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Wandoo B is a concrete gravity-based structure (GBS) and is the main production facility for the Wandoo field offshore northwest Australia. It was installed in 1997 with a design life of 20 years. The structural assessments discussed in this paper are part of a comprehensive life-extension project encompassing wells, subsea systems, marine and safety systems, and topsides facilities and structures to demonstrate fitness for service through the end of field life. The GBS serves as the support structure for the Wandoo B facility and provides oil storage for the Wandoo field. The structure has four shafts approximately 11 m in diameter that support the topsides facilities and a base structure with permanent ballast and oil storage cells (Fig.
Some of the technologies, such as mechanical and control devices commonly used in subsea well and manifold systems, are well developed and can be considered off-the-shelf items. Others, such as subsea power-distribution systems, are still in the product development stage. Many of the emerging products are well-proven surface components modified for subsea application. As in any integrated system, a shortcoming in any one of the links will impair the performance of the whole. Successful implementation requires all the skill sets to work seamlessly and with greater than ever attention to QA/QC in components manufacturing, installation, and system integration. A clear understanding of the process and all its parameters is the first step toward a successful design. As in surface facilities, knowledge of the produced fluid properties, rheology, and flow characteristics are critical. Luckily, whether the process is carried out on the surface or a thousand meters subsea, the process is the same. However, effects of the environmental conditions may be more dramatic and detrimental. Fluids with high foaming tendency will complicate the design and may require mechanical or chemical solutions. For subsea applications, a passive mechanical foam-breaking device (such as a low-shear inlet momentum breaker) is preferred over the more costly to install and operate chemical injection systems.
ABB has won an order worth $120 million to supply the overall electrical power system for the multibillion-dollar Jansz-Io Compression project. The Jansz-Io field is located approximately 200 km off the northwestern coast of Australia at water depths of approximately 1400 m. The field is a part of the Chevron-operated Gorgon natural gas project, one of the world's largest natural gas developments. The Jansz-Io Compression project will involve the construction and installation of a 27,000-tonne (topside and hull) normally unattended floating field control station, approximately 6,500 tonnes of subsea compression infrastructure, and a 135-km submarine power cable linked to Barrow Island. The estimated $4 billion project was greenlit earlier this year.
Are you trying to stay up to date about developments aimed at energy transition efforts in our industry? CCS, CCUS Capture Momentum After a decade of slow progress, carbon capture and storage (CCS) and its cousin, CCUS--the "U" stands for "utilization," indicating the captured carbon is used for purposes beyond permanently storing it underground--are gaining momentum as an all-of-the-above energy-transition strategy for the oil and gas industry. Wood Mackenzie in a recent report pointed to giant European projects such as Northern Lights, Net Zero Teesside, and Port of Rotterdam's Porthos as playing an important role in its proposed basinwide approach that would integrate carbon storage sites, industrial clusters, and oil and gas infrastructure to move toward cross-sector emissions reduction. Baker Hughes is among upstream companies diversifying into CCUS. Shortly after announcing a plan to scope projects in Italy, the company signed a deal with Borg CO2 to build a CCUS hub in Norway.
Flow assurance in subsea oil and gas fields often presents significant challenges. Every field has its own combination of difficulties, and no universal process or system can be used to mitigate these. Detailed knowledge across a broad range of competencies, therefore, is required to find solutions that can minimize the risk of not getting the hydrocarbons safely to the process facilities. Many subsea fields that are being developed today are long tiebacks, taking advantage of existing offshore infrastructure or producing directly to shore. These developments must deal with the long-distance transport of hydrocarbons in deep cold water, commonly increasing the risk of hydrate formation and wax deposition, for example.
Wheatstone and Iago gas fields, part of the larger Wheatstone project, commenced production in June 2017. The foundation subsea system includes nine Wheatstone and Iago development wells tied back to a central Wheatstone platform (WP) for processing. Hydrocarbons then flow through an export pipeline to an onshore processing facility that includes two liquefied-natural-gas (LNG) trains and a domestic gas facility. The complete paper highlights some of the key learnings in well and reservoir surveillance analysis and optimization (SA&O) developed using data from early production. Chevron Australia's Wheatstone project is in the North West Shelf region offshore Australia (Figure 1).
