Solvent Bank Design Using Coning And Dispersion Curves
Authors: Bennett F. 
Published: March 2010

A graphical technique is presented which accounts for dispersion and coning when predicting loss of solvent bank miscibility for a gravity-stable, vertical miscible displacement. This method can be used to determine the effect of solvent bank size, infill drilling and production rate on pool ultimate recovery. Esso's Pembina Nisku ‘K’ Pool is used to demonstrate this technique.

Introduction

Sizing of the solvent bank (or slug) is an important consideration when designing miscible floods. An undersized bank can result in early loss of miscibility while an oversized bank incurs needless expense. In a vertical miscible displacement loss of miscibility results from degradation of the solvent bank, either through coning or through dispersion of the solvent into the chase gas and the oil. The relative magnitude of these effects is influenced by choice of solvent and chase gas compositions and production strategy. Previous approaches in slug design for gravity-stable vertical miscible displacements have generally looked at coning and dispersion effects individually. Compositional simulators have also been used to simultaneously model coning and dispersion effects but encounter high numerical dispersion from the discretization of the flow equations. As a result, excessive computational time is required to adequately model physical dispersion.

In the proposed technique a black oil pseudo-miscible simulator is used to quantify solvent coning and oil production for a well in the Pembina Nisku ‘K’ Pool. Analytical dispersion calculations are then used to adjust recovery predictions by accounting for loss of miscibility.

Reservoir Description

The Pembina Nisku ‘K’ Pool is located in Section 32-49-11W5, in the Pembina field, approximately 240 km north-northwest of Calgary. The pool is a high-permeability, dolomitized Nisku pinnacle reef with a maximum net pay thickness of 81 m. There is no bottom water in this reef. Primary production started in 1978 and 3% of the oil was produced by this means until 1980 when a miscible flood was started, Cumulative oil production to the middle of 1989 is 1216 103 m3 or 43% of the original-oil-in-place (OOIP) of 2823 103 m3. The solvent injected to form the miscible bank was a hydrocarbon gas with an ethane plus content of approximately 32 mole per cent. Operating pressure for this pool is approximately 1000 kPag above the minimum miscibility pressure of 26,000 kPag. The pool has been on chase gas injection since injection of a 35% hydrocarbon pore volume (HCPV) solvent bank was completed in 1987.

Solvent Coning Simulation

Simulation Model

A black oil pseudo-miscible computer simulation of solvent and chase gas coning was the first step in determining the effect of solvent bank size on recovery. To model near-wellbore effects in the central producer a three-dimensional radial model was chosen consisting of a 5 by 6 by 20 grid in the radial, angular and vertical directions, respectively.

Plan and cross-sectional views of the simulation grid overlain on the pool boundary are shown in Figures 1 and 2. The hatched areas in Figure 2 represent inactive grid cells and the shaded areas are cells with pore volume and transmissibility modifiers.