Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Results
A Successful Deployment of Permanent Coiled Tubing Gas Lift Completion in Sabah Mature Deepwater SPAR Asset Providing Significant Effects on Production
Raman, Intiran (PTTEP Sarawak Oil Ltd.) | Wardhana, Yulian (PTTEP Sarawak Oil Ltd.) | Selamat, Kasim (PTTEP Sarawak Oil Ltd.) | Shepheard, Barry (PTTEP Sarawak Oil Ltd.) | Paramalingam, Raj (PTTEP Sarawak Oil Ltd.) | Alptunaer, Kaya (PTTEP Sarawak Oil Ltd.) | Caldow, Scott (PTTEP Sarawak Oil Ltd.) | Azhar, Herman (Schlumberger) | Yong, Nigel (Schlumberger) | Kalidas, Sanggeetha (Schlumberger) | Sorman, Ignatius (Schlumberger) | Wijoseno, Danny Aryo (Schlumberger) | Sudiyono, Agus Widyanari (Schlumberger) | Shafiee, Muhamad Zaidi (Solar Alert Sdn. Bhd.) | Blacklock, Jon David (Formerly worked at Murphy Oil Corp.)
Abstract A mature deepwater asset of 1,330 m of water depth offshore Sabah, Malaysia, has been delivering notable production since 2007, and currently the field is in its declining mode. The second phase of the field development focused on producing from the thin-bed layers of the reservoirs, which were found less efficient in pressure maintenance given existing water injection support as the primary support. Initial conceptual studies were conducted between 2012 and 2014 to determine which improved oil recovery (IOR) initiative would be the most effective and economical way to retain declining production of the field, extend end-of-life, and ultimately protect reserves. Further in-house engineering studies and follow-up with a field mini-trial in 2014 demonstrated that providing gas lift to the spar wells would improve and revive production of the targeted wells. A permanent coiled tubing (CT) with gas lift completion (CTGL) was determined as the most efficient and cost-effective solution. Single-point gas injection is sufficient given available injection pressure, static/dynamic fluid level, and the available maximum depth of the injection tip. Modifications of the dry tree on the spar facility were required to accommodate the changes; changes included a new 5-in. gas lift pipeline; topside piping at the spar; and installation of associated control, metering, and instrumentation devices. Specific CT bottomhole assembly (BHA)/components were determined to safely deliver gas inside the 3.5-in. and 4.5-in. production tubing to slightly above the wellโs downhole safety valve. A total of 14 dry-tree wells were selected for this project and the project has successfully completed installation of CTGL in 11 wells by mid-year 2019. Wellhead modification was carried out by installing the tubinghead spool and gas injection arm. A CT rigid riser well stackup was rigged up directly on the tubinghead spool. The 1.25-in. outer diameter (OD) chrome CT string and gas lift BHA of specific simulated venturi sizes were deployed to the targeted depth in each well. Downhole completion safety valve and gas lift BHA double flapper check valves were then be inflow tested. Blowout preventer (BOP) was engaged against the 1.25-in. OD CT string, and pressure in the well stackup above the rams was bled off before cutting off the CT string. The CT tubing hanger was made up directly on the cut CT string. Finally, the CT tubing hanger was installed into the tubinghead spool with a 4-in. flow release pulling tool. An additional simulation study was performed to confirm the ability of the 1.25-in. OD CT BHA to inject up to 3 MMscf/D. The executed wells were brought online, and a comparison of the well tests was performed. The CTGL wells responded very well whilst being assisted with gas lift, which delivers an outstanding result by adding incremental gain of 20%, and even adding value to revive idle wells, which has significant value by doubling the base production figure without gas lift. An estimate of more than 50% protected reserves can be achieved with the 11 CTGL wells at the end of field life. The installation and execution of CTGL came at the right time as the field requires lift assistance to stay productive.
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.34)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Carnarvon Basin > Barrow Basin > Greater Gorgon Development Area > Block WA-4-R > Spar Field > Upper Barrow Formation (0.98)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Carnarvon Basin > Barrow Basin > Greater Gorgon Development Area > Block WA-13-L > Spar Field > Upper Barrow Formation (0.98)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Alpha Arch > Barrow Basin > Greater Gorgon Development Area > Block WA-4-R > Spar Field > Upper Barrow Formation (0.98)
- (2 more...)
