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Soloviev, V., and G. D. Ginsburg. "Formation of submarine gas hydrates." Bulletin of the Geological Society of Denmark 41 (March 30, 1994): 86–94. http://dx.doi.org/10.37570/bgsd-1995-41-09.
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Submarine gas hydrates have been discovered in the course of deep-sea drilling (DSDP and ODP) and bottom sampling in many offshore regions. This paper reports on expeditions carried out in the Black, Caspian and Okhotsk Seas. Gas hydrate accumulations were discovered and investigated in all these areas. The data and an analysis of the results of the deep-sea drilling programme suggest that the infiltration of gas-bearing fluids is a necessary condition for gas hydrate accumulation. This is confirmed by geological observations at three scale levels. Firstly, hydrates in cores are usually associated with comparatively coarse-grained, permeable sediments as well as voids and fractures. Secondly, hydrate accumulations are controlled by permeable geological structures, i.e. faults, diapirs, mud volcanos as well as layered sequences. Thirdly, in the worldwide scale, hydrate accumulations are characteristic of continental slopes and rises and intra-continental seas where submarine seepages also are widespread. Both biogenic and catagenic gas may occur, and the gas sources may be located at various distances from the accumulation. Gas hydrates presumably originate from water-dissolved gas. The possibility of a transition from dissolved gas into hydrate is confirmed by experimental data. Shallow gas hydrate accumulations associated with gas-bearing fluid plumes are the most convenient features for the study of submarine hydrate formation in general. These accumulations are known from the Black, Caspian and Okhotsk Seas, the Gulf of Mexico and off northern California.
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Spence, Samantha, and Helge Kreutz. "The Kingfisher Field, Block 16/8a, UK North Sea." Geological Society, London, Memoirs 20, no. 1 (2003): 305–14. http://dx.doi.org/10.1144/gsl.mem.2003.020.01.26.
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AbstractThe Kingfisher Field is located in the South Viking Graben, Block 16/8a, with a minor extension into Block 16/8c. Block 16/8 was initially awarded in June 1970 to Shell and Esso, with the Kingfisher discovery well 16/8-1 spudded in 1972. The well tested high H2S oil at marginal rates from Upper Jurassic Brae Formation sandstones. Subsequent appraisal well 16/8a-4 (1984) tested gas/condensate from better quality Brae Formation sandstone reservoirs. This well also discovered the deeper Middle Jurassic Heather Formation sandstone gas/condensate accumulation at near-HPHT conditions. The Brae and Heather Formation sandstones contain stacked hydrocarbon accumulations in separate combinations of stratigraphic and structural traps. Production by natural aquifer drive commenced from a sub-sea satellite to Marathon's Brae B platform in 1997, initially from the Brae reservoirs. To date, three production wells have been completed and a fourth well is planned to be on stream in 2000. The Brae Formation sandstones at Kingfisher are interpreted as distal deposits of the Brae/Miller fan-apron system and range in quality from excellent to very poor across the field. The Heather Formation reservoir consists of medium quality sands deposited within a submarine incised valley. The most recent volumetric estimate (1998) for the total field predicts an ultimate recovery of 41.2 MMBBL of pipeline liquids and 280 BCF of dry export gas. Regional reservoir architecture and connectivity as well as hydrocarbon composition are key to understanding the production performance of the critical gas/condensate below dewpoint. Advances in sub-sea and horizontal drilling technology have enabled field development.
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Birch, Philip, and Jamie Haynes. "The Pierce Field, Blocks 23/22a, 23/27, UK North Sea." Geological Society, London, Memoirs 20, no. 1 (2003): 647–59. http://dx.doi.org/10.1144/gsl.mem.2003.020.01.51.
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AbstractThe Pierce Field contains oil and gas in Palaeocene Forties Sand and fractured Chalk, draped around the flanks of a pair of Central Graben salt diapirs. Whilst the two diapirs constitute a single field containing over 387 MMSTB AND 125 BCF, it took almost 25 years, and several advances in seismic, drilling and production technology, for the field to be brought into production. Many appraisal wells were drilled on the field. Data from these wells were interpreted to suggest the field was highly segmented both in terms of petroleum distribution and pressure variance. On the basis of this interpretation an economic development required a floating production system with long reach horizontal wells to penetrate the many reservoir segments. The results of development drilling have indicated that few pressure seals exist within the field, with concentric faults being more likely to seal than radial faults. The various reservoir pressures and oil-water contacts have been re-interpreted as a single, highly tilted oil-water contact, facilitated by the location of the field in the low permeability toe of the Forties submarine fan, a major conduit for the transport of basinal fluids away from the deep Central GrabenPalaeocene reservoir depositional patterns closely resemble those predicted by analogue models. The greatest reservoir thickness and net/gross are located in areas of flow velocity reduction (depletive flow), on the 'lee' side of the diapirs, but porosity and permeability are optimized in areas of increased flow velocity (accumulative flow), towards the crests of the diapirsStrontium residual salt analysis has been used to study the charge history of the field. Interpretation suggests that South Pierce was filled before North Pierce, from a local Upper Jurassic source kitchen. Oil and gas subsequently spilled into North Pierce to form a composite trap with a single, tilted oil-water contact. The South Pierce gas cap has since been breached, and the escape of gas is currently leading to the retreat of the tilted water contact, once again isolating the two diapir structures
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Underhill, John R. "The tectonic and stratigraphic framework of the United Kingdom's oil and gas fields." Geological Society, London, Memoirs 20, no. 1 (2003): 17–59. http://dx.doi.org/10.1144/gsl.mem.2003.020.01.04.
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AbstractOnshore exploration success during the first half of the 20th century led to petroleum production from many, relatively small oil and gas accumulations in areas like the East Midlands, North Yorkshire and Midland Valley of Scotland. Despite this, the notion that exploration of the United Kingdom's continental shelf (UKCS) might lead to the country having self-sufficiency in oil and gas production would have been viewed as extremely fanciful as recently as the late 1950s. Yet as we pass into the new century, only thirty-five years on from the drilling of the first offshore well, that is exactly the position Britain finds itself in. By 2001, around three million barrels of oil equivalent were being produced each day from 239 fields. The producing fields have a wide geographical distribution, occur in a number of discrete sedimentary basins and contain a wide spectrum of reservoirs that were originally deposited in diverse sedimentary and stratigraphic units ranging from Devonian to Eocene in age. Although carbonates are represented, the main producing horizons have primarily proved to be siliciclastic in nature and were deposited in environments ranging from aeolian and fluviatile continental red beds, coastal plain, nearshore beach and shelfal settings all the way through to deep-marine, submarine fan sediments. This chapter attempts to place each of the main producing fields into their proper stratigraphic, tectonic and sedimentological context in order to demonstrate how a wide variety of factors have successfully combined to produce each of the prospective petroleum play fairways and hence, make the UKCS such a prolific and important petroleum province.
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Jayakumar, K., K. Akash Koundinya, T. Jayakumar, M. Harshal, and G. Gopinath. "Experimental Studies on the Effect of Drilling Parameters on Monel Alloy." Materials Science Forum 979 (March 2020): 137–41. http://dx.doi.org/10.4028/www.scientific.net/msf.979.137.
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Monel K-500 is a Nickel based super alloy which have superlative properties such as high strength, resistance to corrosion, retention of mechanical properties at service temperature and structural stability. It finds wide application in aerospace application, nuclear reactor, gas turbines, submarines, combustion engine exhaust valve, petro chemical components, heat exchanger, etc. However, during machining of super alloys, difficulties are there due to its low thermal conductivity and work hardening effect. Challenges in conventional machining can be minimized by using suitable machining as well as process parameters. Among the different machining processes, not much work has been initiated on drilling of above super alloys. Normally, drilled holes are used in screws, bolts, shafts, steam pipes, fitting of furniture and other equipments. By considering the applications and difficulties in machining of super alloys, drilling experiment is selected on Monel K-500. Experiments were conducted as per Taguchi’s L9 orthogonal array using process parameters such as different drill tool material, drilling speed, feed and cutting fluids and Surface roughness and MRR values were measured as output responses. Effect of selected process parameters on the above machinability responses were analyzed. Optimum process parameters were identified to improve the machinability of Monel K-500.
