TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper describes the strategy, design and the drilling fluid and cement operations in the first two wells drilled with Coil Tubing on the Gullfaks field. The strategy and design is explained in great detail. Excellent hole cleaning was achieved in both wells.A serious problem of differential sticking was eliminated by a radical change in drilling fluid strategy and design. It was possible to successfully drill a 3 ¾" hole, log and run/cement a 2 7/8" liner at a maximum inclination of 122 o .A virtually solids free Potassium Formate Brine/Polymer drilling fluid with a density from 1.50 -1.56 g/cc was used. The flow properties of the drilling fluid is characterised by a very low fluid loss due to a high extensional viscosity, a low viscosity at all shear rates and a low degree of shear-thinning.
TX 75083-3836 U S.A. , fax 01-972-952-9435. AbstractGel is considered to have an interesting potential for water shut off applications, especially in fields having natural shale barriers and large permeability variations and/ or where reduction in tubing/ casing diameter is not \vanted. This paper describes a case study from the Statfjord Field where polymer silicate gel was used to build up experience for water shut off applications of the lower producing inten,al in a well that produced from two intervals. The intervals where separated by 5m in 9 5/8" casing and located at approximately 3100 m.The primary objective was to shut off water and secondly to evaluate gel technology. Mechanical techniques and gel technology were considered as means of achieving the objectives. Both required the use of 2" coiled tubing in a live well ( Fig. 1-'). Gel technology was selected since diameter restriction in the casing was not wanted due to potential later perforations deeper into the well combined with desire of qualifying the technology and related techniques.This paper reports some of the results achieved in the laboratory, and give references to papers where the laboratory techniques and results are given, refs. 1 through 5. The pre planning and the laboratory testing for finding a suitable gel formulation was also performed in collaboration with a service company.Therefore this paper focuses mostly on the well performance, placement of plugs in the well by wireline and coiled tubing, pumping of the gel solution through the coiled tubing and into the lower perforation interval and evaluation of results.The operation has been an economical success. After water isolation from the lower inten·aL the \Yell has produced oil with a gross value of 15 mill . U.S.$ in 6 months and the operation had a pay back time of 50 days.
To be able to lubricate long perforating assemblies (guns) in horizontal wells, and to retrieve them without killing the well has always been attractive for many reasons, both from an operational point of view and to minimise formation damage. This paper describes a case study from the Siri Field where lubricating long gun assemblies against a tubing-retrievable downhole lubricator ball valve (DHLV) enabled running up to 1000 m of 3.5" perforation guns in two runs in a live well. This was performed without the use of a surface deployment system, and without exposing the tubing-retrievable surface controlled subsurface safety valve (TRSCSSV) to potential damage in the event of inadvertently dropping the perforation guns during completion. Use of this equipment gives also the added benefit of considerably reducing the equipment rigup heights for Siri in the future life of the field, after he jackup drilling rig has moved off location. Introduction The Siri Field, discovered in 1995, is located in the Danish Sector of the North Sea (Fig. 1). Production started in March 1999. The field is developed with five oil producers and two SWAG (Simultaneous Water And Gas) injectors, drilled using a jackup rig located over a wellhead tower. Well interventions will typically be rigless, requiring standalone equipment mounted on the wellhead tower. The horizontal producers have up to 1000 m perforations and it was desirable to perforate the entire interval underbalanced. Siri is expected to produce at relatively high water cuts for most of the field's life, and it is water-related problems which most likely will be the main reasons for future well interventions. Scale inhibition treatments at the rate of 1/well/year, reperforation and plugback of watered-out or gassed-out zones form the bulk of the anticipated workover program throughout field life. Coiled tubing would be the most likely intervention method. It is obviously desirable to perform these well interventions without killing the well. Platform design Siri is developed with a wellhead tower containing 12 well slots, at a centre-centre spacing of roughly 1,1m, connected to a jackup production platform. Headroom from the Xmas trees to the weather deck is only 2–2.5m. With future workovers in mind, ample deck space was included in the platform design, also workover fluid tanks and extra living accommodation to allow wireline, coiled tubing, pumping, snubbing and possibly coiled tubing drilling operations to be carried out at short notice from the platform, and without rig mobilisation. The wellhead tower weather deck itself measures roughly 12m×15m and is open to the sea on three sides. All rigup for well operations is above the deck. For coiled tubing operations with a deployment system, this could involve a 10–15m riser in addition to pressure control equipment. During completion operations with the drilling rig on location, support is available, but standalone operations could pose safety and logistical problems, requiring use of scaffolding or a workover derrick arrangement, and being highly weather-dependent. Use of long production logging tools would also lead to high rigups (Fig. 2).
This paper covers the experience from the retrofit of a new dual-mode injection compressor into the existing gas compression facilities on an offshore platform. The implementation of this new and innovative compressor technology made it possible to fulfil new requirements to higher throughput, different kind of service, improved safety level and economical operation. But then the compressor exhibited gas dynamic instability — determined as rotating stall in the impeller — a phenomenon not well understood. The literature on this topic is scare. The rotating stall phenomenon caused a significant reduction in useful operational area of the compressor. An improvement program was carried out. Changes in the impeller geometry led to restoration of the expected operational range. The magnitude of the phenomenon has diminished partially also. Rotating stall criteria proved to be useful in order to improve or avoid rotating stall problems in a centrifugal compressor. The dual-mode injection compressor allowed decommissioning of a whole equipment module, which represents a very useful experience factor in the design of new offshore platforms. The compressor has been in operation since November 1994, and it has been able to fulfil all specified operating requirements.
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