- Information Technology > Communications > Networks (0.46)
- Information Technology > Modeling & Simulation (0.34)
Abstract Decent profit margins enjoyed by the oil industry are mainly due to inexpensive wells of the past. Exploration, development, and production costs have escalated to a level where small to medium size offshore fields are challenged to be economically developed. Each opportunity comes with its own unique constraints requiring adaptive and flexible applications from a variety of processes and systems. The art of field development engineering requires linking interactive and integrated flow of information, best practices, lessons learned, and risk management across all disciplines. This starts with reservoir evaluation and development through surface facilities and transport systems, and production management. Further considerations include finance, procurement and contracting strategy, equipment standardization, and decommissioning. Success of economically challenged field development depends on an experienced team with deep understanding of each respective domain and appreciation in interfacing disciplines. Such a team using a systematic approach challenging each constituent system and process in the field development procedure chain will help identify an optimum development plan. In this paper, the strategy, technology, and step changes necessary for successful development of economically challenged fields are identified. The inter-dependence between sub-surface, drilling and completion, and surface facilities including production and operations are established in relation to cost, safety, and risk management. This paper will discuss a systems approach for prudent selection of all surface facilities and drilling and completion design taking due account of reservoir uncertainty. The primary focus of this work is deep water fields of Gulf of Mexico (GOM) with strong analogs for application in other regions of the world including regional socio-political impact. High level discussion on the main drivers of the selection of deep water platforms, subsea architecture, and risers are presented.
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Carnarvon Basin > Barrow Basin > Greater Gorgon Development Area > Block WA-4-R > Spar Field > Upper Barrow Formation (0.93)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Carnarvon Basin > Barrow Basin > Greater Gorgon Development Area > Block WA-13-L > Spar Field > Upper Barrow Formation (0.93)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Alpha Arch > Barrow Basin > Greater Gorgon Development Area > Block WA-4-R > Spar Field > Upper Barrow Formation (0.93)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Alpha Arch > Barrow Basin > Greater Gorgon Development Area > Block WA-13-L > Spar Field > Upper Barrow Formation (0.93)
Vortex Induced Motions (VIM) of a Spar platform have significant impact on the performance of mooring and riser systems in terms of both strength integrity and fatigue, especially when the platform is located in high current speed environment. With A/D curves obtained from VIM model tests or CFD analysis, nonlinear time domain analysis tool can accurately predict the motion and mooring tension time history of Spar platforms when subjected to VIM effects. This paper will discuss the time domain analysis of Spar long term and short term VIM fatigue using nonlinear quasi-static program MLTSIM. One advantage of quasi-static time domain program is its high computational efficiency, and since the line dynamics effect is found to be small for a taut leg mooring system, the accuracy is considered to be comparable to fully coupled programs. For mooring analysis, with the tension time history obtained for each environmental bin, the fatigue damage can be calculated using T-N curve and rainflow counting method. For riser/ pull tube analysis, the motion time history may be used in more detailed riser models to obtain stress history, and the fatigue damage can be then obtained using S-N curve and rainflow counting method. Detailed discussion is also given on the impact of polyester stiffness on the mooring fatigue analysis. Example of VIM fatigue analysis of a Truss Spar using cycle counting methods will be presented and the results are compared to those obtained from a spectrum method.
