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Dr. K.M. Strack is president of KMS Technologies- KJT Enterprises Inc. specializing in integrated seismic/electromagnetic technology for land & marine exploration, appraisal drilling and production monitoring for the geothermal/petroleum industry. Present emphasis is to drive the technology enabling smooth energy transition to zero carbon footprint. In that KMS Technologies pioneers borehole, borehole-to-surface, and marine electromagnetics to link with the 3D seismic Earth model. Kurt also serves as Adjunct Professor in the Earth and Atmospheric Geoscience Department and Electrical Engineering Department at the University of Houston, Mahidol University Bangkok, and at Yangtze University, Wuhan China (borehole geophysics and electrical methods for petroleum applications) (and other universities in China, Malaysia, Indonesia, Saudi and Germany). Previously, he was Chief Scientist for Baker Atlas after various management positions.
- Health, Safety, Environment & Sustainability > Sustainability/Social Responsibility > Sustainable development (0.95)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (0.68)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (0.63)
- Health, Safety, Environment & Sustainability > Environment > Climate change (0.58)
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202896, “Optimizing Production From Marginal and Challenging Prospects To Unlock Field Potential: Success Cases in the Jasmine Field, Gulf of Thailand,” by Mukminin Yusuf, SPE, Pattarapong Prasongtham, SPE, and Theeranun Limniyakul, SPE, Mubadala Petroleum, et al. The paper has not been peer reviewed. The development of marginal volumes in the Jasmine field is part of the operator’s strategy to extend the field’s life, involving the exploitation of increasingly challenging prospects. The complete paper highlights two case studies to illustrate how the operator has developed marginal prospects to unlock the Jasmine field’s remaining potential successfully. The use of autonomous inflow control devices (AICD) has played a significant role in optimizing production in reservoirs with small oil rims and thick gas caps. Jasmine Field The designation “Jasmine field” is commonly used to refer to both the Jasmine field and the neighboring Ban Yen field, which are essentially one integrated field from an operational perspective. The fields are in the Gulf of Thailand, approximately 300 km southeast of Bangkok in depths of 190 to 200 ft (Fig. 1).
The development of marginal volumes in the Jasmine field is part of the operator's strategy to extend the field's life, involving the exploitation of increasingly challenging prospects. The complete paper highlights two case studies to illustrate how the operator has developed marginal prospects to unlock the Jasmine field's remaining potential successfully. The use of autonomous inflow control devices (AICD) has played a significant role in optimizing production in reservoirs with small oil rims and thick gas caps. The designation "Jasmine field" is commonly used to refer to both the Jasmine field and the neighboring Ban Yen field, which are essentially one integrated field from an operational perspective. The fields are in the Gulf of Thailand, approximately 300 km southeast of Bangkok in depths of 190 to 200 ft (Fig.
Total's Laggan Tormore project claimed the International Petroleum Technology Conference (IPTC) Excellence in Project Integration Award at the 10th IPTC in Bangkok, Thailand. The IPTC Excellence in Project Integration Award highlights projects that have demonstrated distinction throughout the entire value chain, and are equivalent in value to at least USD 500 million. Past winners have included both international and national oil companies. Taken into account are projects that exemplify strong teamwork, solid geoscience knowledge, reservoir and production engineering expertise, outstanding facilities engineering practices, a strong commitment to health, safety, and the environment, and advocate innovative and people-oriented human resource policies and community programs. Previous award winners include the Qatargas Debottling project by Qatargas, the Independence Hub project by Anadarko Petroleum, Sakhalin-1 by Exxon Neftegas, Qatargas 2 by Qatargas, Parque das Conchas by Shell, Pazflor by Total, Perdido by Shell, RGX2 by RasGas, and CLOV by Total.
