ABSTRACT

The need to re-develop one of the Brown fields located in the Niger Delta area of Nigeria was necessitated by the fact that there are still three undeveloped reservoirs in the field.

A total of six stacked reservoirs, A100 to A600 (all oil bearing with associated gas) were penetrated between 8552 ftss and 10652 ftss by APV-1 well. Reservoir blocks A200 and A600 are the largest in the field accounting for 77% of the total field STOIIP. The well was completed with a Two String Multiple (TSM) on the two levels, with the short string producing from the A200 reservoir and the long string producing from the deeper A600 reservoir, A300 behind the sleeve.

The purpose of this research is to identify the best developmental plan to produce the reservoirs, either with a TSM completion or with a Smart well completion based on the economics. There are many single well fields in the Niger Delta area of Nigeria that have not been optimally produced, hence this study seeks to maximize the life of this field.

The reservoirs were simulated and production forecast carried out amounted to 14.55 MMstb for a period of 16 years.

After economic analysis was performed, the Net Present Value for the TSM and the Smart well completion were US $MM 241.9 and 248.88 respectively and an Internal Rate of Return of 155% and 202% respectively, hence the Smart well development plan is recommended.

 

CHAPTER ONE

1.0 BACKGROUND

Petroleum reserves are declining, and fewer noteworthy discoveries have been made in recent years (Abdus, 1990). The need to increase recovery from the vast amount of remaining oil and to compete globally require healthier reservoir management practices (Abdus et al, 1994).

However, technological developments in all areas of petroleum exploration and exploitation, along with fast increasing computing power, are providing the tools to better develop and manage reservoirs to maximize economic recovery of hydrocarbons (Abdus, 1990).

A reservoir’s life begins with exploration, which leads to discovery; reservoir delineation; field development; production by primary, secondary and tertiary means; and abandonment (Figure. 1.1).

Sound reservoir management is the key to successful operation of the reservoir throughout its entire life. It is a continuous course, unlike how the baton is passed in traditional E&P organizations (Abdus et al, 1994).

Reservoir Management is all about excellence in the Operate phase of an E&P project life cycle. This is the only phase (Operate) that earns income, to provide the return on investment and it is the longest of the four (4) E & P business phases (Exploration, Appraisal, Development and Operate) spanning decades. (Shell WRM Operational Excellence, 2010).

Complete reservoir management requires the use of both human and technological resources for maximizing  profits  (Abdus  et  al,  1994).  It  requires  good  coordination  of  geologists, geophysicists,  production,  and  petroleum  engineers  to  advance  petroleum  exploration, development, and production. Also, technological advances and computer tools can facilitate better reservoir management as well as enhance economic recovery of hydrocarbons. Even a 11 small percent increase in recovery efficiency could amount to significant additional recovery and profit. These incentives and challenges provide the motivation to sound reservoir management. Reservoir simulation is the way by which one uses a numerical model of the geological and petrophysical characteristics of a hydrocarbon reservoir to analyze and predict fluid behavior in the reservoir over time. In its simple form, a reservoir simulation model is made up of three parts: (i) a geological model in the form of a volumetric grid with face properties that describes the given porous rock formation; (ii) a flow model that defines how fluids flow in a porous medium, typically given as a set of partial differential equations expressing conservation of mass or volumes together with suitable closure relations; and (iii) a well model that describes the flow in and out of the reservoir, including a model for flow within the well bore and any coupling to flow control devices or surface facilities (Lie, 1994).

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