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Carnarvon Basin > Barrow Basin > Greater Gorgon Development Area > Block WA-4-R > Spar Field > Upper Barrow Formation (0.98)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Carnarvon Basin > Barrow Basin > Greater Gorgon Development Area > Block WA-13-L > Spar Field > Upper Barrow Formation (0.98)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Alpha Arch > Barrow Basin > Greater Gorgon Development Area > Block WA-4-R > Spar Field > Upper Barrow Formation (0.98)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Alpha Arch > Barrow Basin > Greater Gorgon Development Area > Block WA-13-L > Spar Field > Upper Barrow Formation (0.98)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Risers (1.00)
- Facilities Design, Construction and Operation > Offshore Facilities and Subsea Systems > Mooring systems (1.00)
- Facilities Design, Construction and Operation > Offshore Facilities and Subsea Systems > Floating production systems (1.00)
Abstract One of the key features of the Spar platform is its low motion response characteristics. This results in a high degree of functional flexibility that has enabled the Spar to be employed in a variety of different applications such as wet tree host, dry tree wellhead, with or without platform drilling facilities and with or without production facilities. The Spar has also been employed as wellhead only platform, utilizing Tender Assisted Drilling in place of a Spar mounted drill set. While all but one of the Spars in service today operate in the US Gulf of Mexico (the one exception being the Kikeh Spar in Malaysia), new designs have been developed for the Spar platform to further extend its use, both in terms of function and geographic location, in order to meet the needs of other oil and gas producing regions as they extend their E&P activities into deeper waters and more harsh environments. These designs range from relatively simple modifications, such as the incorporation of crude oil storage in the hull to facilitate the use of dry tree completions and motion sensitive riser systems in infrastructure-remote locations, to more significant modifications, such as the reconfiguration of the Spar as a power and control buoy platform, or as a deep water Arctic platform, which requires the Spar to function as an ice-breaker in sheet ice conditions, while also allowing it to be disconnected to avoid larger icebergs. The functional requirements, export infrastructure, operating environments and construction and installation capacity vary significantly across regions. Each of these variations has the potential to drive alterations to the Spar hull configuration. This paper discusses the most significant requirements of a number of key regions where Spar technology can provide significant value, and addresses these requirements in terms of the resulting Spar configuration and how the Spar design has been, or can be, adjusted to meet the local challenges and requirements. The specific regions covered are the ultra deep waters of the Gulf of Mexico, S.E. Asia, West Africa, North Sea, Brazil and the Arctic regions of East Canada and the Barents Sea. A variety of Spar configurations are presented to address nominal solutions for each of the regions, each based on either the Classic, Truss or Cell Spar technology. Introduction The Spar platform exhibits low motion response characteristics in response to environmental loads when compared to other floating structures. This is due to the deep draft design and high stability which results from the inherent separation of the center of gravity and center of buoyancy. The center of gravity is lowered by installing heavy ballast at the platform keel. The low motions of the Spar platform enable the use of motion-sensitive rigid risers such as top tensioned and steel catenary risers in water depths ranging from as shallow as 300 m to over 3,000m. Broadly there are three Spar types: Classic, Truss and Cell. These are shown in Figures 1 to 3. However, there are a number of available variations of each Spar type which address a range of required functionality and operating environment, for example, the Closed Centerwell Spar represents one key variation of the Truss Spar design. Presently there are seventeen Spars in service, three Classic Spars, thirteen Truss Spars and one Cell Spar. All except the Kikeh Truss Spar offshore Malaysia are deployed in US Gulf of Mexico (GOM). While the basic Spar concept dates back several decades, the Classic Spar represents the first reference point for modern Spar technology, with the Neptune Spar marking the first Spar application, having been installed in 1996. The Classic Spar hull comprises three main components as shown in Figure 4.
- North America > United States > Texas (0.28)
- Europe > United Kingdom > North Sea (0.26)
- Europe > Norway > North Sea (0.26)
- (4 more...)
- South America > Brazil > Campos Basin (0.99)
- South America > Brazil > Brazil > South Atlantic Ocean > Santos Basin (0.99)
- North America > Canada > Quebec > Arctic Platform (0.99)
- (20 more...)
