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The simulator also incorporates a genetic algorithm allowing a specified parameter; reservoir permeability, reservoir
pressure, rock temperature, gas to oil ratio (in the case of black oil) and water-cut to be determined automatically for
steady state flowing cases by matching the model to the measured DTS temperature. Reservoir pressures, gas composition, the well completion and reservoir properties are used to characterize the model.
The flow calculation employs a Darcy radial flow model for vertical/deviated wells and a Joshi12 version of the flow equation
if the well is horizontal. Near-wellbore skin is also included in the calculation and can usually be obtained from well test
data. The purpose of the reservoir model is to deliver the correct zone flow at the correct temperature to the thermal model
and respond to changes in flow from other reservoir intervals. This productivity index approach with direct input to the JouleThomson inflow temperature is applicable in almost all cases. Thermal Simulator Operation
To use the simulator for fractured gas wells, it is important to adjust the average “pseudo” zone permeability, accounting for
the fracture and matrix permeabilities. In the simulator, this requires to create the correct pressure drawdown as defined by
the difference between the flowing and shut-in pressures measured by a bottomhole pressure gauge. The surface flowing rate
is an input to the simulator and varying the zone “pseudo” permeabilities will adjust the individual zone flows, drawdown,
and inflow Joule-Thomson temperatures accordingly. After the correct Joule-Thomson inflow temperatures are obtained,
pseudo permeabilities are refined to match the measured flowing DTS temperature and the gas inflow distribution is
Shown in Fig 6 is the simulator output where the flow profile, flowing well temperature and Joule-Thomson inflow
temperatures result from three zones having the same “pseudo” permeability. The difference between the 12-hour transient
flowing temperature profile and the steady state (one year) temperature also illustrates the correct flowing time period must
be used in the simulator to obtain the correct temperature profile. In some cases, one or more reservoir zones might have a
lower reservoir pressure as a result of depletion and this will result in a smaller Joule-Thomson cooling effect for that zone,
as shown in Fig 7. The middle zone reservoir pressure has been decreased by 2.0 MPa and the “pseudo” permeability
increased to produce the same flow rate. Comparing Fig 8 and Fig 7 demonstrates it is possible to obtain a different inflow
distribution from the same temperature profile.
The above example demonstrates that is not possible to obtain a unique solution as proposed by other authors13 by
matching the shape of the temperature curve2,3 to generate an inflow profile. So how is a unique match achieved? Reservoir
depletion input is required to correctly represent the drawdown in...
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This note was uploaded on 02/04/2014 for the course PGE 312 taught by Professor Peters during the Spring '08 term at University of Texas at Austin.
- Spring '08