- Asia > Thailand > Bangkok > Bangkok (0.28)
- Asia > Russia > Far Eastern Federal District > Sakhalin Oblast (0.26)
- Europe > United Kingdom > Atlantic Margin (0.20)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Thailand Government (0.34)
- Asia > China > Xinjiang Uyghur Autonomous Region > Tarim Basin > Keshen Field (0.99)
- Europe > United Kingdom > Atlantic Margin > West of Shetland > Faroe-Shetland Basin > Flett Basin > Block 206/1a > Laggan-Tormore Field > Laggan Field (0.94)
- Europe > United Kingdom > Atlantic Margin > West of Shetland > Faroe-Shetland Basin > Flett Basin > Block 205/5a > Laggan-Tormore Field > Tormore Field (0.94)
This review of technical challenges facing oil and gas producers in the Gulf of Thailand arose from last month's meeting in Bangkok, Thailand, of the SPE Board of Directors with the SPE Asia Pacific Advisory Council, which is represented by senior executives from across the Asia Pacific region and industry value chain. It was an opportunity for Board members to meet with the leadership of the major oil and service companies and discuss how best the SPE can serve its membership in the region. The SPE Board of Directors meets three times per year. One meeting is held in conjunction with the SPE Annual Technical Conference and Exhibition (ATCE), usually during September or October; the other meetings are held in locations around the world chosen for strategic reasons by the SPE President. Thailand is an oil and natural gas producer.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Thailand Government (0.33)
- Government > Regional Government > North America Government > United States Government (0.31)
- Asia > Thailand > Gulf of Thailand > Pattani Basin > G11/48 License > Nong Yao Field (0.99)
- Asia > Thailand > Gulf of Thailand > Malay Basin > G11/48 License > Nong Yao Field (0.99)
- Asia > Thailand > Gulf of Thailand > Bongkot Field (0.93)
- Asia > Thailand > Gulf of Thailand > Arthit Field (0.93)
This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE/IADC 190967, “Development of Low-Toxicity and High-Temperature Polymer Drilling Fluid for Environmentally Sensitive Offshore Drilling,” by Xiaodong Liu, CNPC; Binqiang Xie, Yangtze University; Yonghui Gao, Huiling Gu, Yongle Ma, and Yong Zhang, CNPC; Ruxin Zhang, China University of Petroleum-Beijing; and Qingyang Li, Southwest Petroleum University, prepared for the 2018 IADC/SPE Asia Pacific Drilling Technology Conference, 27–29 August, Bangkok, Thailand. The paper has not been peer reviewed. This paper discusses a new, environmentally safe, water-based polymer drilling fluid that has been developed for offshore drilling applications with temperature resistance to 200°C and low biological toxicity. The system comprises two basic polymeric components for high-temperature rheology and filtration control, along with a special nanoplugging agent, glycol shale inhibitor, extreme-pressure lubricant, and barite or formate weight material. The base slurry is light-colored and nontoxic to the marine environment, and so can be discharged directly into the sea. Results from field testing in a Bohai offshore oil field are presented in•the complete paper. Introduction Historically, significant limitations have been placed on the use of drilling fluids in high-temperature operations in environmentally sensitive areas of China. Oil-based drilling fluid is restricted in use by laws and regulations; polysulfonated, water-based drilling fluid and waste liquid are on the national hazardous waste list; and polymer drilling fluid such as XC/CMC/PAC/PHPA can only be used in temperatures lower than 150°C. Additionally, the offshore drilling-fluid discharge requires a low biological toxicity value. These harsh operation conditions and strict environmental laws and regulations pose severe challenges for high-pressure/high-temperature water-based drilling-fluid-formula design and field construction. In recent years, international oil companies have conducted research on environmentally friendly, high-temperature, polymer water-based drilling fluids for reducing toxicity of the drilling fluid, improving the anti-temperature performance of the treatment agent, and enhancing the anticollapse performance of the drilling fluid. To meet the requirements of high-temperature, deep-well drilling operations and environmental protection in environmentally sensitive offshore areas, a high-temperature synthetic polymer filtrate loss agent and high-temperature viscosifier have been developed, and a matching nanoplugging agent and lubricant were also studied. Then, a high-temperature polymer seawater-based drilling-fluid system was developed, based on a high-temperature synthetic polymer as the main agent, supplemented with the properties of a nanoplugging agent, shale inhibitor, and extreme-pressure lubricant. It can achieve performance comparable to oil-based drilling fluids in terms of lubricity and inhibition of shale hydration and dispersion, and the biological toxicity (LC50) value is greater than 100,000•mg/L. This system has out-standing high-temperature thermal stability and shale-inhibition performance, making it environmentally friendly and able to be discharged directly into the sea. Good results have been achieved in offshore Bohai field•applications.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.56)