Abstract Deepwater field developments in the Gulf of Mexico typically consider Spar, Tension Leg Platform and Semisubmersible hull forms as potential candidates for floating facilities. Since 2005, field development studies for floating systems have had to consider more severe environmental conditions, including increased wind and wave criteria released in API Bulletin 2INTMET in 2007, increased or more prevalent loop/eddy current events and longer wave periods. These changes have quantifiable impacts to Spar hull and mooring design that are evaluated in this paper. In addition to the design challenges presented by the environment, operator functional requirements (e.g. hull-supported top-tensioned risers), robustness requirements (e.g. minimum air gap in survival conditions) and execution plan considerations (e.g. hull dry transport constraints) also have a quantitative impact on the Spar configuration. This paper presents a summary of the recent design challenges affecting Gulf of Mexico Spar design and uses global performance analysis to evaluate different options to update the Spar configuration to effectively satisfy the design challenges. Design solutions that produce acceptable global performance results are further evaluated to quantify the potential benefit to delivery cost and schedule based on overall hull weight. Based on the analysis results, recommendations are made regarding the best solution to meet the identified post-Katrina design challenges. Results indicate that the optimum number of heave plates depends on the top-tensioned riser support system. The effect of overall hull length (a typical execution plan constraint) on overall weight (and therefore cost) for a given payload is identified. The technical solutions and recommendations are applicable to all future field developments that are considering a Spar hull concept to support floating facilities. The offshore oil industry is characterized by more challenging developments, increasing costs, and ever-increasing focus on safety and survivability. The technical conclusions and recommendations from the work discussed in this paper will assist operators that choose the Spar concept in developing more cost effective designs that retain the required robustness and survivability for safe, reliable operations. Introduction Deepwater production of oil and gas in the Gulf of Mexico utilizes floating and subsea systems. Spar, Tension Leg Platform and Semisubmersible hull forms have been used for existing floating production systems and are typically considered for new developments. All of these hull concepts have unique features to meet the demanding functional and environmental requirements of offshore oil and gas production. As experience is gained in deepwater production, functional and environmental requirements are updated and the hull concepts must be evaluated in consideration of the updated requirements to ensure that each implementation provides a good balance of cost, function, reliability and safety. This paper specifically considers the Truss Spar concept and evaluates unique aspects of the concept against updated constraints and requirements, including:โUpdated metocean criteria โUpdated air gap criteria โConstraints on overall hull length due to the preference for single-piece transport โRequirements for top-tensioned riser support in deep water
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Carnarvon Basin > Barrow Basin > Greater Gorgon Development Area > Block WA-4-R > Spar Field > Upper Barrow Formation (0.97)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Carnarvon Basin > Barrow Basin > Greater Gorgon Development Area > Block WA-13-L > Spar Field > Upper Barrow Formation (0.97)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Alpha Arch > Barrow Basin > Greater Gorgon Development Area > Block WA-4-R > Spar Field > Upper Barrow Formation (0.97)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Alpha Arch > Barrow Basin > Greater Gorgon Development Area > Block WA-13-L > Spar Field > Upper Barrow Formation (0.97)
Deep draft floating production units are supposed to have motion characteristics that can accommodate dry tree wellheads. The motion response characteristics are normally determined by means of linear hydrodynamic calculations. The paper shows that there are nonlinear phenomena that may influence the final motion characteristics, like the parametric resonance. We explain the theoretical background of this, and discuss different measures that can reduce the adverse effects of it for different types of deep draft floaters. INTRODUCTION Oil production from floating offshore structures is either based on dry tree risers or flexible risers from sub sea wellheads. Up to now, dry tree solutions are normally accommodated by TLP platforms or SPAR buoys. Ordinary semisubmersibles and FPSOs are normally accommodating flexible risers. The reason for this is the fact that dry tree risers require the motions of the production unit to be relatively moderate; within the stroke lengths of available heave compensators. The "dry tree floaters" have some inherent drawbacks. The TLPs will have very expensive and complicated tether system for large water depths. SPAR buoys have almost no form stability and need to trade large wind heeling angles with reduced topside weight. Therefore it can be interesting to develop deep draft semisubmersible units as dry tree production units, especially for large water depths. So-called deep draft semisubmersible column stabilized units have the potential to accommodate dry tree risers due to reduced wave excitation at deeper drafts. Even if such units have been projected for some years now, very few, if any, have been constructed or put into operation. There is consequently no full scale experience with how such units will behave in real wave conditions. When extrapolating the knowledge from known technology beyond the frontiers of full scale experience, there is always the danger of overlooking something.
