The high-profile blowout at Macondo well in the US Gulf of Mexico, brought the challenges and the risks of drilling into high-pressure, high-temperature (HPHT) fields increasingly into focus. Technology, HSE, new standards, such as new API procedures, and educating the crew seem to be vital in developing HPHT resources. High-pressure high-temperature fields broadly exist in Gulf of Mexico, North Sea, South East Asia, Africa, China and Middle East. Almost a quarter of HPHT operations worldwide is expected to happen in American continent and the majority of that solely in North America. Oil major companies have identified key challenges in HPHT development and production, and service providers have offered insights regarding current or planned technologies to meet these challenges. Drilling into some shale plays such as Haynesville or deep formations and producing oil and gas at HPHT condition, have been crucially challenging. Therefore, companies are compelled to meet or exceed a vast array of environmental, health and safety standards.
This paper, as a simplified summary of the current status of HPHT global market, clarifies the existing technological gaps in the field of HPHT drilling, cementing and completion. It also contains the necessary knowledge that every engineer or geoscientist might need to know about high pressure high temperature wells. This study, not only reviews the reports from the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) and important case studies of HPHT operations around the globe but also compiles the technical solutions to better maneuver in the HPHT market. Finally, the HPHT related priorities of National Energy Technology Laboratories (NETL), operated by the US Department of Energy (DOE), and DeepStar, as a strong mix of large and mid-size operators are investigated.
Napalowski, Ralf (BHP Billiton) | Loro, Richard (BHP Billiton) | Anderson, Calan Jay (BHP Billiton) | Andresen, Christian Andre (ResMan AS) | Dyrli, Anne Dalager (ResMan AS) | Nyhavn, Fridtjof (ResMan AS)
This paper describes the interventionless approach that was successfully executed during the Pyrenees early production phase to identify the timing and location of water breakthrough. Chemical inflow tracers were installed in key production wells within the lower completion along the horizontal production sections. Results from this work have supported the reservoir simulation history matching process and confirmed the performance of the inflow control devices (ICDs). These data in conjunction with the real time rate information from subsea multiphase meters has allowed proactive reservoir and production management that has contributed to the early identification of additional infill opportunities.
The Pyrenees Development comprises three oil and gas fields: Ravensworth, Crosby and Stickle. The fields are located in production licenses WA-42-L and WA-43-L, offshore Western Australia, in the Exmouth Sub-basin and are operated by BHP Billiton (Fig. 1). Eighteen subsea wells, including 14 horizontal producers, 3 vertical water disposal wells and 1 gas injection well have been constructed to date and additional wells are planned for infill and to develop additional resources. First oil was achieved during February 2010 and production exceeded 50 million barrels in November 2011.
The Pyrenees fields are low relief, with oil columns of approximately 40 metres within excellent quality reservoirs of the Barrow Group. The 19° API crude has moderate viscosity, low gas / oil ratio (GOR), and a strong emulsion forming tendency which makes oil/water separation and accurate well test metering difficult. Early in the project design phase it was identified that the complex subsea gathering system and the need to reduce measurement uncertainties would dictate special attention to production measurement.
Subsea multiphase flow meters (MPFMs) were specified to meet the challenges of production optimization and allocation while at the same time minimizing production deferral for separator testing. Each oil producer is monitored by a dedicated MPFM. With 14 meters, Pyrenees is among the largest subsea MPFM installations worldwide.
This paper describes the process of MPFM qualification and commissioning together with their performance over 2 years in the field. We show how close cooperation between the Operator and MPFM Vendor has enabled quality rate measurements of emulsified production despite large changes in producing gas/oil ratio and water cut.
While the primary justification for Pyrenees subsea MPFMs was production allocation and optimization, interpretation of transient water cut and GOR data proved valuable for production and reservoir engineering applications. Examples of proactive reservoir and production management including optimizing drawdown of Inflow Control Device (ICD) equipped wells, optimizing well lineup and gas lift to commingled wells are presented.
Producing and delivering North West Australia (NWA) deepwater gas reserves to LNG plants poses unique challenges. These include extreme metocean conditions, unique geotechnical conditions, long distances to infrastructure and high reliability/availability requirement of supply for LNG plants. A wet or dry tree local floating host platform will be required in most cases. Whereas semisubmersible, TLP, Spar and floating LNG (FLNG) platform designs all have the attributes to be a host facility, none has been installed in this region to date.
This paper will address important technical, commercial and regulatory factors that drive the selection of a suitable floating host platform to develop these deepwater gas fields off NWA. Linkages between key reservoir and fluid characteristics and surface facility requirements will be established. A focus will be on the unique influence of regional drivers and site characteristics including metocean and geotechnical conditions, water depths and remoteness of these fields.
