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As easily accessible petroleum basins have matured, exploration and development have expanded farther offshore and to remote areas. New development challenges are in deep water and in marginal fields with smaller reserves. The facilities required in these new developments are similar in function to conventional processing facilities, but the packaging requirements can be quite different. Process facilities can now be placed literally anywhere between the reservoir and the product pipeline, including subsea and downhole. Obviously, minimizing surface equipment size and weight reduces costs for deepwater platforms.
- Asia (0.92)
- Europe > United Kingdom > North Sea (0.28)
- North America > United States > Texas (0.28)
- Oceania > Australia > Western Australia (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Oil & Gas > Midstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.92)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Barrow Basin > Greater Gorgon Development Area > Block WA-13-L > Spar East Field (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Barrow Basin > Greater Gorgon Development Area > Block WA-13-L > East Spar Field (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Block 14/20b > Highlander Field (0.99)
- (37 more...)
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Casing and Cementing (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- (24 more...)
- Information Technology > Knowledge Management (0.50)
- Information Technology > Communications > Collaboration (0.40)
ABSTRACT: Subsea oil and gas fields are often expanded throughout their life cycle, in some cases by single satellite tie-back while in other cases with significant new developments. The initial development of fields often includes, to a varying degree, preparation and design for some expansion. The reasons for introducing satellite tie-backs are many, but will typically be:–Initially catered for to increase or maintain production rates at a certain point in time. Typically to utilize available processing capacity after production is off plateau or to access anticipated hydrocarbon accumulations in the vicinity of the main development. –Unplanned satellite tie-backs may be the result of lower well productivity than expected, or potentially due to unforeseen reservoir compartmentalization. –Area maturity. Typically the smaller pockets of hydrocarbons will be developed last in an area, thus in some cases resulting in a timeframe challenge with respect to the existing infrastructure. In many cases oil companies include spare capacity in their subsea systems to ensure high availability and redundancy, including possibility to expand with new wells in case of unplanned situations. This includes availability of spare electrical and hydraulic control lines and connection points as well as connection points for production flow and/or injection. Even though potential expansion is often catered for, the adaptation and realization will often encounter technical and commercial obstacles and challenges, all at the same time as customer drivers must be satisfied. Satellite tie-backs are often challenged by their economy, less robust and often with a relatively high investment cost per producing well compared with a greenfield development. Flexible system solution that can quickly be brought on line and that contributes to minimize CAPEX and OPEX is consequently imperative. Also license ownership may differ from the host production system, which, among other factors, makes accurate production allocation crucial. This paper outlines methodology for optimizing the design of satellite tie backs, focusing on:–Standardization and synergies with existing hardware, potential for simplified solutions through re-configuration –Minimizing rig hours and installation time –Implementation of process elements, optimum location in the production system –Advanced monitoring solutions addressing flow assurance, high-accuracy production allocation and optimization combined with condition monitoring of all vital components of the production system
- North America > United States > Texas (0.46)
- Europe (0.29)
- Geophysics > Borehole Geophysics (0.91)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.36)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 50 > Block 34/10 > Gullfaks Sør Field > Statfjord Group (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 50 > Block 34/10 > Gullfaks Sør Field > Lunde Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 50 > Block 34/10 > Gullfaks Sør Field > Lista Formation (0.99)
- (12 more...)
Abstract This paper investigates the benefits of adding energy or performing partial processing to a subsea production system. An hydrodynamic transport study has formed the basis for a subsea process and power demand analysis. It was followed by a technology review to identify current technology gaps for realizing the studied alternatives. A generic field case has been selected as work basis. A spreadsheet model has been developed for year-by year analysis of various production profiles and to combine the results of the different parts of the study. This paper will focus on the study summary tool with emphasis on three scenarios where the reservoir depletion strategy varies from fixed liquid production with pressure maintenance by water injection, maximum acceleration of production using the available installed power and reduced reservoir pressure maintenance. The results are discussed based on an economic NPV analysis where added oil sales value, CAPEX and OPEX are input. This paper will not focus on technology gaps, feasibility or state of the art. However the study has covered these aspects. The CAPEX figures do not cover savings compared to topside solutions even though these savings might be substantial. The study has demonstrated that there are great potential benefits from boosting at the mudline level in deep offshore conditions.For high productive wells, mudline boosting technology may compensate for high riser pressure drop at high watercut. For wells with lower productivity index, multiphase pumps or gas/liquid separation with liquids pumping might lower the wellhead pressure and accelerate the production. For reservoirs where water injection is not effective or not recommended, multiphase pumps or gas/liquid separation and pumping might be used to lower the bottom hole pressure. However this requires high power demands and possibly multiple pumps. The separation alternatives are not competitive unless topside savings are obtained, but if the technology becomes commercial, it has a large savings potential. Introduction. Producing hydrocarbons from deep offshore fields involves many technical challenges, and it is generally assumed that the challenges get tougher with larger water depths. For several aspects of the installation, maintenance and operation of subsea equipment, this assumption is true. However, there are also benefits linked to deep water production, benefits that are increasing with increasing depth. These benefits are linked both to the environment of the installation and to process conditions. Our industry is bound to develop deep water technology if we want to produce from the deep water fields. However, when doing so we must keep in mind the positive aspect of the subsea environment and maintain focus on the total field economy, using the advantages of the deep waters to reduce cost pr. barrel and stay competitive even at low oil price. We will in this paper look at the benefits of deep water production, compare some new concepts and evaluate the economy resulting from life cycle cost and income profiles.
