Formation damage from completion workover fluids

When completion or workover operations are conducted on a well (perforating, gravel packing, etc.), the fluid present in the wellbore must minimize the impact on the near-wellbore permeability. Several decades ago, engineers realized that the use of drilling fluids during completions was inappropriate because fluids caused severe damage to the productive zone. A wide variety of fluids are now available as completion or workover fluids. This page focuses on formation damage issues related to these different types of completion and workover fluids.

Types of completion and workover fluids

A list of fluids used for completion or workover is provided in Table 1.

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  Table 1

Reduction in permeability

Water based fluids usually consist primarily of clear brines. The only problem with clear brines is that they are not ever really clear.They always contain some solids, including:

• Corrosion products
• Bacteria
• Debris from the wellbore and surface tanks

The density of the brine is maintained large enough so that the bottomhole pressure exceeds the reservoir pressure by a safe margin (typically 300 to 600 psi). Substantial amounts of solids can be pushed into the formation, resulting in a loss of permeability in the near-wellbore region. Fig. 1 shows the loss in permeability observed when brines with differing quantities of solids are injected into a core. Rapid reductions in permeability are observed even with relatively clean fluids. Surface filtration facilities are often used to clarify and filter completion brines, which can help to reduce the permeability impairment substantially. Most of the high-density brines used can be quite expensive. Large volumes of fluid loss can add substantially to the cost of a completion operation. An important fact to keep in mind with completion and workover fluids is that, unlike drilling fluids, they do not contain drill solids. This means that there is no effective bridging material available to reduce fluid leakoff.

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  Fig. 1—Apparent permeability reduction in Cypress sandstone cores injected with treated and untreated bay water from offshore Louisiana.

When fluid-leakoff rates are very high, fluid-leakoff-control additives may be used to minimize leakoff and formation damage. Use of acid-soluble granular additives such as calcium carbonate is the most common strategy. If this method proves to be ineffective, viscosifying polymers are used to reduce the amount of fluid loss. Hydroxyethylcellulose (HEC) is commonly used because it is soluble in hydrochloric acid. HEC is a poor viscosifier at higher (> 250°F) temperatures, and unbroken and unhydrated HEC in the form of fisheyes can be damaging.

Polymer fluids suffer from similar drawbacks. Severe formation damage can occur if large amounts of polymer are lost to the formation. This problem is particularly acute if the polymer is not completely hydrolyzed in the brine.

If the density requirements of the completion fluid are relatively modest, emulsions can be used as completion fluids. In these instances, the droplets that form the dispersed phase act as a filtration-control agent. Both water and oil external emulsions have been used when reservoir pressures are low.

Oil based fluids such as crude oil and invert-emulsion muds can be used as completion fluids. It is important to ensure that the crude oil does not contain asphaltenes or paraffins that might precipitate under changes in pressure and temperature as the fluid is circulated into the well. Several authors provide a more detailed discussion of some of the issues summarized in this page. In addition, crude oil is flammable and messy to handle.

Noteworthy papers in OnePetro

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External links

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See also

Formation damage

Completion systems

PEH:Formation_Damage