Twenty Five Years of Ekofisk Reservoir Management
Authors: Hermansen H. , Thomas L.K. , Sylte J.E. , Aasboe B.T. 
Published: December 2007

This paper describes the development of Ekofisk from the start of production in 1971 to the current time. In addition, future Ekofisk redevelopment plans will be discussed. A summary of operations during this time is given which includes primary depletion with excess gas injection followed by successive stages of water injection. Drive mechanisms including solution gas drive, gravity drainage, compaction, water-oil imbibition, viscous recovery and compositional effects will be discussed. An outline of future possible EOR scenarios will also be discussed.

The reservoir management strategies and details of reservoir description and reservoir simulation will be presented. Special features needed for Ekofisk Field modeling that will be discussed include the effect of matrix-fracture flow, compaction due to elastic/plastic deformation and water weakening, compositional changes due to dry gas injection, thermal effects resulting from the injection of cold seawater into a relatively hot reservoir, surface field constraints which are used to optimize oil and gas production from Ekofisk and related fields, and voidage balancing controls to optimize future water injection volumes.

The challenges of redeveloping the Ekofisk Field with the installation of a new process and transportation facility and wellhead platform with 50 slots will be presented. Methods used to identify new infill locations, develop drilling schedules and phasing out of existing facilities will be briefly reviewed.

Introduction

The Ekofisk Field is located in the Norwegian Sector of the North Sea, Figure 1. The reservoir is an elongated anticline with the major axis running North-South covering approximately 12,000 acres, Figure 2. It produces from two fractured chalk horizons, the Ekofisk and Tor Formations separated by a tight zone. The overlying Ekofisk Formation has a depth of about 9,600 feet and varies in thickness from 350 – 500 feet with porosities ranging from less than 30% to a maximum of 48%. The underlying Tor Formation varies in thickness from 250 – 500 feet. Its porosities range from less than 30% to 40%. Approximately two thirds of the 6.4 billion STB hydrocarbon porevolume in place is found in the Ekofisk Formation.

Ekofisk Field initial reservoir pressure was 7135 psia at a depth of 10,400 feet. The field initially contained an undersaturated volatile oil with a bubble point pressure of 5560 psia at an initial temperature of 268 degrees F.

This paper describes the development and operations of Ekofisk from start of production in 1971 to current time. Reservoir management strategies and details of reservoir characterization and reservoir simulation are presented. Redevelopment activities that are currently underway will also be discussed.

Development History

The Ekofisk Field was discovered in 1969 and test production was started in 1971 from the discovery well and three appraisal wells tied into the converted jackup rig Gulftide to eliminate initial concerns of well productivity losses due to pressure depletion and closure of the natural fracture system. Commercial oil production rates in excess of 10,000 STB/D per well were experienced over several months and a decision was made in 1972 to develop the field and drill 30 wells from three platforms and to install process facilities to handle an oil production rate of 300,000 STB/D. P. 873^