Summary
High-pressure, low-permeability reservoirs have been encountered in various
parts of the world within the past few years. Commercial development of these
reservoirs may require operating wells with high drawdown pressures, possibly
in excess of 6,000 psi. The effects of drawdown pressures in this range are
increases in near-wellbore temperatures because of Joule-Thomson expansion of
the reservoir fluids and significant reductions in oil viscosity. The effects
of high drawdown pressures are evaluated with a transient, single-phase thermal
simulator in which the oil viscosity is modeled as both temperature and
pressure dependent and Joule-Thomson expansion and viscous dissipation effects
are considered. Results indicate near-wellbore temperature increases of 4 to
28°F for drawdowns between 2,000 to 10,000 psi because of Joule-Thomson
expansion of the reservoir oil and connate water. Furthermore, if oil viscosity
is not modeled as pressure dependent, skin values from well tests and
productivity indices will be underpredicted. Temperature profiles within the
formation are presented for a range of rates and drawdowns. Technical rationale
is also presented to explain the transient heating or cooling phenomena that
occur immediately after a rate change. Synthetic well tests are generated to
illustrate the effect of high drawdown on well test interpretation. These tests
show a region of improved mobility in the near-wellbore region because of the
reduction in the oil viscosity.
Introduction
Commercial production rates for deep, high-pressure and low-permeability
reservoirs may require high drawdowns. This is particularly true if stimulation
techniques such as hydraulic fracturing or acidizing are not feasible because
of technical limitations, operational constraints, or cost. Oil viscosity must
be modeled as a function of pressure and, to a lesser extent, temperature for
accurate productivity predictions and well test analysis. While the dependency
of oil viscosity on pressure and temperature is well established (McCain 1973),
applications to drawdowns in the range of 6,000 to 10,000 psi have rarely been
considered. The definition of drawdown considered in this study refers to the
difference between the pressure at the reservoir outer radius and the wellbore
flowing pressure. It does not refer to pressure gradients within the
near-wellbore region. Drawdowns of this magnitude constrained to the
near-wellbore region would certainly be catastrophic for either the completion
equipment or the formation.
© 2009. Society of Petroleum Engineers
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History
- Original manuscript received:
6 July 2008
- Meeting paper published:
21 September 2008
- Revised manuscript received:
11 March 2009
- Manuscript approved:
12 March 2009
- Published online:
5 November 2009
- Version of record:
12 March 2010
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