From the effect of global energy demands, the oil industry's search for new hydrocarbon accumulations has led to drilling of even deeper wells with high temperature and high pressure. Since high pressure fields contain relatively more hydrocarbons than the normally pressured fields. They make commercial targets even with technical difficulties in drilling and producing.

For example, drilling in challenging environments such as deserts and iced covered fields that involve high temperature, pressure (HTHP) and high level of sour gas (H2S and CO2). Drilling under such extreme conditions has become common practice over the past 15 years. , and new technologies are being developed to keep up with the need to drill safely and efficiently, minimize formation damage, and improve the production rate.


Figure1: HPHT fields. The number of HPHT wells is growing worldwide.

Drill under high temperature and high pressure

The general term "high temperature and high pressure drilling" has slightly varying definitions under different areas. Wells with undisturbed bottom hole temperature above 150 ℃ [302°F] are classed as high temperature. Those with wellhead pressure greater than 10000psi or a maximum anticipated downhole pore pressure exceeding a 0.8psi/ft hydrostatic gradient are considered high pressure. This condition can possibly cause wellbore instability, well control problems and ultimately loss of the well.

The drilling and development of HPHT reservoirs presents many challenges to the Industry and it is essential to continued research into and development of equipment suitable for use in this environment.

Among the challenges are:

  • The highly pressured reservoirs present unique challenges in well control.

  • The high temperatures require the development of downhole tools capable of operating in that environment.

Special logging tools

The high temperature in HPHT wells causes conventional logging tool electronics to fail. Extreme temperature and pressure are also known to affect tool sensor response. Conventional logging tool tools are upgraded to high temperature specifications by installing all sensitive electronic components in a 20,000 psi pressure-rated dewar flask housing, The dewar flask protect the electronic circuit from excessive borehole temperature.


Figure 2: Extreme tool string for ultra HPHT logging

New High Temperature Explosive

The figure below shows a new high temperature explosive, called HTX. This formulation overcomes performance disadvantages that exist with HNS or PYX. Today, HTX is replacing HNS and HMX as the most commonly used high-temperature explosive. HTX charges are rated at 500 °F for 1hr and have been tested to 440°F for 200 hrs continuous operations. It is long enough for most tubing-conveyed perforating operating.


Figure3: HTX versus HNS performance

Mud design

Under such extreme conditions, drilling fluids become unstable and causing well control problems, wellbore instability and ultimately loss of the well. The high temperatures also require special mud systems, since water based mud is typically unsuitable in that environment. This means the use of a synthetic or oil based mud is necessary.


Table 1 shows a synthetic-based drilling fluid used in the Qiongdongnan Basin, offshore China’s Hainan Island Province.


  • API Class G or Class H cements are performed for all high temperature cementing operations.

  • Weighting agents such as barite or hematite can be used

  • Cement slurry: High Density Performance Cement Slurry(HDHPS) is used

  • Use of high temperature retarder

  • Choice of mixing equipment: continuous mixing systems with a density accuracy of plus or minus 0.01g/cm3 (0.1ppg).

Tool string

The figure below shows the standard HPHT downhole testing string, rated to 15,000 psi differential pressure at 425°F, was used to test many deep, high profile wells in the North Sea, these tools are manufactured using H2S-rated materials.

Figure 4: standard HPHT downhole testing string

Drill in high level of sour gas wells

Sour gas is a term used to refer to gas which contains hydrogen sulfide in concentrations greater than four parts per million. H2S is a toxic gas. It can be a series threat to people’s life and environmental pollution. It is also considered as a corrosive gas which could cause severe corrosion damage to metal equipment and tools.

Furthermore, high-strength pipe becomes embrittled and damage immediately in the presence of H2S. When the pipe is in a stretched state or of stress concentration caused by the abnormal operations of Drill Pipe Slip, it is more likely to have brittle failure. For some gas wells of the high temperature and pressure, the H2S and CO2 in the formation are in a supercritical state which can induce serious blowout.

Major causes of blowout induced by supercitical H2S and CO2 during drilling

  • Owing to the penetration of supercritical H2S and CO2 leads to drilling fluid density decrease
  • The low viscosity and large diffusibility of supercritical H2S and CO2 cause blowout due to abrupt volumetric change of supercritical fluid.
  • High dissolubility for supercritical H2S and CO2.
  • The sudden volume expanding of H2S and CO2 during the transition of supercritical phase to normal atmospheric state.


Cementing high temperature deep sour gas wells present a number of challenges to well construction engineers. High temperature and pressure and long cement columns all contributes to the operational risks not only during placement of the cement slurry in the wellbore, but also during the life of the well. Sour gas such as H2S and CO2 bring additional challenges to deep well cementing. Since H2S reacts with metal hydroxide in cement and form metal sulfides, which could cause collapse of set cements. Gas migration is another consideration in cementing deep sour gas wells.

New cement slurry systems were developed to address the problems encountered in cementing deep sour gas wells. The innovative cement system includes feathers such as

  • Superior gas migration control

  • Predictable thickening time and right angle setting

  • Stable API properties at different slurry densities without chemical shrinkage

  • Great resistance to H2S, CO2 and salt corrosion


H2S caused severe damage to drillstrings and even failure in high strength drilling components. The environment can be controlled traditionally by maintaining a pH of water base drilling fluids above a certain level, use of H2S inhibitors or drilling H2S berating formations with oil base fluids in order to prevent sulfide stress cracking (SSC). However, in order to safely drill wells in more areas with high H2S concentration, sour service drill pipe was introduced for sour drilling. It was first manufactured in 1993. The pipe consisted of tubes with minimum yield strength of 95,000 psi that were resistant to SSC combined with standard API tool joints.


figure 5 : second-generation double should drill pipe

More recent work related to sour service drill pipe development has focused on higher strength material grades, tool joint metallurgy and welding technology with improved SSC resistance for high H2S concentration environment.