This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 191001, “Fracture Packing in Previously Gravel-Packed Well Using Single-Trip Multizone System,” by Jianming Deng, Yingwen Ma, and Ming Zhang, China National Offshore Company; Jiacheng Qian and Chao Fang, Halliburton; and Qiang Wang and Xiaobo Wang, formerly Halliburton, prepared for the 2018 IADC/SPE Asia Pacific Drilling Technology Conference, Bangkok, Thailand, 27–29 August. The paper has not been peer reviewed. This paper details the design and execution of what the authors say they believe is the first successful frac-pack operation in a previously gravel-packed well. The well, in China’s Bohai Bay, exemplifies a new method of recompleting mature wells to enhance production without performing a sidetrack, thus significantly reducing costs. Challenges and solutions are discussed as well as the methods used to squeeze fluid and proppant into the formation. Introduction For the past 13 years, a single-trip multizone (STMZ) gravel-packing system has been widely used in Bohai Bay for sand control. The practice has been to run single-trip, multizone, wire-wrapped screen in the casing and then perform a gravel pack for each stage. In some wells, production can decline quickly and the well can stop flowing within a couple of years. A typical solution is to pull the upper completion, plug the lower completion, and sidetrack. The cost of this method can be significant. Operators desired a lower-cost workover plan that would restore production from the current completion. The proposed method involved recompleting a well by running in service tools to perform fracture packing within the existing multizone gravel-pack completion. High-viscosity fluid would be pumped into the formation as a prepad; then, fracture packing would be performed. The reservoir of the Suizhong 36-1 field in the Liaodong Bay area of the Bohai Sea is composed of multilayer sandstone formations. This field experiences sand-production issues for several reasons. Because of its high permeability and high porosity, the formation sand is unconsolidated. Production began in 1993, and, over the years, water has been injected to maintain it. Currently, the average water cut is 70%. Water production can cause sand production. The oil is heavy. It has a high asphaltene content, and its viscosity is 37–160 cp, which generates significantly high friction forces when flowing in the near-wellbore region, thus increasing the likelihood of sand production. The treatment includes cleaning the wellbore for recompletion. Use of the STMZ system proved the downhole service tool could be tripped back in and out of hole safely in the same trip following fracture packing of a previously gravel-packed multizone well completion. The method also shows that, through careful planning and designing of the tool and treatment, the risk of failure caused by a stuck tool string, unwanted fluid loss, or premature screen out can be minimized. The job execution and lessons learned also can provide a guideline for improvement of future treatments in similar situations.
- Research Report (0.35)
- Summary/Review (0.34)
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 191060, “Operational Design and Application of MPD in Offshore Ultra-HP/HT Exploration Wells,” by Qishuai Yin and Jin Yang, China University of Petroleum; Bo Zhou, CNPC; Ming Luo, Wentuo Li, and Yi Huang, CNOOC; and Ting Sun, Xinxin Hou, Xiaodong Wu, and Junxiang Wang, China University of Petroleum, prepared for the 2018 IADC/SPE Asia Pacific Drilling Technology Conference, Bangkok, 27–29 August. The paper has not been peer reviewed. The South China YQ Basin, with its 15 trillion m of natural gas, is typical of ultrahigh-pressure/high-temperature (ultra-HP/HT) plays, with the highest bottomhole temperature (BHT) at 249°C, the maximum bottomhole pressure (BHP) at 142 MPa, and an extremely narrow pressure window. Predictably, drilling challenges in these plays are numerous. This paper discusses the successful application of managed-pressure drilling (MPD) in the basin with reduction in risks and well costs. Overview of the YQ Basin In recent years, approximately 27% of major oil and gas discoveries have come from HP/HT fields. The South China YQ Basin is one of the three major offshore HP/HT regions in the world and is located at the intersection of the Eurasian, Pacific, and Indo-Australian plates and has a complex geological structure. The drilling in this basin, as is the case in any HP/HT area, faces various technical challenges, including the following: The temperature and pressure gradient is very high. The highest temperature gradient is 5.51°C/100 m. The formation-pressure transition zone is short, and the formation pressure rises rapidly. The safety drilling-fluid-density window between pore pressure and fracture pressure is extremely narrow, and the safety factor is very small. Formation pressure is hard to predict accurately, and the associated error is greater than 20% in some complex wells. Formation drillability is bad because the main targeted layer is over 5000 m. As a result, the rate of penetration (ROP) is very low, which leads to longer drilling cycles and more-frequent downhole accidents and issues such as casing wear. The natural environment is harsh (i.e., frequent typhoons in summer). Operational Design of MPD The operational design of MPD consists of three parts: the precise calculation of drilling-fluid equivalent circulating density (ECD), the optimization of operational parameters, and well control. Calculation of ECD. This process includes four models: Wellbore-temperature field model Drilling-fluid equivalent-static-density (ESD) model Drilling-fluid rheological-property model A model representing the effect of cuttings concentration on ECD The process involves the following four steps: Establish the instantaneous wellbore-temperature model on the basis of the convection and thermal conductivity theory by dividing the wellbore into five areas. Establish the ESD model by considering the elastic compression effect of high pressure and the thermal expansion effect of high temperature. Establish the drilling-fluid rheological property model on the basis of the Herschel-Bulkley model by considering the effect of ultra-HP/HT on dynamic shear force, consistency coefficient, and liquidity index. Consider the effects of cuttings concentration on ECD on the basis of the solid/liquid two-phase flow.
