A prominent area of concern related to drill-in and completion operations is
damage caused by polymer and/or brine filtrate invasion into the producing
formation. It is common knowledge within the petroleum industry that, in
overbalanced conditions, filtrate invasion into the pore spaces of a reservoir
is continuous as long as the drill-in fluid (DIF) and wellbore are in contact.
It is also commonly known that certain polymers and modified starch additives
tend to adsorb or to be retained by, and sometimes plug, the water-wet linings
of reservoir pores. Once this occurs, flow paths are restricted and
formation permeability is impaired. Despite the careful selection of
less-damaging polymeric viscosifiers and fluid loss agents, reduced mobility of
production fluids remains a problem. Depending on the compatibility of the
aqueous filtrate with the reservoir fluids, strong water/oil emulsions may be
formed and may also plug reservoir pores.
This paper presents credible laboratory data demonstrating the benefits of a
special surfactant molecule engineered to pass through a drill-in fluid filter
cake along with the other filtrate components to maximize wellbore
productivity. Functionally, this chemistry:
• Inhibits the adsorption of the drill-in and completion fluid polymers on
the in-situ surface areas of the reservoir.
• Reduces the water saturation level of the formation rock to increase flow
• Promotes compatibility between the brine filtrate and formation crude.
• Reduces the surface properties between filter-cake particles to enhance
the ease of wellbore cleanup during displacement and natural cake “liftoff”
during the onset of production.
Collectively, these benefits, when used to complement pre-established
drill-in fluid design criteria, further increase reservoir productivity in
openhole completion applications.
There are numerous factors influencing the degree of damage to producing
formations during the reservoir drill-in phase with water-based fluids.
During the past decade, the drilling fluids industry has made significant
progress in fluid designs to minimize reservoir damage. This has been
accomplished by customizing drill-in fluid formulations based on reservoir
characteristics (Argillier et al. 1999, Audibert et al. 1999, Sánchez et al.
2004). Most of the recent design work has centered on selecting specially sized
bridging materials that minimize spurt and total filtrate invasion rates
(Bailey et al. 1999). Each of these factors strongly influences the
quality and thickness of the internal filter cake, the thickness of the
external filter cake and the flow initiation pressure (FIP) in openhole
completions. In addition to optimizing filter-cake development, some
degree of emphasis has centered on selecting biopolymers and modified starches
that tend to be relatively nondamaging to production.
Collectively, these drill-in fluid design criteria, along with advancing
wellbore cleanup technology, have consistently led to higher production rates
in standalone screen, expandable screen, and gravel-pack applications. Also, in
injection wells, it may be necessary to perform a complete and uniform wellbore
cleanup to maximize water injectivity (Twynam et al. 2003). It has been
extensively shown that water-based fluids (WBM) do not affect or modify
reservoir wettability but can significantly reduce reservoir permeability
(Cuiec 1989, Sharma and Wunderlich 1985). Thus, one of the main formation
damage mechanisms that still needs to be prevented is the occurrence of
waterblock. This is the result of the invasion of an oil-bearing formation by a
water-based fluid which increases the near-wellbore water saturation. This
effect is elevated with the retention and adsorption phenomena of polymeric
additives that are not retained in the filter cake and can deeply invade the
reservoir (Argillier et al. 1999, Audibert et al. 1999). During the production
phase, when oil flows through this low-permeability zone, it may take a
considerable length of time before the filtrate is expelled. Components of the
fluid may even be retained and irreversibly plug the formation. Capillary
pressure and retention phenomena both oppose the displacement of the
water-based filtrate by the oil, inducing a permanent impairment.
Modification of the relative permeability has been observed and quantified
for all the main water-based formulations and strongly depends on the
viscosifier and fluid loss reducer characteristics, such as chemistry,
molecular weight, and polydispersity (Argillier et al. 1999, Audibert et al.
1999, Sánchez et al. 2004).
The objectives of the study presented were to design and select a special
surfactant molecule engineered to pass through a drill-in fluid filter cake,
along with the other filtrate components, to maximize wellbore productivity and
prevent formation damage with water-based fluids (i.e., completion fluids or
DIFs). The selection criteria were the following:
• The additive must be dispersible in a water-based fluid.
• The chemistry must be compatible with the different chemical components
used in the WBM such as the viscosifier, fluid loss reducer, and lubricant.
• The molecular weight of the molecule must be adapted so that the additive
easily passes through the external and internal filter cake. For this to occur,
the surfactant molecule must not be retained and/or adsorbed on the solids.
• During the drilling process, the concentration must be adjustable for
fluid losses within the drilled formation.
• It must not induce any emulsion (water-in-oil or oil-in-water) with
• Many cases of in-situ emulsification, resulting from the presence of polar
components in the crude, such as resins and asphaltenes, have been reported in
the literature. The design of a molecule that may act as a demulsifier of any
natural emulsification between the fluid filtrate and the reservoir fluids may
also help to increase production.
The surfactant discussed in this paper is identified as RA, for reservoir
activator. The relationships between the molecular structure of the RA
surfactant and its chemical properties were key factors in its selection.
Before its use in the field, RA was tested for toxicity and biodegradability
and has been assigned a GOLD rating using the CHARM classification model.
© 2006. Society of Petroleum Engineers
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- Original manuscript received:
21 June 2004
- Revised manuscript received:
13 July 2005
- Manuscript approved:
21 July 2005
- Version of record:
20 February 2006