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Frederick, J. B., E. J. Davies, P. G. Smith, D. Spancers, and T. J. Williams. "EXPLORATION OPPORTUNITIES, EAST COAST BASIN, NEW ZEALAND." APPEA Journal 40, no. 1 (2000): 39. http://dx.doi.org/10.1071/aj99003.
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The Westech-Orion Joint Venture holds onshore Petroleum Exploration Permit 38329 and offshore PEPs 38325, 38326 and 38333 in the East Coast Basin, New Zealand. The Joint Venture holds 24,117 km2 covering Hawkes Bay and the Wairarapa shelf.The Westech-Orion Joint Venture has drilled six exploratory wells and five appraisal wells in the onshore East Coast Basin over a two year period. All wells encountered significant gas shows, with two wells discovering hydrocarbons in potentially commercial volumes. Each well was drilled on the crest of a seismically mapped structure, characterised by asymmetric folding over a northwest dipping thrust fault.Prior to this drilling program, the reservoir potential of the Wairoa area was inferred to be dominated by turbidite sandstones of the Tunanui and Makaretu formations (Mid-Late Miocene). The new wells show that the Mid Miocene and parts of the Early and Late Miocene pinch out across the 'Wairoa High'.One of the primary onshore reservoirs is the Kauhauroa Limestone (Early Miocene), a bryozoan-dominated, tightly packed and cemented limestone with dominantly fracture porosity. The other primary reservoir is the Tunanui Sandstone (Mid Miocene), which in well intersections to date comprises medium-thickly bedded sandstone, with net sand typically 40%. The sands have high lithic content, and are moderately sorted and subangular-subrounded.Abnormally high formation pressures were encountered in all wells, ranging up to 3,400 psi at 1,000 m. Crestal pressure gradients commonly exceed 70% of the lithostatic pressure gradient, despite the relative proximity to outcrop. The overpressure may reflect relatively young uplift of fossil pressures, with insufficient time for pressure equilibration within a generally overpressured system.The prospectivity of the area has been highgraded by recent maturation and reservoir studies in Hawkes Bay and by gas discoveries in Westech-Orion wells onshore northern Hawkes Bay. Maturation studies identified nine kitchen areas with oil migration commencing in the Late Miocene. Seismic stratigraphy and correlation with onshore wells identified offshore submarine fan deposits of Eocene, Early Miocene, Mid Miocene and Pliocene age.A 594 km2 exploration 3D seismic survey was acquired in Hawke Bay in April 1999, and 685 km of 2D seismic were acquired in March 2000. Preliminary interpretation of the 3D survey has yielded five prospects, each covering 20–90 km2. One prospect is a lowstand fan identified by stacked mounding and bidirectional downlap, correlated with the onshore Mid Miocene Tunanui Sandstone. High amplitude seismic events of Mid-Late Miocene ages are inferred to be pulses of submarine fan development, in places associated with direct hydrocarbon indicators (DHIs). High amplitude seismic events in the Pliocene include a package of high amplitude seismic reflectors interpreted as structurally trapped DHI truncated by a major unconformity.
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Pelletier, F., and C. Gunn. "The Gryphon, Maclure, Tullich and Ballindalloch fields, Blocks 9/18b, 9/18c, 9/19a, 9/23d and 9/24e, UK North Sea." Geological Society, London, Memoirs 52, no. 1 (2020): 837–49. http://dx.doi.org/10.1144/m52-2018-91.
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AbstractThe Gryphon Field was discovered in 1987 in Quadrant 9 in the Beryl Embayment. Oil was encountered in a thick Balder Formation sandstone, and the reservoir was interpreted as lobes of a submarine fan system, such as many of the prolific early Tertiary fields in the North Sea. After an extensive appraisal phase, oil production started in 1993 through the Gryphon floating production, storage and offloading vessel.After a successful initial development phase, the integration of production data, improved and regularly acquired seismic data, and a better geological understanding resulted in the identification of sandstone intrusions. These have since been interpreted to form a volumetrically significant part of the Gryphon reservoir. The drilling of further infill wells, and the development of satellite fields Maclure, Tullich and the future Ballindalloch, ensued from this change to the geological model. To date, the Gryphon, Maclure and Tullich fields have produced more than 200 MMbbl of oil compared to an initial reserve estimate of 151 MMbbl.Although the current and mid-term focus remains on maximizing oil production, the final phase of the wider Gryphon area fields’ development should see the production of the regional gas cap.
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JPT staff, _. "E&P Notes (December 2020)." Journal of Petroleum Technology 72, no. 12 (December 1, 2020): 16–17. http://dx.doi.org/10.2118/1220-0016-jpt.
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China Shale-Gas Field Sets Production Record Sinopec recorded China’s highest daily output of shale gas at 20.62 million cubic meters (Mcm) at its Fuling shale-gas field in Chongqing, China, a key gas source for the Sichuan-East gas pipeline. The first major commercial shale-gas project in China, Fuling has continuously broken records for the shortest gasfield drilling cycle while significantly increasing the drilling of high-quality reservoirs covering more than 3 million m, according to Sinopec. Gasfield production construction was also expanded to raise production capacity. The company said the field maintains a daily output of 20 Mcm, producing an estimated 6.7 Bcm per year. Apache and Total Plan Suriname Appraisals Apache filed appraisal plans for its Maka and Sapakara oil discoveries in block 58 offshore Suriname. The company said another submission is expected for Kwaskwasi, the largest find in the block, by the end of the year. Operations continue for Keskesi, the fourth exploration target. There are plans to drill a fifth prospect at Bonboni in the North-Central portion of the concession. Partner company Total is assuming operatorship of the block ahead of next year’s campaigns. BP Emerges as Sole Bid for Offshore Canada Parcels BP was the only operator to place a bid in the Canada-Newfoundland and Labrador Offshore Petroleum Board (C-NLOPB) Call for Bids NL20-CFB01, which offered 17 parcels (4,170,509 hectares) in the eastern Newfoundland region. The successful bid was for Parcel 9 (covering 264,500 hectares) for $27 million in work commitments from BP Canada Energy Group. Subject to BP satisfying specified requirements and receiving government approval, the exploration license will be issued in January 2021. No bids were received for the remaining 16 parcels, which may be reposted in a future Call for Bids. Criteria for selecting a winning bid is the total amount the bidder commits to spend on exploration of the parcel during the first period of a 9-year license, with a minimum acceptable bid of $10 million in work commitments for each parcel. Beach Energy To Drill Otway Basin Well Beach Energy plans to drill at its Artisan-1 well about 32 km offshore Victoria, Australia, in the Otway basin, before the end of 2021. The well, located on Block Vic/P43, was to be spudded in 1H 2020 but was delayed due to COVID-19. The timeframe for drilling was confirmed by the National Offshore Petroleum Safety and Environmental Management Authority, which also said Beach is keeping open the option to suspend the well and develop it, pending reservoir analysis. Anchors, mooring chains, and surface buoys have already been laid for the well, which is in a water depth of approximately 71 m. The well is expected to take approximately 35–55 days to drill, depending on the final work program and potential operational delays. Diamond Offshore’s semisubmersible Ocean Onyx was contracted for the drilling program. Artisan is the first of Beach’s planned multiwell campaigns, which also include development wells at the Geographe and Thylacine fields. Hess Completes Sale of Interest in Gulf of Mexico Field Hess completed the sale of its 28% working interest in the Shenzi Field in the deepwater Gulf of Mexico (GOM) to BHP, the field’s operator, for $505 million. Shenzi is a six-lease development structured as a joint ownership: BHP (operator, 44%), Hess (28%), and Repsol (28%). The acquisition would bring BHP’s working interest to 72%, adding approximately 11,000 BOE/D of production (90% oil). The sale is expected to close by December 2020. Hess CEO John Hess said proceeds from the sale will help fund the company’s investment in Guyana. Greenland Opens New Offshore Areas Greenland opened three new offshore areas for application of oil and gas exploitation licenses off West Greenland. The areas are Baffin Bay, Disko West, and Davis Strait. The country also said it is working on an oil strategy to reduce geological uncertainty by offering an investment package to companies that engage in its Open Door Procedures. The procedures are a first-mover