TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe 21 Sand reservoir in the Mahogany field has a 63-75 ft oil leg overlain by a gas cap and underlain by water. In order to utilize reservoir energy and efficiently develop the field, the oil reserves must be recovered prior to producing the gas which is dedicated to the Atlantic Liquified Natural Gas plant in Trinidad. A horizontal well program was planned to develop the oil leg. An in-house reservoir simulator was used to predict performance of the oil wells.The 21 Sand is 400' thick and has been segregated into 7 stratigraphic intervals. One hundred and twenty feet (120 ft) of core was acquired through these intervals and the petrophysical properties were measured on representative plug samples. This data was then correlated to well log data. Porosity-permeability flow units were then derived for optimum well placement. Modified-Lorenz plots (Ref. 1) were used to identify the units that would contribute to the flow and those that would act as baffles. Three dimensional visualisation models were then used to place the horizontal wells in high quality reservoir rock. Additionally, placement of the development wells for the deep gas reservoirs was designed to provide vital structural and stratigraphic information for potential heel and toe points for horizontal drilling.This paper describes how all this work was compiled into a simulation model which has successfully predicted the current well producing rates and pressure draw down.

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.

A petrophysical refresh of the bpTT fields in the Columbus Basin in Trinidad has been carried out. The objectives of the refresh were to provide continuity and consistency in petrophysical interpretations in this mature basin where over the years multiple vendors and differing interpretational approaches have been employed. In an effort to create a more robust core data set, data gaps were identified in the existing core analyses and supplemental analysis performed. The core data set was expanded to include Co/Cw measurements on plugs from 2 wells to augment legacy data to investigate log-based water saturation methods. New models were developed for permeability and water saturation and each of these models were calibrated against the core dataset. Permeability was re-evaluated with the new model being based on core-derived measurements and tuned to dynamic well test data to incorporate upscaling heterogeneities. Both log-based and core-based water saturation models were explored. The new core conductivity measurements provided support for the log-based method selected. Air-brine capillary pressure data have provided a key input to the development of a new saturation height function. The match between the new saturation height function water saturation and that derived from resistivity-based saturation is good, reinforcing its validity.

A Petrophysical Refresh of the bpTT fields in the Columbus Basin in Trinidad has been carried out. The objectives of the Refresh were to provide continuity and consistency in petrophysical interpretations in this mature basin where over the years multiple vendors and differing interpretational approaches have been employed.In an effort to create a more robust core data set, data gaps were identified in the existing core analyses and supplemental analysis performed.The core data set was expanded to include additional porosity and permeability measurements at net mean stress, laser particle size analysis was conducted on shaley intervals from 4 wells to confirm volume of shale method.New models were developed for volume of shale, porosity and net cut-offs and each of these models were calibrated against the robust core dataset. A curvilinear volume of shale was confirmed to be the most appropriate to estimate volume of shale for the bpTT fields. A total porosity model has been recommended, replacing the legacy effective porosity models. Core derived minipermeability profiles were combined with core photos, and log-derived volume of shale and effective porosity log curves to explore the limits of what might constitute net.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractHorizontal oil well drilling, completion and production techniques have continued to advance through the use of shared learnings and new technology as applied in the most recent BP Amoco field development in Trinidad. The Mahogany field is being developed to supply gas to the Atlantic LNG plant in Trinidad. The 21 Sand reservoir in this field has a 60 foot oil column overlain by a 400 bcf gas cap and underlain by water. As with other fields in Trinidad that have thin oil columns horizontal well technology was selected as the preferred method to develop the Mahogany 21 Sand oil leg. During the front end loading design phase of the Mahogany field development an extensive review of evolving technology and recent world wide experience was undertaken. As well, the front end loading involved a review of the BP Amoco Immortelle (Trinidad) horizontal well program which was in its third phase as the Mahogany front end loading was being completed.The critical success factors that emerged from the front end loading review were well placement within the oil column, avoid drilling poor quality reservoir, avoid undulating wellbores, the need to understand well performance with very low drawdowns, the need to land the well in the right place and at the right angle. All of these issues were addressed in the Mahogany horizontal well designs and have been successfully implemented.The front end loading work and continuing optimization of the well designs has resulted in a highly successful 21 sand oil development which is expected to deliver economic results superior to the authorized metrics.