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Carnarvon Basin > Barrow Basin > Greater Gorgon Development Area > Block WA-4-R > Spar Field > Upper Barrow Formation (0.98)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Carnarvon Basin > Barrow Basin > Greater Gorgon Development Area > Block WA-13-L > Spar Field > Upper Barrow Formation (0.98)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Alpha Arch > Barrow Basin > Greater Gorgon Development Area > Block WA-4-R > Spar Field > Upper Barrow Formation (0.98)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Alpha Arch > Barrow Basin > Greater Gorgon Development Area > Block WA-13-L > Spar Field > Upper Barrow Formation (0.98)
Abstract Beginning in 1999, BP and its co-lessees embarked on an ambitious program to develop four major fields in deepwater regions of the Gulf of Mexico. Along with presenting a brief summary of each development's unique features, this paper describes the primary challenges facing BP's management in planning and executing this string of major projects and the associated pipeline transportation system project. Contracting approaches and associated issues such as standardization are discussed, along with constraints imposed by service industry limitations and available human resources. BP's approach to technology selection and technology development, in light of limited industry experience and specific Gulf of Mexico environment challenges, are also addressed. Introduction The hydrocarbon potential of the deepwater Gulf of Mexico has been known by the industry for over two decades. Widescale development began in the nineties, most visibly through the deployment of a series of TLPs by Shell in water depths of 3000-4000 feet. Field development in water depths beyond 4000 feet began in earnest around the year 2000, perhaps highlighted by four major projects led by BP: Holstein (with co-lessee Shell), Mad Dog (with co-lessees BHP Billiton and Unocal), Thunder Horse (with co-lessee ExxonMobil), and Atlantis (with co-lessee BHP Billiton). The schedules for these four projects are sequential but largely overlapping, with the first installation targeted for 2004 and the last one scheduled for 2006. All four projects will export oil and gas through the Mardi Gras transportation system, also operated by BP and, itself, a major project. Importantly, with each complex constituting a "hub" and operating for a nominal period of twenty-five years, there will be opportunities for BP and its co-lessees to further utilize the infrastructure by tying in other discoveries to maintain or increase production levels. The overall program has required a coordinated yet flexible approach to contracting and resources. Technology selection and development has been a major challenge in view of the water depths, environment issues, and reservoir conditions. None of the projects can be categorized as "business as usual," with each having an impressive list of unique features and industry firsts. Overview of the Developments The Holstein, Mad Dog, and Atlantis fields are in the Southern Green Canyon area with hub locations in water depths of 4344, 4420, and 7100 feet respectively. The Thunder Horse field is located in the Mississippi Canyon area with its hub facility located in a water depth of 6300 feet. Two basic development concepts were ultimately chosen for the overall program, the truss Spar and the semi-submersible, as depicted in Figure 1. Holstein and Mad Dog are truss Spars while Thunder Horse and Atlantis are semi-submersibles. Figure 2 provides a visual comparison of the water depths. Approximate start-up dates are also indicated. The installation sequence is as follows: Mad Dog, Holstein, Thunder Horse, and Atlantis. For completeness, three existing deepwater hubs operated by BP in Gulf of Mexico deepwater are included in Figure 2: Marlin, Horn Mountain, and Na Kika. To briefly describe these three existing hubs, the host facility at Marlin is a TLP, which has been operating since 1999. Horn Mountain is a truss Spar, which was installed and began production in 2002. Na Kika is a semi-submersiblebased development where BP, as prescribed in the field's Joint Operating Agreement, began its role as post-production Operator upon start-up late in 2003. Prior to start-up, Shell, BP's co-lessee in the development, served as the preproduction Operator. Shell was responsible for design, constructi
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Mississippi Canyon > Block 822 > Thunder Horse Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Mississippi Canyon > Block 778 > Thunder Horse Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > West Gulf Coast Tertiary Basin > Green Canyon (0.98)
- (14 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > HP/HT reservoirs (1.00)
- Management > Strategic Planning and Management > Project management (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Risers (1.00)
- Facilities Design, Construction and Operation > Offshore Facilities and Subsea Systems > Floating production systems (1.00)
