BAKER HUGHES - Drilling Fluids Reference Manual

BOREHOLE PROBLEMS
• Elimination of casing strings
• An alternative option to expandable casing
Various studies have investigated wellbore strengthening with a view to preventing drilling fluid
losses. One method suggests using temperature changes to alter the stress state around the
wellbore. Drilling fluid heaters can be used to heat the circulating fluid and increase the nearwellbore
stresses, thereby giving a strengthening effect. However, this method might be difficult
to control and would not be suitable in wells with an already high bottom hole temperature. In an
alternative approach a method was developed to allow small fractures to form in the wellbore
wall, and to hold them open using bridging particles near the fracture opening. The bridge must
have a low permeability that can provide pressure isolation. Provided the induced fracture is
bridged at or close to the wellbore wall this method creates an increased hoop stress around the
wellbore, which is referred to as a “stress cage” effect. The aim is to be able to achieve this while
drilling by adding appropriate materials to the drilling fluid. Short fractures are best and so it is
necessary to arrest the fracture growth very quickly as the fracture starts to form. This means high
concentrations of bridging additives will be preferable. The additives need to be physically strong
enough to resist the closure stresses, and sized to bridge near the fracture mouth to produce a near
wellbore stress cage. Assuming an opening width of 1 mm, the particle size distribution of the
fluid would need to range from the colloidal clays up to values approaching 1 mm, to give a
smooth particle size distribution and produce a low permeability bridge.
In permeable rocks the particle bridge need not be perfect because fluid that passes through the
bridge will leak away from within the fracture into the rock matrix. Thus, there will be no
pressure build-up in the fracture and the fracture cannot propagate. Achieving a stress cage effect
in permeable rocks is straightforward. If the drilling fluid contains particles that are too small to
bridge near the fracture mouth, the fracture could still become sealed by the build-up of a filter
cake inside. Fracture gradients observed in sands are usually higher than predicted by theoretic
models, probably due to the presence of solids in the drilling fluid and the deposition of filter
cake.
In low permeability rocks such as shale the bridge will need to have an extremely low
permeability to prevent pressure transfer into the fracture and fracture propagation. “Ultra-low
fluid loss muds” with HPHT filtrates as low as 0.1 ml are thought be beneficial to wellbore
strengthening. The driving force for bridge formation across a shale fracture needs to be
considered carefully. The initial rush of fluid into the fracture when it forms will deposit the
bridging solids at the fracture mouth, but a pressure difference across the bridge is required to
hold it in place. Pressure decay into the shale matrix behind the bridge will be minimal especially
with oil-based drilling fluids, which have an added sealing action due to interfacial tension
(capillary pressure) effects. In water-based drilling fluids, there may be a slow pressure leak-off
into the shale, but the challenge would then be to produce water based drilling fluid with an ultralow
filtrate so that the bridge at the fracture mouth has a sufficiently low permeability.
• Laboratory studies and field experience have shown calcium carbonate and graphitic
blends (LC-LUBE) as one of the best ways to reduce mud losses into fractures.
• The fluid should contain a smooth/continuous range of particle sizes ranging from clay
size (around 1 micron) to the required bridging width.
• Ideal packing theory (the d ½ rule) is useful for selecting the optimum size distribution in
low density drilling fluids.
BAKER HUGHES DRILLING FLUIDS
REFERENCE MANUAL
REVISION 2006 7-33