Abstract

This paper documents the integration of pressure transient data with reservoir simulation in the development planning of a large faulted gas reservoir in offshore Tanzania. A key risk for the project is early water production from a regional aquifer system and the effect that it may have on the recovery of gas and the ability to sustain a contract gas rate. Modeling was used to determine the risk of early water production in the field. Ordinarily, the limited production history in the field would have meant that history matching the model was not possible, however, in this case the model was history matched by simulating pressure transient responses in the wells and then comparing to actual pressure transient responses that were available from recent well tests. The results from the modeling were enlightening. Prior to history matching to the pressure transient response, the two most likely scenarios based on the geologic and petrophysical data for the reservoir were 1) layered reservoir with normal fault transmissibility and 2) layered reservoir with high conductivity fault planes connected to the aquifer. Disconcertingly, these two cases resulted in very different predictions of water production and where to position additional wells to maximize gas recovery. After modeling the pressure transient response, the results showed a strong match for the model with fault plane conductivity to the aquifer. The well test match is consistent with the massive extensional faulting in the region.

Introduction

The commercial market for gas in Tanzania has expanded greatly in recent years with the imminent construction of a gas-to-electric project and conversions of liquid fueled industries to gas fuel. The development of the Songo Songo field will bring significant new gas reserves on-line to help meet the market demand.

The Songo Songo gas field lies both on and offshore of Songo Songo Island, approximately 15 kilometers from the Tanzanian mainland and about 200 kilometers south of the capital city of Dar es Salaam as shown in Figure 1. Gas was initially discovered in 1974 with the drilling of the AGIP/Amoco Songo Songo #1 (SS-1). Between 1976 and 1983, eight more wells were drilled in the field. Five wells - three offshore (SS-5, SS-7, and SS-9) and two onshore (SS-3 and SS-4)- are capable gas producers. At least two wells were drilled deep enough to confirm a large water zone lying below the gas column.

The ability of the wells to produce the required gas rates and, in particular, the potential risks associated with water influx on reservoir performance are key issues that may impact the field development strategy and, ultimately, the long-term contracts for the Songo Songo gas. The purpose of this study is to quantify the risk of water influx on the field's long term gas deliverability.

FIELD DESCRIPTION

The Songo Songo reservoir is a thick sandstone deposit of Neocomian (early Cretaceous) age. Significant faulting has resulted in a complex structure as shown in Figure 2. The dominant faults are a series of North-South trending converging and diverging normal extensional faults, which were active in Pre-Cambrian time.

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