Abstract This paper presents a discussion on design of Spar top tensioned risers for 10,000 ft water depth. A parametric study on Spar configurations, riser configurations and tensioning systems is reported. Performance of these concepts for such a deep water depth is compared. Assessment of various riser solutions for 10,000 ft water depth will provide guidelines for selecting the best riser solution. Effect of riser system on design of the Spar is also highlighted through the parametric studies. Results of the study show the difficulties involved in design of riser system for such water depth. Several alternatives are suggested to overcome the design problems. Response of the various Spar/Riser configurations is presented and recommendations are made for most suitable tensioning alternatives. As the offshore production moves to deeper water depths, riser design challenges increase. Applicability of present designs have to be reevaluated for the new design parameters. Present paper provides guidance for riser designs for 10,000 ft water depth. Introduction The offshore production is slowly moving towards deeper water depths. Recent drilling activity in 10,000 ft water depth has increased interest in evaluating options for production for this water depth. In past few years, the Spar concept has become a popular option for the development of deep-water fields. Three Spars of the classical configuration have been installed in the Gulf of Mexico (Ref. 4,6,7), three Spars of the truss configuration are being fabricated (Ref. 1), and a number of additional Spars are in advanced planning stage. Spar offers several advantages over other floater options that have helped to fuel this increase in popularity. Spar is a moored floater that is rather insensitive to water depth. This offers the possibility of reusing the vessel at another site in the future. The center of buoyancy of the Spar is designed to be above the center of gravity. Thus the vessel remains stable in all environmental conditions. The topside deck and facility are very similar to those used on conventional fixed platforms and can perform typical drilling, workover, and producing operations. The motions of a Spar are significantly less than a typical semisubmersible, allowing more drilling and operational up time. Several different riser systems have been developed for Spar platforms. Both top tensioned and steel catenary risers are viable with the Spar concept. The design of risers and mooring lines is the primary challenge in extending the applicability of Spars to 10,000 ft water depth. This paper presents results of a parametric study on different Spar/riser configurations aimed at evaluating performance of various tensioning system options. This study mainly focuses on Truss Spar designs. Several Truss Spar configurations for different topsides operating weights and number of risers were studied to examine the performance of different riser and tensioning system options. Description of Parametric study Objective of this study was to evaluate the behavior of different Spar/Riser configurations. Primary parameters that are important to the sizing of Spar platforms are deck payload, number of top tensioned risers to be installed and environment, in addition to the water depth.
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.48)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Carnarvon Basin > Barrow Basin > Greater Gorgon Development Area > Block WA-4-R > Spar Field > Upper Barrow Formation (0.93)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Carnarvon Basin > Barrow Basin > Greater Gorgon Development Area > Block WA-13-L > Spar Field > Upper Barrow Formation (0.93)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Alpha Arch > Barrow Basin > Greater Gorgon Development Area > Block WA-4-R > Spar Field > Upper Barrow Formation (0.93)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Alpha Arch > Barrow Basin > Greater Gorgon Development Area > Block WA-13-L > Spar Field > Upper Barrow Formation (0.93)
ABSTRACT Oryx Energy Company installed the word's first production Spar platform in the Gulf of Mexico in September 1996 in 1930 ft of water. In order to obtain better understanding of the dynamic behavior of the Spar platform, a field monitoring program was commissioned under a Joint Industry Project involving 12 participants. A suite of instruments was installed to measure platform motions, riser and mooring line tensions as well as environmental conditions such as currents, waves and wind. Full-scale measurements from this field study provide valuable data for verifying the predicted Spar responses. The Oryx Neptune Spar platform was also model tested at the Offshore Technology Research Center wave basin. Analytical and numerical simulations predicted the Spar natural period in heave to be about 28 seconds. However, the field data does not show significant heave response of the Spar at the predicted 28 second natural period. The 16 production risers of the Oryx Neptune Spar terminate in buoyancy cans that float independently from the Spar platform. It is speculated that the additional damping and stiffness contributions from the risers/buoyancy cans/platform interactions cause this discrepancy in the predicted and measured Spar heave response. The model test data includes measurements of the riser top tensions and riser relative heave motion. The model test data provides valuable insights into some of the riser/buoyancy cans/Spar hull interactions. The paper presents an analysis of the model test data to study the influence of the risers on the Spar heave motion. An analysis of the riser/Spar hull interaction forces and its effects on the platform heave motion is presented. INTRODUCTION The deep-draft cylindrical Spar has found increasing use for deepwater production, drilling and storage platform (Halkyard, 1996).
