Modeling Gas-Condensate Well Deliverability
- Øivind Fevang (Norwegian Technical and Natural Science U.) | C.H. Whitson (Norwegian Technical and Natural Science U.)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Engineering
- Publication Date
- November 1996
- Document Type
- Journal Paper
- 221 - 230
- 1996. Society of Petroleum Engineers
- 5.6.9 Production Forecasting, 4.1.5 Processing Equipment, 5.6.4 Drillstem/Well Testing, 5.1 Reservoir Characterisation, 4.6 Natural Gas, 5.5 Reservoir Simulation, 5.4.3 Gas Cycling, 5.2.1 Phase Behavior and PVT Measurements, 5.2.2 Fluid Modeling, Equations of State, 4.1.2 Separation and Treating, 5.8.8 Gas-condensate reservoirs, 5.2 Reservoir Fluid Dynamics
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This paper gives an accurate method for modeling the deliverability of gas-condensate wells. Well deliverability is calculated with a modified form of the Evinger-Muskat1 pseudopressure (originally proposed for solution-gas-drive oil wells). The producing gas/oil ratio (GOR) is needed to calculate pseudopressure, together with pressure/ volume/temperature (PVT) properties (black-oil or compositional), and gas/oil relative permeabilities. The proposed method is successfully tested for radial, vertically fractured, and horizontal wells.
Using the proposed deliverability model, we show that fine-grid single-well simulations can be reproduced almost exactly with a simple rate equation that uses pseudopressure. The key is knowing the producing GOR accurately. The effect of near-wellbore damage, vertical fracture, or flow improvement caused by horizontal well trajectory is readily incorporated into the rate equation as a constant skin term.
The effect of gas/oil relative permeability is studied. We show that well deliverability impairment resulting from near-wellbore condensate "blockage" is dependent only on relative permeabilities within the range defined by 1 < krg/kro < 50. Usually this represents gas and oil relative permeabilities ranging from 0.05 to 0.3. Gas relative permeabilities at low oil saturations (krg > 0.3) affect deliverability only for richer gas condensates.
A key observation and conclusion from this study is that critical oil saturation has no direct effect on well deliverability. We also show that interfacial tension (IFT) dependence of relative permeability has little or no effect on gas-condensate well performance (e.g., length of plateau production). The most important application of this study is to provide a simple method for calculating bottomhole flowing pressure (BHFP) in coarse-grid models. We show that the proposed pseudopressure method is readily calculated for each well grid cell on the basis of only grid-cell pressure and saturation (i.e., producing GOR). Local grid refinement near wells is not necessary, and relatively large well grid cells can be used and still provide an accurate description of well deliverability.
Calculation of gas-condensate well deliverability has been a longstanding problem without a simple solution. When BHFP drops below the dewpoint, a region of high condensate saturation builds up near the wellbore, resulting in reduced gas permeability and lower gas deliverability. The effect of a condensate-blockage region depends on PVT, absolute and relative permeabilities, and how the well is being produced. Reduced gas deliverability because of condensate blockage is important only when condensate-blockage pressure drop is significant relative to the total-well (tubing and reservoir) pressure drop and the BHFP reaches a minimum (dictated by surface constraints) and the well is forced to go on decline.
Muskat2 addresses the condensate-blockage problem in his discussions of gas cycling, where he introduces a simple method for estimating the radius of condensate blockage as a function of time, gas rate, and reservoir-rock and -fluid properties. Fetkovich3 uses Muskat's results to derive a rate- and time-dependent blockage skin for use in the standard gas rate equation.
Kniazeff and Naville4 and Eilerts et al.5,6 were the first to numerically model radial gas-condensate well deliverability. These studies show radial saturation and pressure profiles as functions of time and other operational variables, confirming that condensate blockage reduces well deliverability. Kniazeff and Naville also study the effect of non-Darcy flow (in the gas phase) on well deliverability. Gondouin et al.7 contribute toward the fundamental understanding of gas-condensate well deliverability through radial black-oil simulations. They extend the work by Kniazeff and Naville, showing the importance of condensate blockage and non-Darcy flow effects on backpressure performance. They also give experimental procedures and measurements that quantify the effects of relative permeability and multiphase non-Darcy flow.
O'Dell and Miller8 present the first gas rate equation that uses a pseudopressure function to describe the effect of condensate blockage. The equation is valid when the produced wellstream is the original reservoir gas and when the blockage radius is relatively small (Le., the reservoir pressure is significantly above the dewpoint). From their results, it is clear that well deliverability can be significantly reduced even for small regions of condensate blockage. Fussell9 presents equation-of-state (EOS) compositional simulations of radial gas-condensate wells producing by pressure depletion below the dewpoint. He shows that the O'Dell-Miller equation (with a small correction to account for gas dissolved in the flowing oil phase) dramatically overpredicts the deliverability loss from condensate blockage, compared with simulation results.
Jones and Raghavan10,11 primarily treat transient pressure behavior (drawdown and buildup) of radial wells. They use EOS compositional simulation with simple three-component (C1/C4/C10) gas-condensate mixtures. The key observation they make concerning long-term (boundary-dominated) well deliverability is that the pseudopressure function presented by Fussell is accurate at all times during depletion. However, the integral must be evaluated with pressures and saturations known as a function of radius at a given time in depletion (reservoir integral pseudopressure). However, they point out that this isn't very helpful because they have to do compositional simulation to know the pressures and saturations at a given time in depletion. We show in this paper how to get the pressures and saturations easily from the instantaneous producing GOR (i.e., the producing well stream composition).
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