BAKER HUGHES - Drilling Fluids Reference Manual

RESERVOIR APPLICATION FLUIDS
differential drilling fluid column pressure. Particles smaller than the formation pores are introduced
into the formation during mud spurt loss, but they rapidly bridge on the pore throats in the near
wellbore formation. Particles larger than the formation pores accumulate at the formation face,
initiating a mud cake build-up. The invasion of whole drilling fluid is stopped quickly by the mud
cake, and only filtrate is allowed to penetrate the formation.
Unless the formation is exceptionally permeable or fractured, the plugging of the formation by
drilling fluid solids is very near the wellbore and usually can be by-passed easily by perforating
after production casing is set. However, if the casing and formation are perforated in drilling fluid,
this formation face damage is transferred into the perforation channel and can become even more
difficult to remove than the mud cake on the face. Removal is complicated, because of the
tendency of the drilling fluid in the perforations to dehydrate and form a cement-like plug.
A second type of solids plugging can occur when fine drill solids or drilling fluid additives
penetrate the formation to depths beyond the near wellbore region. These solids migrate into an
ever increasing number of radial passageways. This increase is due to the radial flow geometry.
When the well is flowed during production, if the invading particles do not traverse the entry route
in reverse, they are likely to become lodged in narrow passageways and block further fluid flow.
The problem is exacerbated when unfiltered brine, such as a completion or workover fluid,
containing a low solids content is used as a working fluid. After reviewing other models proposed
to describe wellbore impairment by internal cake formation in the rock matrix, van Velzen and
Leerlooijer, in agreement with Maly, concluded that, for fluids with low solids content, the degree
of impairment depends on particle/pore-size ratio and inflow velocity. When inflow velocities are
greater than 3.94 inch/minute, the generally accepted “1/3 to 1/7 rule” applies. This rule states that
particles larger than one-third of the pore throat diameter will bridge at the pore opening on the
formation phase to form an external filter cake, while particles between one-third and one-seventh
of the pore throat diameter will invade the formation and be trapped to form an internal plug.
However, for low fluid flow velocities (i.e., < 0.8 inch/minute), a “1/3 to 1/7 rule” is probably more
applicable. It may be logically concluded from these references that it is better to have either a very
dirty or a very clean fluid in contact with the formation rock than a slightly dirty one.
Solids plugging also can occur from the swelling or migration of clays or non-clay minerals within
predominantly sandstone formations. Clay and other fine particles are held on the pore surfaces by
a variety of forces including, London, van der Waals, electrostatic, Born repulsion, hydrodynamic,
and gravitational. These particles can be mobilized when these forces are altered by fluid flow
and/or chemically incompatible fluids.
Montmorillonites and mixed-layer clays are typical examples of swelling clays. In the presence of
fresher water than that originally contained in the pore space, montmorillonites with a high content
of sodium can swell to many times their original volume. This swelling plugs pore openings and
reduces porosity and permeability. While smectites are the principal forms of swelling clays, illites
also can swell when they coexist with smectites.
Kaolinite has a platelet structure similar to smectites clays but exhibits little or no swelling
characteristics. This group of clays usually is attached loosely to the host rock and can be
mobilized by the infiltration of fluids with salinities below the critical salt concentration for
colloidally induced particle release or with flow rates high enough to exceed the critical shear stress
necessary to carry the fine particles away from the pore surfaces. Other clay or mineral types with
needle-like or regular crystalline shapes may be affected similarly by the chemistry of invading
fluids, whether they are the filtrate of drilling fluid or the whole fluid of completion and workover
brines. These mobilized fines then migrate until they are trapped at pore restrictions (the pore
BAKER HUGHES DRILLING FLUIDS
REFERENCE MANUAL
REVISION 2006 6-17