advantage to remove national oil company Nunaoil, as a carried partner, reducing turnover and surplus royalties. It is estimated to reduce the government take by 51.3% to 40.6%. Shell and Impact Oil & Gas Agree to South Africa Farmout Africa Oil announced Impact Oil & Gas entered into two agreements for exploration areas offshore South Africa. The company has a 31.10% share-holding in Impact, a privately owned exploration company. Impact entered into an agreement with BG International, a Shell subsidiary, for the farm-out of a 50% working interest and operatorship in the Transkei and Algoa exploration rights. Shell was also granted the option to acquire an additional 5% working interest should the joint venture (JV) elect to move into the third renewal period, expected in 2024. Algoa is located in the South Outeniqua Basin, east of Block 11B/12B, containing the Brulpadda gas condensate discovery and where Total recently discovered gas condensate. The Transkei block is northeast of Algoa in the Natal Trough Basin where Impact has identified highly material prospectivity associated with several large submarine fan bodies, which the JV will explore with 3D seismic data and then potential exploratory drilling. Impact and Shell plan to acquire over 6,000 km² of 3D seismic data during the first available seismic window following completion of the transaction. This window is expected to be in the Q1 2022. After the closing of the deal, Shell will hold a 50% interest as the operator and Impact will hold 50%. Impact also entered into an agreement with Silver Wave Energy for the farm-in of a 90% working interest and operatorship of Area 2, offshore South Africa. East and adjacent to Impact’s Transkei and Algoa blocks, Area 2 complements Impact’s existing position by extending the entire length of the ultradeepwater part of the Transkei margin. Together, the Transkei and Algoa Blocks and Area 2 cover over 124,000 km2. Area 2 has been opened by the Brulpadda and Luiperd discoveries in the Outeniqua Basin and will be further tested during 2021 by the well on the giant Venus prospect in ultradeepwater Namibia, where Impact is a partner. Impact believes there is good evidence for this Southern African Aptian play to have a common world-class Lower Cretaceous source rock, similar excellent-quality Apto-Albian reservoir sands, and a geological setting suitable for the formation of large stratigraphic traps. Following completion of the farm-in, Impact will hold 90% interest and serve as the operator; Silver Wave will hold 10%. Petronas Awards Sarawak Contract to Seismic Consortium The seismic consortium comprising PGS, TGS, and WesternGeco was awarded a multiyear contract by Petronas to acquire and process up to 105,000 km2 of multisensor, multiclient 3D data in the Sarawak Basin, offshore Malaysia. The contract award follows an ongoing campaign by the consortium in the Sabah offshore region, awarded in 2016, in which over 50,000 km2 of high-quality 3D seismic data have been acquired and licensed to the oil and gas industry to support Malaysia license round and exploration activity. The Sarawak award will allow for a multiphase program to promote exploration efforts in the prolific Sarawak East Natuna Basin (Deepwater North Luconia and West Luconia Province). The consortium is planning the initial phases and is engaging with the oil and gas industry to secure prefunding ahead of planned acquisition, covering both open blocks and areas of existing farm-in opportunities. Total Discovers Second Gas Condensate in South Africa Total made a significant second gas condensate discovery on the Luiperd prospect, located on Block 11B/12B in the Outeniqua Basin, 175 km off the southern coast of South Africa. The discovery follows the adjacent play-opening Brulpadda discovery in 2019. The Luiperd-1X well was drilled to a total depth of about 3,400 m and encountered 73 m of net gas condensate pay in well-developed, good-quality Lower Cretaceous reservoirs. Following a coring and logging program, the well will be tested to assess the dynamic reservoir characteristics and deliverability. The Block 11B/12B covers an area of 19,000 km2, with water depths ranging from 200 to 1800 m. It is operated by Total with a 45% working interest, alongside Qatar Petroleum (25%), CNR International (20%), and Main Street, a South African consortium (10%). The Luiperd prospect is the second to be drilled in a series of five large submarine fan prospects with direct hydrocarbon indicators defined utilizing 2D and 3D seismic data. BP Gas Field Offshore Egypt Begins Production BP started gas production from its Qattameya gasfield development offshore Egypt in the North Damietta offshore concession. Through BP’s joint venture Pharaonic Petroleum Company working with state-owned Egyptian Natural Gas Holding Co., the field, which is expected to produce up to 50 MMcf/D, was developed through a one-well subsea development and tieback to existing infrastructure. Qattameya, whose discovery was announced in 2017, is located approximately 45 km west of the Ha’py platform, in 108 m of water. It is tied back to the Ha’py and Tuart field development via a new 50-km pipeline and connected to existing subsea utilities via a 50-km umbilical. BP holds 100% equity in the North Damietta offshore concession in the East Nile Delta. Gas production from the field is directed to Egypt’s national grid.
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Yamada, Tomomi, and Yoshiyuki Okano. "A Volcanic Reservoir: Integrated Facies Distribution Modeling and History Matching of a Complex Pressure System." SPE Reservoir Evaluation & Engineering 10, no. 01 (February 1, 2007): 77–85. http://dx.doi.org/10.2118/93159-pa.
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Summary A Tcf-class gas field has been producing over several decades in Japan. The reservoir body comprises stacked rhyolite lava domes erupted in a submarine environment. A porous network developed in each dome and rapid chilling on contact with seawater caused hyaloclastite to be deposited over it. Although hyaloclastite is also porous in this field, its permeability has been reduced dramatically by the presence of clay minerals. Impermeable basaltic sheets and mudstone seams are also present. Each facies plays a specific role in the pressure system. Stratigraphic correlation originally identified multiple reservoirs. Gas has been produced almost exclusively from the largest one. However, following 10 to 20 years of production, the pressures within unexploited reservoirs were noticed to have declined at a variety of rates. Unusual localized behavior has also been observed. Because seismic data were not proved particularly informative, we decided to remodel the entire system by specifically using pressure data. We employed a combination of multipoint geostatistics and probability perturbation theories. This approach successfully captured the curved facies boundaries within stacked lava domes while accounting for pressure data by means of history matching to address nonstationarity in the real field. Building a suitable training image is commonly a difficult aspect of multipoint methods and poses particular problems for volcanic reservoirs. It was accomplished here by iteratively adjusting the prototype until satisfactory history matching was achieved with a reasonable number of perturbations. Ambiguous reservoir boundaries were represented stochastically by populating a predetermined model space with pay and nonpay pixels. The modeling results closely simulate measured pressure histories and appear realistic in terms of both facies distributions and reservoir boundaries. They suggest that uneven pressure declines between different units are caused by the tortuous flow channels that connect them. The results also account for the unusual smaller-scale pressure performances observed. The final training image obtained here indicates more intensive spatial variations in facies than previously appreciated. Original gas in place (OGIP) estimates made with 20 equiprobable realizations are scattered within ±15% of the mean value. Estimates of incremental recovery made by drilling a step-out well reveal greater variation than those made by installing a booster compressor, which quantifies a higher associated geological risk.
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MINAMI, KAZUO. "Development well drilling on Iwaki gas field." Journal of the Japanese Association for Petroleum Technology 51, no. 2 (1986): 160–73. http://dx.doi.org/10.3720/japt.51.160.
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Denney, Dennis. "Offshore HP/HT Gas Well: Drilling and Well Testing." Journal of Petroleum Technology 65, no. 04 (April 1, 2013): 111–15. http://dx.doi.org/10.2118/0413-0111-jpt.
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Tang, Yang, Jiaxin Yao, Guorong Wang, Yin He, and Peng Sun. "Analysis of Multi-Phase Mixed Slurry Horizontal Section Migration Efficiency in Natural Gas Hydrate Drilling and Production Method Based on Double-Layer Continuous Pipe and Double Gradient Drilling." Energies 13, no. 15 (July 23, 2020): 3792. http://dx.doi.org/10.3390/en13153792.
