Managing Base Decline in a Big Gas Business
Authors: Baksh Kirk , Jackson Peter 
Published: May 2016

BP Trinidad and Tobago produces gas from the Columbus Basin located off the east coast of Trinidad. Gas is produced via ten producing platforms and daily gas production averages 2.6 bscfd. Gas produced is used to supply a domestic market and an LNG scheme. The field portfolio comprises of a mix of new to mature fields producing from a deltaic environment which comprises of several stacked, very good quality sandstone reservoirs. The reservoir connectivity is good and wells have been primarily designed as big-bore/high-rate completions with the aim of delivering gas to market with minimal well count.

Gas supply assurance is of utmost importance and to this end most facilities are equipped with continuous surface and downhole monitoring. This enables production and reservoir data to be collected on a continuous basis for well and reservoir monitoring. As excess production deliverability over demand decreases with field depletion; the ability to accurately forecast well and field gas deliverability is critical to both the end users and the business for proper activity planning and efficient development of resources.

Some wells are not produced at their maximum deliverability rates for various reasons (well integrity, erosion concerns, sand production, and market demand). Hence the tracking of the actual deliverability decline becomes difficult since wells are produced against a number of varying conditions. A proper and full understanding of the actual deliverability decline is of paramount importance to the business.

This paper serves to outline the method of deliverability forecasting using the data gathered from the continuous monitoring system along with the tools used to analyze them and how deliverability decline is tracked given the production inefficiencies.

Introduction

BP Trinidad and Tobago produces an average of 2.6 bscfd of gas from the Columbus Basin located off the east coast of Trinidad (Figure 1) via ten production platforms. The rapid expansion of the domestic and LNG markets saw the need for fast paced project development to enable adequate supply of gas to market. Cost optimization and capital efficiency led to new fields being developed via smaller Normally Unmanned Installations (NUIs) which have smaller footprints and are fully automated. As reservoir connectivity and quality is good; the producer wells have been primarily designed as big-bore/highrate completions with the aim of delivering gas to market with minimal well count. Wells are crestally placed to allow for efficient sweep and maximum gas recovery. Production from these fields is processed at three normally manned central hubs; Cassia; Amherstia and Mahogany.

Gas supply and proper resource management has lead to the installation of permanent downhole and surface monitoring on all the new facilities. This has enabled surface production data (Corrected Wet Gas Rates; Tubing Head Pressures; Tubing Head Temperatures; Choke Setting) and inflow performance data (Flowing Bottom Hole Pressure (FBHP); Flowing Bottom Hole Temperature) to be collected on a continuous basis. Reservoir Pressure Build Up (PBU) tests are done via planned well shut-ins and the frequency of these shut-ins are one PBU per every 10% of ultimate reserves produced or thereabouts; unplanned PBU data is also utilized as it becomes available.