Summary
Environmental constraints and high costs, especially offshore, are making
conventional-well testing less and less feasible and accepted by the public
administration.
New options were thoroughly evaluated to find a viable alternative to
standard production tests for characterizing the well productivity without
surface production. An accurate investigation demonstrated that injection tests
could provide all the information needed to calculate the well productivity at
reasonably low costs and with a good degree of reliability.
On the basis of the results of laboratory and field pilot tests, it was
proved that injectivity tests could be applied successfully to a real sour-oil
field. Laboratory tests proved that brine could be a suitable injection fluid
because there were no compatibility problems with the oil and the reservoir
rock. It was verified that the interpretation of the pressure transients should
be referred to the falloff period rather than to the injection phase. The
formation permeability-thickness product (kh) could be identified
correctly from the pressure-derivative analysis only if multiphase flow was
assumed. The total skin value could also be obtained from the test
interpretation.
The total skin comprises two components: a mechanical component resulting
from permeability damage and a biphase component resulting from fluid
interaction in the reservoir. Except for a limited number of cases, the biphase
skin can be evaluated only with numerical well testing, provided that the fluid
relative permeability curves are available. It was also demonstrated that the
biphase component depends mainly on the injection rate but is independent of
the formation permeability.
Then, the well-known transient equation was applied to determine the well
productivity index (PI) based on the kh and the mechanical skin. PI
values calculated from injection tests compared satisfactorily with PI values
measured from six drillstem tests (DSTs) performed on appraisal wells.
Introduction
In the vast majority of situations associated with exploration activities,
there is no infrastructure and no equipment in place to collect the
hydrocarbons produced during well tests; thus, it is common practice to burn
the produced fluids. However, the demands (if not requirements) to reduce or
avoid hydrocarbon emissions and the restrictive environmental regulations in
place make conventional well testing less and less feasible for appraisal wells
(Levitan 2002; Hollaender et al. 2002). In addition, the general target of
reducing the time and cost of operations, especially for challenging oilfield
developments, requires evaluating whether conventional well testing is always
the optimal cost-effective option. Therefore, the potential value of
alternatives that might be used as a substitute to conventional well testing
needs to be investigated. It is likely that individually, these alternatives do
not fulfill all the targets of conventional tests; thus, a clear understanding
of the capabilities of each is necessary.
The work presented in this paper refers to a real, naturally fractured
reservoir with more than 200 development wells to be tested after final
completion. Standard production tests are not allowed by local regulations
because of the environmental concerns and the risks associated with the
presence of high percentages of H2S. Possible alternatives to
conventional well testing were investigated, with the principal goal being the
estimation of the productivity of the field’s main geological units (Pool 1,
Pool 2, and Pool 3).
© 2007. Society of Petroleum Engineers
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History
- Original manuscript received:
20 February 2006
- Meeting paper published:
12 June 2006
- Revised manuscript received:
8 January 2007
- Manuscript approved:
13 February 2007
- Version of record:
20 April 2007
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