To see the other types of publications on this topic, follow the link: Offshore drilling (Petroleum).
Journal articles on the topic 'Offshore drilling (Petroleum)'
Create a spot-on reference in APA, MLA, Chicago, Harvard, and other styles
Consult the top 50 journal articles for your research on the topic 'Offshore drilling (Petroleum).'
Next to every source in the list of references, there is an 'Add to bibliography' button. Press on it, and we will generate automatically the bibliographic reference to the chosen work in the citation style you need: APA, MLA, Harvard, Chicago, Vancouver, etc.
You can also download the full text of the academic publication as pdf and read online its abstract whenever available in the metadata.
Browse journal articles on a wide variety of disciplines and organise your bibliography correctly.
1
Krassay, Andrew, Jane Blevin, and Donna Cathro. "Exploration highlights for 2007." APPEA Journal 48, no. 1 (2008): 395. http://dx.doi.org/10.1071/aj07028.
Full textAbstract:
Record-high oil prices along with on-going development of infrastructure, increasing domestic demand and international LNG sales continued to drive significant investment in exploration in onshore and offshore Australia during 2007. These trends are reflected nationally by strong uptake of acreage and continued high levels of drilling activity and seismic acquisition. Overall, drilling and discovery trends were similar to 2006 which showed significant exploration activity focussed on proven hydrocarbon basins (Carnarvon, Browse, Perth and Cooper basins). Most petroleum discoveries made in 2007 were located within 10 to 15 km of existing fields. In terms of number of exploration wells, the offshore Carnarvon continued to dominate with over 20 new field wildcats drilled. Discoveries include a major deep-water gas find for BHP-Billiton at Thebe-1 on the outer Exmouth Plateau, Apache’s gas finds at Brunello–1, Julimar–1 and Julimar East–1, oil for Santos at Fletcher–1 and gas at Lady Nora–1 for Woodside. The Browse Basin saw a significant increase in drilling activity with some success. Exploration in the offshore southwest margin received a major boost with a series of shallow-water discoveries for ROC Oil in the Perth Basin with gas at Frankland–1 395and Perseverance–1 and gas and oil at Dunsborough–1. Onshore, the Cooper/Eromanga basins continued to experience the highest level of drilling activity and seismic acquisition. This activity resulted in numerous small to moderate oil discoveries for Santos, Beach Petroleum, Eagle Bay Resources, Stuart Petroleum and Victoria Petroleum. There were a few notable exceptions to near-field exploration in 2007 with several wildcats drilled in frontier regions including PetroHunter Energy and Sweetpea Petroleum’s Shanendoah–1 in the Georgina/Betaloo basins, Austin’s Gravestock–1 in the onshore Stansbury Basin and the onshore drilling campaign by ARC Energy in the Canning Basin. In Queensland, CSM exploration and discovery continued to experience strong positive growth underpinned by delivery to local markets.
2
Brooks, Deidre. "2012 PESA industry review—exploration." APPEA Journal 53, no. 1 (2013): 141. http://dx.doi.org/10.1071/aj12012.
Full textAbstract:
The Australian exploration landscape experienced an escalation of unconventional activity in 2012. Drilling targeting shale oil and gas, basin-centred tight gas, and coal gas is on the increase compared to previous years. Drilling for onshore oil and large offshore gas continued to be a staple activity for the year although, in general, offshore, the number of wells drilled is continuing to decline, in line with previous years. A number of very large 3D seismic surveys were acquired in 2012 and this is hoped to provide many future drilling targets. Within Australia, 19 new offshore conventional petroleum exploration permits were awarded within the Commonwealth jurisdiction (compared to 24 in 2011), of which 15 are located in WA, two in Victoria, one in NT, and one in the Territory of Ashmore and Cartier Islands (NT). Onshore exploration tenures awarded in 2012 included four in WA, 14 in NT, six in Queensland, and nine conventional and six geothermal in SA. At least 25 3D and six 2D seismic surveys were acquired offshore in 2012, including some very large 3D marine surveys, the largest covering an area of 12,417 km2. Onshore seismic activity was highest in Queensland and SA where 33 and 11 surveys were acquired, respectively. Offshore, 21 conventional petroleum exploration wells were drilled during the year, which resulted in 11 announced discoveries. Two exploration wells, which were spudded late in 2011, were announced as discoveries early in 2012. Five wells, which were spudded in 2012, were still drilling at year end. This equates to a better than 50% technical success rate for offshore exploration drilling for all well results known at year end. All but two of these wells were located in WA waters, the others being located in NT and Victoria. Australia-wide onshore drilling was more active than in 2011 and, as is reflected in the seismic activity, the most wells (1,048) were drilled in Queensland (dominated by CSG drilling), followed by SA (77).
3
Brkić, Dejan, and Pavel Praks. "Proper Use of Technical Standards in Offshore Petroleum Industry." Journal of Marine Science and Engineering 8, no. 8 (July 24, 2020): 555. http://dx.doi.org/10.3390/jmse8080555.
Full textAbstract:
Ships for drilling need to operate in the territorial waters of many different countries which can have different technical standards and procedures. For example, the European Union and European Economic Area EU/EEA product safety directives exclude from their scope drilling ships and related equipment onboard. On the other hand, the EU/EEA offshore safety directive requires the application of all the best technical standards that are used worldwide in the oil and gas industry. Consequently, it is not easy to select the most appropriate technical standards that increase the overall level of safety and environmental protection whilst avoiding the costs of additional certifications. We will show how some technical standards and procedures, which are recognized worldwide by the petroleum industry, can be accepted by various standardization bodies, and how they can fulfil the essential health and safety requirements of certain directives. Emphasis will be placed on the prevention of fire and explosion, on the safe use of equipment under pressure, and on the protection of personnel who work with machinery. Additionally considered is how the proper use of adequate procedures available at the time would have prevented three large scale offshore petroleum accidents: the Macondo Deepwater Horizon in the Gulf of Mexico in 2010; the Montara in the Timor Sea in 2009; the Piper Alpha in the North Sea in 1988.
4
Rahman, S. S. "Technoeconomic Model for Offshore Supply Operations." Journal of Energy Resources Technology 110, no. 2 (June 1, 1988): 102–8. http://dx.doi.org/10.1115/1.3231362.
Full textAbstract:
The vital role of logistic support for maintaining uninterrupted drilling operations is well known to offshore petroleum engineers. Moreover, its importance is growing as exploration and production activities are extended to progressively deeper water and harsher weather conditions. However, no systematic approach for ensuring effective logistic support has yet been realized. A method of studying the characteristics of logistic support and of designing a system for securing effective supply to an offshore rig is proposed. It is based on event simulation modeling of offshore supply operations, together with more conventional technical and economic models for yielding economic criteria which take into account a possible interruption of drilling operations. The method has been developed through a detailed investigation of each component of the supply operation and of the inherent problems. To evaluate the feasibility of the approach, an example has been provided.
5
Lockhart, D., and D. Spring. "PESA Australian exploration review 2018." APPEA Journal 59, no. 2 (2019): 493. http://dx.doi.org/10.1071/aj18284.
Full textAbstract:
Available data for 2018 indicates that exploration activity is on the rise in Australia, compared to 2017, and this represents a second year of growth in exploration activity in Australia. There has been an increase in area under licence by 92 000 km2, reversing the downward trend in area under licence that commenced in 2014. Since 2016, exploratory drilling within Australia has seen a continued upward trend in both the number of wells drilled and the percentage of total worldwide. Onshore, 77 conventional exploration and appraisal wells were spudded during the year. Offshore, exploration and appraisal drilling matched that seen in 2017, with five new wells spudded: two in the Roebuck Basin, two in the Gippsland Basin and one in the North Carnarvon Basin. Almost 1500 km of 2D seismic and over 10 000 km2 of 3D seismic were acquired within Australia during 2018, accounting for 2.4% and 3.9% of global acquisition, respectively. This represents an increase in the amount of both 2D and 3D seismic acquired in Australia compared with 2017. Once the 2017 Offshore Petroleum Acreage Release was finalised, seven new offshore exploration permits were awarded as a result. A total of 12 bids were received for round one of the 2018 Offshore Petroleum Exploration Release, demonstrating an increase in momentum for offshore exploration in Australia. The permits are in Commonwealth waters off Western Australia, Victoria and the Ashmore and Cartier islands. In June 2018, the Queensland Government announced the release of 11 areas for petroleum exploration acreage in onshore Queensland, with tenders closing in February/March 2019; a further 11 areas will be released in early 2019. The acreage is a mix of coal seam gas and conventional oil and gas. Victoria released five areas in the offshore Otway Basin within State waters. In the Northern Territory, the moratorium on fracking was lifted in April, clearing the way for exploration to recommence in the 2019 dry season. With the increase in exploration has come an increase in success, with total reserves discovered within Australia during 2018 at just under 400 million barrels of oil equivalent, representing a significant increase from 2017. In 2018, onshore drilling resulted in 18 new discoveries, while offshore, two new discoveries were made. The most notable exploration success of 2018 was Dorado-1 drilled in March by Quadrant and Carnarvon Petroleum in the underexplored Bedout Sub-basin. Dorado is the largest oil discovery in Australia of 100 million barrels, or over, since 1996 and has the potential to reinvigorate exploration in the region.
