Method corrects API bottomhole circulating-temperature correlations

July 15, 2002
Critical for properly designing cement slurries, drilling engineers must accurately predict bottomhole circulating temperatures (BHCT) during drilling and completion of oil and gas wells.

Critical for properly designing cement slurries, drilling engineers must accurately predict bottomhole circulating temperatures (BHCT) during drilling and completion of oil and gas wells.

A new approach corrects the American Petroleum Institute's (API) current BHCT correlations for surface-formation temperature (SFT) variations.

The author suggests to the API Subcommittee 10 on well cements that it should not use a constant value for SFT to process field data for future revisions of BHCT correlations.

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Downhole temperature is an important factor affecting the thickening time of cement, rheological properties, compressive strength development, and set time.

The API Subcommittee 10 on well cements developed new temperature correlations to improve estimates of circulating temperatures for cementing.1-3

Using API's current BHCT correlation schedules for designing the thickening time of cement slurries, for a given depth, requires technicians to know the averaged static temperature gradient.

The current API test schedules assume the SFT to be 80° F. To calculate the static temperature gradient, therefore, operators must determine the static or undisturbed temperature profile of formations with reasonable accuracy.

The value of SFT-the undisturbed and essentially constant formation temperature at about 50-ft depth-of 80° F. is typical only for wells in the Southern US and some other regions.

For this reason, the API test schedules are inaccurate for determining values of BHCT for cementing in wells drilled in deep waters, in the tropics, or in arctic regions.

For example, the equivalent parameter of SFT for offshore wells is the temperature of sea-bottom sediments or the mud line, which is close to 40° F. In arctic areas, the value of SFT is well below water's freezing point.

Many operators have concluded that computer-temperature simulations, rather than the API schedules, provide better estimates of cementing temperatures.4-6

On this note, the author presents a novel concept-the API equivalent wellbore (API-EW)-and will show that API's current BHCT correlations will apply for any deep well and for any surface formation temperature values.

With the technique referred to as the API-EW method, an empirical formula and computer simulation results verify the suggested technique's applicability.

Empirical equation

A previous work had shown that the empirical Kutasov-Targhi equation could estimate the BHCT as a function of two independent variables: the static temperature gradient (G) and the bottomhole static or undisturbed temperature (Tfb).7

Equation 1 gives the relationship but should be used with caution for extrapolated values of Tfb and Γ, noting that API's current BHCT correlations apply for values of Γ ≤ 1.9° F./100 ft (see accompanying box).

Workers generated the equation based on 79 field measurements and from data collected in wells ranging from 5,520 to 23,670-ft deep. Its accuracy is 8.2° F. as estimated from the sum of squared residuals.

Equation 2 expresses values of Tfb as a function of SFT (To), which for land wells is the temperature of formations at 50-ft depth, and total vertical depth (H).

In practice, for deep wells, Equation 3 does not consider the 50-ft interval from surface to SFT (To). Equation 4 assumes that for offshore wells To is the mud-line or bottom-sediment temperature, about 40° F., and the water depth is Hw.

API-EW method

Workers considered field measurements from many deep wells to generate the API correlations for BHCT. To process field data, the staff of API Subcommittee 10 on well cements had used two variables: the averaged static temperature gradient and the vertical depth.

The need to assume a constant value of SFT presents a problem and forces the drilling engineer to estimate the static temperature gradient from Equation 5 to use the API schedules.

Differences between the relationships of Equations 3 and 4 and that of Equation 5 become apparent and reveal why significant deviations exist between the measured and predicted BHCT values.

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Table 1 compares the range of errors obtained with a simulator and with the new API method.6

Wells with To = 80° F. should have good agreement between measured and estimated values of BHCT from API correlations.

The author, therefore, suggests transforming a real wellbore to an API-equivalent wellbore.

For example consider a well with the following parameters:

•H = 20,000 ft
•Γ = 0.020° F./ft
•To = 60° F.

It follows that the 80° F. isotherm would be 1,000 ft or (80-60)/0.020.

The vertical depth of the API equivalent wellbore, H*, would be 19,000 ft or 20,000 ft less the 1,000 ft at To. Similarly for a well with To = 100° F., the vertical depth of the API-equivalent wellbore would be 21,000 ft or 20,000 ft plus 1,000 ft.

Equations 6 and 7 present the calculations for equivalent vertical depth, H*, for a land well. Equation 8 presents the calculation for an offshore well, where To is the mud-line temperature and G is the temperature gradient from the mud line to the total wellbore depth (Equation 9).

Examples

Several examples illustrate BHCT determination with the API-EW method.

