This paper illustrates five examples where the application of reservoir surveillance has improved the understanding and ultimately the performance of gas reservoirs.The reservoirs in question are located off the southeast coast of Trinidad in the Cassia, Flamboyant, Parang, Amherstia and Immortelle fields.Gas is produced to satisfy both Trinidad's domestic and international LNG markets.With the contractual demands brought about by these markets, reservoir surveillance is seen as the key to identifying new well opportunities to sustain supply.
A host of surveillance tools have been employed in Trinidad, including cased hole logging tools such as the reservoir saturation tool (RST) to track movement of fluid contacts, and the production logging tool (PLT) to identify producing intervals and fluid types.Data from both permanent and temporary downhole pressure gauges have been used in material balance modeling and pressure transient analysis to assess reservoir size and drive mechanisms, quantify reserves and deliverability forecasting.Examples of these best practices are discussed within this paper.
The Cassia, Flamboyant, Parang, Amherstia and Immortelle fields are situated 30–45 miles off the southeast coast of Trinidad (Figure 1).The Cassia and Flamboyant gas fields have been producing since the 1980's and 1990's, respectively, and supply gas to the domestic market. Surveillance has been limited to well testing and static pressure surveys. This data aids in reserves estimation and deliverability forecasting.
In the late 1990's, the gas market grew with the expansion of the Point Lisas petrochemical industry in Central Trinidad and the construction of the Atlantic LNG Plant (ALNG) at Point Fortin.A significant proportion of the gas supply for the first two LNG trains and the rapidly expanding local gas market came from the Immortelle, Mahogony and Amherstia fields.
At present, over 60 wells produce natural gas for sale to the domestic and ALNG markets. Well designs have evolved to deliver high rate gas to meet the ever increasing contractual demands.Initial well rates, previously of the order of 75–100 MMscfd, now exceed 200 MMscfd, due in part to the use of larger 7" tubing and improvements in completion efficiency.
There are obvious benefits to drilling and completing "big" wells; the most significant is the reduction in well count associated with high offtake rates from single producers, and the subsequent deferral of capital expenditure.However, the counter to this is accelerated depletion. This, in conjunction wicth a poor understanding of reservoir performance, could certainly jeopordise supply. For these reasons, the emphasis on reservoir and well surveillance is now even greater.The business unit no longer is just reliant on pressure surveys and well testing to understand reservoir performance, but now looks to the application of cased hole logging tools and sand detection for reservoir and well management, and the deployment of permanent downhole pressure gauges to manage reserves and supply.