6
Pinzone, Giulio B. "Challenges and lessons learned from environmental approvals for drilling in frontier offshore basins, using the Great Australian Bight as an example." APPEA Journal 57, no. 2 (2017): 514. http://dx.doi.org/10.1071/aj16005.
Full textAbstract:
The recent withdrawal of BP Developments Australia Pty Ltd from its exploration drilling efforts in the Great Australian Bight (GAB) has brought focus to the challenges of obtaining environmental approvals for offshore petroleum exploration projects, particularly in frontier, deep-water basins such as the GAB. In preparing the first two environment plan (EP) submissions for the BP GAB drilling exploration project, Aventus Consulting Pty Ltd has come across numerous such challenges, which are summarised in the present paper.
7
Toldo, Elírio E., Ricardo N. Ayup-Zouain, and Sérgio A. Netto. "Environmental monitoring of offshore drilling for petroleum exploration (MAPEM Project): shallow waters." Environmental Monitoring and Assessment 167, no. 1-4 (June 2, 2010): 1–5. http://dx.doi.org/10.1007/s10661-010-1514-4.
Full text
8
Toldo, Elírio E., and Ricardo N. Ayup Zouain. "Environmental monitoring of offshore drilling for petroleum exploration (MAPEM): A brief overview." Deep Sea Research Part II: Topical Studies in Oceanography 56, no. 1-2 (January 2009): 1–3. http://dx.doi.org/10.1016/j.dsr2.2008.10.002.
Full text
9
Bate, K. J., and F. G. Christiansen. "The drilling of stratigraphic borehole Umiivik-1, Svartenhuk Halvø, West Greenland." Bulletin Grønlands Geologiske Undersøgelse 172 (January 1, 1996): 22–27. http://dx.doi.org/10.34194/bullggu.v172.6738.
Full textAbstract:
Svartenhuk Halvø is one of the few areas onshore West Greenland where Upper Cretaceous and Lower Tertiary marine sediments are exposed (Fig. 1). Geological studies in the area have been made intermittently since the late 1930s but have intensified since 1990 as part of the Survey's overall effort to assess the petroleum potential of the Disko - Nuussuaq - Svartenhuk Halvø area and adjacent offshore basins.
10
Li, Zhi Yong, Shui Xiang Xie, Guang Cheng Jiang, Mu Tai Bao, Zhi Li Wang, Xian Bin Huang, and Fan Xu. "The Use of Biotreatment Technology to Dispose of Offshore Drilling Waste Oily Fluids." Advanced Materials Research 424-425 (January 2012): 592–97. http://dx.doi.org/10.4028/www.scientific.net/amr.424-425.592.
Full textAbstract:
Disposing of oil-based drilling fluid with biotreatment technology has many advantages: it is only 30-50% of the expense of conventional chemical or physical processing technologies, has a low impact on the environment, with no secondary pollution, and utilizes local control and entails simple operations. After a series of collection, isolation, purification, cultivation and domestication of petroleum degrading bacterial, three strains were obtained that can effectively degrade petroleum hydrocarbons. The growth of the bacterial strains and the consequent crude oil degradation were found to be at the greatest rates using the following biochemical processing conditions. The strains were grown in ammonium nitrate and a small quantity of yeast powder at a temperature of 50°C and pH of 6.0. The strain quantity was 2%, and the rotating speed of the shaker was 180rpm. The biochemical disposal process and laboratory-scale simulation of processing devices of oil-based drilling fluid were also designed. The oil content of disposed oily waste mud generally was generally less than 2mg/L, and the degradability of the waste was over 98%. The performance index meets the requirement of the China’s offshore wastewater discharge standards.
11
Shannon, Patrick M. "Old challenges, new developments and new plays in Irish offshore exploration." Geological Society, London, Petroleum Geology Conference series 8, no. 1 (December 15, 2016): 171–85. http://dx.doi.org/10.1144/pgc8.12.
Full textAbstract:
AbstractMore than 46 years of exploration in the Irish offshore has yielded modest commercial success. However, working petroleum systems have been proven in all the offshore basins. The pace of exploration has been controlled by: (a) data quality and technological advances; (b) geological understanding and plays; (c) fiscal and infrastructural environments; and (d) international conditions. Irish offshore exploration drilling started in the Celtic Sea basins in 1970 and the region has seen a recent renewal of exploration interest, stimulated by new and much improved seismic data. In the Atlantic margin basins west of Ireland, there has been a recent significant improvement in the understanding of the geological evolution and petroleum systems, especially in the hyperextended basins such as the Porcupine and Rockall basins. Here the major targets of current exploration are stratigraphic traps at Lower Cretaceous and Lower Cenozoic levels. The application of new and innovative seismic and other geophysical technologies in a number of the Irish offshore basins has led to significant enhancement in data quality and in resolving imaging challenges. Combined with recent geological learnings, they offer renewed hope for exploration success in the Irish offshore basins.
12
Yang, Yuan. "Reforming Health, Safety, and Environmental Regulation for Offshore Operations in China: Risk and Resilience Approaches?" Sustainability 11, no. 9 (May 7, 2019): 2608. http://dx.doi.org/10.3390/su11092608.
Full textAbstract:
Offshore drilling accidents have triggered regulatory reforms in China. The reforms aim to explore proper regulatory approaches to supervise offshore operations and improve their health, safety and environmental (HSE) performance. This study offers a review on the roles of risk and resilience in managing offshore operations and a well-defined analysis on their integrations with Chinese laws and regulations. The study finds risk and resilience approaches can promote the effectiveness of HSE regulation for offshore operations, while both are difficult to be transposed into legally binding rules in China. To fully develop and implement risk regulation for offshore operations, the study suggests to decentralize China’s command-and-control regulatory regime and encourage self-regulation in offshore petroleum companies. Transposing resilience thinking into legal practice is also highlighted so that various regulatory powers can keep proactive and flexible to any possible changes and uncertainties.
13
Fainstein, Roberto, Ana Krueger, and Webster Ueipass Mohriak. "Ultra-deepwater seismic plays offshore Brazil — Future drilling off Santos and Campos Basins." Interpretation 7, no. 4 (November 1, 2019): SH99—SH109. http://dx.doi.org/10.1190/int-2018-0251.1.
Full textAbstract:
Contemporaneous seismic data acquisition in the Santos and Campos Basins offshore Brazil have focused on image characterization of deepwater and ultra-deepwater reservoirs and their relationship with hydrocarbons originating from synrift source rocks. Our interpretation has mapped the stratigraphy of postsalt turbidite reservoirs, and, on the presalt lithology, it has uncovered the underlying synrift sequences that embrace oil-bearing source rocks and the prolific, recently discovered, microbialite carbonate reservoirs. The new phase in geophysical data acquisition and offshore drilling that started in 1999 bolstered the Brazilian offshore petroleum production to record levels. The new, massive, nonexclusive, speculative 2D and 3D data acquisition surveys conducted offshore the Brazilian coast far exceed the amount of all existing cumulative vintage data. Deepwater drilling programs probed the interpreted new prospects. As whole, the modern geophysics data libraries offshore Brazil brought in the technology era to seismic interpretation, reservoir characterization, and geosteering operations in deepwater development drilling. Still, regional interpretation mapping of the outer shelf, slope, deepwater and ultra-deepwater provinces of the Santos and Campos Basins indicates plenty of prospective future drilling in the salt locked minibasins of the ultra-deepwater provinces. Salt tectonics shapes the architecture of these basins; hence, postsalt deepwater turbidite plays were readily interpreted from seismic amplitudes of the modern data that also allow for resolution images of the synrift source rocks, salt architecture, migration paths through faulting and salt windows, reservoir characterization, and regional seal mapping. The new techniques of prestack depth migration have enabled uncovering the imaging structure of the synrift that led to characterization of the presalt carbonate reservoirs and discovery of giant accumulations. Future offshore exploration will continue aiming at postsalt deepwater and ultra-deepwater minibasins plus presalt plays under the massive salt walls, still an underexplored frontier.
14
Ismail, Zubaidah, Keen Kuan Kong, Siti Zulaikha Othman, Kim Hing Law, Shin Yee Khoo, Zhi Chao Ong, and Sharif Muniruzzaman Shirazi. "Evaluating accidents in the offshore drilling of petroleum: Regional picture and reducing impact." Measurement 51 (May 2014): 18–33. http://dx.doi.org/10.1016/j.measurement.2014.01.027.
Full text
15
Wright, D. J., and S. R. le Poidevin. "DEVELOPMENT OPTIONS FOR OFFSHORE OIL AND GAS FIELDS: IMPLICATIONS FOR OPTIMUM LONG-TERM RECOVERY." APPEA Journal 32, no. 1 (1992): 391. http://dx.doi.org/10.1071/aj91030.
