Summary
Verifying pressure integrity of a casing string and the adjacent formation
is an important requirement during drilling of a well. Crucial decisions on mud
weight, kick tolerance, and the setting depth of the next casing string are
based on the outcome of formation-strength tests (FSTs) such as leakoff tests
(LOTs) or formation-integrity tests (FITs). Moreover, government regulations
usually require that a minimum integrity is guaranteed before a well may be
deepened.
Yet the majority of FSTs and their interpretations currently carried out in
the field can only be characterized as inadequate. Commonly, FSTs lack quality
and accuracy because of insensitivity in the hydraulic system to subtle
pressure effects in the wellbore, use of highly compressible synthetic or oil
muds, nonlinear thermal profiles, poorly understood formation-stress and
-strength behavior, or simply because of poor data capturing (e.g., by using
hand-generated plots). This may have a significant negative impact on the
drilling operation. For instance, when mud-weight windows are assessed
incorrectly after testing, lost circulation or well-control problems may ensue
on wells with tight drilling margins.
Here, we highlight several of the problems underlying current FSTs and their
interpretations, illustrating them with actual field examples [such as the
discrepancy often observed between surface readings and downhole
pressure-while-drilling (PWD) readings obtained while testing], and show how
test artifacts can be either avoided or accounted for. A case is made for the
use of downhole recorded pressure data to determine casing-shoe strength
correctly.
Introduction
FSTs are carried out during the drilling phase of a well after a string of
casing has been cemented and before a new section of hole is drilled. In these
tests, the cement at the casing shoe is drilled out and a section of new hole
(typically 10–20 ft) is drilled, the blowout preventer (BOP) is closed around
the drillpipe (DP), and the well is pressured up slowly using mud. Testing
serves the following purposes:
1. To confirm the strength of the cement bond around the casing shoe and to
ensure that there is no open flow path to formations above the casing shoe or
to the previous annulus. If such a flow path exists, remediation of the casing
shoe (e.g., by cement squeeze) is necessary.
2. To investigate the capability of the wellbore to withstand additional
pressure (as dictated by the in-situ stresses and formation strength) below the
shoe in order to assess the competence of the well to handle an influx of
formation liquid or gas and to allow for proper well design with regard to the
safe drilling depth of the next hole section.
3. To collect data on formation strength and in-situ stresses that can be
used for wellbore-stability and lost-circulation prediction purposes, both for
the well being drilled currently and for future well designs (e.g., in a
multiwell development).
Proper planning, selection of a fit-for-purpose test method, and execution,
interpretation, and reporting of FST results are essential for such important
matters as picking appropriate casing points, maintaining zonal isolation,
establishing maximum allowable annular surface pressures (MAASPs) and kick
tolerances, maintaining well control, determining conditions for cuttings
reinjection (CRI), avoiding wellbore instability, and preventing exorbitant mud
losses. Specific regulations govern FSTs and associated follow-up on FST
outcomes in many parts of the world.
Many well engineers and field staff regard FSTs as well-established and
routine, with straightforward execution and interpretation. In our experience,
however, FSTs present many complications that are rarely accounted for in
actual field practice. Some of these complications are new and associated with
the introduction of new systems or practices [e.g., the widespread use of
synthetic-based muds (SBMs) in deepwater wells, with associated
mud-compressibility, thermal-expansion and gel -trength issues]. Others have
probably always been a part of FSTs but have not been accounted for properly,
such as the effects of temperature on fracture gradient and the location of the
cementing unit on pressure analysis. We discuss several of these complications
here and highlight ways to account for them or avoid them altogether. Our aim
here is to minimize the downside risks associated with faulty FST execution or
interpretation, which may give rise to serious operational problems.
© 2008. Society of Petroleum Engineers
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History
- Original manuscript received:
14 November 2006
- Meeting paper published:
20 February 2007
- Revised manuscript received:
13 November 2007
- Manuscript approved:
12 February 2008
- Version of record:
15 September 2008
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