Summary
The Pinedale anticline of southwest Wyoming has proved technically
challenging to drill and cement. This tight gas reservoir has more than
5,000 ft of vertical-pay interval in stacked-lenticular sands. With pore
pressures ranging from normal to more than 16.5 lbm/gal, unplanned circulation
losses were negatively impacting drilling and cementing operations. In
early 2002, desired top of cement (TOC) was being achieved on only 31% of the
production casings. As a result, one of three things would
occur:
• Stimulation treatments would not go to the intended zones, resulting in no
production for completion dollars spent. As a result, petrophysical
evaluations of entire intervals were being questioned.
• Costly remediation treatments had to be conducted during completion
operations to isolate zones before they could be completed.
• Production reserves were at risk or deferred because of inadequate annular
isolation.
Completion engineers use fracturing applications to enhance well
performance, while drilling with drilling-induced fracturing is difficult to
manage. In both disciplines, knowing fracture and pore pressures is
critical. A process was developed to determine and calibrate pore
pressures and minimum horizontal stresses for the design of
hydraulic-fracturing treatments and production
prediction. Fracture-extension-pressure variation with depth was measured
on each well completion. Mechanical rock properties were measured in the
laboratory to validate calculations from openhole logs that were used in the
fracturing simulator. The data were validated further by post-matching the
simulator with fracturing-treatment data. The question was asked: “Why not use
these fracture data to prevent drilling-induced fracturing?”
Because of losses and wellbore-stability issues, completion data from offset
wells were incorporated into casing and mud programs. Underbalanced
drilling techniques were also introduced, which in turn, created obvious
problems for the cement design. Best practices were incorporated,
including foam cement, on a selective basis. As a result, cement tops are
now reaching the desired heights 100% of the time. Even in cases in which
there has been no circulation when the cement job is started, desired cement
tops have been achieved. As a result, costly remediation efforts have been
eliminated, saving an estimated U.S. $1.3 million/year. All the desired
pay intervals are being isolated so that the decision to complete reservoir
intervals is based on reservoir quality, rather than mechanical issues with the
wellbore. Production can now be attributed to given pay intervals with
confidence, aiding in proper evaluation of entire sections of the
reservoir.
© 2005. Society of Petroleum Engineers
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History
- Original manuscript received:
4 June 2004
- Revised manuscript received:
17 June 2005
- Manuscript approved:
17 July 2005
- Version of record:
15 September 2005
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