There have been 17 FPSOs producing oil in Australian waters. These facilities have been chosen because of the remoteness of the fields and the lack of pipeline and process infrastructure. Storing oil on the FPSO for offloading and shipping from the fields becomes an obvious solution. Semisubmersible, TLP or Spar platforms show little advantage in such developments.
For deepwater gas developments, the product has to be processed, compressed and piped to shore for liquefaction. As host processing facilities, Semisubmersible, TLP and Spar platforms have clear advantages over FPSOs because of their superior motion performance in the harsh Australian metocean environment and other benefits such as facilitating drilling, dry tree completion and well services. FPSOs or FSOs may be applied for storage of associated oil and condensates. For marginal and remote gas field developments, an LNG FPSO (FLNG) may be an attractive option as it eliminates long pipelines and land-based liquefaction plants.
As discussed by Dorgant and Stingl (2005), a deepwater field development life cycle following discovery usually involves five distinct phases, Figure 1. The "select?? phase occurs after a discovery has been appraised sufficiently to further evaluate it for development. It consists of evaluating multiple development concepts and scenarios and selecting the one that will most likely achieve the identified commercial and strategic goals. Selecting a floating platform and its functions for a deepwater development is an important subset of the select phase and the overall field development planning.
The process of field development planning involves a complex iterative interaction of its key elements (subsurface, drilling and completions, surface facilities) subject to regional and site constraints (D'Souza, 2009). The objective is to select a development plan that satisfies an operator's commercial, risk and strategic requirements. It entails developing a robust and integrated reservoir depletion plan with compatible facility options. The selection occurs while uncertainty in critical variables that determine commercial success (well performance, reserves) is high. One of the challenges is to select a development plan that manages downside reservoir risk (considering the very large capital expense involved) while having the flexibility to capture its upside potential.
The Santos Health & Well Being program has been running since 2006. Integrated with a range of proactive human resource initiatives implemented over a number of years and guided by Santos values, significant improvements in health related indicators as well as improvements in human resource outcomes have been achieved. These results are built on a foundation of leadership development, employee engagement, targeted interventions and a range of Santos policies that support and focus on people development and encouraging healthy environments across the business.
Overview of Santos
Santos is an Australian energy pioneer that has operated since 1954 and is one of the country's leading gas producers, supplying Australian and Asian customers. The company today is the largest producer of natural gas to the Australian domestic market, supplying 16% of the nation's gas needs from remote outback operations in South Australia and Queensland and offshore operations in Western Australia and Victoria. Santos has also developed major oil and liquids businesses in Australia and operates in all mainland Australian states and the Northern Territory. In addition to it's Australian businesses, Santos has significant operations in Indonesia and Bangladesh, is developing it's business in Vietnam and is conducting exploration activities in Central Asia.
From this base, Santos is pursuing a transformational liquefied natural gas (LNG) strategy with interests in four exciting LNG projects. This strategy is led by the cornerstone GLNG project in Queensland - a leading project in converting coal seam gas into LNG. Also in Santos' LNG portfolio are the PNG LNG project, which was formally approved in December 2009, Bonaparte LNG, a proposed floating LNG project in the Timor Sea, and Darwin LNG, Santos' first LNG venture, which began production in 2006.
In 2011, Santos' total production was 47.2 million barrels of oil equivalent. We have the largest Australian exploration and production portfolio by area of any company circa 152,000 square kilometres. Santos has about 2,700 employees working across its operations in Australia and Asia and is one of Australia's Top 30 listed companies.
An Integrated Approach
The Santos health programme is aligned with the company's values and the broader HR strategy. Such an integrated approach has enabled Santos to develop its organisational culture and achieve broader people related outcomes which support and sustain the business achieve its long term goals.
In May 2011 Shell announced its commitment to the development of a Floating Liquefied Natural Gas (FLNG) concept by taking the Financial Investment Decision on the Prelude FLNG Project. Prelude is located in Australian offshore waters, approximately 475 km north-northeast of Broome and 825 km west of Darwin, and will be Shell's and possibly the world's first FLNG development. FLNG offers a number of environmental advantages over traditional onshore LNG developments. This paper describes some of these and the associated environmental permitting/approval conditions for the project.
An analysis approach to assess borehole stability following a hypothetical blowout from representative deepwater scenarios is presented. It addresses whether imposed underbalanced conditions cause sufficient instability that the borehole bridges-over and the well kills itself. The approach uses a series of interrelated analyses: (i) analyses of the kick and blowout development are performed predicting how bottom pressure and in-flow velocity changes over time; (ii) underbalanced wellbore failure in exposed shales and sands is then determined; (iii) cavings and produced sand volumes are calculated from the estimated failure zone, and the transport of these materials in the borehole is determined from the predicted hydrocarbon flow rates; and (iv) bridging tendency is assessed by considering the concentration of cavings in either the enlarged borehole or in flow-paths within the well casing or annuli.