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In order to improve the recovery efficiency of natural gas hydrate in solid-state fluidized mining of natural gas hydrate, we solve drilling safety problems, such as narrow density of natural gas hydrate formation pressure window and poor wellbore stability caused by high upstream velocity during drilling and production. In this study—in order to increase the natural gas hydrate output and reduce production costs—based on the principle of the solid-state fluidized mining, a natural gas hydrate drilling method based on double-layer continuous-pipe double-gradient drilling was proposed to solve the above problems. The article introduces a drilling and production tool combination scheme and the mathematical model of wellbore-pressure dynamic regulation. Simulation software was used to study and compare the migration efficiency of multiphase mixed slurries of sediment and natural gas hydrates in the horizontal section of the double-layer continuous-pipe double-gradient drilling method and traditional drilling method. The results show that the transport efficiency of the multiphase mixed slurry of sediment and natural gas hydrate in the horizontal section of the double-layer continuous-pipe double-gradient drilling method is better than the traditional drilling method under the same conditions. When the double-layer continuous-pipe double-gradient drilling method is adopted, the multiphase mixed slurry of sediment and natural gas hydrate is transported in the pipe and has the function of the submarine lift pump, which effectively avoids the problem of the stability of the shaft wall caused by excessive flow velocity. This will also be more suitable for the transportation of large-diameter particles during the solid-state fluidized mining of natural gas hydrates.
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Wang, Xiujuan, Shiguo Wu, Yiqun Guo, Shengxiong Yang, and Yuehua Gong. "Geophysical Indicators of Gas Hydrate in the Northern Continental Margin, South China Sea." Journal of Geological Research 2011 (October 17, 2011): 1–8. http://dx.doi.org/10.1155/2011/359597.
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Gas hydrate drilling results show that gas hydrate has a close relationship with strong bottom-simulating reflectors (BSRs) identified from seismic data in the Baiyun sag, South China Sea. The BSRs observed on seismic profiles at the crests of submarine canyons indicate the likely existence of gas hydrate. We calculate the acoustic impedance using constrained sparse spike inversion (CSSI), the interval velocity, and the seismic reflection characteristics such as reflection strength, instantaneous frequency, blanking, and enhanced reflection to demonstrate the presence of gas hydrate. Higher acoustic impedance and P-wave velocity were identified above the BSR. A remarkable low impedance, low frequency, and acoustic blanking indicated the presence of gas below gas hydrate stability zone. The occurrence of gas hydrate at the crests of canyons suggests that the abundance of gas hydrate in Baiyun sag may be due to the migrating submarine canyons providing the structural reliefs and the topographic ridges.
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Zazarli Shah, Mohamad Safwan, Arina Sauki, Wan Zairani Wan Bakar, Nurul Aimi Ghazali, and Azlinda Azizi. "Drilling Fluid Design for Shale Gas Drilling." Advanced Materials Research 1113 (July 2015): 617–24. http://dx.doi.org/10.4028/www.scientific.net/amr.1113.617.
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Shale gas nowadays is an important source of unconventional gas. The limited conventional gas supply makes the unconventional sources as a new source of gas. In this research, the aim is to design a mud formulation that can carry out essential functions of mud for shale gas drilling. Commonly for shale gas drilling, water based mud is used. However, water based mud is ineffective when dealing with water-sensitive shale. The alternative way to deal with this type of shale is using synthetic-based mud (SBM) or oil-based mud (OBM). OBM is an effective mud while drilling well. However, it is toxic and gives negative impact to environment. SBM somehow is more environmental friendly compared to oil based and ester is one of the synthetic based fluids. In order to prove this statement, a toxicity test was carried out to investigate the impact of ester based mud on selected marine life. The results of the test were compared with past research results. The ester use in this research is methyl-ester C12-C14 derived from palm oil and the mud was formulated at different oil-water ratios which are 70/30, 80/20 and 90/10, respectively and the best rheological performance can be seen at 80/20 oil-water ratio. Then, the performance of this mud had been compared to other types of mud which are sarapar-based and WBM. The findings revealed that the rheological performance of ester based mud is comparable with common based mud used for shale gas drilling. Apart from that, it is less toxic than other based mud which can maintain 60% prawn’s survival even after 96 hours exposure in 100,000 ppm of mud concentration in artificial seawater.
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Liu, Yang, Zhuo Pu He, Qi Ma, and Yu Hang Yu. "Horizontal Well Penetration Rate Increasing Technology in Sulige Gas Field." Applied Mechanics and Materials 733 (February 2015): 17–22. http://dx.doi.org/10.4028/www.scientific.net/amm.733.17.
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In order to improve the drilling speed, lower the costs of development and solve the challenge of economies of scale development in sulige gas field, the key techniques research on long horizontal section of horizontal well drilling speed are carried out. Through analyzing the well drilling and geological data in study area, and supplemented by the feedback of measured bottom hole parameters provided by underground engineering parameters measuring instrument, the key factors restricting the drilling speed are found out and finally developed a series of optimum fast drilling technologies of horizontal wells, including exploitation geology engineering technique, strengthen the control of wellbore trajectory, optimize the design of the drill bit and BHA and intensify the drilling parameters. These technologies have a high reference value to improve the ROP of horizontal well in sulige gas field.
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Li, Yan Jun, Xiang Nan He, Xiao Wei Feng, Ya Qi Zhang, Ling Wu, Xiang Fang Li, Kai Wen Huang, Yi Huang, and Li Min Luo. "Well Control Technology of High Temperature and High Pressure with Different Well Shapes." Applied Mechanics and Materials 316-317 (April 2013): 860–66. http://dx.doi.org/10.4028/www.scientific.net/amm.316-317.860.
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Well control safe is the prerequisite of safety drilling, especially for high temperature and high pressure horizontal wells. However, there are few papers about well control of horizontal well drilling, which mostly learn from vertical well control process. By means of analysis of the theory of gas kick, we conclude that underbalance, the bottom hole pressure is less than the formation pressure is the main means of gas invasion. During balance period, the gas also intrudes into wellbore through the way of direct invasion, diffusion invasion and replacement invasion, but the amount of gas kick is less, so the risk of well control is small. This paper also anlyses the kick tolerance, the kick tolerance decreases with the increasing of drilling fluid density when the formation pressure and drilling equipment is constant.
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Sun, Shi Hui, Tie Yan, Xue Liang Bi, and Peng Wang. "Analysis on the Influence Factors of Well Deviation in Gas Drilling." Advanced Materials Research 577 (October 2012): 132–36. http://dx.doi.org/10.4028/www.scientific.net/amr.577.132.
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Well deviation control has become a bottleneck restraining the development of gas drilling. Without lubrication of drilling fluid and the existence of negative pressure differential, the reasons of well deviation in gas drilling are different from in mud drilling. The effects of stress distribution difference, rock-breaking mechanism, well bore enlargement and water export on well deviation during both gas drilling and mud drilling are compared and studied on the basis of the previous studies in this paper. The conclusion demonstrates that the new stress state of the bottom rock, the uneven crater which is formed by rock breaking and the borehole enlargement are the main causes of well deviation during gas drilling.
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Pavlovskaya, A. V., and O. A. Serebro. "Innovation effectiveness in oil and gas well drilling." Problems of Economics and Management of Oil and Gas Complex, no. 5 (2018): 21–26. http://dx.doi.org/10.30713/1999-6942-2018-5-21-26.
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Yan, Chuanliang, Jingen Deng, Baohua Yu, Lianbo Hu, Zijian Chen, Hai Lin, and Xiaorong Li. "Fracturing Pressure in Oil and Gas Well Drilling." Research Journal of Applied Sciences, Engineering and Technology 5, no. 19 (May 10, 2013): 4775–79. http://dx.doi.org/10.19026/rjaset.5.4318.
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Rommetveit, Rolv, and Anette Blyberg. "Simulation of gas kicks during oil well drilling." Modeling, Identification and Control: A Norwegian Research Bulletin 10, no. 4 (1989): 213–25. http://dx.doi.org/10.4173/mic.1989.4.3.