Full textAbstract:
Technology used in the Australian offshore oil and gas industry in recent years has diversified with the introduction of innovative concepts for field developments. These innovations are aimed at cost reduction and greater access to reserves, especially those in small and remote fields. Further innovations are anticipated as research progresses in several areas of potential cost reduction. Changes in technology can dramatically affect the relative economics of data acquisition, contingency planning and the extent of field development. Drilling and workover economics, well servicing, reservoir surveillance and the opportunities for infrastructure development are strongly dependent on the choice of development technology. These choices, in turn, have implications for long-term recovery, including the discovery and development of new pools and extensions to known pools, overall field recovery factors, the opportunities for development of gas caps and nearby fields, and the future potential for enhanced oil recovery (EOR).Government involvement in development approvals in various countries has diverse objectives. The Australian Petroleum (Submerged Lands) Act specifies as one objective the optimum long-term recovery of petroleum. Critical areas of interest are pre-development planning with necessarily incomplete information, the phenomenon of unexpected reserves growth, and provision for contingencies such as well failures. Early drilling and completion decisions and infrastructure planning have major effects on future developments. Subjects of direct relevance for future improvements in development economics include reductions in pipeline construction costs, reductions in the cost of drilling from mobile rigs and flexibility in completion design.
16
Ivanov, A. N., M. M. Veliev, and V. A. Bondarenko. "Historical aspects of the offshore exploratory drilling at the rise of Vietnam petroleum industry." Neftyanoe khozyaystvo - Oil Industry, no. 4 (2019): 38–43. http://dx.doi.org/10.24887/0028-2448-2019-4-38-43.
Full text
17
Cox, David R., Paul C. Knutz, D. Calvin Campbell, John R. Hopper, Andrew M. W. Newton, Mads Huuse, and Karsten Gohl. "Geohazard detection using 3D seismic data to enhance offshore scientific drilling site selection." Scientific Drilling 28 (December 1, 2020): 1–27. http://dx.doi.org/10.5194/sd-28-1-2020.
Full textAbstract:
Abstract. A geohazard assessment workflow is presented that maximizes the use of 3D seismic reflection data to improve the safety and success of offshore scientific drilling. This workflow has been implemented for International Ocean Discovery Program (IODP) Proposal 909 that aims to core seven sites with targets between 300 and 1000 m below seabed across the north-western Greenland continental shelf. This glaciated margin is a frontier petroleum province containing potential drilling hazards that must be avoided during drilling. Modern seismic interpretation techniques are used to identify, map and spatially analyse seismic features that may represent subsurface drilling hazards, such as seabed structures, faults, fluids and challenging lithologies. These hazards are compared against the spatial distribution of stratigraphic targets to guide site selection and minimize risk. The 3D seismic geohazard assessment specifically advanced the proposal by providing a more detailed and spatially extensive understanding of hazard distribution that was used to confidently select eight new site locations, abandon four others and fine-tune sites originally selected using 2D seismic data. Had several of the more challenging areas targeted by this proposal only been covered by 2D seismic data, it is likely that they would have been abandoned, restricting access to stratigraphic targets. The results informed the targeted location of an ultra-high-resolution 2D seismic survey by minimizing acquisition in unnecessary areas, saving valuable resources. With future IODP missions targeting similarly challenging frontier environments where 3D seismic data are available, this workflow provides a template for geohazard assessments that will enhance the success of future scientific drilling.
18
Mackie, S. I. "2001 EXPLORATION REVIEW." APPEA Journal 42, no. 2 (2002): 71. http://dx.doi.org/10.1071/aj01059.
Full textAbstract:
Exploration expenditure in 2001 was the highest ever and successful wildcats were drilled in all major petroleum basins. Much of the success can be attributed to the increasing use of 3D seismic data prior to drilling. Although 2001 saw the first onshore exploration permits awarded since the mid-90s the resolution of Native Title still remains the highest concern for onshore exploration. Decreasing 2D acquisition may indicate failure to be exploring in frontier areas. The discovery of the Thylacine and Geographe fields in the offshore Otway recharged exploration on Australia’s southern margins. The success of Cliff Head–1 in the offshore Perth Basin demonstrates that small independents can still play a major role in Australian exploration.
19
Lavin, Ciaran, Terry Walker, and Yvette Knowles. "2010 PESA industry review–exploration." APPEA Journal 51, no. 1 (2011): 147. http://dx.doi.org/10.1071/aj10010.
Full textAbstract:
An uncertain global economy, offset by strong commodity prices, provided the backdrop to a subdued yet solid level of exploration activity in 2010. The major loci of activity in the Australian oil and gas industry were the Exmouth Plateau, where exploration for conventional gas in support of LNG projects was the primary driver, and the Bowen/Surat Basin, where coal seam gas (CSG) for LNG was the main target. Onshore permit awards dominated new licensing in 2010, with 31 exploration permits awarded over an area of 190,000 km2. The majority of these permits are focused on unconventional gas exploration. Conversely only 14 exploration permits (30,000 km) were awarded offshore, all in northwest Australia. This historically low level can be related to an already extensive coverage of existing permits in the offshore petroleum provinces and delays in the announcement of acreage awards from the 2009(II) acreage release. Twenty-nine 2D seismic surveys were started in 2010, with three still active at the end of the year. Once completed, the 2010 surveys will total nearly 37,000 km of data, with 76% offshore. Twenty-one 3D seismic surveys commenced in 2010, with six still active at year end. The 2010 surveys will ultimately comprise approximately 29,000 km2 of data, with 95% offshore. Northwest Australia dominated seismic activities. Exploration drilling for conventional hydrocarbon resources was relatively subdued in 2010, with 63 wells spudded, compared to 92 wells in 2008 and 74 in 2009. Of the 49 wildcat wells where results are known, 51% reported hydrocarbon discoveries. This was a little less than the 57% in 2009 and up on the 39% in 2008. The discoveries were distributed across most of the traditional petroleum provinces. High levels of CSG drilling continued in 2010, exceeding 2008 activity but less than that of 2009. At least 648 CSG wells were spudded in 2010, mostly in the new heartland plays of the Bowen/Surat, Gunnedah and Clarence-Moreton basins. This compares with more than 600 CSG wells drilled in 2008 and more than 900 in 2009. The first dedicated Australian shale gas exploration drilling took place in 2010. Emerging shale plays in the Cooper and Perth basins were tested.
20
Northrup, Herbert R. "The Twelve-Hour Shift in the Petroleum and Chemical Industries Revisited: An Assessment by Human Resource Management Executives." ILR Review 42, no. 4 (July 1989): 640–48. http://dx.doi.org/10.1177/001979398904200412.
Full textAbstract:
This study, a follow-up of one published in 1979, reports the results of a questionnaire concerning the twelve-hour shift that was sent to human resource management executives at 23 chemical, petroleum, pharmaceutical, and cosmetic companies in 1987. Respondents from all 11 chemical companies and 4 petroleum companies that returned the form indicated they were using the shift. Most of them reported that the shift was popular with employees, largely because of the longer periods of time off and greater freedom on weekends and evenings it provides. The twelve-hour shift is also widely used in the mini-steel and offshore oil drilling industries, and it is used to a limited extent in paper manufacturing, data processing, metal can manufacturing, and electric utilities.
21
Bakke, Torgeir, Jarle Klungsøyr, and Steinar Sanni. "Environmental impacts of produced water and drilling waste discharges from the Norwegian offshore petroleum industry." Marine Environmental Research 92 (December 2013): 154–69. http://dx.doi.org/10.1016/j.marenvres.2013.09.012.
Full text
22
Morrow, Derek C., and Nick E. Jackson. "GOODWYN ‘A’ DRILLING FACILITIES." APPEA Journal 33, no. 1 (1993): 343. http://dx.doi.org/10.1071/aj92025.
