Arctic Offshore Development: Managing The Risk
Authors: Helmer C.M. , Churcher A.C. , Mclvor G.R. , Shields R.G. 
Published: October 2008

Existing equipment, with relatively minor conversion, supported by existing tankers can carry out year-round extended flow testing, early production and delivery of oil to market from the Arctic offshore.

This Paper discusses the advantages of the early production (EPS) approach, describes the required conversions to equipment and proposes a tanker transportation system. Economic implications of the EPS are also discussed.

Application of this approach increases the development potential for the many identified Arctic oil/gas reserves.

INTRODUCTION

The decision to develop a significant Arctic offshore oil field complete with a product transportation system is a billion dollar decision. The degree of confidence with which this decision is made depends on the quality and quantity of key parameter information available to the operator (e.g., amount of oil recoverable, reservoir rock and fluid properties). Additionally, an oil transportation must be considered to perform meaningful economic analysis.

To date, the technology and equipment to perform an extended evaluation in the Arctic have not been available. Consequently, a field development risk profile would typically be as shown in Table 1 (a) where significant risks are not fully resolved before the decision to commit to major investment must be made.

This Paper describes how the risk associated with proceeding to field development can be reduced by using suitably modified existing equipment. This approach both proves the producability of the reservoir and, as well, evaluates the transportation system before proceeding with the major investment [Table 1 (b)].

In addition to reducing the risk, this approach provides two further advantages, specifically, predrilling of production wells and early production. Predrilling can advance fill production and the project break-even point by one or two years. Early production can also provide early revenue. In the event that the decision to proceed to full production is not taken, may allow the project, to that point, to be cash neutral.

Table 1.a:Risk sequence using standard evaluation Techniques (Available in full paper) Table 1.b:Risk sequence with full reservoir and transportation evaluation (Available in full paper)

RISKMANAGEMENT:RESERVOIR

In the Arctic, as elsewhere, a discovery must first be made. Once the initial discovery has been established, the reservoir size and performance must be delineated.

There are a number of performance parameters which can be defined by cores, logs and standard drill stem tests such as permeability, porosity, saturations, initial well producability, etc. Historical data from similar geological structures and production simulations can also lead to valuable analyses. Assessment, however, of long-term performance parameters of the reservoir, such as primary production rates, the effects of water injection, optimum injection pattern, well decline rates, water cuts and ultimate reservoir recovery are best obtained by conducting a long-term well test program. Obtaining reliable information on parameters, such as waterflood performance, may take in excess of 12 months of testing and monitoring. Determining these and other parameters, with a high level of confidence, is the key to the optimum economic development of a field.