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Spanos, P. D., A. M. Chevallier, N. P. Politis, and M. L. Payne. "Oil and Gas Well Drilling: A Vibrations Perspective." Shock and Vibration Digest 35, no. 2 (March 1, 2003): 85–103. http://dx.doi.org/10.1177/0583102403035002564.
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Mao, Liangjie, Mingjie Cai, Qingyou Liu, and Guorong Wang. "Dynamical well-killing simulation of a vertical H2S-containing natural gas well." Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles 75 (2020): 71. http://dx.doi.org/10.2516/ogst/2020065.
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This work aims to explore the dynamical well-killing process of a vertical H2S-containing natural gas well. A dynamical well-killing model considering an H2S solubility was established to simulate the overflow and well-killing process of a vertical H2S-containing natural gas well. The mass and momentum equations of the coupled model were solved using finite difference method, while the transient temperature prediction model was solved using finite volume method. The coupled model was validated by reproducing experimental data and field data of Well Tiandong #5. The effect of H2S content, mud displacement, drilling fluid density, and initial overflow volume on the dynamical well-killing process of an H2S-containing natural gas well were obtained and analyzed in this work. Results showed that H2S will gasify near wellhead during well killing when casing pressure decreases. To balance the bottom hole pressure, when H2S releases, the casing pressure increases as H2S content increases. As initial overflow volume increases, the annular temperature, annular pressure and the casing pressure increase significantly. When H2S gasifies, the casing pressure applied at wellhead should be higher at lower initial overflow volume to balance bottom hole pressure. In the well-killing process, the annular pressure and temperature decrease as drilling fluid density increases and a lower casing pressure is needed for balancing bottom hole pressure. The casing pressure is lower at a higher displacement for higher friction resistance. Besides, as well-killing displacement increases H2S will gasify at an earlier time. When drilling for H2S-containing natural gas well, early detection of gas kick should be more frequent to avoid severe overflow. Besides, higher displacement and density of drilling fluid should be considered to avoid stratum fracturing and prevent leakage accidents under the premise of meeting drilling requirements.
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Huang, Yi, Jin Yang, Lingyu Meng, Xuyue Chen, Ming Luo, and Wentuo Li. "Numerical Investigation on Gas Accumulation and Gas Migration in the Wavy Horizontal Sections of Horizontal Gas Wells." Mathematical Problems in Engineering 2020 (August 12, 2020): 1–9. http://dx.doi.org/10.1155/2020/7275209.
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Wavy horizontal sections are typically encountered in horizontal gas wells, which will result in gas accumulation on top of the wavy horizontal sections. This gas accumulation can be a problem and may trigger gas kick or blowout accident while tripping and pulling this gas into the vertical section. In this paper, a numerical model for gas accumulation and gas migration in the wavy horizontal sections of the horizontal gas well is developed; meanwhile, the gas accumulation and gas migration process is numerically investigated. The results show that the gas exhausting time in the wavy horizontal section increases with the increase of the wellbore curvature and the critical drilling fluid flow velocity for gas exhausting increases with the increase of the wellbore curvature. When the drilling fluid flow velocity is higher than the critical drilling fluid flow velocity for gas exhausting, no gas accumulation will occur. With all other parameter values set constant, the number of the wavy horizontal sections has a great effect on the gas-liquid flow pattern while it has little effect on the efficiency of the gas exhausting. This work provides drilling engineers with a practical tool for designing the drilling fluid flow velocity to avoid gas kick or blowout accident in horizontal gas well drilling.
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Lukawski, Maciej Z., Brian J. Anderson, Chad Augustine, Louis E. Capuano, Koenraad F. Beckers, Bill Livesay, and Jefferson W. Tester. "Cost analysis of oil, gas, and geothermal well drilling." Journal of Petroleum Science and Engineering 118 (June 2014): 1–14. http://dx.doi.org/10.1016/j.petrol.2014.03.012.
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McNeill, Lisa, Brandon Dugan, Katerina Petronotis, Kitty Milliken, and Jane Francis. "Late Miocene wood recovered in Bengal–Nicobar submarine fan sediments by IODP Expedition 362." Scientific Drilling 27 (May 27, 2020): 49–52. http://dx.doi.org/10.5194/sd-27-49-2020.
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Abstract. Drilling and coring during IODP Expedition 362 in the eastern Indian Ocean encountered probably the largest wood fragment ever recovered in scientific ocean drilling. The wood is Late Miocene in age and buried beneath ∼800 m of siliciclastic mud and sand of the Bengal–Nicobar Fan. The wood is well preserved. Possible origins include the hinterland to the north, with sediment transported as part of the submarine fan sedimentary processes, or the Sunda subduction zone to the east, potentially as a megathrust tsunami deposit.
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Wei, Na, Ying-Feng Meng, Gao Li, Ping Guo, An-Qi Liu, Tian Xu, and Wan-Tong Sun. "Foam drilling in natural gas hydrate." Thermal Science 19, no. 4 (2015): 1403–5. http://dx.doi.org/10.2298/tsci1504403w.
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The key problem of foam drilling in natural gas hydrate is prediction of characteristic parameters of bottom hole. The simulation shows that when the well depth increases, the foam mass number reduces and the pressure increases. At the same depth, pressure in drill string is always higher than annulus. The research findings provide theoretical basis for safety control.
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Li, Gao, Ying-Feng Meng, Na Wei, Zhao-Yang Xu, Hong-Tao Li, Gui-Lin Xiao, and Yu-Rui Zhang. "Gas reservoir evaluation for underbalanced horizontal drilling." Thermal Science 18, no. 5 (2014): 1691–94. http://dx.doi.org/10.2298/tsci1405691l.
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A set of surface equipment for monitoring the parameters of fluid and pressure while drilling was developed, and mathematical models for gas reservoir seepage and wellbore two-phase flow were established. Based on drilling operation parameters, well structure and monitored parameters, the wellbore pressure and the gas reservoir permeability could be predicted theoretically for underbalanced horizontal drilling. Based on the monitored gas production along the well depth, the gas reservoir type could be identified.
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Xie, Gang, Ming Yi Deng, Jun Lin Su, and Liang Chun Pu. "Study on Shale Gas Drilling Fluids Technology." Advanced Materials Research 868 (December 2013): 651–56. http://dx.doi.org/10.4028/www.scientific.net/amr.868.651.
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Via discussing the advantages and disadvantages of different types of oil-based drilling fluids, the main reason why oil-based drilling fluids are less used in our country is obtained that dont form a complete series of matching technology. The essence of wellbore instability caused by using water-based drilling fluids to drill shale is analyzed that the formation collapse pressure is greater than drilling fluids column pressure. The fundamental way of controlling borehole wall stability that use water-based drilling fluids to drill shale horizontal well was proposed that deeply researched the shale hydration mechanism, developed efficient blocking agent and inhibitors and established shale gas drilling fluid suppression system, which made water-based drilling fluids have excellent performance.
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Li, Ben, Hui Li, Boyun Guo, Xiao Cai, and Mas lwan Konggidinata. "A New Numerical Solution To Predict the Temperature Profile of Gas-Hydrate-Well Drilling." SPE Journal 22, no. 04 (February 13, 2017): 1201–12. http://dx.doi.org/10.2118/185177-pa.
