HPHT Technology review

Testing the limits in extreme well conditions HPHT market heavily dominated by USA (80 %) & Thailand (20 %) API classification for HPHT is 15,000 psi pressure & 350 F temperature. Important document: “Protocol verification and validation of HPHT equipment” Washington,

DC: API Technical report , 1 ed, 2012This document covers primarily design standards related to design specifications of equipment, acceptable material & testing of well control equipment and completion hardware.

HPHT classification criteria:-well control rated equipment pressure greater than 15,000 psi-anticipated shut-in surface pressure in excess of 15,000 psi-flowing temp. at surface greater than 350 F

Schlumberger HPHT classification:

Two most common causes of electronic tool failure: corrosion and vibration MDT Forte tool for HPHT conditions.

Temperature rating: 177 deg CPressure rating 25,000 psi

GSPC discovery in KG Basin800 m of gas bearing sandstone at around 5,500 mtr.

HPHT well constructionPapers recommanded:

The institute of Petroleum: Well control during the drilling and Testing of high pressure offshore wells” (part 17)

SEDCO 407 HPHT manual, mallard development

HPHT Drilling fluid properties

Simulation of downhole temperature profiles at all phases of drilling operation is key to understand the behavior of HPHT drilling fluids.

Circulating fluid along the well gains or losses heat from it’s surroundings. The rate of heat exchange depends upon temperature, velocity of fluid, the thermal conductivity of formation, geothermal gradient in undisturbed reservoir , specific heat capacity of mud and other factors.

There is net transfer of heat from formation to the mud as it goes down the well. On the reaching bit, mud is still cooler than surrounding formation. The mud still continues to heat up as it returns to the surface until it reaches to a depth where formation temperature equals mud temperature. Above this depth, the mud cools on the it’s way to the surface.

The mudCADE Main Inputs are- specific heat capacity & thermal conductivity of each component Output- temp. of mud inside drillpipe, temp. of mud inside annulus

In theory, after circulation ceases it takes approximately 16 hours for mud temp. to approach within 10 % of the geothermal gradient, while circulating temp. can take over 6 hours to equilibrate.

Once details of temp. are known, the effective mud weight can be computed from the relationship between local density, pressure and temp.

COMPUTING DOWNHOLE FLUID PRESSUREStatic pressure-

PVT analysis of mud needs to be conducted. With temperature, viscosity and density changes in oil based mud.

by staring at surface where pressure and temperature are known, the local density of fluid can be computed. The predicted hydrostatic pressure and temperature permit the density at the next deeper level in well to be computed.

Dynamic pressure- dynamic pressure accounts for annular pressure losses, pipe velocity (surge and swab) and inertial pressure from string acceleration when tripping & excess pressure required to break thixotropic gels. Predicting the dynamic pressure contribution to the total pressure requires accurate mud rheology modeling. Depending on data, mud engineer selects appropriate rheological model on the basis of fitting curve to data from HPHT viscometer test.

Continuous model validation is needed. As same fluid w.r.t. can change it’s behavior. To predict accurate properties, one should keep on checking which rheological model is best suitable at that time.

Disadvantages – mask the gas kick as in oil base mud, gas is soluble and thermal expansion is higher compare to water based mud so lead to pressurization of annulus.