Example 1 is for a land well with the following surface temperature, vertical depth, static temperature gradient, and bottomhole static temperature:

•To = 50° F.
•H = 20,000 ft
•Γ = 0.015 °F./ft
•Tfb = 350° F.

Equations 10 calculates the equivalent vertical depth at 18,000 ft. Using API's new calculations for BHCT yields 291° F, given H* of 18,000 ft and G of 0.015° F./ft.2

This is in good agreement with the value of 301° F. determined by Equation 11, noting that the equation's accuracy is 8.2° F.

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Example 2 presents calculations for an offshore well with 50° F. water surface temperature and mud-line temperature, To, of 35° F.

Other parameters of vertical depth, water depth, static temperature gradient, and bottomhole static temperature are as follows:

•To = 35° F.
•H = 20,000 ft
•Hw = 2,000 ft
•Γ = 0.015 °F./ft
•Tfb = 305° F.

Fig. 1 shows the static temperature profiles for the onshore and offshore wells of Examples 1 and 2.

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Equation 12 calculates the equivalent vertical depth of 15,000 ft. API's new calculations for BHCT yields 244° F. for H* of 15,000 ft and Γof 0.015° F./ft.2

This is in good agreement with 256° F. calculated in Equation 13.

Example 3 presents calculations for an offshore well with 76° F. water surface temperature and mud-line temperature, To, of 38° F.4

Other parameters of vertical depth, water depth, static temperature gradient, and bottomhole static temperature are as follows:

•To = 38° F.
•H = 10,125 ft
•Hw = 3,828 ft
•Γ = 0.015 °F./ft
•Tfb = 180° F.

Equations 14 and 15 calculate the static temperature gradient from the mud line to total well depth of 0.02255° F./ft and equivalent vertical depth of 4,434 ft.

New API correlations for these values, with extrapolation, yields a BHCT of 116° F.2 Table 2 shows the value to be in good agreement with computer simulation results. Since the H* depth of 4,434 ft is beyond the applicability of Equation 1, it was not used for comparison.

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Table 3 presents the results of Examples 4, 5, and 6, with the parameters for three wells taken from Reference 8.

One observes that the suggested API-EW method predicts the bottomhole circulating temperatures with a satisfactory accuracy. For the three cases, the average deviation from computer stimulation results is 11° F.

References

  1. API Spec 10, Specification for Materials and Testing for Well Cements, Washington, DC, Fifth Edition, July 1, 1990.
  2. Covan, M., and Sabins, F., "New correlations improve temperature predictions for cementing and squeezing," OGJ, Aug. 21, 1995, p. 53.
  3. API RP 10B, Recommended Practice for Testing Well Cements, Washington, DC, 22nd Edition, December 1997.
  4. Calvert, D.G., and Griffin, T.J., Jr., "Determination of Temperatures for Cementing in Wells Drilled in Deep Water," Paper No. SPE 39315, presented at the 1998 IADC/SPE Drilling Conference, Dallas, Mar. 3-6, 1998.
  5. Honore, R.S., Jr., Tarr, B.A., Howard, J.A., and Lang N.K., "Cementing Temperature Predictions Based on Both Downhole Measurements and Computer Predictions: a Case History," Paper No. SPE 25436, presented at the Production Operations Symposium, Oklahoma City, Mar. 21-23, 1993.
  6. Guillot, F., Boisnault, J.M., and Hujeux, J.C., "A Cementing Temperature Simulator to Improve Field Practice," Paper No. SPE 25696, presented at the 1993 SPE/ IADC Drilling Conference, Amsterdam, Feb. 23-25, 1993.
  7. Kutasov, I.M.. and Targhi, A.K., "Better deep-hole BHCT estimations Possible," OGJ, May 25, 1987, p. 71.
  8. Goodman, M.A., Mitchell, R.F., Wedelich, H., Galate, J.W., and Presson, D.M., "Improved Circulating Temperature Correlations for Cementing," Paper No. SPE 18029, presented at the SPE Annual Technical Conference and Exhibition, Houston, Oct. 2-5, 1988.

The author

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I. Kutasov is a senior research engineer for Pajarito Enterprises, Los Alamos, NM. Prior to his current position, he was a senior lecturer in the school of petroleum engineering at University of New South Wales, Sydney, and a graduate faculty member in the department of petroleum engineering and geosciences at Louisiana Tech University, Ruston. He also worked for Shell Development Co., Houston, as a senior research physicist. Kutasov holds an MS in physics from the Yakutsk State University and a PhD in physics from O. Schmidt Earth Physics Institute in Moscow. Kutasov is a member of SPE.