TECHNOLOGY New correlations improve temperature predictions for cementing and squeezing

Mike Cowan
Shell Development Co.
Houston

Fred Sabins
Westport Technology Center International
Houston

New temperature correlations from the American Petroleum Institute (API) improve the accuracy of predicting temperatures for cementing operations in deep wells.

The previous correlations for shallow (

API Committee 10 on Well Cementing has released new cementing temperature data which were compiled during an 8-year study conducted by 13 cementing experts representing a cross section of the oil and gas industry.

The new temperature schedules are currently available from the API by request and will be published in mid-1996 in API Recommended Practice 10B, Recommended Practices for the Testing of Cementing Materials, 22nd edition.

These new schedules significantly affect thickening time calculations for wells deeper than 10,000 ft. In wells shallower than 10,000 ft, current temperature schedules will continue to apply even though the measured times for achieving bottom hole circulating temperature (BHCT) are now different. The new temperature schedules offer operators and service companies two major benefits:

• More accurate calculations for BHCT, even if BHCT was not measured during field operations

• Calculations that can help simulate actual downhole conditions, such as thickening time at well temperature and pressure, in the laboratory.

API temperature schedules are used by cementing job designers to help determine the amount of time required for the temperature of the pumped cement slurry to rise to well temperature at a given pressure.

The temperatures in these schedules can be used when well-specific temperature data were not collected during field operations. Whenever possible, it is always best to design a cementing job with temperature, pressure, and time to reach downhole conditions measured directly in the subject well. If this information is not available, then operators should refer to API well cementing schedules.

With the temperature and pressure data from the API schedules, the cement job designer can then determine the necessary amounts of additives to be mixed with the cement slurry to produce the desired properties downhole. The proper use of additives allows the cement slurry to remain pumpable only as long as is necessary to place the cement downhole. Once the cement is in place, its compressive strength development should be rapid to avoid any waste of valuable rig time.1-4

Background

API has gathered, correlated, and disseminated cementing temperature data for more than 50 years. The first published cementing temperature schedules were released in 1948 and a second edition in 1950. Both editions, known as API Code 32, contained well simulation test schedules generated for casing cementing at depths to 18,000 ft.

Temperatures in Code 32 were based on a correlation made from eight data points collected from wells along the U.S. Gulf of Mexico coast. Code 32 was replaced by API RP 10B in 1953. This specification included squeeze cementing well simulation test schedules for wells of depths to 16,000 ft.

Temperatures in the casing and squeeze cementing schedules received no further changes until the 19th edition of API RP 10B, January 1974, was published. From 1948 to 1974, a single temperature/depth correlation, or temperature gradient, was used for estimating temperatures for casing cementing well simulation test schedules. The following other significant changes were made to the cementing schedules from 1948 to 1977:

• In 1962, a casing cementing schedule for well depths to 20,000 ft and a squeeze cementing schedule for well depths to 18,000 ft were added.

• In 1965, squeeze cementing schedules were extended to applications of plugback cementing operations.

• In 1965, liner cementing schedules were issued.

• In 1971, hesitation squeeze cementing schedules were included, although classified as tentative, in the 17th edition of RP 10B.

• In 1974, new casing cementing well simulation schedules were issued. These schedules were initially classified as tentative and contained temperatures correlated on depth and geothermal temperature gradient. Temperatures for these schedules were greater at some depths than temperatures for previous casing cementing schedules.

• In 1977, temperatures for liner cementing well simulation test schedules were correlated on depth and geothermal temperature gradient.

Temperatures for squeeze cementing operations remained unchanged from the 1953 values, even though significant changes were made to other schedules.

In 1984, a group of 13 representatives from operating and service companies were asked to serve on an API task group to investigate a new set of temperature data and develop new squeeze cementing temperature schedules. Eventually, the scope of the assignment was expanded to include updating temperatures in the well simulation test schedules.

Temperature data acquisition

Fig. 1 (78261 bytes) shows the device used to collect all of the data used to develop temperature correlations for API well simulation cementing test schedules. Some improvements have been made to this tool, particularly because of advancements in electronics; however, the basic device and collection procedure were similar for all data sets collected between 1948 and 1991.1 2

Temperature data used to prepare correlations for well simulation test schedules were not collected during actual cementing operations. All of the data were measured by sensors deployed on the drillstring prior to running casing. The well bore was kept static, or fluid was not circulated, for an extended time period prior to the measurement of temperature. Not circulating the well bore fluids allowed the temperature in the well to return to very near or equal to the undisturbed geothermal temperature. This static temperature was recorded and used to calculate a temperature gradient for the well.