- Geology > Geological Subdiscipline (0.68)
- Geology > Structural Geology > Tectonics > Plate Tectonics (0.34)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > China Government (0.55)
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 191054, “Thailand Joint-Development Project Delivers 200°C MWD/LWD Triple Combination: Eliminating Wireline, Driving World-Class Efficiency, and Slashing Days Per Well,” by T. Kleawyothatis, SPE, and J. Pruimboom, SPE, Weatherford, and S. Dendandome, SPE, N. Pisarnbut, SPE, and P. Thipmongkolsilp, SPE, Chevron, prepared for the 2018 IADC/SPE Asia Pacific Drilling Technology Conference, Bangkok, 13–14 March. The paper has not been peer reviewed. A joint-development project has delivered a high-temperature measurement-while-drilling/logging-while-drilling (MWD/LWD) suite rated for 200°C. Results to date are compared with previous performance in the Gulf of Thailand (GoT). The new suite required a complete redesign of printed circuit board (PCB) electronics in order to meet the temperature-qualification criteria of 200 hours at 200°C with a survivability of 210°C for 4 hours. Background When the joint development of extreme-high-temperature tools began in May 2014, the goal of the collaboration was to eliminate wireline in wells with temperatures over 175°C. Historically, the need for wireline was driven by the requirement to identify hydrocarbons, measure reservoir properties, and book reserves in high-temperature wells; this was accomplished by using a wireline string consisting of gamma ray (GR), resistivity, formation- density, and neutron-porosity sensors. Because of the 175°C temperature limits of the available LWD technology at that time, there was no viable option to log these wells while drilling. This resulted in valuable rig time spent on additional trips to change out bottomhole assemblies (BHAs), mitigate temperatures, and run wireline to gather this data. This also increased the exposure to nonproductive-time (NPT) events, stuck wireline tools, or loss of data if these tools did not reach bottom. Thus, the requirement arose to log these wells while drilling to reduce days per well and improve data collection. To this end, the joint development of extreme-temperature LWD tools was initiated and staged in two phases. Phase 1 was the development of a 200°C-rated mud-pulse telemetry system, a bore- and annular-pressure-while-drilling tool, a GR tool, and a thermal neutron porosity tool. These were jointly developed within a 9-month period. Thirty-two wells were drilled with these tools with zero NPT and only two minor failures in secondary sensors before commercialization. A second phase of the development was endorsed to develop bulk-density and resistivity sensors to complete the triple-combo logging suite. This would ultimately deliver the principal objective of eliminating the need for running wireline. Phase 2 began in March 2015 and was given an 18-month window to deliver final products. The sensors required a complete re-design of all electronics to meet the temperature-qualification criteria outlined previously. Ten PCBs were designed and tested. The next step involved a thermal-vibration qualification by building up individual inserts, strapping them on a vibration table, and subjecting them to 15–20 Gs of random vibration while heated to 200°C. This harsh testing identified more modifications and re-designs needed until all inserts met these criteria. After completion of all testing, five complete prototypes were built and delivered on time and on budget in September 2016 to begin field trials.
Abstract IPIECA provides leadership on environmental issues for the oil and gas (O&G) industry through anticipating challenges, enabling improvements and informing members on key issues; a key platform for this is the use of training workshops, such as the Biodiversity and Ecosystem Services (BES) Peer-to-Peer Workshop Series. The BES Peer-to-Peer Workshop Series is highly beneficial for oil and gas industry practitioners. The platform allows increased awareness, uptake and operationalization of the BES approach and good practices by oil and gas companies, thus enabling companies to improve performance. Attendees receive comprehensive up-to-date training in BES; awareness of latest expectations, good practices, tools and practical examples associated with BES management in the oil and gas; ideas on how to build the business case for BES action within their organisations; benefits of insights around shared perspectives – challenges, opportunities and experiences from industry representatives; and, excellent networking opportunity with like-minded people in O&G industry. The workshop has been held in Paris, Houston and Bangkok, reaching 150+ individuals and 30+ oil and gas companies. To measure workshop success, IPIECA survey attendees. We evaluate whether BES management awareness has increased, participant critique of the workshop and, participant uptake of BES approaches and IPIECA guidance. To-date, results gathered from post-workshop surveys have been very positive. Attendees particularly highlight the quality of the workshop materials and the opportunity to hear case studies from industry professionals. The training workshops are a unique forum for industry outreach, particularly in regions that have only more recently begun developing their O&G resources. The next Peer-to-Peer Workshop is planned for May 2018, in South Africa.
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