Estimating Oil Reserves of Fields With Oil/Water Transition Zones
- J.R. Fanchi (Colorado School of Mines) | R.L. Christiansen (Colorado School of Mines) | M.J. Heymans (Geological Consultant)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- August 2002
- Document Type
- Journal Paper
- 311 - 316
- 2002. Society of Petroleum Engineers
- 4.6 Natural Gas, 5.4.1 Waterflooding, 5.7 Reserves Evaluation, 5.3.2 Multiphase Flow, 1.6.9 Coring, Fishing, 5.6.2 Core Analysis, 5.1.5 Geologic Modeling, 2.4.3 Sand/Solids Control, 4.3.1 Hydrates, 5.3.4 Reduction of Residual Oil Saturation, 1.2.3 Rock properties, 5.5.1 Simulator Development, 5.2 Reservoir Fluid Dynamics, 5.2.1 Phase Behavior and PVT Measurements, 5.1 Reservoir Characterisation
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The amount of recoverable oil in an oil/water transition zone depends on the distribution of oil saturation as a function of depth and on the relationship between initial and final oil saturation in the transition zone (Soitz and Sortz), as well as the volumetric extent of the zone. Conventionally, it is assumed that Sortz is constant and equal to the residual oil saturation in the oil column (Sor) above the transition zone. However, limited data in the literature show that residual oil saturation depends on initial oil saturation as described by the trapped-oil relationship. Thus, Sortz should be a function of Soitz.
The purpose of this paper is to present recent experimental corroboration of the trapped-oil relationship and to demonstrate the impact of the trapped-oil relationship on reserves determination in oil/water transition zones. The effect of the trapped-oil relationship on reserves determination is shown in two ways: first, with an analytical model that shows the maximum possible incremental benefit of including the trapped-oil relationship; and second, with an extended black-oil simulation that incorporates the effects of relative permeabilities on reserves determination.
Transition zones may vary in thickness from a few feet to a few thousand feet.1 The size of the transition zone affects the estimates of original hydrocarbons in place and the distribution of recoverable reserves. It is important to characterize transition zones accurately because of their potentially large effect on reservoir economics. Heymans2 describes a 90-ft-thick transition zone that contributed more than 30% of the estimated original oil in place in an edge-waterdrive reservoir with a nearly 1,000-ft oil column. In other words, the volume of hydrocarbons in a seemingly relatively thin transition zone that formed a ring around the example reservoir with edge-waterdrive had a significant consequence on original- oil-in-place estimates.
An oil/water transition zone is generally described from the perspective of oil recovery as a zone in which both oil and water are produced. The top of a transition zone in a reservoir is the elevation at which water-free oil can be produced. It corresponds to the depth at which mobile water first appears. The bottom of an oil/water transition zone is the shallowest depth at which oil-free water is produced. In some reservoirs, the entire oil column is in the transition zone.
Limited data in the literature suggest that residual oil saturation Sor is a function of initial oil saturation Soi. The relationship between Sor and Soi is referred to as a trapped-oil relationship. Trapped-oil relationships can be measured in experiments with partial saturation of a sample with oil. However, such measurements of trapped-oil saturations and the associated oil/water relative permeabilities are rarely reported (see Morrow3). Indeed, the only paper with measurements of trapped-oil relationships is that of Pickell et al.,4 who used porous-plate methods to saturate their sandstone samples to initial oil saturation; then, the samples were waterflooded to residual oil saturation.
There are many more reports of trapped-gas saturation in the literature. Pickell et al.4 give a trapped-gas relationship for Austin limestone. Land5 used six sets of data from previous literature to develop a correlation for trapped gas relationships. Keelan and Pugh6 compare trapped-gas relationships for three classes of rocks from carbonate formations. Yuan and Swanson7 compared trapped-gas relationships measured with the method of Pickell et al. to estimates from rate-controlled porosimetry. The trapped-gas relationship could be a good estimate of the trapped-oil relationship for a rock sample, particularly if the sample is strongly water wet. Fig. 1 is a trapped-gas relationship that was used as a trapped-oil relationship by Schowalter and Hess.8
In this paper, conventional practice for estimating recovery from transition zones is investigated, and the need for additional rock/fluid property measurements is highlighted. We describe the procedure and the results of recent experiments for measuring the trapped-oil relationship for water-wet media. Then, the effect of the trapped-oil relationship on estimates of oil reserves is demonstrated with a simple analytical method and a numerical simulator. A numerical simulation example illustrates a relatively arduous procedure for including the trapped-oil relationship in existing simulators.
Conventional Practice in Reservoir Engineering.
Conventional simulators for modeling hydrocarbon production from a transition zone use drainage (or reducing water saturation) capillary pressure core data and forced imbibition (waterflood, or increasing water saturation) relative permeability core data. Ideally, both sets of measurements are performed on statistically representative core samples from the reservoir. The tests are also performed, ideally, with reservoir fluids at reservoir temperature and pressure.
Drainage capillary pressure measurements provide several key elements for reservoir analysis. The minimum water saturation from these tests is an estimate of the water saturation in the oil column at discovery. Typically, this is the same saturation used for initializing the waterflood relative permeability measurements. With drainage capillary pressure data at reservoir conditions, an oilsaturation profile as a function of height in a reservoir can be graphed, as shown in Fig. 2. The base of the transition zone at the bottom of the productive oil column is often defined by the residual oil saturation Sor from a single waterflooding test, so initial oil saturations that are less than the waterflood Sor are considered unrecoverable.
The conventional practice described earlier is somewhat dubious because it correlates forced imbibition measurements from the waterflood with drainage capillary pressure results. Though dubious, it is convenient for numerical simulators as presently constructed. The drainage capillary pressure data are used to establish the transition zone at the start of a waterflood, and the forced imbibition relative permeabilities contribute to the mobilities of fluids.
To precisely describe fluid movement, one should combine capillary pressure and relative permeabilities for the same saturation history (e.g., drainage capillary pressures with drainage relative permeabilities). This combination is shown in Fig. 3. The capillary pressure and relative permeability combination in Fig. 3 is appropriate for describing the filling of a water-wet reservoir with oil or for describing an oilflood of a water-wet core.
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