Recovery of Condensate From a Heterogeneous Reservoir by the Injection of a Slug of Methane Followed by Nitrogen

Abstract

SPE Members Abstract The process of injecting gas into a gas condensate reservoir during production is vital to maintain the reservoir pressure so that the heavy hydrocarbon fractions will be recovered. One would like to inject a gas into the reservoir that is cheaper than methane, but recent one-dimensional studies have shown that the injection of nitrogen into gas condensate at reservoir conditions will result in the loss of much of the condensate liquid. This is a result from the liquid dropping out of the gas phase when nitrogen mixes with the condensate. A solution to this situation is the initial injection of a slug of methane (or dry gas) followed by the injection of nitrogen for pressure maintenance. If the methane slug is large enough it will separate the nitrogen from the condensate and the liquid recovery will be high. The physical processes that tend to destroy the integrity of the methane slug are mixing due to rock heterogeneity, fluid fingering, and bypassing. This paper studies the two step injection process numerically with a three-dimensional EOS compositional simulator. The gases are injected into a heterogeneous quarter five spot. The recovery of liquid condensate is studied as a function of the composition of the injection gas, the methane slug size, and the magnitude of the permeability variations (heterogeneities) of the porous media. A fine grid involving 8,000 blocks is used to allow the proper description of the heterogeneities and to keep numerical dispersion, which simulates sub-grid block dispersion, at a reasonable level. Monte Carlo simulations are performed on realizations of reservoirs. The results show that the heterogeneities allow the nitrogen to mix with the condensate when the methane slug is small (5% to 10% of a porevolume) but the incremental recovery over the porevolume) but the incremental recovery over the injection of nitrogen is large enough to pay for the cost of the methane. Economics are given to allow one to size a methane slug for a real heterogeneous reservoir so as to maximize the profit of the project. project. Introduction The recovery of liquid hydrocarbons from a gas condensate reservoir is dependent upon maintaining as much of the reservoir as possible as a single phase gas. To accomplish this a fluid must be injected into the reservoir as condensate is produced to replace the reservoir volume, maintaining the reservoir pressure above the dew point pressure, and to displace the condensate towards the producing wells. The obvious choice of injecting dry separator gas (basically methane) plus some make-up gas (usually also methane) has both positive and negative aspects. On the positive side, combining methane with most gas condensates has only a small effect on the mixture's dew point. Thus, no liquid falls out. On the negative side, the injected methane is very expensive since it is not available for sales. A alternate choice is the injection of an inexpensive, inert gas, such as nitrogen. Previous experimental displacements with nitrogen Previous experimental displacements with nitrogen and a gas condensate in a slim tube have shown that liquid recoveries are as high as in displacements with methane, that is, of the order of 98%. However, in a numerical study, Kossack et al have shown that at field scale Peclet Numbers the increased mixing between the nitrogen and the condensate would cause a loss of 30 to 40% of the liquid as compared to a displacement with methane. Their simulations were one-dimensional, and thus, did not include areal sweep, gravity segregation, or viscous fingering. Their results did show that injecting a mixture of nitrogen and methane would increase the recovery over that of pure nitrogen. P. 19

A Case Study of Gas-Condensate Reservoir Performance with Gas Cycling

“…the primary concept of utilising dry gas is its capacity to vaporise condensed liquid fractions, which can be separated and reused for further injection. the study of process efficiency and injection rim size is frequently conducted on bulk core samples, Pvt units, or compositional modelling [14][15].…”

Assessment of the recovery and front contrast of CO2 EOR and sequestration in a new gas condensate reservoir by compositional simulation and seismic modeling

“…The time-lapse seismic, if available, may have potential to monitor it in a much large scale as discussed later in this paper. CH 4 and N 2 and CO 2 have been used to re-vaporize condensate [12,16,10]. Once the condensate drops out, the chemical treatment [2] is the most recent method of remediation, and the design and modeling of this chemical treatment, along with its solvent flowback process, is very challenging [21,22], as it involves three-phase flow, relative permeability, and phase identity complicacy [19,20].…”