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Summary Gas-hydrate cuttings are conveyed upward by the drilling fluid through the outer drillpipe/wellbore annulus during the gas-hydrate-well-drilling process. The temperature profile along the wellbore during the drilling process has not been thoroughly investigated because the gas-hydrate cuttings could affect the temperature of the drilling fluid along the wellbore. As the mixture of drilling fluid and gas hydrates flows from the bottom to the surface, the methane and other hydrocarbons present in the gas hydrates would change from liquid to gas phase and further cause well-control issues. Furthermore, the bottomhole pressure would decrease and could not provide sufficient balance to the formation pressure, which could significantly increase the risk of well blowout. A numerical solution is presented in this paper to predict the temperature profile of the gas-hydrate well during the drilling process. The main considerations were the following: Hydrate cuttings entrained in the bottom of the hole would affect the temperature of the fluid in the annulus space. The entrained hydrate cuttings could affect the fluid thermal properties in the drillstring and in the annulus. Because of the Joule-Thomson cooling effect at the outlet of the nozzles, the fluid temperature at the bottom of the hole was lower than that above the drill-bit nozzles. Hence, the gas-hydrate-dissociation characteristics were considered and integrated in the proposed numerical model. The numerical model was validated by comparing the obtained data with the Shan et al. (2016) analytical model. In addition, the obtained data were also compared with the measured temperature data of a conventional well drilled in China and a gas-hydrate-well drilling record in India. Sensitivity analysis was used to evaluate the effects of the pumping rate, Joule-Thomson effect, and injection drilling-mud temperature on the annulus temperature-profile distribution. It was found that the injection drilling-mud temperature and pumping rate could affect the temperature profile in the annulus, whereas the Joule-Thomson effect could decrease the annulus temperature of the drilling mud near the bottom.
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Foroud, Toomaj. "Well Deviation Problem: A Case Study in an Iranian Gas Well Drilling." International Journal of Petroleum Technology 7, no. 1 (July 25, 2020): 7–19. http://dx.doi.org/10.15377/2409-787x.2020.07.2.
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Rayner, Nathan, Ross Hendrie, and Michael Bowe. "Producing gas from low permeability coals." APPEA Journal 50, no. 2 (2010): 719. http://dx.doi.org/10.1071/aj09083.
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An assessment framework for selecting optimal drilling and completion, forecasting and operating procedures in low permeability coals. Themes covered: low permeability coal drilling and production alternatives; production forecasting and operating procedures; and, economics and technical feasibilty. Arrow Energy Limited has been exploring for and producing from moderate to low permeability coals for over eight years, both in Australia and internationally. Arrow has developed a systematic approach to assessing the optimal drilling and completion, forecasting and operating procedures to evaluate the best appraisal and development options. Following the confirmation that the coal resource is of low permeability (less than 5mD) the selection of the drilling and completion strategies is inter-linked with the expected production and operating procedures. This paper summarises the approach taken by each of these discipline areas and maps out the key alternatives, data requirements and selection criteria used to recommend a production pilot in a low permeability environment. The first stage of the assessment is to review the drilling alternatives. This includes consideration of horizontal versus deviated or vertical wells, wellbore stability and solids production conditions, stimulation requirements and the production string, including artificial lift. Production forecasting is conducted with due regard to the technical alternatives screened as part of the drilling assessment. The quality of the forecast will be determined by the available data and the use of the appropriate forecasting tools ranging from analogue assessments, simple single well modelling through to 3D reservoir modelling. Finally, the production procedures appropriate for the well will be selected based on the well configuration and forecast deliverability as well as regional geology and geomechanics. This framework ensures that a consistent methodology is applied for selecting well type and operations that maximises the flow potential from our low permeability coals while ensuring due consideration to economics and technical feasibility.
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Zhu, Zhong Xi, Gong Hui Liu, Jun Li, and Meng Bo Li. "Gas Drilling Cuttings Breaking on Return." Applied Mechanics and Materials 90-93 (September 2011): 151–56. http://dx.doi.org/10.4028/www.scientific.net/amm.90-93.151.
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More cuttings producing in higher penetration rate of gas drilling are usually in the larger non-uniform size at the bottom and in the smaller uniform size back to the wellhead. It is indicating that cuttings in the well should be appeared in the successive breaking in the process of upward migration. According to the particle broken theories, the successive breaking phenomenon were analyzed, and given the calculating method for the probability of secondary impact crushing, and applied the breaking process matrix and the particle size distribution function to the cuttings migration crushing in the whole wellbore. The calculating results show that the cuttings in the wellbore are broken by the uneven size volumetric fracture progressively turned into the surface fracture of the uniform process, and ultimately stabilized the small size distribution.
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Liu, Li, Guo Sheng Jiang, Fu Long Ning, Yi Bing Yu, Ling Zhang, and Yun Zhong Tu. "Well Logging in Gas Hydrate-Bearing Sediment: A Review." Advanced Materials Research 524-527 (May 2012): 1660–70. http://dx.doi.org/10.4028/www.scientific.net/amr.524-527.1660.
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In exploration for natural gas hydrates, drilling, coring and well logging are the most important access to make deep understanding of the nature of hydrate reservoirs, besides the seismic prospecting methods. Because of the harsh conditions for hydrate stability and the complex of occurrence formations, the drilling and coring generally have a great difficulty and high cost. Therefore, the well logging becomes the priority method. The resistivity and sonic logging method, which were applied as the earliest logging method in the evaluation of hydrate reserviors, have been continuously applied ever since and the evaluation results derived from them have a relative accuracy and reliability. Other logging tools, such as borehole imaging, density, electromagnetic, nuclear magnetic resonance, etc. are also used to make integrated interpretation and evaluation for the hydrate reservoirs. Until now the applied porosity and hydrate saturation evaluation models are better suitable to the homogeneous reservoirs. However, they still need to be amended or improved for the anisotropism (e.g., fracture sediment) and shale-rich reservoirs. In addition, the external factors such as drilling fluid washout and invasion will also affect the well logging results. The combination of various well logging methods is an effective way to improve the accuracy of identification and quantification of hydrate reservoirs.
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Zhou, Fengde, Glen Fernandes, Joao Luft, Kai Ma, Mahmoud Oraby, Mariano Ospina Guevara, Dan Kuznetsov, Brad Pinder, and Sean Keogh. "Impact of in-seam drilling performance on coal seam gas production and remaining gas distribution." APPEA Journal 59, no. 1 (2019): 328. http://dx.doi.org/10.1071/aj18049.
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Drilling horizontal wells in low permeability coal seams is a key technology to increase the drainage area of a well, and hence, decrease costs. It’s unavoidable that some parts of the horizontal section will be drilled outside the targeted coal seam due to unforeseen subsurface conditions, such as sub-seismic faulting, seam rolls, basic geosteering tools, drilling practices and limited experiences. Therefore, understanding the impact of horizontal in-seam drilling performance on coal seam gas (CSG) production and remaining gas distribution is an important consideration in drilling and field development plans. This study presents a new workflow to investigate the impact of horizontal in-seam performance on CSG production and gas distribution for coal seams with different porosity, permeability, permeability anisotropy, initial gas content (GC), initial gas saturation and the ratio of in-coal length to in-seam length (RIIL). First, a box model with an area of 2 km × 0.3 km × 6 m was used for conceptual simulations. Reduction indexes of the cumulative gas production at the end of 10 years of simulations were compared. Then, a current Chevron well consisting of a vertical well and two lateral wells, was selected as a case study in which the impact of outside coal drilling on history matching and remaining gas distribution were analysed. Results show that the RIIL plays an increasing role for cases with decreasing permeability or initial gas saturation, while it plays a very similar role for cases with varied porosity, permeability anisotropy and GC. The size and location of outside coal drilling will affect the CSG production and remaining gas distribution.
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Wang, Fu Hua, Rui He Wang, and Xue Chao Tan. "How to Improve Rate of Penetration for Oil and Gas Wells." Advanced Materials Research 524-527 (May 2012): 1439–49. http://dx.doi.org/10.4028/www.scientific.net/amr.524-527.1439.
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Improved optimization of drilling bit selection and the compatibility between drilling bit and formation constraint the ROP and cost of deep well drilling to some extent. This combined with lab comprehensive lab drilling simulations and mechanisms of rock penetration can hold promise for improving drilling efficiency in deep wells. This paper reviews the mechanical characteristic parameters of rock engineering and demonstrates the obstacle of rock penetration in deep wells. Based on the general predictable formula of ROP, the relationship between drilling sensitive index and formation drillability is analyzed and the optimization and optimal match of drilling technology parameters are described. Technology Benefit Index (TBI) is proposed to evaluate the technical performance of drilling bit, advices and warnings from lab experiment and field experience on selecting and using bit are put forward. Statistical analysis of Well A based on TBI is made, the analysis of ROP improvement potential and overall program (including Bottom Hole Assembly, drilling parameters and type of drilling bit) of ROP improvement for Well B are worked out. Suggestions of drilling bit using based on mechanisms of rock penetration are proposed. Guided by the theory on improving ROP field tests of improving drilling rate are conducted to examine the field performance. By comparison, the tested sections yield high performance of ROP improvement. The designed program enhancing ROP for experiment section proves to be operable and shows great promise in further improvement and application.
