Case History: Results of Horizontal Development in Immortelle Field
Authors: Attong D.J. , DeLandro W. 
Published: December 2007

Case History: Results of Horizontal Development in Immortelle Field.

Amoco Trinidad Oil Company successfully completed a horizontal drilling program to develop a thin oil column in a particular reservoir in one of its offshore fields. As the first to attempt horizontal technology in the island of Trinidad there was considerable anxiety with regard to its effectiveness and application. This paper will present the results of a 5 well horizontal program. Drilling operations will be discussed along with primary completion considerations such as wellbore instability, wellbore cleanup and sand control operations. Productivity indices between 5 horizontal wells and one vertical well will be discussed based on our current reservoir data. Because of the favourable results of this phase, a subsequent development phase is currently being evaluated for mid-1996 implementation.

Introduction

The Immortelle Field is located approximately 45 miles offshore, southeast of Galeota Point off the island of Trinidad (Fig. 1). The Immortelle Field Development began as the second of a two-phase gas supply plan to satisfy a Gas Sales Contract. The first phase was the successful two well Flambuoyant development which is capable of delivering 140 mmcfd from two wells. After drilling the first two Immortelle gas wells it became apparent that gas supply would be adequate and therefore resources were put in place to exploit the '16' sand oil. Because of the thin oil rim, and 39 ft. oil column and the concern for coning problems, a multidisciplinary approach was taken to exploit the oil using Horizontal technology. Considerable focus was placed on the Immortelle development as we were the first to attempt horizontal technology in Trinidad. Five wells were successfully drilled and completed with sand control. Productivity indices of between 10-20 BOPD/psi were observed from the horizontal wells. One offset vertical well exhibited a Productivity Index of 0.8 BOPD/psi. Production monitoring is conducted with downhole pressure gauges and PLT data obtained using coil tubing technology. The success of this five well program has led to the evaluation and implementation of a follow up horizontal phase by mid 1996.

'16' Sand Geology

The Immortelle structure is a northwest plunging, 3 way dip closure up against a normal A-4 fault. The structure is cut by numerous down to the east faults, which over geologic time may not have been very good seals, as evidenced by the common hydrocarbon contacts across them (Fig. 2). These faults may act as seals over production time, but more data is needed to substantiate this. The '16' sand interval is a 375 ft.-thick interbedded sand and shale sequence. The sands were deposited in a deltaic environment and the whole interval is a generally coarsening upwards sequence. Based on well data, the interval can be divided into 5 distinct lobes, namely 16, 16L2, 16L3, 16L4 and 16L5. The interbedded shales which separate the major lobes are very distinct on the gamma ray, and may be permeability barriers. Further work with cuttings and core data will be used to model these shales. The average porosities for the lobes range from 25-30% with horizontal permeabilities in the range 50 - 1500 md. The overlying 15A shale appears to be a major flooding surface and is easily correlatable throughout the field from well data and seismic.

Reservoir ModelIng

The preliminary mapping and reservoir analysis indicate approximately 65 MMBO of oil and 275 BCF of gas in place in the three main fault blocks of the '16' Sand. The '16' sand top is encountered at a depth of nearly 7000 ft. SS. The thickness of the column averages 39 ft. (Fig. 3). The average reservoir pressure is 3219 psi and the oil gravity is 39 API. The majority of the oil potential (98%) occur as an oil rim which is overlain by a gas cap and underlain by an aquifer. Due to the likelihood of gas coning and low anticipated recoveries in these sands (less than 10% if conventional wells are drilled and completed), a multidisciplinary team was formed to evaluate the application of horizontal wells to effectively drain the reservoir. Industry experience indicates that recoveries of 20-25% are possible using horizontal wells. A simulation study to predict the performance based on the Joshi Model indicated an expected rate of 1 BOPD/foot of lateral section. The reservoir modeling predicts that 1 to 2 MMBO of oil and over 10 BCF of gas can be recovered from each horizontal well.

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