Drilling in depleted reservoirs, high-pressure/high-temperature (HP/HT) wells, and deepwater conditions presents narrow drilling margins between the pore pressure and the fracture pressure gradient. Currently, these challenging scenarios are commonly experienced in the field, and they will become an increasingly persistent phenomenon in the future as drilling continues into deeper plays.

When drilling through sand/shale sequences in deepwater operations, severe loss of drilling fluid is a typical problem that must be solved quickly. The operator may not only lose valuable drilling fluid, but can also accrue expensive non-productive time (NPT) in trying to arrest the losses. Once a lost circulation event occurs, it is recommended to apply the appropriate fluid solution as quickly as possible to help minimize NPT and maximize wellbore value. Using an engineering model to estimate large fracture widths, a major drilling fluids company has designed new equipment to simulate sizeable fractures, as well as design new materials, that have proven in the field to mitigate severe to total lost circulation in a variety of formations (e.g., depleted sand, fractured shale, and fractured limestone). The new equipment uses standard industry test procedures and is efficient in screening the best treatment system candidates for field validation. In this paper, the design model and laboratory results are reviewed for two new systems, along with field results from one application, which were proven to mitigate severe lost circulation events while drilling trouble zones.


During lost circulation, whole fluid flows partially or completely into areas of the formation commonly referred to as " thief zones." Although each fluid delivers a variety of specialized purposes, those most affected by the occurrence of lost circulation are the needs to maintain hydrostatic pressure in the annulus and prevent formation fluids from entering the wellbore. The consequences for failing to maintain this balance of wellbore pressure can range from strictly economic considerations to problematic operational issues. In the worst cases, loss of the well or even loss of life can result. The sources of whole fluid loss to the formation can be generally categorized according to the type of aperture through which it is lost.

  • Lost circulation to permeable formations can occur in any type of pervious thief zone when the solids in the fluid are not sufficiently fine to seal the formation face. Because of their highly permeable substrates and extensively porous networks, porous gravel and unconsolidated sands are the primary formation types in which fluid loss occurs. This type of loss can generally be identified by a slow and gradual reduction of the fluid level in the pits. If this source of lost circulation is not managed, it could eventually lead to a complete loss of returns. It is typical for these formations to be weak and susceptible to induced fractures. The rate of loss to this type of formation is strictly a function of the overbalance and the permeability of the formation.

  • Induced fracturing occurs when the wellbore pressure becomes high enough to split the surrounding formation apart. These induced fractures can form unintentionally when the equivalent circulating density (ECD) increases (i.e., fluid density increases, surge pressures while tripping, excessive cuttings loading from drilling too fast, etc.). Because of the sensitivity of the aperture to fluid pressure, both losses and gains can be observed when drilling weak formations that are sensitive to induced fractures.

  • Natural fractures can occur in any type of formation. If drilling is continued and more natural fractures are exposed, a complete loss of returns might be experienced.

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