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Sellars, Andrew, Thivanka Dedigama, and Mohammad Zaman. "Roma development drilling – evolution of well design and drilling performance." APPEA Journal 59, no. 2 (2019): 814. http://dx.doi.org/10.1071/aj18254.
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Santos’ Roma field, located in the Surat Basin, has been producing coal seam gas (CSG) since 1988; however, development drilling did not commence until 2011. Since this time, well design has evolved to maximise access to coals and operability for artificial lift systems. Concurrently, performance has dramatically improved through scale of sanctioned work programs and revised contracting strategies, enabling continuous and sustainable time and cost reductions. This paper reviews Santos’ development drilling activity in the Roma CSG field since 2011, highlighting critical events and step changes. The following aspects are addressed: • Evolution of well design: A series of well designs have been trialled, ranging from deviated to vertical, fracture stimulated to open-hole slotted liner well types. Collaboration with both Reservoir Engineering and Production Operations have been critical in arriving at a fit-for-purpose design. • Effect of the industry downturn: The industry downturn spanning 2014–2016 presented an opportunity to reset and rationalise execution approach. • Operating and contracting model: The updated model focused on utilising a consistent, fit-for-purpose rig fleet and service companies, supported by lean office and field based operations teams. • Benefits of large scale, continuous work programs: The scale and continuity of operations are key to achieving continuous and sustainable time and cost reductions. • Opportunities: Future opportunities have been identified for ongoing optimisation in a changing market.
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Horn, M. J., and D. P. Plathey. "New Well Architectures Increase Gas Recovery and Reduce Drilling Costs." SPE Drilling & Completion 13, no. 03 (September 1, 1998): 144–50. http://dx.doi.org/10.2118/51184-pa.
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Fang, Qiang, Yingfeng Meng, Hongtao Li, Na Wei, and Gao Li. "Transient Pressure Fluctuation Effect During Gas Drilling in Horizontal Well." Chemistry and Technology of Fuels and Oils 55, no. 4 (September 2019): 497–507. http://dx.doi.org/10.1007/s10553-019-01056-y.
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Wei, Na, Yang Liu, Zhenjun Cui, Lin Jiang, Wantong Sun, Hanming Xu, Xiaoran Wang, and Tong Qiu. "The Rule of Carrying Cuttings in Horizontal Well Drilling of Marine Natural Gas Hydrate." Energies 13, no. 5 (March 3, 2020): 1129. http://dx.doi.org/10.3390/en13051129.
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Horizontal well drilling is a highly effective way to develop marine gas hydrate. During the drilling of horizontal wells in the marine gas hydrate layer, hydrate particles and cutting particles will migrate with the drilling fluid in the horizontal annulus. The gravity of cuttings is easy to deposit in the horizontal section, leading to the accumulation of cuttings. Then, a cuttings bed will be formed, which is not beneficial to bring up cuttings and results in the decrease of wellbore purification ability. Then the extended capability of the horizontal well will be restricted and the friction torque of the drilling tool will increase, which may cause blockage of the wellbore in severe cases. Therefore, this paper establishes geometric models of different hole enlargement ways: right-angle expansion, 45-degree angle expansion, and arc expanding. The critical velocity of carrying rock plates are obtained by EDEM and FLUENT coupling simulation in different hydrate abundance, different hydrate-cuttings particle sizes and different drilling fluid density. Then, the effects of hole enlargement way, particle size, hydrate abundance and drilling fluid density on rock carrying capacity are analyzed by utilizing an orthogonal test method. Simulation results show that: the critical flow velocity required for carrying cuttings increases with the increase of the particle size of the hydrate-cuttings particle when the hydrate abundance is constant. The critical flow velocity decreases with the increase of drilling fluid density, the critical flow velocity carrying cuttings decreases with the increase of hydrate abundance when the density of the drilling fluid is constant. Orthogonal test method was used to evaluate the influence of various factors on rock carrying capacity: hydrate-cuttings particle size > hole enlargement way > hydrate abundance > drilling fluid density. This study provides an early technical support for the construction parameter optimization and well safety control of horizontal well exploitation models in a marine natural gas hydrate reservoir.
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Wei, Na, Ying-Feng Meng, Gao Li, Yong-Jie Li, An-Qi Liu, Jun-Xi Long, Chun-Yan Xin, and Sheng-Bin Wen. "Cuttings-carried theory and erosion rule in gas drilling horizontal well." Thermal Science 18, no. 5 (2014): 1695–98. http://dx.doi.org/10.2298/tsci1405695w.
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In gas horizontal drilling, the gas with cuttings will go through the annulus at high speed which will lead strong erosion to the drill tools. This paper proposes a cuttings-carried theory and modified the critical cuttings-carried model for the gas-solid flow. Meanwhile, the erosive energy is obtained through simulating the gas-solid mixture in different conditions. The study result has positive significance on the determination of reasonable injection volume by optimizing construction parameters of horizontal well in gas drilling.
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Han, Guo You, Xi Sheng Zhang, and Xiu Hua Du. "The Application of BOP During Oil Well Drilling." Advanced Materials Research 1094 (March 2015): 419–22. http://dx.doi.org/10.4028/www.scientific.net/amr.1094.419.
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This is an introduction to brief application of blowout preventers and accessory equipment. Fluid (either liquid or gas) erupts from the well, usually with great force, and often ignites into a roaring inferno, especially if the fluid is gas. The trouble arises when the pressure in the formation is higher than that in the well. The pressure in the well is maintained by the type and amount of drilling fluid being circulated through it. Blowout preventers(BOPs), in conjunction with other equipment and techniques, are used to close the well in and allow the crew to control a kick before it becomes a blowout.
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Yaremiychuk, R. S. "DRILLING OF OIL AND GAS BORE: YESTERDAY, TODAY, TOMORROW." PRECARPATHIAN BULLETIN OF THE SHEVCHENKO SCIENTIFIC SOCIETY Number, no. 2(46) (December 14, 2018): 191–96. http://dx.doi.org/10.31471/2304-7399-2018-2(46)-191-196.
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The article deals with development of bore drilling technologies over the past 150 years. Rotor drilling and drilling with turbo booms, electric drills, screw engines are analyzed.According to the author drilling operations of bores should consist of two parts the first of which provides maximum possible drilling speed, and the second – the proper disclosure of productive strata.When implementing the first and second parts of the project it is recommended to use service system for the implementation of certain types of work with the involvement of specialists of the profile. This applies in the first place to the regulation of the properties of washing liquids, the modes of their circulation in the well, and also the processes of fixing the walls of the well. According to the author service companies should also be involved in all types of recovery of filtration characteristics of reservoir layers.
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Song, Yuan Hong, Fei Gao, Fu Hai Zhong, Xuan Yin, Jin Bo Wu, and Li Ying Tang. "Application of Extension Hanger in Gas Well Cementation of Narrow Layers Pressure Windows." Advanced Materials Research 868 (December 2013): 597–600. http://dx.doi.org/10.4028/www.scientific.net/amr.868.597.
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As a cat well in Mahudang of Burma on anticline structure zone, YH-1 encountered narrow formation pressure window stratum in the process of drilling with the problem that loss of filtration is serious and the speed of air cutting rises rapidly. Application of drilling liner hanger into cementation, combined with expansive slurry system in well YH-1 has met cementing requirements. Well sections are qualified and sealing sections of high quality amount to 49.4 percent. The field application results display that the usage of drilling liner hanger in narrow formation pressure window well section, associated with appropriate slurry system are able to satisfy well cementation requirements.
