Summary Andrew field in the U.K. Continental Shelf, which is operated by British Petroleum (BP) Exploration, is being developed using horizontal oil producers and completed with cemented liners. The main challenges of perforating these wells are maximizing well productivity by avoiding formation damage, minimizing the possibility of sanding, maximizing ultimate hydrocarbon recovery, perforating long horizontal sections safely and efficiently, optimizing the economic value of perforating, and minimizing perforating debris. In general, to avoid impairing well productivity, it is best to perforate the underbalance. However, the advantage is compromised, because of the fluid invasion and loss-control material, if a well will be killed when the tubing-conveyed perforating (TCP) guns are removed. Existing deployment methods with coiled tubing (CT) enable perforation and subsequent gun removal in an underbalance condition. Unfortunately, various limitations would require multiple runs with CT for perforating each horizontal well in the Andrew field, which would result in significant time and on balance perforation for each subsequent run. The combination of the newly developed mechanical ball valve and the deployment of TCP guns with hydraulic workover units enables long horizontal wells to be perforated in one run in underbalance, and enables the guns to be removed without killing the well. Specially engineered guns and perforating charges are used to minimize sanding and gun debris. This paper describes how these new technologies, used for perforating operations, meet many challenges. The same technologies can be used readily for perforating other long horizontal wells with similar problems. To date, three horizontal wells in Andrew field were perforated successfully with the method described in this paper. The initial results indicate that the combination of the cemented liner completion, the engineered perforation systems, and the correct TCP gun deployment method using the mechanical deployment valve have contributed to improve well performance, to reduce cost, and to improve operability and safety in long horizontal wells.

The Andrew Field produces from a Palaeocene sandstone saturated oil reservoir, in UK North Sea Blocks 16/27a and 16/28. Cyrus is a small subsea tieback, 7km NE of Andrew, containing undersaturated oil. Both fields are operated by BP Exploration. Field development was sanctioned in 1994, some 20 years after discovery. During those 20 years, numerous development concepts failed to achieve the expected economic return. However, in 1992 the Andrew well count was reduced from 18 to 10 by changing from vertical to horizontal producers. In conjunction with an Alliance risk/reward approach to topsides construction, which was expected to significantly reduce Capex, development sanction was obtained. Andrew development drilling started in September 1995, with three pre-drilled template wells. These were tied-back to the platform in 1996 and followed by further platform-drilled producers. A 1993 horizontal appraisal well was also tied back as an Andrew producer. Two horizontal subsea producers were drilled on Cyrus in 1996, replacing two earlier horizontals wells which had suffered rapid water production. First oil was achieved in June 1996, 6 months ahead of programme. Current production is at the expected plateau level of about 58 000 bbl/D from Andrew and 12 000 bbl/D from Cyrus. Reducing well numbers and using only horizontal wells relies on the long term performance of these wells for economic success. Andrew/Cyrus is amongst BP's first all-horizontal field developments. Key design decisions started at the sandface completion: openhole sand control screens were considered because of sand production concerns; the cost and difficulties of cementing and perforating long horizontal liners were reviewed; the savings from using pre-holed, uncemented liners were set against the concerns over long-term production and external casing packer (ECP) reliability. Multilaterals were also considered in detail. The outcome of this work was to install pre-holed liners with cement inflated ECP's in both Cyrus wells, but to use cemented and perforated liners on Andrew. The Andrew Well Engineering Alliance was created, and was aligned to BP's key business objectives through the 'minimum performance standards' of well on target, % of the horizontal section contributing to flow, zonal isolation and data acquisition. These measures were the basis of triggers for gainshare payments. Maximising the % contributing to flow led to the world's first through-tubing, underbalanced, single trip, no kill, horizontal perforating system using a hydraulic workover unit and formation isolation valve. The success of this approach has been confirmed by recent coiled tubing production logging (CT-PLT). This paper discusses the reservoir uncertainties and anticipated well management challenges. It describes the balance of factors that impacted the design of the horizontal completions. Initial well construction experiences and the first 6 months of production are described. Development Outline Figure 1 gives an outline of the development area. The Andrew topsides were installed in May 1996, with the gas and oil export pipelines and subsea bundle tie-back of Cyrus completed a few weeks later. Andrew reserves are estimated at 112 × 106 bbl. Development drilling on Cyrus has suggested that the sanction estimate of 24 × 106 bbl was optimistic, with the structure being somewhat smaller than expected. Cyrus 're-development' is through primary depletion from two new horizontal wells, replacing the previous horizontals. The Andrew reservoir, a four-way dip-closed structure with a 58m oil column between gas cap and aquifer, is being developed with ten horizontal producers. It is expected that aquifer support will be sufficient to maintain reservoir pressure. Whilst the development includes a vertical gas management well completed in the gas cap, there are no plans for water or gas injection wells for pressure maintenance. P. 375^

