TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractLarge multi-million cell geological models are frequently constructed in an effort to "capture" the vertical heterogeneity measured by well logs and the areal heterogeneity inferred by the depositional environments. These criteria often result in fine scale models at a resolution of 0.1-0.3 m vertically and 30-100 m areally, resulting in reservoir models to the order of 10 7 grid cells. Recourse is made to upscaling in order to obtain coarsened but computationally efficient flow simulation models. The coarsened models commonly result in no more than 1-5% of the original grid size underscoring the need for judicious upscaling. Of greater importance is to demonstrate, for the chosen grid dimensions, that the upscaled representation is both reasonable and optimal in the sense that a significantly better template would be difficult to obtain.We consider two non-uniformly coarsened models to demonstrate the issues involved, and show that the use of 3D streamline methods offers insightful alternatives to decoupled analysis for both, the scale-up template design and pre-and post-diagnostics. We confine ourselves to property upscaling methods that use local grid information as opposed to estimating upscaled properties based on some global measure. For this class of problems we demonstrate that the diagnostic phases are necessarily separate from the upgridding and upscaling processes.
High rate offtake gas and gas condensate wells require both hydraulic and erosive issues to be addressed. The erosional aspects are particularly difficult and require special attention in high velocity areas if solid particles are present. In the past, industry has attempted to handle the problem through API-RP14E, however; this standard has been widely accepted as conservative and physically unsound when applied to gas or gas condensate fluids, because it does not account for solid particle impingement. Since then, numerous models and correlations have been developed to predict wear rates in various tubing configurations. The Tulsa work appears most comprehensive but there is little published information on how to apply many of its findings and present the results of erosional calculations in a form suitable for well design and field development planning. This paper uses the Tulsa erosional work and presents a consistent methodology for predicting and displaying the erosion rates in a number of high offtake big bore well designs when solids production and liquid loading are present. The ideas and procedures developed here can be used with other wear estimation methods. The use of tolerable erosion (or sand) rate strategy as opposed to previously adopted (and widely used) "maximum solids free rate" approach is advocated. The difficulties with prescribing the C constant in API RP14E are discussed and alternative derivations based on friction factors are presented. Subsequent sections consider examples of alternative gas well design, some of which use big bore technology, to demonstrate an application of a staged design process. The stages cover hot spot analysis, wear estimates and required erosional allowances before proposing an operating/monitoring strategy. Introduction In recent years, Big Bore Technology (BBT) has become a preferred alternative in developing a large gas and gas condensate fields1,2,3. The economic benefits are especially pronounced in offshore environment where increased hydraulic limits can effectively reduce the number of offtake wells thereby generating significant cost savings. Relative to smaller diameter wells, large bore wells offer the potential of much higher hydraulic capacity and initial rates. Moreover, even when operating at fixed lower rates they offer substantially increased plateau times. Both of these improvements generally result at modest cost increases over a conventional well. Allowing large bore wells to achieve offtake rates close to their hydraulic limits has to face the increased exposure to metal loss and wear that has the potential for wall breach in a worst-case scenario, particularly if solid particles (sand) are also present. Historically the industry has tended to rely on modified shear stress relations, such as API RP14E, to forecast maximum (threshold) gas velocities which would allow continuous service. While the shortcomings of API RP14E are well known, an integrated approach to couple completion design, hydraulic performance and erosion management and tolerance has proved difficult to describe and implement. The purpose of this work is to show how the wear rates predicted by correlations developed from the University of Tulsa can be incorporated into production strategy based on tolerable sand production that has made prior allowance for metal losses in key zones. In order to discuss the issues associated with completion design, operating, and monitoring strategies in the presence of solid particles, it is helpful to first present a review of key concepts before discussing API RP14E and its range of applicability. Following this, various models are discussed for predicting wear rates when small amounts of solid particles are present in the gas stream and briefly consider the major advantages of the SPPS erosional model from Tulsa University.
