumentation signals and to transport fluids & gas in one assembly over long distance to the Offshore Oil and Gas facilities. The installation of power generation facilities at offshore platforms is not a preferred option due to space constraints and the huge installation and running cost. Hence, the electrical power is transmitted from onshore generation facilities to offshore facilities by composite subsea cables. Similarly for example the cost of installing corrosion inhibitor package at offshore facilities is huge considering the space occupied by the package skid which in turn increases the structural cost. The electricity required to run the corrosion inhibitor pump motor and other auxiliaries will result in higher power demand and subsequently the higher installation and operation cost. Hence, it is economical to transfer the corrosion inhibitor from nearby onshore facilities to offshore facilities by using instrumentation tubes, pipes and hoses. The use of umbilical which houses the composite subsea cable and tubes carrying fluids/gases in one assembly result in substantial cost savings in terms of installation, transportation and laying cost. The housing of submarine composite cable with tubes in one assembly poses many challenges for the design and selection of umbilical. This paper provides comprehensive ideas about design, testing and selection of umbilical, the challenges faced and the way forward to overcome the challenges in selection of umbilical.
{"title":"Challenges Faced in Design & Selection of Umbilical for Offshore Facilities","authors":"Naresh Kumar, Raju Paul, F. Kamal, Oussama Takieddine","doi":"10.2118/197374-ms","DOIUrl":"https://doi.org/10.2118/197374-ms","url":null,"abstract":"\u0000 The present trend is to use the umbilical for transmitting electrical power, instrumentation signals and to transport fluids & gas in one assembly over long distance to the Offshore Oil and Gas facilities. The installation of power generation facilities at offshore platforms is not a preferred option due to space constraints and the huge installation and running cost. Hence, the electrical power is transmitted from onshore generation facilities to offshore facilities by composite subsea cables.\u0000 Similarly for example the cost of installing corrosion inhibitor package at offshore facilities is huge considering the space occupied by the package skid which in turn increases the structural cost. The electricity required to run the corrosion inhibitor pump motor and other auxiliaries will result in higher power demand and subsequently the higher installation and operation cost. Hence, it is economical to transfer the corrosion inhibitor from nearby onshore facilities to offshore facilities by using instrumentation tubes, pipes and hoses.\u0000 The use of umbilical which houses the composite subsea cable and tubes carrying fluids/gases in one assembly result in substantial cost savings in terms of installation, transportation and laying cost. The housing of submarine composite cable with tubes in one assembly poses many challenges for the design and selection of umbilical. This paper provides comprehensive ideas about design, testing and selection of umbilical, the challenges faced and the way forward to overcome the challenges in selection of umbilical.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"29 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80793011","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}
Xuanze Ju, Zhigang Liu, Lei Shi, Gang Li, Guangkuo Xing
Subsea manifold is a flow-routing subsea hardware (subsea flow router) that connects between subsea trees and flowlines. It is used to optimize the subsea layout arrangement and reduce the quantity of risers connected to the platform, the new engineering technology of subsea manifold to be studied in this paper. From the perspectives of safety, economy, constructability, installation, operability and maintainability, it is proposed to divide the subsea manifold into three parts: manifold module, protection structure module and foundation module, thus forms the new split-type subsea manifold engineering. On the basis of analyzing the functional requirements of subsea manifolds, the method of manifold design and piping stress check is given herein. The protection structure design mainly involves protection against dropped object impact, fishing nets and dropped object. The structure design and strength checking method of dropped objects impact and trawl-board impact are also given. There are mainly two types of foundation for subsea facilities: mudmat and suction pile. Mudmat is more cost effective, hence it is the preferred solution. The design calculation method of mudmat is given (including vertical bearing capacity, torsional resistance, sliding resistance, overturning resistance, settlement calculation, skirt penetration capacity). Finally, the three modules are combined to form a new split-type subsea manifold design, which has been successfully implemented in South China Sea, providing a reference for the application of the new split-type subsea manifold.
