SWAG Injectivity Behavior Based on Siri Field Data

Abstract

Abstract Injection of water and gas in combination, in most cases injected in an alternating scheme (WAG), is one of the most successful IOR methods applied in the North Sea. Simultaneous water and gas injection (SWAG) has so far gained less experience. Simulations show in general an IOR potential of the same magnitude as WAG. Field limitations may in some cases be in favor of SWAG injection. The main contributions to increased recovery come from improved sweep, oil swelling and reduced residual oil saturation. SWAG has recently been implemented on the Siri Field on the Danish Continental Shelf and represents the first reported full field application of its kind in the North Sea. The associated produced gas is mixed with injection water at the wellhead, and injected as a two-phase mixture. The Siri Field has performed SWAG injection from the production start in 1999. SWAG injection on Siri and experiences has previously been reported1. Reservoir studies predict field recovery improvements with combined water and gas injection. Injection of a two-phase mixture of water and gas represents some new challenges. One relates to injectivity. Combined water and gas injection may result in lower injectivity than for single-phase injection. Injectivity is therefore important in connection with practical implementation of SWAG. A discussion of injectivity behaviour and interpretation of Siri data will be presented. For the Siri Field, hydraulic fracturing of the injectors proved unavoidable due to unexpected low permeability in the injection zone. Above the fracturing pressure, the injectivity can be strongly dependent on the gas fraction of the injection mixture. Introduction The Siri Field, discovered late 1995, is located in the Danish Sector of the North Sea. Production started in March 1999 and injection in June the same year. Plateau oil production is 8000 Sm3/d. The reservoir is characterized by a relatively low relief structure with oil zone thickness up to 25m. The GOR is moderate, approximately 100 Sm3/Sm3 and there is no initial gas cap. An 80–100 m thick underlying water zone gives some pressure support. The field has been developed with five producers and two SWAG injectors (one horizontal). The injectors are placed at the periphery of the reservoir in order to displace the oil to the central part of the field. The SWAG solution with re-injection of gas is expected to give an IOR of up to 6 % over a water injection scheme. No former North Sea field applications of SWAG have been reported, but pilot tests performed in 1994 on Kuparuk River Field in Alaska2,3 have demonstrated the feasibility of SWAG injection. The relatively small amounts of gas produced, and the rapidly falling gas rate, made it uneconomical to develop a gas export solution for Siri alone. Re-injection of the gas to provide reservoir pressure support, better sweep and hence enhanced recovery, was the best overall solution. SWAG offered a solution whereby a changing mixture of injection fluids could be accommodated, with the flexibility to distribute the water or gas to the areas of the field deriving the most benefit. Full fluid injection volume could be maintained by combining produced gas and produced water, supplemented by seawater to the required total injection volume. Downhole pressure/temperature gauges have monitored conditions both during startup of gas and water injection as well as SWAG. Such measurements play an important part in well monitoring. The wellhead design pressure, compressors and injection pumps, the hydrostatic fluid column weight, and the near-well injectivity may restrict the actual injection rates for a SWAG injector. This paper discusses the different factors governing the actual injection rates. It includes a more detailed analysis of the near-well injectivity behavior on the Siri field observed in the first 8 months period after injection startup. Measured data are interpreted in terms of Eclipse simulations and an analytical injectivity model described below.