After the static temperature was measured, fluid circulation through the drillstring was resumed, and the well bore temperature typically decreased. Sufficient volume was circulated to allow the temperature during circulation to stabilize to a near-steady-state condition (Fig. 2)(24561 bytes). This minimum temperature was recorded and used as the circulating temperature of the well at sensor depth.

[FIG. 3](24266 bytes)

[FIG. 4](24094 bytes)

This measuring and recording procedure was generally followed for collection of all temperature data used by API for development of the well cementing test schedule temperature correlations. A step was added to this procedure during collection of the most recent temperature data set to gather data points that would help develop squeeze cementing temperature correlations. The following procedure was used to collect the most recent temperature data set:

• Install the temperature collection device on the drillstring, and run it into the well bore.

• Do not circulate well bore fluids for a period of time to allow the temperature sensor to measure and record the static temperature of the well bore prior to circulation. Record the elapsed time between the last circulation of well bore fluid and the time required for the temperature sensor to reach its total depth in the well bore.

The static temperature recorded was used to calculate the geothermal temperature gradient of the well.

• Restart fluid circulation, and circulate a volume of fluid equal to the volume contained by the drillstring. Stop circulation for a short period to allow the temperature sensor to measure and record the temperature.

The recorded temperature was used to develop squeeze cementing temperature correlations.

• Resume fluid circulation and record the temperature at specified time intervals.

The minimum temperature recorded was used to develop casing and liner cementing temperature correlations.

Eleven temperature data points were gathered to develop the first temperature correlations for well cementing operations in API Code 32. Eight of the eleven were used to develop the correlation. From 1969 to 1974, 102 data points were collected to develop updated correlations that incorporated geothermal gradient. Only 41 of the 102 data points were actually used to develop the correlation.

The task group's initial focus was to evaluate 175 data points collected with this procedure from 1980 to 1984.

Development of temperature correlations

Temperature correlations incorporating depth into API Code 32 and the changes made in 1974 were developed using a similar method. Temperature data vs. true vertical depth were plotted on linear coordinates. A line was then fitted to the data points. The line was drawn from surface through the maximum depth (18,000-20,000 ft).

For the 1974 temperature correlations, the data collected were separated into temperature gradient groups. A line was drawn through each of the curves plotted from group data points. The line represented the predicted temperature trend formed by the data.

After all curves were plotted and lines drawn through them, the results were overlaid to determine whether any of the lines intersected or crossed the lines of other temperature gradient groups. Adjustments were made to all curves to prevent intersection of the predicted temperature line among the various gradients.

The task group chose to use statistical (multivariate regression) methods to develop new correlations for casing and squeeze cementing temperature schedules. Data for static temperature, true vertical depth, temperature gradient, and squeeze or circulating temperature were used to develop mathematical equations to predict squeeze and casing cementing temperatures. The predicted temperatures from these correlations were significantly greater for well depths shallower than 10,000 ft and less for depths greater than 10,000 ft. This prediction raised many questions about the new data set and the methods used to develop the correlations.

The difference in methods used to develop the correlations (statistically generated curves versus hand-drawn curves) was the first point investigated. Several different equations were used to curve fit the data, and all produced the same trends.

The 1948 and 1969-74 data sets were reevaluated using the same statistical methods. Results from this reevaluation agreed with the task group's findings. Predicted temperatures of the statistically fit correlations were higher at depths shallower than approximately 10,000 ft and lower at depths greater than 10,000 ft than were the hand-drawn correlations of the same data.

Most of the data in the 1969-74 data set and the new data set investigated by the task group were for well depths greater than 10,000 ft. Fewer measurements were made at shallower depths because of the higher degree of confidence that exists in predicting temperatures at these depths. The task group concluded that more data were needed at depths shallower than 10,000 ft to enable more-accurate correlations for casing cementing simulation schedules.

New correlations

Data from the 1969-74 data set and the new data set for circulating temperatures were combined into a single data set. A subset containing 66 records was used to develop new casing cementing temperature correlations using statistical methods. All of the subset data records had static times greater than 24 hr.

Forty of the 66 subset records contained squeeze data. These 40 records were used to develop new squeeze cementing temperature correlations using statistical methods.

The correlations for casing cementing temperature developed from the subset data still predicted higher temperatures at depths shallower than approximately 10,000 ft. The task group felt that these higher temperatures were caused by the small amount of available data for shallow depths. They also recognized that existing temperature correlations for such shallow depths had been used successfully for at least 20 years. Therefore, the task group and the API Committee 10 on Well Cementing voted to modify the casing cementing temperature correlations for depths greater than 10,000 ft.