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Moore, G. F., K. Kanagawa, M. Strasser, B. Dugan, L. Maeda, and S. Toczko. "IODP Expedition 338: NanTroSEIZE Stage 3: NanTroSEIZE plate boundary deep riser 2." Scientific Drilling 17 (January 7, 2014): 1–12. http://dx.doi.org/10.5194/sd-17-1-2014.
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Abstract. The Nankai Trough Seismogenic Zone Experiment (NanTroSEIZE) is designed to investigate fault mechanics and seismogenesis along a subduction megathrust, with objectives that include characterizing fault slip, strain accumulation, fault and wall rock composition, fault architecture, and state variables throughout an active plate boundary system. Integrated Ocean Drilling Program (IODP) Expedition 338 was planned to extend and case riser Hole C0002F from 856 to 3600 meters below the seafloor (m b.s.f.). Riser operations extended the hole to 2005.5 m b.s.f., collecting logging-while-drilling (LWD) and measurement-while-drilling, mud gas, and cuttings data. Results reveal two lithologic units within the inner wedge of the accretionary prism that are separated by a prominent fault zone at ~ 1640 m b.s.f. Due to damage to the riser during unfavorable winds and strong currents, riser operations were suspended, and Hole C0002F left for re-entry during future riser drilling operations. Contingency riserless operations included coring at the forearc basin site (C0002) and at two slope basin sites (C0021 and C0022), and LWD at one input site (C0012) and at three slope basin sites (C0018, C0021 and C0022). Cores and logs from these sites comprehensively characterize the alteration stage of the oceanic basement input to the subduction zone, the early stage of Kumano Basin evolution, gas hydrates in the forearc basin, and recent activity of the shallow megasplay fault zone system and associated submarine landslides.
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Huang, Wan Long, Yi Shan Lou, Xiao Yong Ma, Hai Min Xu, and Qiang Wang. "Performance Evaluation and Application of the Non-Clay Weak Gel Drilling Fluid for Daniudi Gas Field." Advanced Materials Research 781-784 (September 2013): 2861–64. http://dx.doi.org/10.4028/www.scientific.net/amr.781-784.2861.
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Daniudi Gas Field reservoir has low degree of porosity and permeability, thus it is highly susceptible to the invasion of the solid phase of clay particles in the drilling fluid during the drilling process, in view of these problems, we introduce the non-clay weak gel drilling fluid system. Experiments of the drilling fluid system for rheological property, salt-resisting pollution, hot rolling rate of recovery, reservoir damage evaluation and drilling fluid treating chemical opimization have been taken. The experimental results show that the drilling fluid system has excellent temperature-resisting and salt-resisting character, good ability of suspending debris and strong inhibitory action, its rheological property can meet the needs of the long horizontal section of drilling engineering and the reservoir protection effect is excellent. In DP21 well horizontal section construction, each performance indicator of the drilling fluid can be controlled well and effectively solve the problems of cuttings carrying, borehole wall stability and reservoir protection, successfully completed the DP21 well drilling construction task.
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Xu, Zhengming, Xianzhi Song, Gensheng Li, Zhaopeng Zhu, and Bin Zhu. "Gas kick simulation in oil-based drilling fluids with the gas solubility effect during high-temperature and high-pressure well drilling." Applied Thermal Engineering 149 (February 2019): 1080–97. http://dx.doi.org/10.1016/j.applthermaleng.2018.12.110.
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Xu, Dong, Ling Bi Wang, Hong Xiang Zhao, and Su Hu. "The Experience & Enlightenment from Low-Cost Strategy of Shale Gas Development in America." Advanced Materials Research 986-987 (July 2014): 771–74. http://dx.doi.org/10.4028/www.scientific.net/amr.986-987.771.
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The experience of shale gas low-cost development in America provided production organization and management methods including horizontal well drilling, cluster well drilling, pad drilling, batch drilling, factory drilling, and reservoir volume fracturing. The policy of finance and taxation has played a positive role in promoting and encouraging shale gas development. The development of shale gas in China is different from America in sides of resource features, development process, the technical levels and the policy environment. We should learn from the technical means, management method and encouraging fiscal and financial policy of low-cost development strategy of America, study and formulate policy suitable to China's own characteristics, to promote low-cost development of shale gas.
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Zhuralov, Yu I. "USE EFFICIENCY OF THE FLEXIBLE CONNECTIONS (FC) OF DECK MECHANISMS." Ship power plants 39, no. 1 (May 5, 2019): 143–49. http://dx.doi.org/10.31653/smf39.2019.143-149.
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Statement of the problem in a general case and its connection with the important scientific or practical problems. The flexible connections (FC) of large length are used at towages, deep-water well-drilling and other works in the marine economy complex of Ukraine as a part of ship power plants. The solving of the problem for an estimation of oscillations in flexible working tools of large length will allow to reduce the terms and amount of the works related to their assembling, and, in turn, will bring down the expenses on acquisition and exploitation (FC). The deriving of the oscillations ’ equations (FC) is of undoubted interest, since they can be used for the study of the World ocean, investigation and exploitation of submarine mineral deposits, submarine geology and topography, choice of routes of submarine cable lines and pipelines, control of works’ quality on their laying, study of the sea ecology.
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Ju, Pengfei, Zhiyi Yang, Weixuan Li, Yong Guo, and Zhongxi Zhu. "Minimum gas injection of gas drilling while temperature and pressure coupling." E3S Web of Conferences 198 (2020): 02005. http://dx.doi.org/10.1051/e3sconf/202019802005.
Full textAbstract:
Gas drilling technology not only has the advantages of avoiding well leakage, shale hydration expansion,reservoir pollution and other issues, but also can greatly improve the drilling speed 4 to 8 times, it is helpful to timely discover and effectively protect reservoir and improve recovery efficiency and single well production of oil and gas reservoir, especially has important significance for hard strata and dense reservoir exploration. However, there are some problems hindered the promotion of this technology, such as gas is hard to carries cuttings and gas hole blocking. One of the key technologies to solve these problems is the determination of gas volume. Most of today’s literature use formation temperature instead of annulus temperature to calculate minimum gas volume. Owing to gas’ PVT effect, temperature is dramatically influenced by pressure flow velocity, there will be big error if we use formation temperature instead of annulus temperature. Meanwhile, most of traditional minimum gas volume methods use top of the drill collar as key point. In this study, we found that on the top of the drill collar, the carrying kinetic energy of gas is not is not necessarily the minimum, and change of the key position is strongly influenced by wellbore structure and make-up of drill tool. Minimum gas volume determined by applying temperature - pressure coupling calculation is more close to site construction, under the given conditions, error of the minimum gas volume is about 0.4%.
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Khalifeh, Mahmoud, Larisa Penkala, Arild Saasen, Bodil Aase, Tor Henry Omland, Knut Taugbøl, and Lorents Reinås. "Gel Pills for Downhole Pressure Control during Oil and Gas Well Drilling." Energies 13, no. 23 (November 30, 2020): 6318. http://dx.doi.org/10.3390/en13236318.
Full textAbstract:
During drilling of petroleum or geothermal wells, unforeseen circumstances occasionally happen that require suspension of the operation. When the drilling fluid is left in a static condition, solid material like barite may settle out of the fluid. Consequently, the induced hydrostatic pressure that the fluid exerts onto the formation will be reduced, possibly leading to collapse of the borehole or influx of liquid or gas. A possible mitigation action is placement of a gel pill. This gel pill should preferably be able to let settled barite rest on top of it and still transmit the hydrostatic pressure to the well bottom. A bentonite-based gel pill is developed, preventing flow of higher density drilling fluid placed above it to bypass the gel pill. Its rheological behavior was characterized prior to functional testing. The designed gel pill develops sufficient gel structure to accommodate the settled barite. The performance of the gel was tested at vertical and 40° inclination from vertical. Both conventional settling and the Boycott effect were observed. The gel pill provided its intended functionality while barite was settling out of the drilling fluid on top of this gel pill. The barite was then resting on top of the gel pill. It is demonstrated that a purely viscous pill should not be used for separating a high density fluid from a lighter fluid underneath. However, a bentonite or laponite gel pill can be placed into a well for temporary prevention of such intermixing.