{"title":"Study on the Split-Type Subsea Manifold Engineering Technology","authors":"Xuanze Ju, Zhigang Liu, Lei Shi, Gang Li, Guangkuo Xing","doi":"10.2118/197963-ms","DOIUrl":"https://doi.org/10.2118/197963-ms","url":null,"abstract":"\u0000 Subsea manifold is a flow-routing subsea hardware (subsea flow router) that connects between subsea trees and flowlines. It is used to optimize the subsea layout arrangement and reduce the quantity of risers connected to the platform, the new engineering technology of subsea manifold to be studied in this paper. From the perspectives of safety, economy, constructability, installation, operability and maintainability, it is proposed to divide the subsea manifold into three parts: manifold module, protection structure module and foundation module, thus forms the new split-type subsea manifold engineering. On the basis of analyzing the functional requirements of subsea manifolds, the method of manifold design and piping stress check is given herein. The protection structure design mainly involves protection against dropped object impact, fishing nets and dropped object. The structure design and strength checking method of dropped objects impact and trawl-board impact are also given. There are mainly two types of foundation for subsea facilities: mudmat and suction pile. Mudmat is more cost effective, hence it is the preferred solution. The design calculation method of mudmat is given (including vertical bearing capacity, torsional resistance, sliding resistance, overturning resistance, settlement calculation, skirt penetration capacity). Finally, the three modules are combined to form a new split-type subsea manifold design, which has been successfully implemented in South China Sea, providing a reference for the application of the new split-type subsea manifold.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"43 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83114859","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}
Today, small-scale liquified natural gas (SSLNG) plants are planned and built in different areas around the globe. Due to the overall market situation and competition, these projects are challenged to decrease capital expenditure (CAPEX), while becoming increasingly efficient to meet mid-size investors' operating expenditure (OPEX) targets and return on investment (ROI) expectations. The main challenges are the overall efficiency of the plant, seal leakage rates, operational flexibility and the plant's space limitations. To a big extent, the aforementioned points are closely connected to liquefaction technology selection (either single mixed refrigeration or nitrogen Brayton cycle) as well as the rotating equipment used: Firstly, regarding energy use, the refrigeration compressor is the main power consumer in an SSLNG plant (in addition to pumps and smaller compressors). Secondly, a large amount of process leakage is linked to the seals of the rotating equipment. Regarding the third point, operational flexibility, this parameter is closely related to the deployed compressor and expander, and their respective process characteristics. Lastly, the footprint and equipment size have an impact on the installation costs and ultimately CAPEX. Often, especially in a nitrogen Brayton cycle, compressors as well as warm and cold turboexpanders are supplied as single skid each: that is, a nitrogen compressor skid as well as both warm and cold expander compressors installed on another skid. To reach their future objectives, some SSLNG plant operators are taking new approaches that combine these two technologies: compressor and expander applications are installed on one single gearbox and skid – this is called a Compander. This approach is already used in other industry segments and applications, including LNG carriers. Atlas Copco's first land-based LNG refrigeration Compander was installed back in 2002 at a plant in Norway. The Compander design allows for only one gearbox on which compressor and expander stages are mounted, one oil system, one control system and one seal gas panel – instead of having all of these components twice. By applying these bridging technologies, SSLNG plants are finding new ways to improve OPEX while at the same time reducing the financial burden on new projects. In this case study, we discuss how SSLNG plants in Norway and customers in other places have implemented Atlas Copco Gas and Process integrally geared technology that merges the functions of a centrifugal compressor and turboexpander into one compact Compander unit. In addition, different configurations of separate compressors and expanders are discussed and compared to a single-skid (Compander) solution. During the discussion, the benefits of a Compander compared to single and separate equipment designs are evaluated.