Full textAbstract:
The Drilling Facilities Package designed and developed by Atwood Oceanics Australia Pty. Ltd. for operation on Woodside Offshore Petroleum Pty. Ltd.'s Goodwyn 'A' Platform will break new ground in the development and application of offshore modular drilling rig technology when commencement of offshore drilling is achieved. These facilities are among the largest, specifically designed, offshore demountable drilling rigs in the world today.Initially, Woodside performed sufficient engineering to determine a design specification for the Drilling Facilities which detailed the types of equipment necessary and the final performance characteristics required by the finished facility to drill the Goodwyn 'A' production wells.Following award of the Drilling Facilities Contract to Atwood Oceanics in 1989, Woodside's role was essentially related to technical interface and contract administration management. The responsibility for the design, fabrication, commissioning and operation of the Drilling Facilities lay with Atwood Oceanics.The Drilling Facilities consist of fifty-two (52) small modules, each weighing up to 105 tonne. These modules are assembled into three (3) major structural packages, these being the Drilling Support Facilities, weighing some 1300 tonne, the Sub-Base weighing 1100 tonne and the Derrick weighing 260 tonne. Total operating weight of the facilities will exceed 4500 tonne.The modular design of these facilities was developed by Atwood Oceanics from previous modular rig design of relatively simple facilities and technical scope, up to the high capacity, technical complexity and flexibility in design demanded for operation on the Goodwyn 'A' Platform. Following the issue of the Cullen Report on the Piper Alpha Disaster, extensive control and monitoring safety systems were included in the design. These systems have had an adverse impact on the modular concept due to the large increase in electrical interfaces, however the modular concept remains sound and viable.Modular rig design has allowed a Drilling Facility to be developed which has accrued savings in design, fabrication, fit-out, transport and installation and has resulted in reduced overall installed weight. These savings are real and demonstrable when compared with conventional large-module drilling rig packages of similar scope and complexity. Unlike its North Rankin 'A' development, Woodside elected to have the Drilling Facilities for Goodwyn 'A' designed, procured, fabricated and commissioned by an experienced drilling contractor, who will then operate and maintain the rig during the drilling phase (P.Scott et al., 1991). Woodside will realise substantial cost savings at the point when the facilities are installed and ready to drill. Further savings will accrue during drilling operations by allowing the drilling contractor more autonomy and responsibility (eg. maintenance of the complete drilling facilities will be by contractor personnel).The relative ease of removal of the facilities and potential for re-use on other installations will generate additional significant cost benefits in the future.The Drilling Facilities are state-of-the-art in their applied technology and are capable of year-round, self-contained operation for the drilling of highly deviated, long reach wells of up to 72° deviation from the vertical and up to 7000 m along hole depth.This paper provides an overview of the design, fabrication, fit-out, onshore commissioning, transport and installation of the modules which comprise the Goodwyn 'A' Drilling Facilities, for which Atwood Oceanics were awarded a Commendation for a High Standard of Engineering Achievement at the Institution of Engineers, Australia 1992 Engineering Excellence Awards.
23
Bilstad, T., T. Bosdal, and E. Toerneng. "Biodegradation of Oil on Drilled Cuttings." Water Science and Technology 19, no. 3-4 (March 1, 1987): 355–69. http://dx.doi.org/10.2166/wst.1987.0216.
Full textAbstract:
Drilled cuttings from offshore petroleum exploration are discarded to sea. Oil based drilling fluids leave oil on cuttings that may become environmentally toxic. Successful biological separation of oil and cuttings was accomplished by addition of nitrogen and phosphorus to seawater in completely mixed aerobic batch reactors at 10 and 20°C. Substantial biodegradation in flow-through aquaria, however, was not accomplished. Both retort distillation and solvent extraction using dichloromethane in a Soxhlet apparatus separated reproduceable quantities of hydrocarbons from cuttings. The oil was characterized by glass capillary gas chromatography and medium pressure liquid chromatography.
24
Katz, H. R. "A Historical Review of Petroleum Exploration in New Zealand." Energy Exploration & Exploitation 6, no. 2 (April 1988): 89–103. http://dx.doi.org/10.1177/014459878800600203.
Full textAbstract:
Active exploration for petroleum in New Zealand is over 120 years old. While some sporadic, commercial production was obtained already in the earliest part of this century, exploration until 1920 was entirely guided by the occurrence of natural seepages. 1925–1944 was the first period of scientifically-oriented exploration, spurred particularly by the requirements of the second World War. In 1955 began the present period of more intensified prospecting, which in 1965 extended to New Zealand's very large ofshore area. The onshore Kapuni gas/condensate field was discovered in 1959, and the giant offshore Maui field in 1969. Production started in 1970 and 1979, respectively. Exploration enormously increased and expanded all over the country in the late 1960's and early 1970's, with concession holdings reaching a record high in 1970/71:131,673 km2 onshore and 1,003,669 km2 offshore. But a sharp decline followed in the mid-late 1970's, which was partly Government-induced and political, partly due to a prolonged lack of success. A change of Government policy in 1980 started a new cycle of intense exploration, with enthusiasm rapidly fuelled by a string of new, though small discoveries in Taranaki onshore, and, in 1986/87, by what is believed to be a large oil and gas discovery in Taranki offshore. Drilling activity has reached record levels over the last years, while exploration in general is branching out again to many other areas and basins, outside Taranaki. Total production in 1986 amounted to 4,546 million m3 of gas (plus 744 million m3 re-injected), 1.208 million m3 of condensate, 186,700 m3 of LPG and smaller amounts of natural gasoline and butane, and 0.501 million m3 of oil.
25
Nelson, August. "Staatsolie's VISION 2030: the contributions of petroleum geology to Surinamese society." Netherlands Journal of Geosciences - Geologie en Mijnbouw 95, no. 4 (September 19, 2016): 375–92. http://dx.doi.org/10.1017/njg.2016.32.
Full textAbstract:
AbstractStaatsolie Maatschappij Suriname N.V., together with the gold mining industry, has gradually become a major contributor to the Surinamese economy since the decline of the alumina industry. In the last 35 years, about 110MMbbls (million barrels) of crude oil have been produced. Staatsolie is now in the early stages of fulfilling its VISION 2030, which is not only aimed at increased exploration and production but also at power generation, further diversification and regional expansion. The basis for achieving these goals is accelerated on- and offshore exploration, followed by growth in production. The offshore region remains a frontier area, with only a few wells drilled. Current production is about 17,000bopd (barrels of oil per day). Between 2007 and 2014, Staatsolie has spent about US$120 million on exploration. An integrated study for the Suriname–Guyana Basin carried out by Staatsolie in 2009 demonstrated the upside potential of this basin from a source rock potential perspective, which has been proven by both the Liza-1 oil discovery offshore of Guyana in 2015 and the Zaedyus-1 oil discovery offshore of French Guiana in 2011.Staatsolie is now focusing its efforts on the near-shore area, where it recently concluded a five-well drilling programme, following a 3-D seismic survey. In the deep offshore area, international oil companies (IOCs) are actively pursuing the next discovery in the Atlantic Margin, partly driven by the conjugate-margin theory geologically linking South America and West Africa.Staatsolie is also attempting to increase recovery from the most mature and largest oilfield, the Tambaredjo Field, through Enhanced Oil Recovery (EOR) technologies of which polymer flooding is deemed the most suitable, with estimated potential incremental recovery of up to 12%.Staatsolie recognises the role of a highly skilled and motivated workforce and therefore continues investing in its people through internal as well as external training. Thirty-five years after it was founded by Mr Eddy Jharap, a geologist by training and the first Managing Director of the company, it can be stated that Staatsolie has taken its place in Surinamese society as a significant contributor to the economy, a preferred employer, a nucleus for industrial spin-off and an example for other companies.
26
An, Yong Ning, Qing Feng Song, and Jing Li. "Appropriate Jackup Selection in Disturbed Wellsite by Pile Inserting and Pulling in Offshore Oilfield." Applied Mechanics and Materials 580-583 (July 2014): 2206–9. http://dx.doi.org/10.4028/www.scientific.net/amm.580-583.2206.
Full textAbstract:
Pile inserting and pulling activities may occur for many times in some wellsite in Offshore Oilfield, that resulted in serious stratum disturbance and complex strength change, it’s difficult to select appropriate jack-up drilling platform in the workover process latterly. By applying American Petroleum Institute <API RP 2A-WSD> norms, calculating the pile bearing capacity of two typical jackup, combing with the actual data of jackup emplaced, this paper analyzes and compares the suitability of various type of jackup in place in seriously disturbed wellsite by pile inserting and pulling, and then offers a proposal on how to select the appropriate jackup in such wellsite as a reference.
27
Feo, Giuseppe, Jyotsna Sharma, Dmitry Kortukov, Wesley Williams, and Toba Ogunsanwo. "Distributed Fiber Optic Sensing for Real-Time Monitoring of Gas in Riser during Offshore Drilling." Sensors 20, no. 1 (January 2, 2020): 267. http://dx.doi.org/10.3390/s20010267.
Full textAbstract:
Effective well control depends on the drilling teams’ knowledge of wellbore flow dynamics and their ability to predict and control influx. Unfortunately, detection of a gas influx in an offshore environment is particularly challenging, and there are no existing datasets that have been verified and validated for gas kick migration at full-scale annular conditions. This study bridges this gap and presents pioneering research in the application of fiber optic sensing for monitoring gas in riser. The proposed sensing paradigm was validated through well-scale experiments conducted at Petroleum Engineering Research & Technology Transfer lab (PERTT) facility at Louisiana State University (LSU), simulating an offshore marine riser environment with its larger than average annular space and mud circulation capability. The experimental setup instrumented with distributed fiber optic sensors and pressure/temperature gauges provides a physical model to study the dynamic gas migration in full-scale annular conditions. Current kick detection methods primarily utilize surface measurements and do not always reliably detect a gas influx. The proposed application of distributed fiber optic sensing overcomes this key limitation of conventional kick detection methods, by providing real-time distributed downhole data for accurate and reliable monitoring. The two-phase flow experiments conducted in this research provide critical insights for understanding the flow dynamics in offshore drilling riser conditions, and the results provide an indication of how quickly gas can migrate in a marine riser scenario, warranting further investigation for the sake of effective well control.
