This paper describes the first use of a novel drilling fluid based on potassium formate brine and weighted with manganese tetraoxide. Also included is the completion technique used to open hole complete an unconsolidated reservoir. The fluid was selected for maximum brine density, and to facilitate removal of the filtercake criteria for fluid and completion selection are presented together with laboratory work conducted to optimise the fluid and the completion for a specific application. Potential problems related to operations and working environment were identified through a risk analysis approach. Predicted solutions are compared to actual field experience. Key factors included minimisation of ECD, monitoring of soluble barium in the drilling fluid, rig-crews' exposure to manganese tetraoxide and barium, and procedures to combat lost circulation. The filtercake removal and its transportation through the pre-packed screen completion were comprehensively investigated. The perceived benefit of the formate brine system was the possibility to drill, complete and produce an unconsolidated, pressure sensitive reservoir with the same fluid. This was achieved with minimal on-site fluid treatment. The fluid was significantly more expensive than conventional alternatives. However, based on drilling fluid performance, rig-time and well productivity, one can conclude that the field test was successful and the use of the fluid was justified. Introduction The Gullfaks field is located in block 34/10 in the Norwegian sector of the North Sea, 150 km west of the Sognefjord. Gullfaks is the first field developed by a fully Norwegian licence group consisting of Statoil as the operator, Norsk Hydro and Saga Paetroleum. The fields current production is more than 90,000 Sm3/D from three reservoirs. The field has been developed with three concrete gravity-base platforms: Gullfaks A, B and C, each platform with two drilling shafts. Hence, while drilling in one of the shafts, wire-line, snubbing or coiled tubing operations may take place in the opposite shaft. To date, more than 90 wells have been drilled from the three platforms. Further 25 platform wells are planned. The oil is located within three major sandstone formations of Jurassic age; the Brent Group, the Cook formation and the Statfjord formation. The Brent Group is further subdivided into two groups; P. 647

This paper was prepared for presentation at the 1999 SPE European Formation Damage Conference held in The Hague, The Netherlands, 31 May–1 June 1999.

Well productivity can be significantly affected by damage to the near well-bore area caused during drilling in the reservoir section of a well. Historically, the use of perforated completions allowed for penetration of the producing formation beyond the damaged area but the recent trend towards non-perforated completions has resulted in an increased emphasis on damage minimisation. This, in turn, has increased the importance of evaluating drilling fluids and completion techniques used from a reservoir damage perspective. The suitability of a drilling or completion fluid for use in a particular reservoir can, and should, be determined using the measurement of return permeability or some other indication of formation damage. A major factor which limits this practice is that no industry standard equipment or methodology exists for this type of testing and differences in results obtained at different times or in different laboratories cannot be reliably compared. Repeatability and reproducibility of the tests conducted have not been widely established. In order to address these problems, a recommended practice for formation damage testing has been developed which covers all aspects of the test methodology from core selection and preparation to the writing of the final report and interpretation of the results. By standardising on equipment and methodology, it has been possible to establish the degree of variation which can be expected when the same samples are tested in the same way in different laboratories. Further testing in which selected parameters have been varied has also given an indication of the degree to which the setting of these variables affects the final result. It is hoped that this recommended practice will now gain acceptance throughout the industry and that the process of evaluating fluids for formation damage potential will become simpler and more efficient through the greater use and validity of comparisons between data from different sources. Introduction During the last ten years, there has been a very significant increase in the number of highly deviated and horizontal wells drilled through hydrocarbon reservoirs. At the same time, completion techniques have also changed with an increase in the number of open-hole completions. The driver for these changes has been financial, with economic pressures on oil companies resulting in the need to more cost-effectively develop resources. Open hole completions allow production from a greater percentage of the wellbore surface than cased and perforated completions but this increase will only be realised in practice if the damage caused by the drilling and completion fluids can be overcome. This requirement has lead to the development of specialised "drill-in" fluids with a focus on the minimisation of reservoir damage. It is now becoming common practice to evaluate the efficacy of such fluids prior to use by the measurement of formation damage potential. The most common test which is used for this purpose is the measurement of return permeability, either using standard material such as Berea sandstone, synthetic disks or reservoir core if available. Return permeability testing is conducted in many laboratories using many different techniques ranging from simple evaluations taking a few hours to more complex methods requiring up to a week to produce a result. The basic process involves the determination of the initial permeability of a sample of reservoir material or surrogate, the exposure the sample to drilling and/or completion fluids and the subsequent re-measurement of permeability. The difference between the two measured permeabilities is taken as an indication of the suitability of the fluid under test for exposure to the reservoir. There are many points in the testing where decisions have to made concerning the selection of a method or technique to use and there is no industry standard to guide this process. Obviously the testing should be designed to simulate field conditions as closely as possible. P. 103^

