BAKER HUGHES - Drilling Fluids Reference Manual

RESERVOIR APPLICATION FLUIDS
contains hydrocarbons. Cap rock also contains free sulfur. Free sulfur is present in cap rock of
almost all salt domes, but it appears in commercial quantities only in salt domes that have a thick
limestone cap.
FORMATION DAMAGE AND PROTECTION MECHANISMS
Introduction
The objective of a well completion or workover is to establish or re-establish unrestricted
communication between the wellbore and an oil or gas producing formation. Any restriction to
flow around the wellbore reduces the maximum flow potential and possibly the ultimate
hydrocarbon recovery. If the restriction is the result of formation porosity or permeability
impairment, it is called formation damage. Other factors that cause a reduction in flow rate into the
wellbore are turbulence, partial completion, partial formation penetration (i.e., not drilled deep
enough), and poor perforation practices. These are called pseudo-damage because they are not the
result of pore-size or permeability reduction. Discussion in this section is limited to factors that
cause formation damage and to measures that can be used to protect the formation from damage
during drilling, completion and workover operations.
Formation Damage Mechanisms
Formation damage may be the result of physical, chemical, or bacterial alteration of the producing
formation rock and/or in-situ fluids from contact either with whole fluids or with components of a
drilling and/or completion and workover fluid. The mechanisms of formation damage from
invading fluid generally include:
• plugging of pore spaces on the face of the formation by a mud-cake during drilling.
• dispersion of clays or other minerals contained in the rock matrix.
• water-blocking.
• narrowing of fine pore spaces (capillaries) through adsorption of water-soluble polymers.
• dislodgement of fine particulates contained within the pore spaces to lodge in pore throats.
• chemical precipitation of solution salts.
• emulsion formation.
• change in rock wettability.
• presence of sulfate-reducing or slime-producing bacteria and their precipitated byproducts.
• swelling of in-situ clays to fill pore spaces.
During drilling, the density of the drilling fluid is usually maintained to give a hydrostatic pressure
greater than the formation fluid pressure to prevent a possible well blow-out. Therefore, as new
formation is exposed by the drill bit, drilling fluid is forced into the formation by the positive
BAKER HUGHES DRILLING FLUIDS
REFERENCE MANUAL
REVISION 2006 6-16