Chevron has confirmed that it and the Gorgon joint venture participants will proceed with the $4-billion Jansz-Io Compression (J-IC) project offshore Western Australia. Nigel Hearne, Chevron Eurasia Pacific exploration and production president, said J-IC represents Chevron's most significant capital investment in Australia since the sanctioning of the Gorgon Stage 2 project in 2018. "Using world-leading subsea compression technology, J-IC is positioned to maintain gas supply from the Jansz-Io field to the three existing LNG trains and domestic gas plant on Barrow Island," Hearne said. "This will maintain an important source of clean-burning natural gas to customers that will enable energy transitions in countries across the Asia Pacific region." A modification of the existing Gorgon development, J-IC will involve the construction and installation of a 27,000-tonne normally unattended floating field control station, approximately 6,500 tonnes of subsea compression infrastructure, and a 135-km submarine power cable linked to Barrow Island.
The Plover Formation is one of two reservoirs in the Ichthys field of the Australian North West Shelf. The objective of this study is to build multiple scenario-based models to optimize development planning in preparation for the upcoming production phase. The authors have integrated data and interpretations of thin sections, cores, well logs, and seismic data to create multiple geological concepts for the field and to identify key geological uncertainties. The Ichthys liquefied natural gas project is one of the world's largest and involves the development of a gas-condensate field in the Browse Basin. The field is approximately 220 km offshore Western Australia and covers an area of approximately 800 km2 with an average water depth of approximately 250 m.
This page provides SPE members access to the July 2021 issue -- digital, pdf, and online. Digital archive of issues back to January 2020 is available – scroll down from the current issue cover. These are the papers synopsized in JPT this month. They are available to SPE members only through 31 August 2021. There are also links to them at the bottom of each related synopsis.
Abstract Faulting is one type of structural trap for hydrocarbon reservoirs. With more and more fields moving toward the brownfield or mature operations stage of life, the opportunity to target bypassed or attic oil in the vicinity of bounding fault(s) is becoming more and more attractive to operators. However, without an effective logging-while-drilling (LWD) tool to locate and map a fault parallel to the well trajectory, it has been challenging and potentially high risk to optimally place a well to drain oil reserves near the fault. Operators often plan these horizontal wells at a significant distance away from the mapped fault position to avoid impacts to the well construction and production of the well. Often, the interpreted fault position, based on seismic data, can have significant lateral uncertainty, and uncertainties attached to standard well survey measurements make it challenging to place the well near the fault. This often results in the wells being placed much farther from the fault than expected, which is not optimal for maximizing recovery. In other cases, due to uncertainty in the location of the fault, the wells would accidentally penetrate the side faults and cause drilling and other issues. Conventional remote boundary detection LWD tools do not assist with locating the fault position, as they only detect formation boundaries above or below the trajectory and not to the side. In this paper, the authors propose a novel approach for mapping features like a fault parallel to the well trajectory, which was previously impossible to map accurately. This new approach utilizes a new class of deep directional resistivity measurements acquired by a reservoir mapping-while-drilling tool. The deep directional resistivity measurements are input to a newly devised inversion algorithm, resulting in high-resolution reservoir mapping on the transverse plane, which is perpendicular to the well path. These new measurements have a strong sensitivity to resistivity in contrast to the sides of the wellbore, making them suitable for side fault detection. The new inversion in the transverse plane is not limited to detecting a side fault; it can also map any feature on the transverse plane to the well path, which further broadens the application of this technology. Using the deep directional resistivity data acquired from a horizontal ultra-ERD well recently drilled in the Wandoo Field offshore Western Australia, the authors tested this approach against the well results and existing control wells. Excellent mapping of the main side fault up to 30 m to the side of the well was achieved with the new approach. Furthermore, the inversion reveals other interesting features like lateral formation thickness variations and the casing of a nearby well. In addition, the methodology of utilizing this new approach for guiding geosteering parallel to side fault in real time is elaborated, and the future applications are discussed.