BAKER HUGHES - Drilling Fluids Reference Manual

RESERVOIR APPLICATION FLUIDS
of surfactants in completion fluids to prevent emulsion formation between the working fluid and
the formation hydrocarbons may also change the characteristic wetting of the formation rock.
The natural tendency of water to wet polar surfaces contributes to another formation damage
mechanism called water-block. The significant force of attraction between water molecules and the
polar molecules at the surface of a solid is evidenced by the spontaneous rise of water in a glass
capillary tube. The height to which the liquid column rises is dependent on its density, surface
tension, and the radius of the capillary tube. The maximum height is reached when the hydrostatic
pressure of the liquid column equals that of the forces causing the liquid to rise. The hydrostatic
pressure is then equal to the capillary pressure. Mathematically:
2σ
(cosθ
)
gh L
ρ =
r
where,
g = the gravitational constant, ft/sec 2
h L = equilibrium height of the liquid, feet
ρ = the liquid density, lbm/gal
σ = the liquid surface tension, dynes/cm
θ = the contact angle between the immiscible liquid interface and the solid surface
r – radius of the capillary, inches
The term gh L ρ is the force driving the liquid into the capillary and is the mathematical description
of the capillary pressure. As is apparent from this relationship, the pressure required to remove
water from a water-wet formation pore is inversely proportional to the radius of the pore. Capillary
pressure promotes the displacement of oil by water but resists the displacement of water by oil. In
most reservoirs, native pressures are great enough to overcome capillary pressure. However, in low
pressure and tight, low permeability formations, the capillary pressures resisting displacement of
water by oil may be significant enough to cause permanent impairment. The problem of waterblock
is especially serious in the near-wellbore region, where the pressure drop of the oil/water
interface approaches zero. The probability of water-block increases as the volume of fluid lost to
the formation increases.
Another cause of capillary impairment is in-situ emulsification of in place oil with
completion/workover fluids. Even in the absence of commercial surfactants, concentrated salt
solutions have an inherent tendency to form mechanical emulsions with crude oil. Stable
mechanical emulsions are formed by mixing normally immiscible fluids at high shear rates. In-situ
emulsification is possible because, while the total volume of flow may be low, the rate of shear at
the constrictions in the flow channels and pore throats is high. Because the viscosity of oil/brine
emulsions is very high, their movement through the rock is severely restricted. As the emulsion
droplets become trapped in the capillary pore spaces, called an emulsion block, the effective
permeability of the formation rock is impaired.
Large, polar, water soluble polymers used for viscosity and filtration control may adsorb on the
rock matrix in pore spaces and thus reduce the flow channels available for hydrocarbon movement.
Removal of these polymers is difficult both because of the strong attraction and because the
polymers are not mutually soluble in water and hydrocarbons. The slime produced by sulfate
reducing bacteria is similar to water soluble polymers and has essentially the same effect on
permeability. Sulfate reducing bacteria are very resistant to hostile environments, such as salt
BAKER HUGHES DRILLING FLUIDS
REFERENCE MANUAL
REVISION 2006 6-19