Water-Injection Techniques Increase Recovery in Conventional Gas Reservoirs

Abstract

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 191206, “Exploiting Water-Injection Techniques for Increasing Gas Recovery in Conventional Gas Reservoirs,” by Keval Darvesh Rambaran, SPE, Sarah Tammie Chin Chee Fat, SPE, and Lugard Evans Layne, SPE, University of Trinidad and Tobago, prepared for the 2018 SPE Trinidad and Tobago Section Energy Resources Conference, Port of Spain, Trinidad and Tobago, 25–26 June The paper has not been peer reviewed. Primary gas recovery for a volumetric reservoir ends when the reservoir pressure declines below the value required to flow gas to the surface at the sales-line pressure. Secondary gas-recovery techniques can then be used to increase the recovery. The most common of these techniques is gas compression, but another feasible technique that is rarely explored is water injection. This paper evaluates the incremental benefit of water injection in a conventional gas reservoir when compared with gas compression. Introduction An operator hopes to increase the recovery in Reservoir TM-20 in the Sorrel Field offshore Trinidad and Tobago by use of water injection once the technique is deemed more economical than gas compression. The wells in the reservoir are drilled from the Tamarind Platform, which also acts as a hub for the separation of fluids from fields in the immediate vicinity. Gases and liquids are piped through separate lines, with the liquids heading to the onshore liquid-processing facility. However, the company can modify the platform separators to operate in three phases and use the produced water for injection. Company records show that the average water-production rate from the platform is approximately 5,000 BWPD. If the shut-in wells were to be opened, roughly 10,000 BWPD of produced water and 15 MMscf/D of gas would be added for each well until liquid loading, thus increasing gas output significantly. Field History The Sorrel Field is a retrograde gas-condensate field located in the Columbus Basin, which has been producing from the TM-20 reservoir since 1998. The reservoir is a faulted sandstone formation of good quality that is divided into two hydrocarbon-bearing segments and underlain by an active aquifer. Segments 1 and 2 have been producing from Wells X and Y and Wells A and B, respectively, as shown in Fig. 1. Unlike Segment 1, primary gas recovery in Segment 2 ended because of a decline in the reservoir pressure, thus making it a suitable choice for water injection. Segment 2 is a wedge-shaped structure bounded by two faults, with both faults being interpreted as sealing. Production in Segment 2 began in April 1999 with a reservoir pressure of 4,732 psig. It ended in January 2014 because of an inability to flow at the sales-line pressure of 950 psig.