Well Test Analysis of Horizontal Wells in Gas-Condensate Reservoirs
- Abdolnabi Hashemi (Imperial College) | Laurent Nicolas (Gaz de France) | Alain C. Gringarten (Imperial College)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- February 2006
- Document Type
- Journal Paper
- 86 - 99
- 2006. Society of Petroleum Engineers
- 3.3.1 Production Logging, 5.1 Reservoir Characterisation, 5.5.2 Core Analysis, 5.6.11 Reservoir monitoring with permanent sensors, 1.6 Drilling Operations, 5.3.2 Multiphase Flow, 1.6.9 Coring, Fishing, 4.1.5 Processing Equipment, 5.2.1 Phase Behavior and PVT Measurements, 4.1.2 Separation and Treating, 4.6 Natural Gas, 5.1.1 Exploration, Development, Structural Geology, 5.2.2 Fluid Modeling, Equations of State, 5.6.4 Drillstem/Well Testing, 2.4.3 Sand/Solids Control, 5.1.7 Seismic Processing and Interpretation, 4.2 Pipelines, Flowlines and Risers, 5.8.8 Gas-condensate reservoirs, 5.5.8 History Matching, 5.2 Reservoir Fluid Dynamics, 2.2.2 Perforating
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Gas/condensate reservoirs usually exhibit complex flow behaviors owing to the buildup of condensate banks around the wells when the bottomhole pressure drops below the dewpoint pressure. The formation of this liquid saturation can lead to a severe loss of well productivity and, therefore, lower gas recovery. Several studies have examined various ways to minimize the pressure drop in order to reduce liquid dropout and related problems. One solution implemented over the past decade is the use of horizontal wells.
There is a lack of published knowledge on the flow behavior of horizontal wells in gas/condensate reservoirs. The limited studies in this area (Muladi and Pinczewski 1999; Dehane et al. 2000; Harisch et al. 2001) focused on well performance rather than on well-test behavior. There has been no evidence of condensate dropout effects in published horizontal-well-test data.
This paper presents preliminary results from a study aimed at establishing an understanding of the near-wellbore well-test behavior in horizontal wells in gas/condensate reservoirs, with a focus on the existence of different mobility zones caused by condensate dropout.
We used a 3D fully compositional model to develop derivative shapes to be expected from horizontal-well-test data in gas/condensate reservoirs below the dewpoint under various conditions. We then analyzed actual well-test data that exhibit such derivative characteristics, using a uniform flux horizontal well with wellbore storage and skin model and appropriate reservoir boundaries. The condensate drop effects in the production tests have been accounted for through changes in the values of the total skin effect. Finally, we used a compositional model to verify the results obtained from conventional well-test analysis.
It was found that condensate deposit near the wellbore yields a well-test composite behavior similar to what is found in vertical wells, but superimposed on horizontal-well behavior, which makes it much more complex.
Many studies (Fussel 1973; Barnum et al. 1995; Afidick et al. 1994) have reported significant losses of well deliverability in gas/condensate reservoirs because of condensate blockage. The level of productivity decline depends on several factors, including critical condensate saturation, relative permeabilities, non-Darcy flow, and high capillary number effects.
Retrograde condensation occurs when the flowing bottomhole pressure falls below the dewpoint pressure (Kniazeff and Naville 1965; Gringarten et al. 2000), creating three regions in the reservoir with different liquid saturations. Away from the well, an outer region has the initial liquid saturation; next, nearer the well, there is a rapid increase in liquid saturation and a decrease in the gas mobility. Liquid in that region is immobile. Closer to the well, an inner region is formed in which liquid saturation is higher than a critical condensate saturation and both the oil and gas phases are mobile. Finally, in the immediate vicinity of the well, there is a region with lower liquid saturation owing to capillary number effects, which represents the ratio of viscous to capillary forces. Such a region has been inferred from a number of experimental core studies at low interfacial tension and high flow rates (Henderson et al. 1998; Ali et al. 1997). The existence of the fourth region is important because it counters the reduction in productivity caused by liquid dropout.
The various mobility zones described above can be identified by well-test analysis using a variety of analytical and numerical models. Well-test analysis is commonly used to identify and quantify near-wellbore effects, reservoir behavior (i.e., zones of different mobilities and storativities), and reservoir boundaries. Finding all this information from well tests in gas condensate reservoirs, however, is challenging, because of changes in the composition of the original reservoir fluid and the impact of wellbore dynamics. Nonetheless, gas/condensate flow behavior is now reasonably well understood for vertical wells, in which the fluid flow toward the well can be modeled with a simple radial-flow geometry. A number of publications (Afidick et al. 1994; Daungkaew et al. 2002; Marhaendrajana et al. 1999; Saleh and Stewart 1992) have documented vertical well tests in gas/condensate reservoirs that exhibit regions of decreasing gas mobility near the wellbore and include an increased gas mobility region in the immediate vicinity of the wellbore (the fourth region mentioned above) (Gringarten et al. 2000; Daungkaew et al. 2002).
However, the situation is different in horizontal wells. The pressure drawdown is less than in vertical wells under the same conditions; therefore, liquid dropout in gas/condensate well tests is reduced, although it would still occur as the flowing bottomhole pressure drops below the dewpoint. Among the limited publications in this area, only the paper by Harisch et al. (2001) focuses on the multiphase effects on horizontal-well-test behavior. In that paper, the authors successfully history matched 1 year of production data obtained from permanent downhole gauges in a horizontal gas/condensate well. They used a numerical model that incorporated Coats' extended black-oil pressure/volume/ temperature (PVT) model (Coats 1985). A simulation with a dry gas, however, provided the same pressure responses for the same reservoir and horizontal-well parameters. The authors concluded that multiphase flow had no effects on their particular horizontal well test because the test was performed with drawdown pressures just below the dewpoint. The expected well test behavior when a horizontal well test is conducted with drawdown pressures significantly below the dewpoint was not addressed.
|File Size||4 MB||Number of Pages||14|
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