Through-Tubing Rotary Drilling (TTRD) is a technique which has been developed to extend the production life of older fields by substantially reducing drilling costs to render smaller reserves of oil economically recoverable1. However, the small wellbore dimensions required to utilise drill-pipe inside production tubing place some unusual demands on the drilling fluid and when these are compounded by the challenges of drilling into a formation containing a large range of pressures in the reservoir and high pressure shales, a radical approach to drilling fluid design is required. The requirement for a low viscosity fluid (to minimise ECD) which would still meet all other drilling requirements meant that conventional fluids were all unsuitable and a review of the options available resulted in the selection of a novel weighting material, manganese tetraoxide, for use in a mineral oil-based mud as the system most likely to provide the desired properties. The physical properties of commercially available manganese tetraoxide (very small, spherical particles) were known to result in very low plastic viscosities in muds made with this material when compared to muds weighted with barium sulphate. A much-reduced potential for weight material sag was an added bonus. This paper details the design considerations of the fluid used to drill three TTRD side-track wells in Shell's North Cormorant field. Modelling of hydraulic parameters is presented, together with field results from the first well and how these led to modifications of fluid design and engineering practice which were incorporated into the subsequent wells. Introduction The North Cormorant Field was discovered in 1975 and brought onto production in 1982. The field is located 120 miles (190 km) north-east of the Shetland Islands in the northern North Sea. Production from the field peaked at just over 20,000bbls oil/day in the mid 1980s and then dropped slowly to its current level of below 5,000bbls oil/day. Throughout the life of the field, there have been over 100 wells drilled. One of the main sections of the reservoir is characterized by a high degree of faulting and poor connectivity. The faulting combined with the requirement for water injection makes production from this part of the reservoir difficult to achieve. The combination of the following factors:Large number of penetrationsFaulted and isolated nature of the reservoirSmall size of the individual fault blocks has led to a situation with:A reasonable understanding of the stratigraphyLarge numbers of wells required to access the remaining reservesSmall remaining accumulations. All of the above highlighted the need for a drilling technique that would make it possible to drill low cost, short sidetracks without the requirement for a full Logging While Drilling (LWD) capability. Originally, coiled tubing drilling (CTD) was considered as a way to address this need. However, CTD limits the size, and therefore strength, of drill-string that can be used, does not allow pipe rotation, and requires a lot of surface equipment. For these and other reasons, the technique was abandoned in favour of TTRD. In the most general terms, TTRD is a method of sidetracking wells by rigging up BOPs on top of the christmas tree, leaving the completion in place and sidetracking as deep in the well as possible. Many of the problems associated with CTD are resolved by being able to use a larger, stronger drill-string that can be rotated while drilling. TTRD wells are challenging from a drilling fluids point of view primarily as a result of the small annular clearances throughout the length of the well. These challenges are:High kick sensitivityHigh equivalent circulating densitiesHigh pump pressures Kick sensitivity can be addressed by upgrading the accuracy and sophistication of the surface equipment but the other challenges could only be addressed by re-engineering the drilling fluid to have the lowest possible plastic viscosity for the fluid density required.

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