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.
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.
Liu, Zhen (Jiangsu University of Science and Technology) | Zhu, Renqing (Jiangsu University of Science and Technology) | Ji, Chunyan (Jiangsu University of Science and Technology) | Chen, Minglu (Jiangsu University of Science and Technology) | Teng, Bin (Dalian University of Technology) | Li, Liangbi (Jiangsu Modern Shipbuilding Technology Co. Ltd, Jiangsu University of Science and Technology)
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.
Most offshore wells that require artificial lift are gas lifted, as gas typically is readily available and compared to other lift systems, gas lifting is relatively inexpensive and low maintenance. However, electric submersible pumps (ESPs) can
efficiently and economically increase oil production and reserves recovery under the appropriate operating conditions. This may translate to a lower abandonment pressure in the long term—possibly reducing the total number of wells required to deplete an asset.
Since few ESPs currently are installed in offshore wells, an ESP screening "Rules of Thumb" was created as a simple guide for prioritizing offshore ESP candidates. The selection criteria focus on feasibility of installation, operability conditions
and operating practices to maximize run life, and economic considerations. ExxonMobil† and industry experience from North America, South America, West Africa, Asia, Australia, the Middle East, and the North Sea provided the basis for the study.
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.
Qiao, Dongsheng (Center for Deepwater Engineering, Dalian University of Technology) | Ou, Jinping (Center for Deepwater Engineering, Dalian University of Technology) | Wu, Fei (Luxun Academy of Fine Arts)
The Spar platform has developed into a well functioning solution for Gulf ofMexico environment. Considering use of this solution in the North Atlantic, themetocean conditions differ by long period swell and fatigue induced by normaloperational seas.
In order to meet these challenges, it is desirable to consider a classic Sparthat is more fatigue redundant than a truss, but the swell requires highnatural periods, to avoid parametric heave-pitch resonance.
A new version of the Spar in response to these requirements is the Belly Spar.It can be considered as a classic Spar with a Belly; starting below the wavesurface and extending down to the hard tank depth. A concrete Spar concept withreduced waterline diameter has also been developed by Aker Solutions for arcticapplication. This concept had the dual benefit of increasing the natural periodin heave as well as reducing the ice load from sea ice
The concept has been developed for a field in the Norwegian Sea, in water depthof 1,200m (4,000ft). The hydrodynamic analyses show excellent performance,however contain assumptions on damping. The design has been by model testing ofthe design in wave and current combination representing 10,000yr events, asshown by results and correlations in the paper.
The design opens up new areas for the Spar platform, with good motions that canaccommodate steel catenary and top tensioned risers. As for previous Sparconcepts, the application is in deepwater and ultradeepwater.
The plans for many of the upcoming deepwater projects involve the use of highpower Electrical Submersible Pump (ESP) Systems for Artificial Lift. However,the perception in the industry is that the average run-life currentlyachievable with such high power ESP Systems is much shorter than what would bedictated by robust project economics, given that intervention costs in theseapplications can be very high, in the US$50MM - 75MM range. Therefore, theconsensus among operators is that there is a need to try and improve thereliability of these systems.
In response to this industry need, DeepStar® recently commissioned a gap studytowards identifying the barriers that may be preventing ESP Systems fromachieving the desired reliability as well as the additional R&D effort thatmay be required for the industry to close the existing gap. DeeepStar® providesa forum for deepwater technology development, while leveraging the financialand technical resources of the industry (http://www.deepstar.org/).
This paper presents a summary of the results of this study, including: a) theMean Time To Failure (MTTF) that people believe is currently achievable (i.e.with current technology); b) the biggest differences about these applications,which introduce additional uncertainty to the ability of the system to performreliably; c) the main sources of uncertainty regarding each of the major ESPSystem component's reliability; and d) the tentative plan that was outlined aspart of the project, to address the gaps that were identified.
The Gap Analysis was based on phone interviews conducted with recognizedindustry experts, on discussions that took place with members of a TechnicalCommittee (TC) that was put in place for the project, and on a broader industrysurvey conducted through the internet. The proposed go-forward plan consists oftwo follow-up projects: one focused on improved system design and operationalpractices, including system monitoring (or surveillance) and control; and onefocused on validating the design of key components of concern, for thespecifics of these applications, through laboratory testing. The proposednear-future R&D effort has the support of major operators, but still needsto be fine-tuned, with input from the industry, before the actual work canproceed with buy-in and financial support from all of the partiesinvolved.