Characterising Reservoir Performance for the Mahogany 20 Gas Sand Based on Petrophysical and Rock Typing Methods

Abstract

The Mahogany Field in Trinidad produces ~475 MMscfd and is the sole supplier of the gas to Atlantic Liquefied Natural Gas (LNG) plant's train 1. The Mahogany Field's gas reserves are dedicated to the LNG plant. The original reserve calculations assumed volumetric depletion would be the dominant drive mechanism for the gas reservoirs in this field. Four years later, water drive is the dominant drive mechanism for all sands except the 20 Sand. If the 20 Sand eventually shows water drive, the predicted rate profile and reservoir management would be different than if it had been a volumetric reservoir. This study investigates both drive mechanisms and makes recommendations for managing the reservoir in either eventuality. To support this work, a petrophysical description was carried out. This included rock typing of the reservoir and calibrating the wireline log data with 20 Sand core. Three independent methods for rock typing were employed, two of which have not been used on offshore Trinidad core samples previously. A facies description was compared to the rock type classifications and flow units. A reservoir simulation model was built using log analysis from the 20 Sand and incorporating the results of the petrophysical descriptions of the different rock types and flow units. A history match was obtained for the well currently draining this reservoir and predictions on the 20 Sand incorporating a future 7" horizontal gas well were also done. The recovery factors were obtained for the reservoir under different drive mechanisms - volumetric and water drive. Recommendations for optimal reservoir management of the 20 Sand are given. Introduction The Mahogany field is located 61 miles offshore from the southeastern point of the island of Trinidad (Figure 1) in 300 ft of water. The field was discovered in the late 1960s and early 1970s. However, it was not developed due to lack of a gas market. Exploratory drilling in 1994 and 1996 discovered additional gas and condensate reserves. Mahogany's reserves were dedicated to the proposed Atlantic Liquefied Natural Gas plant at Point Fortin1. In early 1996 delineation wells (EM-5 and 5x) encountered additional gas reserves in the 20 Sand in the middle of the field. The original reserve calculations assumed volumetric depletion would be the dominant drive mechanism for the gas reservoirs in this field. Four years and 714 Bscf later, water drive is the dominant drive mechanism for all sands except the 20 Sand. Water handling capacity is limited on the platform. Therefore, if the 20 Sand eventually shows water drive, the predicted rate profile and reservoir management would be different than if it had been a volumetric reservoir. This paper describes the work done to develop a history- matched reservoir model and to predict production performance. Geology/Reservoir Characterisation The Mahogany Field, located in the Columbus Basin within the Eastern Venezuelan Basin, is a faulted anticlinal structure with Pliestocene age stacked sand and shale sequences. There are 15 reservoirs in the field, with over 2 Tscf in gas reserves. The 20 Sand (Figure 2) accounts for 26% of the total field's gas reserves. Estimated original gas in place is 814 Bscf, located in fault blocks IV and V. The productive area is approximately 4 miles long and 2 miles wide.

Improved reservoir characterization by employing hydraulic flow unit classification in one of Iranian carbonate reservoirs

“…searches have been conducted on the evaluation of different flow unit identification techniques (Ali-Nandalal et al, 2003;Hamon, 2003;Frank et al, 2005;Guo et al, 2005;Salman et al, 2009;Hollis et al, 2010;Kale et al, 2010;Rebelle, 2014;Mirzaei-Paiaman et al, 2018). However, a comparative study that includes applications of different methods in reservoir description is lacking (Kadkhodaie-Ilkhchi et al, 2009;Izadi et al, 2013;Mirzaei-Paiaman et al, 2015;Chen et al, 2017).…”