Engineering Calculations of Gas-Condensate-Well Productivity
- Robert Mott (ECL Technology Ltd.)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- October 2003
- Document Type
- Journal Paper
- 298 - 306
- 2003. Society of Petroleum Engineers
- 4.1.9 Tanks and storage systems, 5.2 Reservoir Fluid Dynamics, 5.2.2 Fluid Modeling, Equations of State, 2 Well Completion, 5.6.8 Well Performance Monitoring, Inflow Performance, 3.3.6 Integrated Modeling, 1.8 Formation Damage, 4.2 Pipelines, Flowlines and Risers, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 5.8.8 Gas-condensate reservoirs, 4.3.4 Scale, 4.1.2 Separation and Treating, 5.5.8 History Matching, 5.5 Reservoir Simulation, 4.6 Natural Gas, 5.2.1 Phase Behavior and PVT Measurements, 5.1.5 Geologic Modeling, 1.2.3 Rock properties
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Accurate forecasting of gas-condensate-well productivity usually requires fine-grid numerical simulation to model the formation of the condensate bank and to account for high-velocity phenomena such as non-Darcy flow and changes in relative permeability at high capillary number.
This paper presents a new technique for forecasting the performance of gas-condensate wells, using simpler techniques that can be used in a spreadsheet. The calculation uses a material-balance model for reservoir depletion and a two-phase pseudopressure integral for well inflow performance. The pseudopressure-integral technique has been extended to include high-velocity effects and to allow for the change in produced-fluid composition caused by the formation of the condensate bank.
The new technique has been tested by comparison with the results of fine-grid compositional simulation, and the results are in good agreement for a wide range of cases covering vertical, horizontal, and hydraulically fractured wells.
The spreadsheet-model approach provides a useful tool for rapid forecasts of condensate-well performance, for examining the effects of condensate blockage in different well types, or for studying sensitivities. It is also valuable where simple models of condensate-reservoir performance are required for use in integrated studies involving issues such as surface facilities, drilling schedules, and gas sales contracts.
Well productivity is an important issue in the development of most low- and medium-permeability gas-condensate reservoirs. However, accurate forecasts of productivity can be difficult because of the need to understand and account for the complex processes that occur in the near-well region.
When the well pressure falls below the dewpoint, a region of high liquid saturation builds up around the well, impairing the flow of gas and reducing productivity. It is essential to take account o.this condensate-blockage effect when calculating well productivity.
Most of the drawdown to a condensate well occurs close to the wellbore, where gas velocities may be very high and the relationship between flow rate and pressure drop may be complicated by two additional phenomena - the increase in mobility at high capillary number1-4 (sometimes referred to as positive coupling or viscous stripping) and the non-Darcy (or inertial) flow.
In many gas-condensate wells, the net effect of the two high-velocity phenomena is to improve productivity, reducing the impairment caused by condensate blockage. The importance of high-velocity effects has been demonstrated by history matching results for a number of wells in which it was possible to obtain a satisfactory match only when high-velocity effects were included in the simulation model.5,6 It is important to include these high-velocity effects when simulating gas-condensate-well performance.
The most accurate way to calculate gas-condensate-well productivity is by fine-grid numerical simulation, either in single-well models with a fine grid near the well or in full-field models using local grid refinement. A fine-grid model will allow high-velocity effects to be modeled, and most commercial simulators now include options to account for non-Darcy flow and the increase in mobility at high capillary number.
While numerical simulation is suitable for detailed forecasting of reservoir behavior, there are many applications for which this level of modeling is not justified and simpler engineering calculations are more appropriate.
Simpler calculations are particularly useful to provide rapid forecasts of well deliverability, for sensitivity studies to assess the impact of parameters such as relative permeability or pressure/volume/temperature (PVT) properties, or to estimate the benefits of fractured or horizontal wells. They may also be more appropriate when accurate data on reservoir-fluid or -rock properties are not available.
Another application of a simple model is as part of an integrated study involving issues such as pipelines, surface facilities, drilling schedules, and gas sales contracts. This type of integrated model also can be used with decision risk management techniques to optimize development strategies, while taking account of uncertainties in reservoir data or financial parameters.7
This paper provides a method of forecasting gas-condensate-well performance by use of a material-balance model for reservoir depletion and a two-phase pseudopressure integral for well inflow performance. Fluid PVT properties are calculated from a modified black-oil model, in which properties such as oil/gas ratio (OGR) and formation volume factor are tabulated against pressure. Simulation studies have shown no significant difference between compositional-simulator results and those from a modified black-oil model for gas-condensate reservoirs under depletion,8,9 so a black-oil model is quite adequate for the engineering calculations in this work. Appendix A describes the material-balance model.
The well inflow-performance relationship (IPR) is based on the pseudopressure-integral method, which can take account of condensate blockage, including the impact of high-velocity effects. The well inflow calculation is discussed in detail in the following section.
The well IPR is used to calculate the maximum gas-production rate from the well at a particular value of average reservoir pressure. This rate is then adjusted to allow for any well or facilities limits, resulting in a table of gas rate vs. average reservoir pressure. The pressure intervals in this table are the same as those in the input table of PVT properties (typically at intervals of 200 to 500 psi). From this table, production profiles can be calculated giving oil- and gas-production rates as a function of time.
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