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Drilling HP/HT wells

Revision as of 12:32, 5 September 2012 by Glenda Smith (Glendasmith) (talk | contribs) (→‎Drilling fluid considerations)
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High pressure/high temperature (HP/HT) wells are those where the undisturbed bottom hole temp at prospective reservoir depth or total depth is greater than 300°F or 150°C, and either the maximum anticipated pore pressure of any porous formation to be drilled through exceeds a hydrostatic gradient of 0.8 psi/ft, or a well requiring pressure control equipment with a rated working pressure in excess of 10000 psi. Drilling wells with these characteristics pose special challenges.

Drilling fluid considerations

Where possible, high temperature wells are drilled with oil-based fluids (OBFs) or synthetic-based fluids (SBFs), because of the thermal limitations of most water-based fluids (WBFs). Such limitations of WBFs include:

  • Temperature-induced gelation
  • High risk of CO2 contamination from the formation being drilled and/or from the degradation of organic mud additives
  • Increased solids sensitivity that is related to high temperatures

Historically, WBFs have relied on bentonite clay for both rheology and filtration control. When tested at temperatures ≥ 300°F under laboratory conditions, bentonite slurries begin to thermally flocculate. Under HP/HT conditions with significantly elevated temperatures, a traditional WBF such as the lignosulfonate system might thicken so much that it no longer is usable or requires drastic and costly dilution and conditioning.

The ability to maintain bentonite and other active solids in a deflocculated state is the key to obtaining acceptable rheological and fluid-loss properties for WBFs exposed to high temperatures.[1] Bentonite can be used in relatively low concentrations, if it is supplemented with a high-temperature, high-molecular-weight synthetic polymer for additional carrying capacity. This combination helps to make it possible to maintain 6% by weight of low-gravity solids and a particle-size-distribution (PSD) of these solids in an acceptable micron range. Adding polymeric deflocculant at depths where elevated temperatures are expected assists in rheology control.

An HP/HT viscometer typically is used to monitor the temperature stability of the drilling fluid, and to evaluate its rheological properties at up to 500°F and 20,000 psia. This test is especially useful for determining whether high-temperature flocculation occurs in water-based muds. The test results can be presented graphically by plotting the change in viscosity with respect to temperature over the heating and cooling cycle, which establishes a baseline for recognizing indicators of temperature instability.

There are a number of ways to minimize problems with temperature gelation, including:

  • Eliminating lignite and lignite derivatives from the WBF formulation
  • Lowering the bentonite concentration
  • Supplementing the high-temperature water-based system with synthetic polymers and copolymers

OBFs and SBFs are subject to temperature thinning. Surface density should be corrected on the basis of downhole pressure data from a PWD tool. Hydraulics-modeling software that accurately accounts for fluid compressibility and the effect of temperature can improve the performance of the SBF system by allowing more precise surface conditioning.


  1. Mason, W. and Gleason, D. 2003. System Designed for Deep, Hot Wells. American Oil and Gas Reporter 46 (8): 70.

See also

PEH:Drilling Fluids

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