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Carnarvon Basin > Barrow Basin > Greater Gorgon Development Area > Block WA-4-R > Spar Field > Upper Barrow Formation (0.93)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Carnarvon Basin > Barrow Basin > Greater Gorgon Development Area > Block WA-13-L > Spar Field > Upper Barrow Formation (0.93)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Alpha Arch > Barrow Basin > Greater Gorgon Development Area > Block WA-4-R > Spar Field > Upper Barrow Formation (0.93)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Alpha Arch > Barrow Basin > Greater Gorgon Development Area > Block WA-13-L > Spar Field > Upper Barrow Formation (0.93)
Abstract The Neptune Field Development is the first Spar-based floating production system using multiple production risers from seafloor wellheads back to surface trees. To meet an aggressivedevelopment schedule the design, manufacture, and installation of these risers relied on extensive system and component analyses, field-proven equipment or derivative designs, innovative teamwork, and familiar offshore procedures. Introduction The Neptune Field, jointly developed by Oryx Energy and CNG, is located in Viosca Knoll Block 826. The development utilizes a "Spar" floating production system capable of handling 25000 bid and 30MM cf/d. The Neptune Field is located approximately 90 miles south of Mobile, Alabama in 1930 feet of water, at the Eastern end of the geological area known as the Flex Trend (see Figure 1). The Neptune Spar has a multilevel deck supporting well control equipment, first stage separation, and processing for both Spar-based wellsand future satellite well installations. Production is exported to a nearby platform. The Neptune Spar is a permanently moored installation and can accommodate up to sixteen production risers andsurface trees. Riser and tree installation and removal, as well as workover operations, are performed from the Spar. Operations requiring a seafloor BOP, such as subsequent drilling of new wells, are carried out from a drilling vessel. The first seven wells were drilled before the Spar was brought on location, enabling expeditious installation of risers and trees and thereby minimizing the development schedule. Production Riser System Design Many different companies contributed to the design, analysis, and installation of the Neptune riser system components. Oryx assembled a team of companies and individuals with expertise in various riser system areas. Rapid communication and coordination within the team relied heavily on e-mail sent across the Internet. Open discussions via the Internet allowed everyone to be a part of and contribute to the effort on a schedule that was convenient to their workload. In some cases, discussions between individuals on a particular topic generated helpful and timely input from another individual who would not have normally been requested, available, oreven included if a conventional meeting had been held. To meet the Neptune Field's aggressive development schedule, the production riser system uses component configurationsbased on field-proven equipment or modifications to existing designs. A typical riser system, shown in Figure 2, provides a pressure-containing link between surface tree and seafloor wellhead system. The riser system is designed for complete installation and removal using the Spar-based workover rig. The riser system meets the defined load and operational requirements for the range of conditions and events anticipated during the life of the field. The risers are a permanent part of the field development and, once installed, need not be removed during the life of the field. The Neptune Field produces from various highly fractured formations requiring as many as sixteen Spar-based wells to develop the field's reserves effectively. During the life of the field, well workover and re-completions are anticipated and surface wellheads and trees provide a simple and economic approach for such situations.
- North America > United States > Texas > Dawson County (0.34)
- North America > United States > Alabama > Mobile County > Mobile (0.24)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Carnarvon Basin > Barrow Basin > Greater Gorgon Development Area > Block WA-4-R > Spar Field > Upper Barrow Formation (0.93)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Carnarvon Basin > Barrow Basin > Greater Gorgon Development Area > Block WA-13-L > Spar Field > Upper Barrow Formation (0.93)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Alpha Arch > Barrow Basin > Greater Gorgon Development Area > Block WA-4-R > Spar Field > Upper Barrow Formation (0.93)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Alpha Arch > Barrow Basin > Greater Gorgon Development Area > Block WA-13-L > Spar Field > Upper Barrow Formation (0.93)