Importance of Compaction in Depressurisation of Oil Reservoirs
Authors: Tehrani A.D.H. , Smart B.G.D. , Shwishin N.M.M. 
Published: December 2007

The paper presents the results of an in-depth study in various aspects of the depressurisation of an oil-reservoir, with particular emphasis on critical gas saturation, interfacial tension (IFT) and the rock stress effects on oil and gas recovery. It also presents the results of sensitivity studies, using a compositional simulator, of variables such as pore size distribution index and IFT exponent, which control the shape and magnitude of relative permeabilities, in addition to the important effects of the critical gas saturation and rock compaction. The actual reservoir data of a North Sea field in the United Kingdom has been used. A comprehensive literature survey of the various methods used for determination of critical gas saturation and the weaknesses and strength of each are described and the most appropriate method is recommended1. The study shows which parameters have significant impact on oil and gas recoveries in the depressurisation process, under what circumstances and which ones have no significant effect. One conclusion is that ignoring the compaction effect could result in unrealistically optimistic predictions and investment decisions, which could result in disastrous economics for the project. Recommendations are made for further research into relevant subjects for future.

Introduction

Most of the oil reservoirs in the North Sea are produced by waterflooding. When water cut exceeds an economic limit the field is usually abandoned. Operators have recently considered a period of tail end production by depressurising the reservoir after the waterflooding has matured. Additional recovery of gas (in high GOR fields) is expected at an economical rate, thus prolonging the field life and producing some oil too. There are, however, a few small fields, which are produced by natural depletion (which is a type of depressurisation) before any waterflooding. One such field has been studied in detail and the results are presented in this paper. The reservoir has an initial oil-in-place of 56 million stock tank barrels of oil and 139 billion standard cubic feet of solution gas. The oil was initially undersaturated by about 3000 psi, with the saturation pressure changing with depth, from about 5500 psia on top (ca 11,000') to about 5100 psia at the oil-water contact (ca 11,900'). Figure 1 presents a typical cross section of the reservoir and the water saturation at initial conditions for the four main layers. The top layer (layer 1) has a porosity of 6% and permeability of 0.4 mD. The next three layers have each an average porosity of 13.5% but their permeability varies from 34 mD in layer 2 to 7 mD in layer 4. Within the reservoir, the variation of cell permeability is from as low as 0.01 mD to as high as 1200 mD. The operator had used petrophysical and geological data to determine the simulation cell porosity and permeability values.

The field was put on production in February 1995 with average production rate of about 7000 stbo/d up to 1 January 2000, Figure 2. Total production was 12.4 million stb of oil and 34.8 billion scf of gas, with average GOR of about 2800 scf/stb. Surface oil gravity was about 0.7894 g/cc. There were three producers and three observation wells in the reservoir. A compositional simulator (E300) was used to study the reservoir performance. The study results presented in this paper are based on history matching up to end 1999 and predictions thereafter.

The limited available laboratory data on capillary pressure (Pc) and relative permeability (kr) were used together with scaling methods (J-function for Pc and Corey2 and Lands3 methods for kr) to obtain the basic data for each simulation cell, corresponding to its porosity, permeability and water saturation.