Summary
Individually, coiled tubing (CT), consolidating fluids, or pressure-pulsing
tools do not represent new technology. However, the combination of these
technologies offers a viable solution to the proppant flowback problem after
the proppant has been placed in the fracture. This paper presents the results
of laboratory studies and field case histories of a remedial treatment
technique through use of a low-viscosity consolidation fluid system that is
placed into the propped fractures by CT or jointed pipe coupled with a
pressure-pulsing tool. The treatment fluids are designed to provide
consolidation (for previously placed proppant) near the wellbore to glue the
proppant grains in place without damaging the permeability of the proppant
pack.
Laboratory flow testing indicates that the proppant pack in a fracture model
under closure stress only requires low-strength bonds between proppant grains
to withstand high production flow rates. The consolidation treatment transforms
the loosely packed proppant in the fractures and the formation sand close to
the wellbore into a cohesive, consolidated, yet highly permeable pack. Field
case histories are presented and the treatment procedures, precautions and
recommendations for implementing the treatment process are discussed. One major
advantage of this remedial treatment method is the ability to place the
treatment fluid into the propped fractures, regardless of the number of
perforation intervals and the length of the perforated intervals without
mechanical isolation between the intervals. The fluid-placement efficiency of
this process makes remediation economically feasible, especially in wells with
marginal reserves.
Introduction
The production rates of many fracture-stimulated wells in the world today
are curtailed because of sustained proppant flowback problems. In fact, many
wells are actually shut in because operators found them to be uneconomical to
produce at subsequently lowered production rates. Typically, production becomes
restricted, such as by perforations being covered with produced proppant. The
proppant produced during production often causes damage to downhole pumps and
to surface equipment. In addition, removing the proppant from the wellbore and
repairing the equipment often results in costly downtime for the wells.
Low production rates directly affect potential revenue for the operator.
Frequent workovers required for cleanup or sand removal, including shut-in
time, also factor into the revenue losses resulting from proppant flowback or
sand infill. However, the problem will return and the loss of revenue will
continue to stack up, unless a treatment can be found that will remediate the
problem at its source and not simply clean up the wellbore.
After an initial completion, it is often very difficult to conduct
cost-effective remedial treatments to treat proppant production problems.
Conventional remedial treatments are usually inadequate without some type of
mechanical isolation technique. Conventional methods with a good chance of
effective treatment usually either pose too high of a risk for subsequent well
problems or are too costly to consider for low-return reservoir conditions, or
both.
Consolidation fluid treatments have been applied remedially to treat
proppant flowback. However, a key problem with use of these materials has been
an inability to achieve uniform placement of the consolidation fluid treatment
into the propped fractures such that the entire perforated interval is
adequately treated. This problem is amplified by the presence of variable
permeability, perforation debris, formation damage in the near-wellbore region
and the high viscosity of many resin materials.
A system that attacks the problem at its source is a better approach to this
problem. By use of a system of precisely placed treatment fluids into propped
fractures conveyed by CT can turn many marginal wells into excellent producers
and do so cost effectively. The treatment chemicals introduced into the
formation form a consolidated, highly permeable pack that can withstand the
high drawdown associated with the production. This paper discusses such a
system.
© 2009. Society of Petroleum Engineers
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History
- Original manuscript received:
3 January 2007
- Meeting paper published:
28 February 2007
- Revised manuscript received:
17 April 2008
- Manuscript approved:
5 May 2008
- Published online:
2 March 2009
- Version of record:
26 February 2009
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