28
Sayed, Khalid, Lavania Baloo, and Naresh Kumar Sharma. "Bioremediation of Total Petroleum Hydrocarbons (TPH) by Bioaugmentation and Biostimulation in Water with Floating Oil Spill Containment Booms as Bioreactor Basin." International Journal of Environmental Research and Public Health 18, no. 5 (February 24, 2021): 2226. http://dx.doi.org/10.3390/ijerph18052226.
Full textAbstract:
A crude oil spill is a common issue during offshore oil drilling, transport and transfer to onshore. Second, the production of petroleum refinery effluent is known to cause pollution due to its toxic effluent discharge. Sea habitats and onshore soil biota are affected by total petroleum hydrocarbons (TPH) as a pollutant in their natural environment. Crude oil pollution in seawater, estuaries and beaches requires an efficient process of cleaning. To remove crude oil pollutants from seawater, various physicochemical and biological treatment methods have been applied worldwide. A biological treatment method using bacteria, fungi and algae has recently gained a lot of attention due to its efficiency and lower cost. This review introduces various studies related to the bioremediation of crude oil, TPH and related petroleum products by bioaugmentation and biostimulation or both together. Bioremediation studies mentioned in this paper can be used for treatment such as emulsified residual spilled oil in seawater with floating oil spill containment booms as an enclosed basin such as a bioreactor, for petroleum hydrocarbons as a pollutant that will help environmental researchers solve these problems and completely clean-up oil spills in seawater.
29
Specht, R. N., A. E. Brown, C. H. Selman, and J. H. Carlisle. "Geophysical case history, Prudhoe Bay field." GEOPHYSICS 51, no. 5 (May 1986): 1039–49. http://dx.doi.org/10.1190/1.1442159.
Full textAbstract:
In June 1968 ARCO‐Exxon completed the Prudhoe Bay State No. 1 well, discovering the largest oil accumulation in the United States. This discovery was the result of a [proposed] three‐year seismic program begun in 1963. The three predecessor companies of Atlantic Richfield were involved in separate geophysical programs and by 1964 each program had delineated two major structures on the North Slope coastal plain: Colville and Prudhoe. During the first state sale on the North Slope (late 1964), Sinclair, in partnership with British Petroleum, leased the entire Colville structure. The critical state lease sale covering Prudhoe Bay was held in July, 1965. This sale determined the eventual ownership of the Prudhoe Bay field. ARCO‐Exxon acquired the top tracts, with British Petroleum acquiring flank acreage. In January, 1967, ARCO‐Exxon acquired additional offshore tracts and began drilling the Prudhoe Bay State No. 1 in April.
30
Mackie, Steve. "Australian exploration review 2016." APPEA Journal 57, no. 2 (2017): 363. http://dx.doi.org/10.1071/aj16254.
Full textAbstract:
In 2016, explorers in Australia were called upon to demonstrate realistic optimism. The year clearly demonstrated that during an industry contraction, such as that seen by the upstream oil and gas industry since the oil price crash of late 2014, near field conventional exploration still produces discoveries. These include Shefu, Muruk, Davis, Outtrim and Spartan. Amungee NW demonstrated unconventional gas flows in the Beetaloo Basin. As usual, new reservoirs were discovered in appraisal programs such as at Roc and Phoenix South. Exploration lows, however, were the general mood with the inevitable unsuccessful wells, decreases in permit awards and associated work programs, the general low level of drilling activity both offshore and onshore, frustrations at approval delays and constraints and the still contracting business environment. This Petroleum Exploration Society of Australia review looks in detail at the trends and highlights for oil and gas exploration both onshore and offshore Australia during 2016; not just outcomes with the drill bit, but also leading industry health indicators such as drilling, seismic data acquisition and permit awards. It also seeks to be insightful and to make conclusions about the condition of oil and gas exploration in Australia, as well as comment on future implications for the industry.
31
Blevin, J. E. "EXPLORATION HIGHLIGHTS FOR 2006." APPEA Journal 47, no. 2 (2007): 631. http://dx.doi.org/10.1071/aj06056.
Full textAbstract:
Key business indicators show an upward trend in exploration activity in Australia during 2006. The year was marked by fluctuating high oil prices, a strong uptake of acreage in most basins, and increased levels of drilling activity and seismic acquisition. Market demand for product, production infrastructure and the fruition of several development projects have pushed the level of exploration activity in both offshore and onshore basins. Despite this trend and the spread of tenements, almost all petroleum discoveries made during 2006 were located within 15 km of existing (but often undeveloped) fields.The Carnarvon Basin continued to be the focus of most offshore exploration activity during 2006, with the highest levels of 3D seismic acquisition and exploration/appraisal/development drilling in the country. Discoveries in the Carnarvon Basin also covered the broadest range of water depths—extending from the oil and gas discoveries made by Apache on the inboard margin of the Barrow Subbasin, to the deepwater gas discoveries at Clio–1 and Chandon–1 by Chevron. Several large gas discoveries were made in the Carnarvon and Bonaparte basins and provide significant tie-back opportunities to existing and planned infrastructure. The Bonaparte Basin also saw significantly increased levels of 2D and 3D seismic acquisition during 2006. Onshore, the Cooper/Eromanga basins continued to experience the highest level of drilling activity and seismic acquisition, while maintaining an overall high drilling success rate. For the first time in many years, data acquisition also occurred in frontier basins like the Daly (Northern Territory), Darling (New South Wales), Tasmanian (Tasmania) and Faust/Capel basins (Lord Howe Rise region).Coal seam methane (CSM) exploration maintained a strong performance in 2006, particularly in Queensland, while South Australia, Queensland and Victoria continue to lead the way with large tracts of acreage gazetted for geothermal energy exploration.
32
Bojesen-Koefoed, Jørgen A., Hans Peter Nytoft, and Flemming G. Christiansen. "Age of oils in West Greenland: was there a Mesozoic seaway between Greenland and Canada?" Geological Survey of Denmark and Greenland (GEUS) Bulletin 4 (July 20, 2004): 49–52. http://dx.doi.org/10.34194/geusb.v4.4783.
Full textAbstract:
For many years the existence of an oil-prone source rock off West Greenland was challenged by industry. But since 1992 when active oil seeps were found onshore West Greenland on the Nuussuaq peninsula (Fig. 1; Christiansen et al. 1996; Bojesen-Koefoed et al.1999), the question has changed focus to the age, distribution and potential of the source rock. Five different oils – each with their own characteristics – have been reported by the Geological Survey of Denmark and Greenland (GEUS). One of these, a typical marine shalederived oil with a possible regional distribution, is known as the Itilli oil. Geochemical analysis suggests that it may have been generated from Cenomanian–Turonian age marine shales, equivalent to prolific source rocks known from Ellesmere Island, Nunavut, Canada. Three of the other oils were generated from deltaic source rocks of Albian, Campanian and Paleocene ages, while one is of unknown origin (Bojesen-Koefoed et al. 1999). The presence of a regional marine source rock is important to petroleum exploration; GEUS has therefore investigated the possible existence of Mesozoic, in particular Cenomanian–Turonian, petroleum source rocks in West Greenland offshore areas. Since sediments older than the Santonian are not known from any of the six wells drilled offshore West Greenland (Fig. 1), assessment of oil-prone source rocks in older sedimentary successions must rely on circumstantial evidence offered by oil chemistry data and analogy studies. Petroleum in quantities amenable to chemical analysis has so far not been recovered from offshore. However, oilbearing fluid inclusions are known from the Ikermiut-1 well (unpublished data 2001, Phillips Petroleum and GEUS), a gas-kick was recorded during drilling of the Kangâmiut-1 well (Bate 1997), and seismic data indicate hydrocarbons in many areas (cross-cutting reflectors, bright spots, smearing of seismic). Petroleum exploration offshore West Greenland suffered for many years under the misconception that oceanic crust covered vast areas, rendering the region unattractive. However, the presence of thick sedimentary successions and rotated fault blocks in Cretaceous basins have been demonstrated to be present in areas previously believed to be underlain by Cretaceous–Tertiary oceanic crust (cf. Chalmers & Pulvertaft 2001). New high-quality seismic data, acquired by the seismic company TGS-NOPEC over recent years, combined with gravimetric data, have further demonstrated the presence of deep basins containing thick sedimentary successions in other areas (e.g. Christiansen et al. 2002). Despite the progress made over the past few years, the geological evolution of the Davis Strait region in general remains poorly understood, but new data on oil chemistry may shed some light on the history of this region.
33
Arditto, P. A. "AN INTEGRATED GEOLOGICAL AND GEOPHYSICAL INTERPRETATION OF A PORTION OF THE OFFSHORE SYDNEY BASIN, NEW SOUTH WALES." APPEA Journal 43, no. 1 (2003): 495. http://dx.doi.org/10.1071/aj02026.
