Abstract

This paper describes the combination of integrated petroleum engineering studies with probabilistic decision making to assess the value of information of an appraisal well in a mature field.

The implementation of a cost effective pressure maintenance in the St Joseph Field offshore Malaysia has required consideration of several options, one of which is reverse dump flooding of the oil reservoir from underlying unconnected aquifers. A reverse dump flooding scheme would require drilling of a pilot well to collect additional data on the aquifers. Justification of the pilot (appraisal) well involved a series of studies based on limited data to establish that the dump flooding process had a sufficient probability of leading to a development with better economics than a gas injection scheme.

The aquifer assessment used seismic, biostratigraphic, pressure, regional data, and trend data from logs to define a distribution of connected aquifer size and quality. Well studies defined the ranges of aquifer productivity and oil leg injectivity and resulted in a flexible well completion that could be converted to a production well. Full field reservoir simulation estimated the aquifer and well performance ranges to derive a probability distribution of likely water dump volume and incremental oil reserves. Screening economics were performed and compared with gas injection. Monte Carlo simulation of the many combinations allowed definition of the probabilities as input for a decision tree analysis. Analytical well test simulation showed that uncertainties would remain in aquifer volumes after a pilot test, and needed to be incorporated into the decision tree. Ultimately the value of information of the pilot well was quantified to show an economic justification for pursuing the dump flooding option.

Introduction

St. Joseph Field (Fig. 1.) has been on production since February 1982. At end 1995, the field had produced 105 MMstb oil out of the total ultimate recovery estimated at 230 MMstb. The recovery mechanism to date has been natural depletion under gravity drainage with string-by string control of gas-oil-ratio imposed. Current production potential is 28 Mb/d. Average reservoir pressure has fallen from 1060 psia to about 600 psia with an expanding secondary gas cap, and abandonment pressure under gas lifting is approximately 350 psia.

Of the 550 MMstb oil initially in place (STOIIP) in St Joseph Field, 83% is located in the main reservoir package in the Northwest Flank, which is a simple structure dipping at 20 degrees and sealed by a major strike-slip fault (Fig. 2). The oil reservoirs are Miocene age sands (Stage IVC) with intercalated shales deposited in outer shelf to deltaic/lagoonal environments. The reservoir package is sealed against a major transverse fault. Gross reservoir hydrocarbon thickness is 1450 ft true vertical with the crest of the structure at only 1280 ft ss. Sand porosities and permeabilities are good in the oil column, generally deteriorating down flank into the aquifer. In addition, major slump features have removed large reservoir sections in the aquifer. Direct aquifer influx to the main reservoir package is weak. 3D seismic data show strong continuous reflectors underneath the reservoir package, indicating a thick Stage IVA sequence of which the upper part has penetrated by eleven wells. Log and RFT measurements indicate that Stage IVA sands are water bearing and are overpressured by 60-90 psi. The Stage IVA and IVC deposits are separated by the Upper Intermediate Unconformity (U.I.U).

Pressure Maintenance Options

Three main options for secondary recovery have been considered for St Joseph:

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