Developing marginal petroleum fields or extending the life of mature fields becomes significantly more attractive when technology is available that can enhance cost efficiency and reduce operational and environmental risks. To support the above needs, a major oilfield equipment supplier has introduced an interventionless technique for setting production packers downhole that provides an alternative to conventional setting procedures. When applied to the proper scenarios, the costs relating to setting the packer can be substantially reduced. The system can be used for completions where the capability to set and retrieve a plug is deemed virtually impossible or when the use of wireline or coiled tubing tractors would be very costly and risky. Basically, the system reduces the intervention risks by eliminating the need for intervention. This paper will describe the system, its testing, and the structured approach that was applied throughout system development to enable the concept to materialize from its initial concept to a finished product. Using this technology, a packer can be set without using such traditional techniques as setting and retrieving plugs. In addition, no complicated tools or hazardous materials are required. The concept uses the hydrostatic pressure of the well to provide the energy supply to set the packer. The application of a predetermined surface pressure initiates the setting sequence and does not require electronics or special surface equipment. Two offshore North Sea case histories that will provide data that verifies the cost advantages provided to the operator when the hydrostatic-set packer system is used will be discussed. In fact, one of the wells in which this technology was used is the longest extended-reach horizontal subsea completion in the world to date. Introduction Operators are currently moving into offshore and increasingly deeper waters to develop new petroleum opportunities.1 These environments typically are more difficult to develop; and thus, operating costs, which are traditionally higher for offshore fields because of higher rig costs,2 are further increased by the added risks factors that can occur. To preserve economic feasibility, operators have encouraged service / engineering companies to develop systems that can reduce operational risks and lessen the need for any intervention.3,4,5,6 Traditionally, the preferred type of production packer for these types of installations has been the hydraulic-set packer. Packers that are hydraulically set require a means to establish a pressure differential across the packer's setting piston. This usually requires the setting of a tubing plug below the packer. The introduction of a plug impacts project economics by adding run and retrieval time and the added risk that the plug may not be easily retrieved. In addition, there are the risks associated with the use of wireline or coiled tubing, particularly in remote areas where specialized rig and service rates are more costly and difficult to obtain. Since use of wireline or coiled tubing will typically require heavy lifts offshore, weather will further drive up the cost of using these processes to set packers. If wireline and coiled tubing operations can be eliminated, operational costs and risks can be reduced. Thus, the ideal packer would be one that requires no mechanical manipulation but can be activated quickly and without complicated equipment. An innovative packer that meets these requirements has been developed - a hydrostatic-set packer. Activation of this packer can be accomplished simply by the application of pressure to the wellbore at the surface, and the setting force is generated from the combination of applied surface pressure and hydrostatic pressure from the fluid column in the wellbore. There are no explosives, electronics, or chemicals required, making this system inherently safe and relatively uncomplicated to install.
TX 75083-3e36, U.S.A., fax 01-972-952-943S. AbstractThe Brent field, developed as an oil producing field in the mid 7WS, is now approaching the end of its economic life. However, the large quantity of remaining oil, although only 40% of initial reserves, and the high Gas-Oil ratio of the oil allow extended production from the field by reducing the reservoir pressure. The de-pressurisation will add some 10-15 year of economic life to the field.The de-pressurisation project, unique in the world due to the size and complexity of the Brent field, brings many uncertainties. The well completion design is key in the management of these uncertainties.Cost-effective reservoir management (zonal solation) is a pre-requisite and the choosen completion design should accommodate sand, scale and even H2S management. Furthermore certain wells will require artificial (gas) lift, although the number and location of these wells will be largely unknown up front. The adopted monobore completion design combines maximum flexibility and cost-effectiveness with simplicity and is readily adaptable to gas lift installation. The Brent monobore completion design has reduced cost by 30% and installation time by 6590 as opposed to the Multi-Straddle Assembly completion run previously in Brent. Key features of the completion and retrofit gas lift installation are described in this paper.
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