Full textAbstract:
The study area is within PEP 11, which is more than 200 km in length, covers an area over 8,200 km2 and lies immediately offshore of Sydney, Australia’s largest gas and petroleum market on the east coast of New South Wales. Permit water depths range from 40 m to 200 m. While the onshore Sydney Basin has received episodic interest in petroleum exploration drilling, no deep exploration wells have been drilled offshore.A reappraisal of available data indicates the presence of suitable oil- and wet gas-prone source rocks of the Late Permian coal measure succession and gas-prone source rocks of the middle to early Permian marine outer shelf mudstone successions within PEP 11. Reservoir quality is an issue within the onshore Permian succession and, while adequate reservoir quality exists in the lower Triassic succession, this interval is inferred to be absent over much of PEP 11. Quartz-rich arenites of the Late Permian basal Sydney Subgroup are inferred to be present in the western part of PEP 11 and these may form suitable reservoirs. Seismic mapping indicates the presence of suitable structures for hydrocarbon accumulation within the Permian succession of PEP 11, but evidence points to significant structuring post-dating peak hydrocarbon generation. Uplift and erosion of the order of 4 km (based on onshore vitrinite reflectance studies and offshore seismic truncation geometries) is inferred to have taken place over the NE portion of the study area within PEP 11. Published burial history modelling indicates hydrocarbon generation from the Late Permian coal measures commenced by or before the mid-Triassic and terminated during a mid-Cretaceous compressional uplift prior to the opening of the Tasman Sea.Structural plays identified in the western and southwestern portion of PEP 11 are well positioned to contain Late Permian clean, quartz-rich, fluvial to nearshore marine reservoir facies of the coal measures. These were sourced from the western Tasman Fold Belt. The reservoir facies are also well positioned to receive hydrocarbons expelled from adjacent coal and carbonaceous mudstone source rock facies, but must rely on early trap integrity or re-migrated hydrocarbons and, being relatively shallow, have a risk of biodegradation. Structural closures along the main offshore uplift appear to have been stripped of the Late Permian coal measure succession and must rely on mid-Permian to Early Permian petroleum systems for hydrocarbon generation and accumulation.
34
Todd, Victoria L. G., Laura D. Williamson, Jian Jiang, Sophie E. Cox, Ian B. Todd, and Maximilian Ruffert. "Proximate underwater soundscape of a North Sea offshore petroleum exploration jack-up drilling rig in the Dogger Bank." Journal of the Acoustical Society of America 148, no. 6 (December 2020): 3971–79. http://dx.doi.org/10.1121/10.0002958.
Full text
35
Carpenter, Chris. "Technology Focus: Extended-Reach and Complex Wells (May 2021)." Journal of Petroleum Technology 73, no. 05 (May 1, 2021): 58. http://dx.doi.org/10.2118/0521-0058-jpt.
Full textAbstract:
In selecting papers for this feature, reviewer Stéphane Menand of Helmerich and Payne has identified a trio of papers that investigates new approaches toward familiar issues encountered when drilling complex well types. Whether considering the customization of drilling approaches in Middle Eastern carbonate reservoirs, implementing a collaborative work flow in tackling high-tortuosity wells offshore Western Australia, or researching the ability of a fibrous material to effect hole cleaning as opposed to polymeric sweeps, the authors of these papers understand that technical expertise may not be completely realized if it is not applied to problems in original ways. In carbonate reservoirs, the goal of drilling extended-reach wells is set against the geological makeup of such formations, the complexity of which adds significant uncertainty to geosteering and well placement. The authors of paper SPE 203335 develop a work flow that makes possible the customization of drilling scenarios through an emphasis on mechanical specific energy, as well as the use of an optimized borehole-assembly design. The work flow helped deliver what the authors write is the longest well in the Middle East offshore Abu Dhabi. In a similar vein, the authors of paper SPE 202251 describe a challenging scenario involving an ultraextended-reach well in a mature field offshore Western Australia. The project overcame shallow water depth and a high tortuosity requirement by implementing an integrated plan that used a reservoir-mapping-while-drilling service. The authors stress that this technology, coupled with active collaboration between specialists, town, and rig site, allowed the project to achieve the desired oil-column thickness with zero collision incidents. Highly deviated wells often face problems resulting from ineffective hole cleaning. Paper SPE 203147 studies the properties of a fibrous material when compared with the hole-cleaning performance of common polymeric pills. The authors write that the fibrous material proved effective, in part because of a unique characteristic in which a spiderweb-like network of fibers is created that does not allow cuttings to settle easily in complex wells. In addition, the material is environmentally friendly. All three papers approach well- established problems in the critical industry sector of extended-reach drilling with innovation and confidence. Enjoy the papers and be sure to search SPE’s OnePetro online library for more fresh approaches to the technical challenges posed by these well types. Recommended additional reading at OnePetro: www.onepetro.org. SPE 196410 - Analysis of Friction-Reduction System During Drilling Operation at a High-Inclination Well on Field X by Rizqiana Mudhoffar, Tanri Abeng University, et al. SPE 197257 - Successful Management of Collision Risk in an Extended-Reach Well by Manchukarn Naknaka, Mubadala Petroleum, et al. SPE 202730 - Challenges in Drilling and Completion of Extended-Reach-Drilling Wells With Landing Point Departure of More Than 10,000 ft in Light/Slim Casing Design by Nitheesh Kumar Unnikrishnan, Abu Dhabi National Oil Company, et al.
36
Jamalullail, Aqilah Amir, Ong Swee Keong, Nik Ruzaimi Akmal Nik Ruhadi, Tengku Mohd Syazwan Tengku Hassan, Detchai Ittharat, Phalaphoom Thamniyom, Suphawich Thanudamrong, Zulkarnain Anas, and Stanley Kampit. "Unravelling an abandoned giant in Central Luconia Province, offshore Sarawak, Malaysia — Success story of Lang Lebah." Leading Edge 39, no. 8 (August 2020): 566–73. http://dx.doi.org/10.1190/tle39080566.1.
Full textAbstract:
In 1994, two exploration wells were drilled consecutively to explore for gas prospectivity in Lang Lebah, a Miocene carbonate buildup in the geologic province of Central Luconia located in the Sarawak Basin in Malaysia. High overpressure and operational problems prevented both wells from fully evaluating the target. Postdrill analysis concluded that Lang Lebah has limited potential due to poor reservoir quality, small gas column, and challenging drilling conditions. For these reasons, it was left dormant for 25 years. In 2016, new 3D broadband seismic acquisition and megamerge reprocessing of 3D seismic data sets followed by an integrated application of multidisciplinary workflows successfully derisked key petroleum system elements of the Lang Lebah structure, yielding a more optimistic view of its potential. A new well was justified at Lang Lebah and resulted in one of the major gas discoveries of 2019.
37
Colman, J. G., A. Grubisa, and R. S. Millhouse. "MANAGEMENT OF ENVIRONMENTAL AND STAKEHOLDER ISSUES FOR OFFSHORE EXPLORATION ACTIVITIES IN THE OTWAY BASIN." APPEA Journal 42, no. 1 (2002): 697. http://dx.doi.org/10.1071/aj01046.
Full textAbstract:
Woodside has been managing seismic acquisition and drilling operations as part of a gas exploration program in the offshore Otway Basin in southwest Victoria since July 1999. There are a number of sensitive and complex environmental and multiple-use issues facing companies undertaking exploration activities in these waters, including a seasonal aggregation of feeding blue whales, winter calving and breeding habitat for southern right whales and a productive rock lobster fishery. Recent changes to the legislative regime for environmental approvals of petroleum activities in Commonwealth waters has introduced further complications for operators in this area. Consequently, a key aspect of this exploration program has been the pro-active management of environmental and stakeholder issues.A comprehensive management strategy addressing these issues was developed for seismic acquisition and drilling operations, with the key objectives of ensuring regulatory compliance and facilitating a process where all stakeholders were fully informed about proposed activities. This process focussed on informing stakeholders of the potential impacts of seismic acquisition and drilling, and how Woodside intended to manage those impacts. This approach was driven by a desire for continuous improvement of performance, over and above compliance with all regulatory requirements. It also recognises the legitimacy of stakeholder risk through social, environmental and political values, and has had environmental and economic benefits for the project.Environmental benefits included early identification and assessment of potential environmental impacts resulting from the different phases of exploration, development of management strategies to control and mitigate these potential impacts, and improved environmental awareness across the project team, joint venture partners and external stakeholders. Prevention of delay or denial of regulatory approvals for exploration activities had significant economic benefits to Woodside and the joint venture partners. The development and implementation of a stakeholder involvement process, involving explorers, external affairs and environmental advisers, was an innovative approach that has application across other Woodside activities and the industry generally, particularly for projects in locations with a high level of environmental sensitivity, multiple-use and stakeholder concern.
38
Christiansen, F. G., C. Marcussen, and J. A. Chalmers. "Geophysical and petroleum geological activities in the Nuussuaq – Svartenhuk Halvø area 1994: promising results for an onshore exploration potential." Rapport Grønlands Geologiske Undersøgelse 165 (January 1, 1995): 32–41. http://dx.doi.org/10.34194/rapggu.v165.8275.