Table 1 (39896 bytes) compares casing cementing temperatures from API Specification 10, 5th edition, to those determined with the new correlation.

The new casing cementing temperature correlations use the previous (1974) temperatures for depths shallower than 10,000 ft and temperatures from the statistical correlations for depths greater than 10,000 ft. The new squeeze cementing temperature correlations are based on the correlations developed from the 40 data point subset using statistical methods.

These squeeze cementing temperature correlations are recommended for all depths (surface through the deepest depth shown on the squeeze schedules). Table 2 (31733 bytes) shows a summary of all the new temperatures recommended for casing and squeeze cementing in wells to 20,000 ft. Figs. 3 and 4 are examples of temperature vs. depth for the 1.3 F./100 ft and the 1.7 F./100 ft data, respectively, from Table 2.(31733 bytes)

Results

The new well cementing simulation test schedules represent the most extensive work on cementing test schedules performed to date. The major results of the task group's work include the following:

• Statistical methods were used to develop temperature correlations.

• An exhaustive review included all well cementing temperature data collected to date. The review included a comparison of temperature correlations for wells in which oil-based and water-based drilling fluids were circulated and attempted to include well bore geometry, flow rates, and fluid properties into the development of temperature correlations. Unfortunately, not enough data were available to develop meaningful correlations with these additional variables.

• New surveys of field operations for casing and squeeze cementing to evaluate pressures, heat-up rates, and pressure-up rates for simulation of cementing operations were performed.

• This task group's work was extensively documented, and all temperature data evaluated during the development of API cementing temperature correlations from 1948 to 1991 were compiled. This document is available through API.

• The new temperature correlations developed reflect the applicability of previous correlations to shallow cementing operations and improve the accuracy of predicted temperatures in deep wells.

• Temperature gradient was incorporated into squeeze cementing temperature correlations.

The accuracy of predicted cementing temperatures in the API cementing well simulation test schedules remains unknown. The schedules are not derived from data measured during actual cementing operations. These temperature predictions, however, correlated with depth and geothermal gradient, have been a useful tool to the industry for more than 50 years.

The changes made to the cementing temperature schedules are considered by the task group to be valuable improvements in predicted temperature for cementing operations. The correlations developed by using statistical methods and available data provide the least amount of error in predicting temperatures for well cementing. Further improvement in the data set could make these correlations even more valuable to the industry.

Future work

The oil industry needs more well cementing temperature data. The foremost need is for additional data in wells shallower than 10,000 ft with geothermal gradients between 0.8 F./100 ft and 2.0 F./100 ft. These additional data would greatly improve the current cementing temperature schedules.

Also, correlations for cementing temperatures in long or extended reach wells, where the measured depth is significantly more than the true vertical depth, are needed. Similarly, correlations for wells drilled offshore, particularly in water depths greater than 600 ft, need to be developed.

Acknowledgment

The authors would like to thank the following people, who served on the API task group on well cementing, for their data gathering and assistance: Robert Beirute (chairman 1984-89), Amoco Corp; David Bell, Dowell Schlumberger; John Burkhalter, Halliburton Energy Services; Wayne Cloud, Mobil Oil Research; K.M. Cowan (chairman 1989-91), Shell Development Co.; Craig Gardner, Chevron Corp.; Charles George, Halliburton Energy Services; Tom Griffin, Dowell Schlumberger; W.C. Jones, EG&G Chandler Engineering; Stuart Keller, Exxon Production Research; Franklin Kemp, Chevron Corp.; Art Tragesser, LaFarge Corp.; Jim Venditto, Halliburton Energy Services; and Hank Wedelich, Enertech Engineering.

References

1.Venditto, J.J., and George, C.R., "Better Wellbore Temperature Data Equals Better Cement Jobs," World Oil, February 1984.

2.Sykes, R.L., Stehle, D.E., and Venditto, J.J., "Temperature Data from Cement Interval Extremities Give Reduced WOC Time," Society of Petroleum Engineers paper 16210, SPE Production Operations Symposium, Oklahoma City, Mar. 8-10, 1987.

3.Kabinoff, K.B., Ekstrand, B.B., Shultz, S., Tilghman, S.E., and Fuller, D., "Determining Accurate Bottomhole Circulating Temperature for Optimum Cement Slurry Design," SPE paper 24048, SPE Western Regional Meeting, Bakersfield, Calif., Mar. 30-Apr. 1, 1992.

4.Tilghman, S.E., Benge, O.G., and George, C.R., "Temperature Data for Optimizing Cementing Operations," SPE paper 19939, SPE Drilling Engineering, Vol. 6, No. 2.

The Authors