Predicting gas-condensate reservoir performance: how flow parameters are altered when approaching production wells
Authors: Kalaydjian F.J-M. , Bourbiaux B.J. , Lombard J-M. 
Published: December 2007

Describing flow processes occuring both far from and close to the wellbore region is a major concern to accurately predict gas-condensate reservoir performance. This requires the knowledge of the gas-condensate parameters, e.g. the critical liquid saturation Slc and the gas-condensate relative permeabilities krg and kri. Regarding their determination, this paper addresses two main questions:Can analog fluid systems be used instead of real ones to measure gas-condensate flow parameters?What flow rate dependence must the relative permeabilities account for to properly describe the high flow rate conditions that prevail in the wellbore region?

To acquire flow parameters representative of the inner part of the reservoir, an integrated procedure was used to measure Slc's and kr curves. 29 flow tests were performed in an outcrop clayey sandstone core and 2 in an outcrop chalk core, using as gas-condensate systems, a binary C1C3, a ternary C1C3C7 and finally an actual North Sea reservoir fluid. Slc's for both analog and real fluid systems were found to increase with. For relative permeabilities under the low flow rate conditions that were used, no dependence of the kr curves was put into evidence. This was explained on the basis of a dependence upon a macroscopic capillary number CA that allows to compare viscous to capillary forces. Using this dimensionless number and considering a CA - dependence of the relative permeabilities leads to reconcile variations of relative permeabilities with and flow rate as described in the literature. Finally, this paper discusses what characteristics relative permeabilities should display so as to properly model wellbore flow conditions.

Introduction

Producing a gas-condensate reservoirs gradually lowers the producing well bottom hole flowing pressure below dew point. Once this has happened, retrograde condensation occurs leading to the segregation then the mobilization of the the condensate phase towards the producing wells. The liquid phase accumulates in the wellbore region, forming a ring which impairs progressively the gas deliverability. In addition to that, steadily, the produced gas becomes lighter and therefore less marketable. Predicting reservoir gas performance and economy thus requires an accurate modelling of the flow behaviour and the thermodynamics of those processes.

Quite a large number of papers have appeared over the last years to address this issue. A first set of papers (Refs 1 to 5) dealt with the determination of the critical condensate saturation Slc. This saturation is the minimum liquid saturation above which the condensate starts being mobile, corresponding thus to a non-zero condensate relative permeability. There is quite a controversy about the determination of this value. Values ranging between zero and 50% PV were acknowledged (Refs 4,5). Moreover, there is still a debate about the meaning and the usefulness of this parameter as it corresponds to very low liquid relative permeability values which would not contribute to the production process (Ref. 6). However, it has been largely recognized (Ref. 5) that the determination of the critical condensate saturation is of great importance to predict gas deliverability even though the condensate relative permeability takes very low values. In fact, as it is the case for any gravity segregation processes, these low values of the condensate relative permeability control the gas-condensate segregation and impact afterwards the phases' distribution and consequently the further buildup of the condensate ring.

The optimal way to determine in the laboratory relevant gas-condensate relative permeabilities which will serve as a basis to simulate the productivity of a gas-condensate reservoir has received also great attention. Several questions have arisen.

The first question is to know whether or not it is possible to use analog fluid systems to acquire those parameters. There are practical issues to verify whether an analog system can be used: P. 355