Abstract

The paper discusses the design and installation of remotely controlled in-situ gas lift in the horizontal well B-4 BH on the Norne subsea field. The importance of proper design i.e.; sizing the valve small enough to avoid high pressure gas from the gas cap flowing back into the oil zone and large enough to optimise lift efficiency within the gas processing capacity is emphasized. Both a numerical and an analytical design analysis approach are presented. Examples of current and predicted well performance with and without gas lift are included.

Introduction

Production and injection on the Norne field has resulted in an over-pressured gas cap overlying an under-pressured oil reservoir. This has resulted in the need for artificial lift, especially with increasing water cut (WC). It has also made in-situ gas lift an attractive solution.

This paper discusses the design and installation of remotely controlled in-situ gas lift in the horizontal well B-4 BH on the Norne subsea field.

Current strategy for Norne includes pressuring up the oil reservoir. Process facility constraints coupled with expected reservoir behaviour have dictated a thorough design analysis of the gas-lift valve. The objective being to find a valve size small enough to avoid high pressure gas flowing back into the oil zone and large enough to optimise lift efficiency within the gas processing capacity of the floating production, storage and offloading(FPSO) vessel. With the remotely operated flow control valve in place, the well was cleaned up much faster than expected for the current reservoir and well conditions at Norne.

As expected, the horizontal well B-4 BH initially produced approximately 6000 Sm3/d of water free oil with no gas lift. Seven months later (March 2002)the water cut had increased to 33%. Liquid production with no gas lift was 5065 Sm3/d and marginally more (5160 Sm3/d) with a limited amount of gas lift(60 kSm3/d).

Examples of current and predicted well performance with and without gas lift are presented.

Field Description

The Norne field (Fig. 1) was discovered1 in 1991 and put on production in November 1997. It is the northern most producing field on the Norwegian Continental Shelf; 200 km off shore Norway in approximately 380 m water depth. The field is developed with 5 subsea templates (3 for production and 2 for injection) connected to a FPSO vessel. Each template has 4 well slots giving a total of 20 available slots. Currently 12 are used for oil production, 6 for water injection and 2 for gas injection. Daily production is currently 33 000 Sm3/d limited by the gas processing capacity.

The Norne field is part of a horst structure, and the hydrocarbons are located in sandstone formations of Lower and Middle Jurassic age of generally good reservoir quality. The hydrocarbon column starts at about 2525 m mean sea level and is 135 m thick with a 110 m oil column and an overlying gas cap (Fig. 2). In-place volumes are estimated to 157 MSm3 of oil and 29 GSm3 of gas (including both gas cap and associated gas). Recoverable oil is estimated to 84 MSm3.

The structure is relatively flat and the reservoir consists of four formations: Garn, Ile, Tofte and Tilje. The Garn and Ile formations are separated by the tight Not shale. Based on pressure data from the exploration wells, the Not shale was expected to be non-sealing locally by major faults, providing reservoir communication between the Garn formation and the underlying formations. However, production history has proven this assumption to be wrong. In other words, the Not shale is sealing across the whole field.

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