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.57)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Risers (0.87)
- Facilities Design, Construction and Operation > Offshore Facilities and Subsea Systems > Subsea production equipment (0.69)
- (3 more...)
Abstract With the continuing increase in marginal field developments particularly in the North Sea, the pressure continues to minimise costs. There has pressure continues to minimise costs. There has been a continuous trend towards unmanned facilities to capitalise on reduced operating and first costs. This article reviews the current remote processing facilities utilised offshore with processing facilities utilised offshore with particular emphasis on subsea hardware, process particular emphasis on subsea hardware, process and utility equipment and control and communication systems. The key element to the further use of unmanned systems is the reliability of process equipment. This article analyses the reliability of process and utility systems utilised in offshore oil and gas processing and projects future unmanned facilities scenarios. projects future unmanned facilities scenarios Introduction In todays difficult economic climate the pressure continues to minimise field development pressure continues to minimise field development costs. Future developments will vary between shallow water gas fields near to existing facilities to deep water oil production in harsh environments. Economic solutions are likely to be very different for different developments. However, remote processing of the reservoir fluids is a common theme which will find more extensive application. Southern North Sea gas field developments are likely to consider unmanned facilities as a means of reducing costs. However, in deep water fields subsea developments are more likely to be the economic choice. Selection will undoubtedly be made on the basis of comprehensive cost/benefit analyses. A balance must be achieved between potential capital and operating cost savings for unmanned and subsea developments with the potential additional maintenance costs. In addition, due consideration must be given to cost penalties associates with a reduction in revenue caused by reduced availability of the remote facilities, primarily due to increases maintenance periods. primarily due to increases maintenance periods. This article reviews the current status of remote developments and highlights our experience. In addition the selection criteria for typical fields are developed. Potential future processing options are proposed ana conclusions are made on the most likely candidates for future development. CURRENT EXPERIENCE Unmanned Platforms Significant savings in capital and operating costs can be made by the exclusion of personnel and the associated life support systems. In the North Sea, fifteen unmanned platforms are operating satisfactorily while a further three facilities are currently in different stages of development (Tables 1 and 2). Generally unmanned facilities nave been utilised as a satellite(s) to a central processing facility or within a practical processing facility or within a practical distance from an existing maintenance network. Essentially wellhead type platforms with minimal processing and hence platforms with minimal processing and hence utility requirements have been preferred to minimise maintenance requirements and ensure high facility availability.
- Europe > United Kingdom > North Sea (1.00)
- Europe > North Sea (0.96)
- Europe > Norway > North Sea (0.66)
- (2 more...)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Garoupa Cluster > Garoupa Field (0.99)
- South America > Brazil > Campos Basin (0.99)
- Europe > United Kingdom > North Sea > Southern North Sea > Southern Gas Basin > Sole Pit Basin > Block 49/22 > Victor Field > Leman Sandstone Formation (0.99)
- (6 more...)
Copyright 2012, Offshore Technology Conference This paper was prepared for presentation at the Offshore Technology Conference held in Houston, Texas, USA, 30 April-3 May 2012. This paper was selected for presentation by an OTC program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Offshore Technology Conference and are subject to correction by the author(s). The material does not necessarily reflect any position of the Offshore Technology Conference, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Offshore Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of OTC copyright. Abstract With the present deepwater developments on the increase it is foreseen that a dedicated market will develop for vessels capable of intervening on subsea wells at a lesser cost than existing deepwater drilling units. Thereby (I) extend the life of deepwater developments rendering additional profits and (II) adhere to minimum field production requirements as are being required by the authorities more and more to date. The paper describes the development of the concept for such a Well Intervention Vessel resulting from a combined effort between a Naval Architecture Design Bureau and a major rig equipment supplier with a focus on an open equipment structure facilitating the possible application of multiple levels of/and intervention solutions. The vessel will target Class B /(II) and Class C/(III) type interventions, based upon systems which will use risers and capable of retrieving completions.
- Europe > United Kingdom > North Sea (0.89)
- Europe > Norway > North Sea (0.89)
- Europe > Netherlands > North Sea (0.89)
- (3 more...)