Full textAbstract:
After the successful completion of the 1993 field work and drilling programme in the Marraat area on western Nuussuaq (Fig. 1), including a subsequent logging and geophysical programme (see Christiansen et al., 1994a, b; Dam & Christiansen, 1994), a new picture of onshore exploration opportunities has started to develop. Previously the onshore basins were only considered to have a minor exploration potential, if any at all. However, the Disko-Nuussuaq-Svartenhuk Halvo region has been an important study area because many of the key parameters (sedimentological, stratigraphical and organic geochemical data from the excellent outcrops) may be obtained for predicting the distribution of reservoir and source rocks in the neighbouring major offshore basins in North-West and West Greenland (Christiansen et al., 1992, I994c).
39
BINTI ZAINA ABIDIN, NOOR AZIRAH, NURUL NOR AISHAH BINTI KHAIRIL, NUR RABIAHTUNSAQDAH BINTI ABDUL RAHANI, SHAHIDAH BINTI SHAFEE, and NURUL AFIQAH BINTI MOHD ZAHID. "A STUDY ON LOGISTIC SETUP CHALLENGES DURING A SCHEDULE OFFSHORE PLATFORM SHUTDOWN IN PETRONAS CARIGALI KERTEH, TERENGGANU." International Journal of Entrepreneurial Research 2, no. 1 (March 23, 2019): 15–19. http://dx.doi.org/10.31580/ijer.v1i2.502.
Full textAbstract:
Plant turnaround shutdown is a fundamental asset management in capital intensive process-based industries. Offshore platform is like a ‘town’ in the middle of the sea with a facility for well drilling to explore, process for petroleum and also natural gas, to extract and store. The platform also has facilities for workforce as well. Shutting down an offshore platform for the schedule maintenance is a risky activity that could cost millions of dollar if not properly managed. The success of Offshore platform schedule shutdown is heavily depending on the close coordination among the stakeholder of the project including meeting the logistics requirement. In offshore schedule shutdown, logistics play a critical role in the whole process of the shutdown due to restricted space available for working area, accommodation, and storage. The design for offshore platform include all the requirements including the living space for workers, space for office and many more. The successful implementation of turnaround among others depends on the appropriate provision of institution and organization for the governance of the event. Moreover, it is rare to find literature on organizational characteristics of plant turnaround shutdown. The purpose of this study is to explore the challenges of logistics setup during a schedule shutdown in offshore platform which turn to be a major problem for oil and gas company. In this research propose a framework for examining the organizational challenges during the plant turnaround shutdown and researcher has purpose the efficient way that could lead to the successful initiative for the company. For data collection, researcher is using group focus interview the targeting team and also from the books, journal or website.
40
Valenti, Michael. "Kicking the OPEC Habit." Mechanical Engineering 122, no. 05 (May 1, 2000): 44–51. http://dx.doi.org/10.1115/1.2000-may-1.
Full textAbstract:
This article highlights that major offshore oil and gas projects may help North America reduce its dependence on the oil cartel. When members of the Organization of Petroleum Exporting Countries (OPEC) cut their production by 4 million barrels per day from March 1999 to March 2000, they tripled oil prices, from $11 to $33 per barrel. The combination of higher gasoline, diesel, and heating oil prices led President Clinton and Congress to pressure the OPEC countries to increase their production. Spar technology has been used for 25 years for loading buoys and storage vessels. The spar is a floating system, basically a cylinder on end that maintains its position with mooring lines sunk into the seabed. Many offshore oilfields are beyond the reach of underwater pipelines. This is an opportunity seized by SOFEC Inc. in Houston. Since 1972, the company, a subsidiary of the FMC Corp., has designed equipment to support floating production storage and offloading systems. These systems consist of a floating platform, basically a moored ship-shaped vessel, equipped to accept oil and gas from a drilling system on the sea bed.
41
Soares, Rui, Steve Thompson, and Robert Smillie. "Rigless well intervention and trees on wire from a DPII vessel: a case study." APPEA Journal 50, no. 2 (2010): 744. http://dx.doi.org/10.1071/aj09108.
Full textAbstract:
Since the 2006 bidding rounds, exploration activity in both the Timor-Leste exclusive offshore area (TLEA) and joint petroleum development area (JPDA) has progressed steadily. Within the JPDA, exploration remains largely focussed in the Jurassic-age Plover and Elang Sandstone formations in the Flamingo Trough-Sahul Syncline region. Over 700 MMbbls of liquids and 4Tcf of gas have been discovered in this western region of the JPDA, including the 2008 Kitan oil field discovery by Eni, which is currently scheduled for production in 2011. Recent seismic survey activity within the JPDA by PSC holders Petronas and Oilex has resulted in the combined acquisition of 2,800 square kilometres of new 3D data. These surveys, together with on-going re-evaluation of existing well data by these companies, has helped further refine the knowledge of petroleum systems within the JPDA, in preparation for drilling campaigns scheduled for late 2009 and early 2010. Within the TLEA, multi-client seismic surveys undertaken in 2005, together with on-shore academic research, indicates that the prospective Mesozoic sequence of the Northern Bonaparte Basin underlies the Timor Trough, greatly enhancing the petroleum prospectivity of this region. Further detailed 2D and 3D seismic surveys in the TLEA have been recently completed by PSC holders Reliance Exploration and Eni. The first wells to be drilled in this deeper water frontier region are scheduled for 2010.
42
Harrison, Paul, Chris Swarbrick, Jim Winterhalder, and Mark Ballesteros. "The petroleum prospectivity of the Oobagooma Sub-basin and adjacent Leveque Platform, North West Shelf, Australia." APPEA Journal 56, no. 2 (2016): 563. http://dx.doi.org/10.1071/aj15069.
Full textAbstract:
The Oobagooma Sub-basin of the Roebuck Basin includes the offshore extension of the onshore Fitzroy Trough of the Canning Basin. Together with the Leveque Platform, it covers an area of approximately 50,000 km2, yet only 14 exploration wells have been drilled in the area to date, five of which were drilled in the past 30 years. The sub-basin contains sediments ranging in age from Ordovician to Recent. This study examines the petroleum prospectivity of a region that is one of the least explored on Australia’s North West Shelf. Recent exploration drilling has revived interest in the area, with the 2014 Phoenix South–1 oil discovery in the offshore Bedout Sub-basin and the 2015 Ungani Far West–1 oil discovery in the onshore Fitzroy Trough. The two most significant source rock sequences relevant to the Oobagooma Sub-basin are the Carboniferous Laurel Formation and the Jurassic section. The former interval is part of a proven petroleum system onshore and is the source of the gas discovered at Yulleroo and oil at Ungani and Ungani Far West. A thick Jurassic trough to the north of the Oobagooma Sub-basin is believed to be the source of the oil and gas in Arquebus–1A and gas in Psepotus–1. Hydrocarbon charge modelling indicates significant expulsion occurred during both the Cretaceous and Tertiary from both source intervals. Trap timing is generally favourable given that inversion structures formed in several episodes during the Late Jurassic to Late Tertiary. The Early Triassic, now proven to be oil prone in the Phoenix South area (Molyneux et al, 2015), provides an additional (albeit less likely) source for the Oobagooma Sub-basin. These rocks are thin to absent within the Oobagooma Sub-basin, so long-distance migration would be required from deep troughs to the west.
43
Jang, Junbong, William F. Waite, and Laura A. Stern. "Gas hydrate petroleum systems: What constitutes the “seal”?" Interpretation 8, no. 2 (May 1, 2020): T231—T248. http://dx.doi.org/10.1190/int-2019-0026.1.
Full textAbstract:
The gas hydrate petroleum system (GHPS) approach, which has been used to characterize gas hydrates in nature, uses three distinct components: a methane source, a methane migration pathway, and a reservoir that not only contains gas hydrate, but also acts as a seal to prevent methane loss. Unlike GHPS, a traditional petroleum system (PS) approach further distinguishes between the reservoir, a unit with generally coarser sediment grains, and a separate overlying seal unit with generally finer sediment grains. Adopting this traditional PS distinction in the GHPS approach facilitates assessments of reservoir growth and production potential. The significance of the seal for the formation of a gas hydrate reservoir as well as for efficiency in methane extraction from the reservoir as an energy resource is evident in findings from recent offshore field expeditions, such as India’s second National Gas Hydrate Program expedition (NGHP-02). In regard to gas hydrate-bearing reservoir formations, the NGHP-02 gas chemistry data indicate a primarily microbial methane source. Fine-grained seal sediment in contact with coarser grained reservoir sediment can facilitate that microbial methane production. Logging-while-drilling and sediment core data also indicate that the overlying fine-grained seal sediment is less permeable than the underlying, highly gas hydrate-saturated reservoir sediment. The overlying seal’s capacity to act as a low-permeability boundary is important not only for preventing methane migration out of the reservoir over time, but also for preventing water invasion into the reservoir during methane extraction from the reservoir. Ultimately, the presence of an overlying, fine-grained, low-permeability “seal” influences how gas hydrate initially forms in a coarse-grained reservoir and dictates how efficiently methane can be extracted as an energy resource from the gas hydrate reservoir via depressurization.