To the best knowledge of the author, the proposed analysis presents the first in-depth study of transient wellbore instability, sand / cavings transport and bridging tendency during a blowout. Analyses applied to a typical deepwater blowout scenario suggest that bridging leading to self-killing can occur only in a small number of situations. This differs from the more widely published data from shallow water Gulf of Mexico Shelf wells which show that self-killing is likely in shallow-hazard scenarios.
Important conclusions from the study are: (1) bridging and self-killing can occur in kicks resulting from a catastrophic loss of riser integrity, due to the loss of the riser margin causing underbalanced conditions in openhole sections of the borehole; and (2) bridging and self-killing is more likely to occur in a well control event that develops while drilling-ahead, due to plugging of the borehole/drill-pipe annulus. Bridging is less likely to occur if a kick develops with the drill-pipe not in the open-hole interval. For self-killing to happen this study concludes that it has to occur during the time that the kick is developing - i.e. before hydrocarbons reach the wellhead. Once the kick has fully developed into a blowout it is predicted that typical high productivity deepwater reservoirs will have attained sufficient borehole flow velocity (in the absence of major constrictions to flow) that spalled or produced formations will be transported from the wellbore without bridging. Once a blowout has occurred, therefore, it is largely too late to consider future bridging as a means of terminating the flow, at least in the short-term.
Li, Zhigang (Offshore Oil Engineering Co. Ltd.) | He, Ning (Offshore Oil Engineering Co. Ltd.) | Duan, Menglan (Offshore Oil/Gas Research Center, China University of Petroleum) | Wang, Yingying (Offshore Oil/Gas Research Center, China University of Petroleum) | Dong, Yanhui (Offshore Oil/Gas Research Center, China University of Petroleum)
New oil and gas frontiers are presently looking at projects offshore of theGulf of Mexico and South Atlantic, including West African and Brazilian watersand soon after Asia Pacific. New technologies are required to performinstallation in a cost efficient and safe method; they must encompass the stateof art equipment in order to provide effective solutions. The new ships FDS2and CastorONE are Saipem's replies to the forthcoming challenges indeep/ultra-deep water field development and pipe lying. The new vessels willoperate by using new welding, NDT and field joint coating technologies,including innovative installation equipment able to generate added value forthe implemented solutions. Field development projects include complex risersystems and the new fleet is designed to offer reliable solutions for thefuture configurations, which are designed to route the oil and gas fluids tothe floating treatment units. Saipem FDS2 is described by indicating hercapabilities and her equipment, including those required for project in shallowwater and those specifically designed for deep waters installation.Furthermore, sea keeping and naval features are offered in order to demonstrateher versatility and ability to solve main installation challenges relevant tothe deep water fields. Trunk line projects will be addressed to transportationof large gas volumes over long distances across harsh environments and Saipemvessel CastorONE is presented by showing off her capabilities for the ultradeep water installation. Information on the new state of art rigid stinger isprovided together with some conceptual solutions designed to increase theefficiency of the working stations and of the method to transfer the pipes withspecific equipment. The paper concentrates on the installation requirements forthe in-field production gathering systems and on the oil and gas exportpipelines.
Field development: the leading market trends
Since 1998, numerous deep water field development projects, mainly in the SouthAtlantic region both in West Africa and in Brazil were carried outsuccessfully. The vision for the future leads towards two major trends: evendeeper waters and new surprising geographical regions. Moving in bothdirections, thanks to its top class technologies and assets, Saipem aim to leadthe path towards the even tougher future challenges.
The scope of the work of deep water projects, within EPCI type contracts, hasnormally included all major and minor technical aspect, supplies andinstallation/operations from A to Z, with contract values typically in therange of half to one billion USD. Key of this market segment - which nowrepresents a significant portion of turnover and backlog - has been theintegrated development of original technical solutions and dedicatedfit-for-purpose installation vessels.
Leveraging on its notable competence, track record and offshore constructionfleet, the two main lines of evolution for the offshore field developmentmarket were, are and will be tackled, namely ultra-deep waters and new frontierregions as follows:
• On one hand, the ultra-deep water developments, emerging in the traditionaloil provinces in the Gulf of Mexico and South Atlantic, will require theIndustry to make available new technologies and equipment to support the safeand effective implementation of the relevant production schemes;
• Simultaneously, the development of subsea oil and gas fields is taking placein new world regions bringing quite new challenges from both the technical andexecution standpoints.
Exploitation of oil and gas reservoirs in water depths in excess of 2,000m (?6600') is progressively emerging as the new market. Gulf of Mexico, offshoreBrazil and West of Africa are nowadays showing the greatest concentration offield development projects. In addition, subsea developments in new areas suchas East India, Indonesia, Offshore China and Western Australia are appearing inthe offshore oil and gas theatre both for relatively moderate and for deeperwater depths.
Perdido Regional Development in the Western Gulf of Mexico and the Walker Ridgearea in the Central Gulf of Mexico will be significant and challenging offshoreprojects.