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Temperature-depth profiles

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Selection of appropriate completion equipment requires consideration of not just production operations, but other activities such as injection or treatment. Shutting-in the well also creates changes in temperature and pressure that need to be considered. This article discusses the temperature-depth profiles that occur under different modes of operation.

Modes of operation

There are four modes of operation that any given well might experience:

  • Shut-in
  • Producing (liquid, gas, or a combination)
  • Injecting (hot or cold liquids, or gases)
  • Treating (high, low, or intermediate pressures and volumes).

It is important that all planned operations be considered when designing the completion and selecting a packer. While the primary application may be oil or gas production, any subsequent operations (such as acidizing or fracturing the well) and their associated pressure and temperature changes are extremely important to packer utilization success.[1][2] 

Well temperature-depth profiles

Typical temperature vs. depth profiles are illustrated in Figs 1 through 4. These profiles are similar to those measures in wells operating in the shut-in, producing, injecting, or treating modes.

Fig. 1 depicts a typical geothermal gradient, with the temperature increasing with depth to that of the bottomhole temperature (BHT). Every time a well is shut in, the operating temperature will begin to move toward the shape of the natural geothermal profile.

Production well profiles

Producing-well-temperature profiles for both oil and gas wells are shown in Fig. 2. The wellhead temperature of an oil well will be somewhat less than the BHT. The amount of cooling as crude flows to the surface will depend on several factors:

  • The relative amounts of oil and water
  • The specific heats of oil and water
  • The flow rate, the gas/liquid ratio
  • The vertical-flow pressure drop that controls the gas liberated and the attendant cooling effect, and the thermal heat transfer rate from the wellbore.

The temperature profile of a gas well may have a wellhead temperature lower than ambient. In any case, the wellhead temperature of a gas well will depend on:

  • The BHT
  • The flow rate
  • The pressure drop in the tubing
  • The specific heat of the gas
  • Other factors.

Injection well profiles

Injection-temperature profiles can be quite varied (Fig. 3). The profile will depend on such factors as:

  • The nature of the injection fluid (liquid or gas)
  • The rate of injection
  • The injected-fluid temperature (cold or hot liquids or gas, or even steam).

Initial temperatures of injected fluids are also subject to seasonal changes. These changes can become more severe depending on the local geography and climate in which the operation is being performed. Injected liquids will tend to have little heat gain or loss as they are pumped down the tubing string, while injected gases will tend to pick up or lose heat to approach the BHT.

Treating well profiles

While treating is simply a special case of the injection mode and is temporary in nature, it is considered important enough to be discussed separately. As with the liquid-injection profile [for rates above 1 barrel per minute (BPM)], the treating liquid will not pick up any appreciable amount of heat as it moves down the tubing, and the treating temperature is essentially vertical (Fig. 4).

As illustrated in some examples later, the important thing about these profiles is not their shape but how much the shape and temperature change from one operation mode to another, and how those temperature changes affect the tubing and packer system. It is strongly recommended that anticipated temperature profiles for each operational mode be drawn accurately when planning the various steps of any completion or major workover.

Figs. 5 through 8 show the pressure profiles of the four modes of well operation. Fig. 5 illustrates a typical shut-in well with well-servicing fluid in the wellbore. The slope of the profile and the height to which the fluid level rises on the depth scale (and in the wellbore) will depend on the average reservoir pressure, PR, and the gradient of the well-servicing fluid. Fig. 6 shows the profiles of typical producing oil and gas wells. A liquid-injection profile (Fig. 7) is similar to the shut-in profile, the difference being that the bottomhole injection pressure, (pi)bh, is greater than the average reservoir pressure, PR. The wellhead pressure, pwh, can have any value, from a vacuum to several thousand psi. The gas-injection profile may have a reverse slope on it, or it may have a normal but steep slope, depending on the:

  • Rate
  • Tubing size
  • Bottomhole injection pressure.

Treating pressure

The treating pressure (Fig. 8) is a special temporary case of the injection profile. The bottomhole treating pressure, (pt)bh, often will be greater than the injection pressure, especially in a fracturing job. The surface pressure will be constrained by the burst strength of the tubing and casing and the safety considerations. The slope of the pressure profile will depend on:

  • The tubing size
  • The treating rates
  • The treating pressure downhole, (pt)bh.

It is recommended that pressure profiles for each operational mode be drawn for each step of the completion or major workover. The importance of pressure changes from one well mode to another and their effects on the tubing and packer system cannot be overemphasized.


  1. Eichmier, J.R., Ersoy, D., and Ramey, H.J. Jr. 1976. Wellbore Temperatures and Heat Losses During Production Operations. Paper presented at the CIM Soc. Meeting, Calgary, 6–7 May. CIM 7016.
  2. Arnold, R.B., Sandmeyer, D.J., and Eichmier, J.R. Production Problems of a High-Pressure, High-Temperature Reservoir. CIM 7232.

Noteworthy papers in OnePetro

External links

General references

Allen, T. and Roberts, A.P. 1993. Production Operations, fourth edition, I and II.

Factors and Conditions Which Cause Seal Assemblies Used in Downhole Enviornments to Get Stuck. Baker Oil Tools—Engineering Tech Data Paper No. CS007.

Patton, L.D. and Abbott, W.A. 1985. Well Completions and Workovers: The Systems Approach, second edition, 57–67. Dallas: Energy Publications.

See also


Completion systems