The comparison of today's slickline capabilities with its early usage for routine remedial workovers and maintenance best illustrates the significant advances that have occurred within slickline technology. Today, for example, slickline can be used to I) set and retrieve slickline-retrievable safety valves or plugs, 2) open and close downhole circulating devices, 3)retrieve accurate depthhime data for correlating with memory production surveys for well diagnostics (problem identification) reservoir description, or flow analysis, 4) provide accurate correlation of tubing casing collars, and 5) pull and run multiple flow controls set packers and other downhole equipment without explosives; setting monobore tools; and other perform other well interventions that are dependent upon measurement accuracy. Less than a decade ago, slickline was only considered for mechanical well workovers. This paper will discuss the newly developed technology that allows slickline to economically provide alternatives to services traditionally reserved for other, more costly options. Case histories will be used to illustrate the enlarged scope of services and how the equipment combines to provide the innovative low cost service options that the industry has been seeking. Introduction Economic initiatives are usually the drivers of new technologies, and thus, reacting to the significant decline in the oilfield climate during the last decade, no era has been as momentous in providing stimuli for operational change. Unfortunately, operators who are seeking new methods usually look to new technologies as the potential problem solvers, and in so doing, overlook enhancements to the older, proven technologies that could provide the cost efficient alternatives they want. This has been the case with slickline. Until the resurgence of investigation into new strategies to meet the oilfield cost constraints of the last decade, slickline service was only considered for routine mechanical workovers. Who would have considered using slickline to set a packer in the early 90's. The capabilities that have changed the profile of slickline service from one of routine mechanical well work overs to a multi-faceted service technology are derived from the new slickline tools that can be used independently or combined to further enhance the scope of services. The equipment includes an electronic triggering device (ETD) that enables safe detonation of explosive devices, a battery-operated, electro-mechanical tool that sets wellbore devices on slickline and braided line without explosives, an electronic measurement system that automatically corrects measurement inaccuracies resulting from line stretch and environmental stress factors, a slickline collar locator (SLCL) that accurately verifies collar locations in a tubing string, and data job loggers or acquisition software systems that connect to the electronic measurement system to graphically record dynamic wireline information.

This paper details the overall system design for a 15,000 psi subsea, gas condensate well in the North Sea. Currently, significant industry interest exists in the technology required to complete wells of this type, which would enable substantial hydrocarbon reserves to be developed. Subsea wells such as this have not yet been completed. INTRODUCTION A significant number of high pressure discoveries with surface pressures in excess of 10,000 psi have been made in the Central Graben of the North Sea which await attractive project economics to allow their development. A reduction in cost and risk associated with such a development may provide the incentive required. The technology needed to develop these discoveries economically is likely to include subsea production systems as these are now a proven means of providing a low cost development. Subsea technology has not previously been applied to these high pressure wells and the downhole technology has only previously been applied from platform or land based developments. This paper presents the issues concerned with the completion of such a well and where possible makes recommendations for a special design. In areas where it has not been possible to specify a design comments are made regarding the issues to be considered or resolved and suggestions are made for additional industry development. The work is based upon in-house designs and external studies performed for Marathon Oil UK in order to allow the future development of it?s high pressure prospects and discoveries. This design isbased upon the known and anticipated data from one such North Sea reservoir, Figure 1 shows the formation pressure of this reservoir in relation to existing fields in the North Sea and elsewhere and to other as yet uncompleted prospects. Table 1 lists the operating conditions. The pressures and temperaturesencountered in this design are not as severe as some other discoveries and do not meet some definitions of'hostile? (reference 1) or high pressure / high temperature (HP/HT) (reference 2). However, both these definitions are somewhat arbitrary, and since 15,000 psi drilling and production equipment isrequired for the field, it is a significant departure from previous subsea completion experience. The issues raised in this paper are relevant to the completion of wells with greater pressures and temperatures than those in this well and as such this design can be seen as a 'stepping stone? to overcoming the problems likely to be encountered in these wells. The wide ranging nature of the subject prevents an in depth analysis of each issue but is intended to stimulate and encourage further work in septic areas. Certain aspects and recommendations are likely to be controversial but it is hoped that bypublishing the work and sharing ideas, the development of 15,000 psi subsea wells may become one step closer.