{"title":"Bridging Compressor and Expander Technologies in SSLNG Processes","authors":"Michael Drewes, Tushar Patel","doi":"10.2118/197260-ms","DOIUrl":"https://doi.org/10.2118/197260-ms","url":null,"abstract":"\u0000 Today, small-scale liquified natural gas (SSLNG) plants are planned and built in different areas around the globe. Due to the overall market situation and competition, these projects are challenged to decrease capital expenditure (CAPEX), while becoming increasingly efficient to meet mid-size investors' operating expenditure (OPEX) targets and return on investment (ROI) expectations. The main challenges are the overall efficiency of the plant, seal leakage rates, operational flexibility and the plant's space limitations.\u0000 To a big extent, the aforementioned points are closely connected to liquefaction technology selection (either single mixed refrigeration or nitrogen Brayton cycle) as well as the rotating equipment used: Firstly, regarding energy use, the refrigeration compressor is the main power consumer in an SSLNG plant (in addition to pumps and smaller compressors). Secondly, a large amount of process leakage is linked to the seals of the rotating equipment. Regarding the third point, operational flexibility, this parameter is closely related to the deployed compressor and expander, and their respective process characteristics. Lastly, the footprint and equipment size have an impact on the installation costs and ultimately CAPEX.\u0000 Often, especially in a nitrogen Brayton cycle, compressors as well as warm and cold turboexpanders are supplied as single skid each: that is, a nitrogen compressor skid as well as both warm and cold expander compressors installed on another skid. To reach their future objectives, some SSLNG plant operators are taking new approaches that combine these two technologies: compressor and expander applications are installed on one single gearbox and skid – this is called a Compander. This approach is already used in other industry segments and applications, including LNG carriers. Atlas Copco's first land-based LNG refrigeration Compander was installed back in 2002 at a plant in Norway. The Compander design allows for only one gearbox on which compressor and expander stages are mounted, one oil system, one control system and one seal gas panel – instead of having all of these components twice. By applying these bridging technologies, SSLNG plants are finding new ways to improve OPEX while at the same time reducing the financial burden on new projects. In this case study, we discuss how SSLNG plants in Norway and customers in other places have implemented Atlas Copco Gas and Process integrally geared technology that merges the functions of a centrifugal compressor and turboexpander into one compact Compander unit. In addition, different configurations of separate compressors and expanders are discussed and compared to a single-skid (Compander) solution.\u0000 During the discussion, the benefits of a Compander compared to single and separate equipment designs are evaluated.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"23 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83222641","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}
R. Rommetveit, M. G. Mayani, J. Nabavi, Stig Helgeland, Raymond Hammer, Jostein Råen
As part of the digital transformation in oil and gas industry, well construction move toward new efficient methods using digital twins of the wells. This paper will highlight how the drilling operations are monitored, how a digital twin of the well is utilized and how learnings are implemented for future wells. A Digital Twin is a digital copy of assets, systems and processes. A Digital Twin in drilling is an exact digital replica of the physical well during the whole drilling life cycle. Its functionality is based on advanced hydraulic and dynamic models processing in real time. By utilizing real-time data from the well, it enables automatic analysis of data and monitoring of the drilling operation and offer early diagnostic messages to detect early signs of problems or incidents. In the current study various actual operational cases will be presented related to different wells. This includes using digital twin during drilling under challenging circumstances such as conditions when using MPD techniques. Also, various diagnostic messages which gave early signs of problems during running in the hole, pulling out of the hole and drilling will be presented. High restrictions were detected using comparisons of real-time values and transient modelling results. These will be discussed. Different real cases have been studied. Combining digital RT modelled and real-time measured data in combination with predictive diagnostic messages will improve the decision making and result in less non-productive time and more optimal drilling operations.
{"title":"Automatic Realtime Monitoring of Drilling Using Digital Twin Technologies Enhance Safety and Reduce Costs","authors":"R. Rommetveit, M. G. Mayani, J. Nabavi, Stig Helgeland, Raymond Hammer, Jostein Råen","doi":"10.2118/197465-ms","DOIUrl":"https://doi.org/10.2118/197465-ms","url":null,"abstract":"\u0000 As part of the digital transformation in oil and gas industry, well construction move toward new efficient methods using digital twins of the wells. This paper will highlight how the drilling operations are monitored, how a digital twin of the well is utilized and how learnings are implemented for future wells.\u0000 A Digital Twin is a digital copy of assets, systems and processes. A Digital Twin in drilling is an exact digital replica of the physical well during the whole drilling life cycle. Its functionality is based on advanced hydraulic and dynamic models processing in real time. By utilizing real-time data from the well, it enables automatic analysis of data and monitoring of the drilling operation and offer early diagnostic messages to detect early signs of problems or incidents.\u0000 In the current study various actual operational cases will be presented related to different wells. This includes using digital twin during drilling under challenging circumstances such as conditions when using MPD techniques. Also, various diagnostic messages which gave early signs of problems during running in the hole, pulling out of the hole and drilling will be presented. High restrictions were detected using comparisons of real-time values and transient modelling results. These will be discussed.\u0000 Different real cases have been studied. Combining digital RT modelled and real-time measured data in combination with predictive diagnostic messages will improve the decision making and result in less non-productive time and more optimal drilling operations.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89625242","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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