Salt formations frequently lay over oil-bearing formations, which can be termed pre-salt if older than the salt or sub-salt if younger. Salts are plastic and mobile, so shifts in overburden pressure cause folding and migration of salt beds over time, hence the establishment of sub-salt formations. The formations below salt in the Gulf of Mexico are primarily sub-salt, while those offshore Brazil can be either sub-salt or pre-salt. The ionic make-up of salts can also vary by region. Salt beds in the Gulf of Mexico are primarily NaCl, while those in Brazil contain a wide variety of salts including MgCl2, which is more reactive. Salt formations may contain one or more of the following components:

  • Calcium – Calcite, Dolomite, Magnesite
  • Sulfate – Gypsum and Anhydrite
  • Sodium – Halite
  • Potassium – Sylvite and Carnalite

Drilling through salt requires the aqueous phase of a drilling fluid to be a brine with a salinity just under saturation. If fluid is too unsaturated, the salt will leach into the aqueous phase, changing fluid properties, and will washout the wellbore, increasing the chance of a poor cement job. If the brine is completely saturated the fluid the hole will be too gage. Some washout is necessary in order to run casing. Additionally, the plasticity of the salt may cause shifting, so mud weight must be close to overburden gradient or salt may shift into wellbore and stick pipe. When a salt is over-saturated, the excess salt settles out as a solid and adds to the solids’ effects on fluid rheologies.

Exiting salt formations presents a high risk. Termed rubble-zones, the formations immediately below the salt may be unstable due to the nature of the salt body being formed. The shape of the salt at the exit point may have created a trap that prevents water from exiting the sediments. This trap can create conditions of increasing pore pressure in the immediate area below the salt or a very fluid formation containing water and shale. The salt body is also lighter than normal sediments resulting in reduced overburden and lower fracture gradients than normally encountered at that depth.


Salt formations can be drilled with salt-tolerant water-based drilling fluids or with invert emulsion fluids, depending on the application. In a deepwater environment, shallow salt formations are can drilled using riserless pump and dump operations, and then displaced with the production zone drilling fluid prior to exiting the salt formation. Deeper salt zones, like that which lies over the Bakken, are often drilled with oil-based fluids, then displaced to the production zone fluid after exiting the salt. In riserless pump and dump operations, Newpark uses our salt-washout calculator to maintain a salt content just under saturated. In normal operations with system circulation, the drilling fluid self-saturates the brine phase resulting in gage hole.

Prior to drilling through salt, Newpark project managers work with the drilling engineers to develop a comprehensive salt-drilling and salt-exit strategies to avoid washout while drilling and minimize the risk of the rubble zone once you exit the salt layer. The strategies include fluid selection and “base of salt” hydraulics optimization. Fluid selection, which is based on cost, performance and environmental compliance, includes consideration of fluid density, fluid salinity and fluid rheology:

  • Density: Although salt has no real pore pressure to control by mud weight, the mud weight is used to maintain the wellbore integrity and reduce the creep rate. Density is also required for the possibility of hydrocarbon bearing inclusions. 
  • Salinity: Salinity is required to be at or near saturation to maintain an in gauge hole and minimize washouts.
  • Rheology: Acceptable rheological properties are required to suspend the excess salt before drilling to maintain the salinity once cut with sea water and sufficient residual viscosity after the cut back is required to suspend the salt cuttings.

Salt-Saturated Pump and Dump in the Santos Basin, Brazil: In the deepwater environment of the Santos Basin, a salt formation lies between the carbonate/anhydrite caprock and the production formation. The salt formation is often drilled riserless using a pump and dump strategy where high mud weight fluid is cut back with seawater. Rather than cut back high-density fluid, the operator chose to cut back a super-saltsaturated brine.

High Salinity, Low Activity Oil Mud Improves Performance in Near Salt Drilling: Formations near salt can have high interstitial salinity resulting in increased salinity requirement in the drilling fluid. There are a number of methods that can be used to estimate the required salinity/activity of the drilling fluid.