44
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.
Full textAbstract:
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.
45
Carpenter, Chris. "Drilling Dynamics, Mechanical Specific Energy Data Help Drill Record Extended-Reach Well." Journal of Petroleum Technology 73, no. 05 (May 1, 2021): 59–60. http://dx.doi.org/10.2118/0521-0059-jpt.
Full textAbstract:
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 203335, “Using MSE and Downhole Drilling Dynamics in Achieving a Record Extended-Reach Well Offshore Abu Dhabi,” by Nashat Abbas and Jamal Al Nokhatha, ADNOC, and Luis Salgado, Halliburton, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. Complex extended-reach-drilling (ERD) wells often present challenges with regard to geological aspects of data requirement and transmittal, reactive geosteering response times, and accuracy of well placement. Such scenarios may require innovative approaches in Middle East carbonate reservoirs. The objective of the complete paper is to illustrate that, by assessing the details of reservoir geology and key operational markers relevant for best practices, drilling approaches can be customized for each reservoir or scenario. Reservoir Background and Geology The planned reservoir section is a single horizontal of approximately 25,000-ft lateral length at a spacing of 250 m from adjacent injectors. The well was drilled from an artificial island. Field A, a shallow-water oil field, is the second-largest offshore field and the fourth-largest field in the world. Horizontal drilling was introduced in 1989, and an extensive drilling campaign has been implemented since then using steerable drilling technologies. This study is concerned only with wells drilled to develop Reservoir B in Field A, which contributes to the main part of initial oil in place and production. The thick limestone reservoir is subdivided into six porous layers, labeled from shallow to deep as A, B, C, D, E, and F. Each porous layer is separated by thin, low-porosity stylolites. The reservoir sublayer B, consisting of approximately 18-ft-thick calcareous limestones, was selected as the target zone for the 25,420-ft horizontal section. ERD, constructed on artificial islands, began on 2014 with a measured depth (MD)/true vertical depth (TVD) ratio approaching 2.2:1 or 2.4:1. A recent ERD well, Well A, was drilled at the beginning of 2020 with a MD/TVD ratio of 5:1. This value is a clear indication of progressively increasing challenges since the start of the project. Mechanical specific energy (MSE) has long been used to evaluate and enhance the rate of penetration (ROP); however, its use as an optimization tool in ERD wells has not been equally significant. This may have been mostly because of historical use of surface-measured parameters, which do not necessarily indicate the energy required to destroy the rock, particularly in ERD wells. Using optimization tools as part of the bottomhole assembly (BHA) downhole close to the bit provides actual weight-on-bit (WOB) and torque-on-bit (TOB) applied to the drilling bit to destroy the rock and, thus, results in more-representative MSE measurements to optimize drilling parameters and ROP in ERD wells.
46
Boudreaux, Denis O., SPUma Rao, Praveen Das, and Nancy Rumore. "How Much Did The Gulf Oil Spill Actually Cost British Petroleum Shareholders?" Journal of International Energy Policy (JIEP) 2, no. 1 (May 24, 2013): 15–22. http://dx.doi.org/10.19030/jiep.v2i1.7891.
Full textAbstract:
On April 20, 2010, the Deepwater Horizon Drilling Platform, a British Petroleum (BP) licensed rig, exploded. Two days later the huge rig sank to thebottom of the Gulf of Mexico triggering the United States worst offshore oilspill. By April 26, investors and themarket began realizing that the costs associated with this catastrophic eventto BP could be significant and BP shares fell by over two percent. The next day BP reported its annual earningswhich showed a huge rise in profits, due in part to much higher oil prices forthe previous year and BPs common stock price increased. However, on May 6, 2010, analysts warned that the Gulf ofMexico oil spill disaster would likely cost BP over $23 billion dollars (15bn)and its shares can be expected to lag behind those of its competitors by 5% forthe lasting future. At the same time,Tony Hayward insisted the company would "bounce back" from thesetback though he could not give a timescale for when the flow of oil would behalted. This study investigated BPsstock returns using two models to determine if their stocks experiencedabnormal returns for the period April 20, 2010 through April 5, 2011. Results show that the most significant impact of the oilspill to the stock price was over the first 34 days of the event period. This study estimates a significant negativeimpact of 38% to 41% in share value for BP during this event period.
47
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.
Full textAbstract:
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.
48
King, Rosalind, Simon Holford, Richard Hillis, Adrian Tuitt, Ernest Swierczek, Guillaume Backé, David Tassone, and Mark Tingay. "Reassessing the in-situ stress regimes of Australia's petroleum basins." APPEA Journal 52, no. 1 (2012): 415. http://dx.doi.org/10.1071/aj11033.
Full textAbstract:
Previous in-situ stress studies across many of Australia’s petroleum basins demonstrate normal fault and strike-slip fault stress regimes, despite the sedimentary successions demonstrating evidence for widespread Miocene-to-Recent reverse faulting. Seismic and outcrop data demonstrate late Miocene-to-Recent reverse or reverse-oblique faulting in the Otway and Gippsland basins. In the Otway Basin, a series of approximately northeast to southwest trending anticlines related to reverse-reactivation of deep syn-rift normal faults, resulting in the deformation of Cenozoic post-rift sediments are observed. Numerous examples of late Miocene-to-Recent reverse faulting in the offshore Gippsland Basin have also been observed, with contractional reactivation of previously normal faults during these times partially responsible for the formation of anticlinal hydrocarbon traps that host the Barracouta, Seahorse and Flying Fish hydrocarbon fields, adjacent to the Rosedale Fault System. A new method for interpreting leak-off test data demonstrates that the in-situ stress data from parts of the Otway and Gippsland basins can be reinterpreted to yield reverse fault stress regimes, consistent with the present-day tectonic setting of the basins. This reinterpretation has significant implications for petroleum exploration and development in the basins. In the Otway and Gippsland basins, wells drilled parallel to the orientation of the maximum horizontal stress (ÏH) represent the safest drilling directions for both borehole stability and fluid losses. Faults and fractures, striking northeast to southwest, previously believed to be at low risk of reactivation in a normal fault or strike-slip fault stress regime are now considered to be at high risk in the reinterpreted reverse fault stress regime.
49
Laughery, Kenneth R., Andrew S. Jackson, and Gail A. Fontenelle. "Isometric Strength Tests: Predicting Performance in Physically Demanding Transport Tasks." Proceedings of the Human Factors Society Annual Meeting 32, no. 11 (October 1988): 695–99. http://dx.doi.org/10.1518/107118188786762496.
Full textAbstract:
A study explored the applicability of a battery of four isometric strength tests to steward, utility and warehouse jobs in a company that services offshore drilling and production facilities in the petroleum industry. The jobs involve frequently transporting materials up stairs, a category of tasks not prominent in situations where these tests have previously been applied. A job analysis established critical task requirements such as procedures, weights, distances, sizes of containers, etc. An experiment was then carried out with 25 male and 25 female subjects. The subjects performed two self-paced job-related tasks: transporting a 15.9 kg box up and down stairs and similarly transporting a 22.7 kg box. Measures included heart rate and amount of work performed, which, along with known task parameters, was used to calculate work power. Subjects also performed four standard isometric strength tests: grip, arm lift, back lift and arm press. Correlations between job task and strength performance indicated these tests are applicable to jobs with such requirements, thus extending the generalizability of the strength test battery.
50
Wakelin-King, Gordon. "Highlights and trends in exploration 2009." APPEA Journal 50, no. 1 (2010): 113. http://dx.doi.org/10.1071/aj09008.
Full textAbstract:
2009 saw an overall decrease from high activity from 2008, levelling off in the December quarter as the economy stabilised. Unsurprisingly, most activity was in offshore Western Australia and on coal seam methane (CSM) in Queensland. Highlights include: good results in the Carnarvon and Browse basins for Western Australian operators, interest in Karoon and Conoco-Phillips’ enigmatic Poseidon project, over 180 CSM exploration wells in Queenslandd, and a relatively busy year for Tasmania. Western Australian seismic acquisition approached 10,000 km of 2D and 25,000 km2 of 3D for 38* wells and success rate around 50%. South Australia saw the highest conventional onshore drilling and seismic activity, with good results for 17 wells, while other states saw low activity in this sector. Victoria saw one offshore exploration well and no seismic. Tasmania also saw no new seismic, but saw four exploration wells and encouragement at Rockhopper–1. CSM is picking up in South Australia, and New South Wales saw continued high CSM activity in a historically low-activity region. High success rates suggest two trends: explorers finding value in 3D seismic, and a ‘flight to quality’ as operating costs and poorer access to capital reinforce risk aversion among operators. Elsewhere, geothermal energy helped small cap investors satisfy their appetite for risk outside of the petroleum industry, and results will be watched with great interest. *Numbers are from early public and departmental statistics and may be revised.