Challenging Fields: HPHT Basics

What is HPHT?

In the oil and gas industry, High Pressure High Temperature (HPHT) conditions are generally defined as pressures greater than 10,000 psi and/or temperatures greater than 300⁰F (150⁰C). The application of the “and” or “or” in the above definition can be dependent on the geographical region. In Norway for example, only one of the conditions of high pressure or temperature needs to be met for a well to be classified as HPHT while in the UK, both conditions have to be met (Shadravan and Amani 2012).

Some HPHT Fields

The following are examples of some HPHT fields around the world

• Thunder Horse, Gulf of Mexico (GoM)
• Kristin Field, Norway
• Jade Field, North Sea
• Erskine
• Tahiti, GoM
• Elgin
• Morvin, Norwegian Continental Shelf
• Jade Field, North Sea

HPHT Tier Classifications

Different companies have come up with tier classifications for categorising HPHT conditions. Whereas the pressure and temperature boundaries adopted may differ, three (3) Tiers are generally employed.

• Tier I – HPHT
• Tier 2 – Ultra-HPHT
• Tier 3 – Extreme HPHT

HPHT Tier Classifications (Baker Hughes & Schlumberger)

HPHT Challenges

The challenges in HPHT development can range from technological to regulatory, HSE and so on. The focus here will be on the technological aspects. In identifying some of these challenges, they will be grouped into drilling, cementing and completions challenges.

HPHT Drilling Challenges

1. Well Control:
• Typically narrow drilling window increases the risks of kicks, blowouts or formation fracture
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2. Drilling Fluid
• Mud rheology properties are affected by the high pressures and temperatures. This can impact the equivalent circulating density (ECD) and hole cleaning ability.
• Static and Dynamic barite sag
• Fluid loss
• Solubility of methane and H₂S in oil based mud (OBM)
• High density muds causing formation damage

Barite Sagging of drilling mud (Shadravan 2012)

3. Low Rate of Penetration (ROP)

• Typically 10% of the ROP in normal drilling conditions
• Breakdown of crystal structures in PDC bits
• Roller-cone bits unsuitable
• Reliability of MWD/LWD tools reduce at temperatures above 275⁰F

HPHT Cementing Challenges

• Physical and Chemical changes in cement due to the high temperatures and pressure
• Gas migration
• Strength retrogression at high temperatures
• Loss of zonal isolation caused by cement shrinking and stress changes due to downhole variations in temperature and pressure.
• Casing and formation expansion and contraction can cause cracking of already set cement

HPHT Completion Challenges

• Mechanical integrity of completions components due to hot produced fluids
• Limitations in density of completion fluids
• Corrosion of completion components at high temperatures and typically high flow rates
• Pressure and temperature limits of flow control equipment and electronics
• High compression loads and pipe movements at packers
• Thermal cycling and tubing stress
• Failure of packers and seal materials at high temperatures and pressures
• Performance of elastomers is reduced by the high temperatures
• Ignition and detonation of explosive charge for perforation becomes problematic at high temperature. Charges become unstable and may detonate prematurely.
• Battery temperature limits in intelligent wells
• Depletion-related sand failure

Suggested Reading

SPE-163376-MS - HPHT 101: What Every Engineer or Geoscientist Should Know about High Pressure HighTemperature Wells. Available on OnePetro

References

SHADRAVAN, A. and AMANI, M., 2012. HPHT 101: What Every Engineer or Geoscientist Should Know about High Pressure HighTemperature Wells. Society of Petroleum Engineers.


DEBRUIJN, G. et al., 2008. Hiph-pressure, High-Temperature Tecnologies. Oilfield Review ed. Schlumberger.


CUENCA, N., 2015. Challenges in HPHT Wells Available from: https://www.linkedin.com/pulse/challenges-hpht-wells-nicolas-cuenca [Accessed 29 June 2016]

Challenging Fields: Introduction To Deepwater Developments

Deep Water?

In the oil and gas world, the term deepwater can mean different things depending on the discipline. Geologists generally define deepwater with regards to the depositional environment (Slatt 2013). In drilling and well construction, water depths greater than 500m is generally considered as deepwater because the technology requirements above this depth changes (Cuviller et al. 2000). There have been other sub-classifications of deepwater referring to deepwater as depths between 500m and 2000m and Ultra-deep water as depths greater than 2000m.

Deepwater Potential

The potential of deeepwater reserves has been widely recognised. According to the International Energy Agency (IEA) (2013), it is believed that deepwater reserves harbour about a quarter or 300 billion boe of the remaining recoverable conventional oil in offshore fields. Table 1 shows the ultimate recoverable resources for the major producing deepwater regions.

Table 1 Deepwater Resources for Major Producing Deepwater Regions

Deepwater Reservoirs

Deepwater reservoirs are typically comprised of loose unconsolidated sands depending on age, depth of burial and lithology (Ostermeier 1995). Majority of these reservoirs are relatively young geologically and belong to class of formations known as turbidites (Total 2014). Due to their relatively young geological age, deepwater reservoirs generally have good porosities and can be prolific hydrocarbon producers. The nature of deposition of turbidites (Figure 1) results in layers of relatively uniform sands and hence good permeability (Research Triangle Energy Consortium 2010).

Figure 1 Formation of Turbidite Reservoirs (Total 2014)

Deepwater Challenges

These deepwater fields can be challenging in various regards, from the economics to the technological aspects, to HSE. Some of these challenges are highlighted below.

• They require large investments
• Large volumes of hydrocarbon producing at high rates are required to offset the large investments
• Early sand production due to the poorly consolidated nature of turbidite reservoirs
• Well Intervention is expensive due to high rig costs.
• Reservoir compaction can occur due to the poor consolidation as the reservoir is depleted.
• Observations and data acquisition have to be done remotely.
• The HSE risks are exacerbated due to remoteness from land.

References

CUVILLER, G. et al., 2000. Solving Deepwater Well-Construction Problems. Oilfield Review

INTERNATIONAL ENERGY AGENCY, 2013. Resources to Reserves. International Energy Agency.

NILSEN, T. et al., 2007. Atlas of deep-water outcrops: AAPG Studies in Geology 56.

OSTERMEIER, R.M., 1995. Deepwater Gulf of Mexico Turbidites - Compaction Effects on Porosity and Permeability.

RESEARCH TRIANGLE ENERGY CONSORTIUM, 2010. Deep water completions urgently need innovation. [online] North Carolina: Research Triangle Energy Consortium. Available from: http://rtec-rtp.org/2010/01/25/deep-water-completions-urgently-need-innovation

SLATT, R.M., 2013. Deepwater Deposits and Reservoirs-Chapter 11. Developments in Petroleum Science, 61, pp. 475-552

TOTAL, 2014. Understanding deepwater reservoirs. [online] Paris, France: Total. Available from: http://www.total.com/en/energies-expertise/oil-gas/exploration-production/strategic-sectors/deep-offshore/expertise/understanding-deepwater-reservoirs