Abstract

Since Cullender and Smith(1), surface pressures have been used to calculate bottomhole pressures on shallow, dry gas wells. If the original Cullender and Smith equations are modified to account for produced liquids, the correlation may be extended to gas/condensate wells that are single-phase in the well bore. Single-phase liquid wells (water injectors and oil wells above the bubble point) can also yield accurate well test results from the surface. Testing from the surface reduces the cost and eliminates the risk of running tools into well bores. Surface testing also allows the testing of high-pressure/high-temperature wells that cannot be tested with a downhole gauge because of harsh conditions. Thus, to reduce the cost and risk (or when no other option is available), many operators have chosen to run their pressure transient tests from the surface on single-phase wells.

Recently, it has become possible to test most naturally- unloading gas/condensate and oil wells from the surface. This is due to advances in multi-phase wellbore modeling along with improved pressure transducer quality. Of these, the most important advances are the improvements in transducer manufacture and calibration that make it possible for a surface pressure gauge to be effectively isolated from ambient and wellbore thermal transients. Although the technology exists to get representative reservoir data from the surface, testing procedures in multi-phase wells have to take into account the fluid's behavior in the well bore. With this in mind, the purpose of this paper is to propose guidelines for testing multi-phase wells from the surface. First, the general framework of the surface-to-bottomhole pressure calculation will be presented. Next, multi-phase wells will be categorized based on the type of fluid and the behavior of the fluid both in the reservoir and in the well bore. This categorization will be the basis for both surface testing candidate selection and recommended test procedures. Afterwards, wellbore phase and temperature modeling will be discussed. Next, instrumentation requirements will be presented. Finally, field data comparing calculated bottomhole pressures from surface gauges to measured bottomhole pressures from downhole gauges (and the subsequent analysis) will be presented for both a gas/condensate and an oil well.

These examples will be used to demonstrate that in order to test a multi-phase well from the surface, a thermally compensated quartz pressure gauge must be used in conjunction with a properly designed and executed test procedure. An explanation will also be provided as to why the best test that can be performed on a well to determine skin, permeability and the size of a reservoir is a constant-choke drawdown.

Wellhead to Bottomhole Pressure Calculations

In order to calculate the bottomhole pressure from the wellhead pressure, the following equation is used: (Note that kinetic energy is considered negligible and is not included.)

  • BHP = WHP + ?Pfriction + ?Pgravity

For a well that is shut-in, or for a low rate single-phase liquid well, this reduces to:

  • BHP = WHP + ?Pgravity

While these equations are relatively simple for single-phase fluids, they become quite complex when other phases are introduced. In fact these complexities make it almost impossible to get analyzable build-up data from the surface on oil wells that are below the bubble point in the reservoir. Producing wells may slug, have liquid hold-up, have a standing liquid column, or behave in other fashions that are difficult, if not impossible, to model.

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