Summary The BP Andrew field has been developed using a novel business solution which required the creation of a Well Engineering Alliance with shared objectives, a radically new behavioral approach and jointly developed targets. The paper describes the structure of the Alliance, the development and implementation process and the success that has been achieved. A project update provides a summary of subsequent progress. Field Overview Andrew is a Paleocene oil field 50 km North East of the Forties Field, it is relatively small in size, 112 million stock tank barrels (STB) reserves, and was discovered in 1974. Its development has, until recently, been considered uneconomic due to the high initial cost of development. The arrival of proven horizontal well technology has allowed the number of wells planned for the field to be halved at the same time as increasing the plateau from 45 000 to 58 000 barrels of oil per day (BOPD). Improvements in jacket and topsides construction, increased heavy lift capability and a reduction in offshore manpower needs have allowed the project cost to be substantially reduced. Most significantly, an innovative Alliance approach has been applied to all aspects of the project to create substantial cost reductions and value enhancements. Three wells were predrilled through a subsea template prior to installation of the jacket and topsides in May 1996. Following the tieback and completion of these wells, together with an existing appraisal well, six further wells were drilled from the Andrew Platform. First oil was produced in June 1996. In addition the development includes Cyrus, a small subsea field which is tied back to Andrew by a 6.5 km flowline bundle. Cyrus was developed within the same contractual arrangements using two subsea production wells. Andrew is a project where behavioral issues are considered of paramount importance. The combination of appropriate behaviors and new technology can together deliver a breakthrough performance. These softer, less tangible issues are a key aspect of the project. Contract Strategy The contracting strategy was conceptualized at the project sanction stage in 1993 and was to maximize field productivity for minimum cost through delivery of highly productive, low cost, low risk wells as early as possible. To achieve this, the plan was to create an integrated Well Engineering Alliance incorporating all the skills necessary to drill, complete and maintain the wells. Strategy development and contractor selection involved the following steps:Identification of key business objectives as: maximizing well productivity from the main Paleocene reservoir, accelerating first oil, maximizing value from the Lower Cretaceous underlying reservoir, and minimizing costsIdentification of key implementation success factors as: selecting the correct contractors, getting them onboard early enough to have an impact, and keeping them, i.e., life of field accountability; adopting an integrated team/alliance approach; and ensuring alignment of asset business objectives with contractors objectives through the use of a single alignment mechanism with a focus on both cost and well productivity.Selecting contractors based on ability to deliver on business objectives through an interactive selection process focused on behavioral alignment, technical ability and cost. Contractual Framework The contractual approach within Andrew was designed to effectively align business objectives between contractors and operator, thus generating a true Alliance. The Well Engineering Alliance members were: BP (operator), Schlumberger IPM (Completion Well Management and Data Acquisition), Baker Hughes INTEQ (Integrated Drilling Services), Transocean (Mobile Rig) and Santa Fe (platform rig). Contractual arrangements were defined in two documents: the "works contract" and the "alliance agreement." The works contract between BP and each of the Alliance members covered all the standard contractual and legal terms. Within it, costs were broken down into the components: direct cost, profit and overhead. Based on an agreed budget developed by the Alliance Well Engineering Team shortly after starting the preplanning phase, the profit and overhead were paid on a fixed basis. Direct costs were subsequently paid as they were incurred to a level lesser or greater than those in the budget depending on actual expenditure. This contractual arrangement provided a direct incentive to Alliance parties to reduce direct costs without fear of reducing profit or overhead levels, i.e., to become profit driven rather than revenue driven. By reducing direct costs within the project, companies' profitability actually increased with the fixed profit and overhead component. In addition, the incentive also existed to reduce overhead, thereby further enhancing profit. The second "contractual" document was the Alliance Agreement, which was common to all Alliance members. This document set out how the Alliance would operate including arrangements for risk and reward within the project. The agreement was structured into key minimum performance standards which, if met, provided access to share capex savings and a profit multiplier payment related to well productivity. The minimum performance standards which had to be met on Andrew wells were: correct target location, effective gas cap zonal isolation, acceptable data acquisition and at least 75% of the perforated horizontal interval contributing to flow, averaged over three predrilled wells.