Temperature of cement is an important factor in properly cementing deep well production liners, yet current methods of determining cement temperatures do not account for all variables. In this paper a computer model predicts temperatures of cement while pumping and while waiting on cement, compares computed and measured temperatures, defines the importance of certain cementing variables on temperatures, and provides an explanation of difficulties encountered while cementing liner tops.
Current API standards for cement thickening time tests of casing and liners correlate circulating temperature with two variables - well depth and geothermal gradient. It can be demonstrated that many other factors affect cementing temperatures. Among these are casing sizes, prior drilling history, circulation rates, mud and cement properties, and inlet temperatures. A computer program is used to predict circulating temperatures of mud in drill pipe, slurry placement temperatures, and temperatures during wait on cement. Actual circulating temperature field data from a well used to develop the API standards is compared to model predictions. The model is then used to predict temperatures with typical variations of the different factors. The results not only show which factors cause the most difference in cementing temperatures, but also show the significance of these effects compared to the API standards. Background The importance of temperature for design of cement slurries has been described in previous papers. In particular, Shell and Tragesser show the effects of as little as 20 degrees on pump time, thickening time, and compressive strength. Accurate knowledge of downhole circulating temperatures is even more critical in liner operations because of the need for an adequate seal at the top and bottom of the liner [2]. Circulating temperature measurements for 5 wells were published in 1941 [4) and formed the basis for cementing test schedules until the mid 1970's. The early schedules assumed a 1.5deg.F per 100 ft gradient and correlated circulating temperature with depth. During the 1970's, circulating temperature measurements were obtained in 78 wells. This formed the basis for the current API temperature schedules that correlate circulating temperature with two variables - depth and gradient [5). Figure 1 is a graph of the API circulating temperatures compared to some of the temperature measurements used to develop the schedules. The graph shows general agreement with the API correlation, although variations on the order of 20deg.F are not uncommon. In a more recent study, Venditto and George compared the API schedules to circulating temperature measurements in 52 wells. Figure 2 compares those measurements with the API schedules. Sixty percent of the wells agree with the API schedules within 10deg.F. Thirteen percent of the wells are greater than 20deg.F different than API. Two of the wells are 40deg.F cooler than API, and one well is 60deg.F cooler than API. The overall agreement with the API schedules supports the conclusion that depth and gradient are the two most important variables for correlating cementing temperatures. The combination of depth and gradient results in a bottomhole static temperature. The disagreement with the schedules for 13 percent of the wells indicates the need to consider other variables. This paper uses computer modeling techniques to identify variables other than depth and gradient that can account for these differences. COMPUTER MODEL FEATURES A number of papers describe calculation methods to predict circulating temperatures. The computer model used in this paper was originally developed in 1978 and has been continuously improved since that time. The formulation of the model is described briefly in these references and in detail in reference 18. For accurate prediction of cementing temperatures, the following model features are needed. The model must predict transient temperatures. Downhole temperature during cementing are changing rapidly due to changing flow conditions. P. 727^
This paper describes an advanced method to predict downhole temperatures during operations. Examples are presented that represent actual field cases and demonstrate the advantages of using the advanced method compared to conventional methods of estimating downhole temperatures.Two specific field cases are investigated in detail: Tubing movement during stimulation and well deliverability.In the stimulation case, comparison of the conventional and advanced methods indicates that 35% fewer packer seals are needed in the specific well studied, and the thermal loads magnify the casing stresses by 25-35%.The well deliverability predictions show that a smaller tubing size increases gas production for a constant surface pressure.The paper also presents the key engineering and computing features needed to aid engineers in evaluating and interpreting results predicted with the advanced method.Key variables are identified for the different applications.With the model, variables can be controlled to optimize performance of well components and well operations.
This paper describes the results of a three-year joint industry project to develop improved circulating temperature correlations for casing cementing, liner cementing, tieback cementing, and squeeze cementing. The correlations were developed from over 2,000 simulation cases with a wellbore thermal simulator and compared to field measurements. The correlations apply to offshore and deviated wells, and account for thermal disturbance of the drilling operations with both water base and oil base muds. The temperature correlations are designed so that they can be used at several levels of accuracy depending on the circulation parameter, a new dimensionless quantity formulated in terms of key operational variables. The simplest application uses estimates of the circulation parameter based on the API data used to compile the current API standards. The next level of accuracy determines the circulation parameter under the assumption of a default set of parameter under the assumption of a default set of well conditions that represent the thermal disturbance due to drilling. The highest level of accuracy is achieved by modifying the default drilling correlation to account for the actual drilling variables. Introduction In 1941, the API Committee on Standardization of Oil-Well Cements established a set of circulating temperature guidelines based on measured data from five gulf coast wells. This empirical correlation was presented as a function of depth for a constant static gradient of 1.5 F/100 ft. In the early 1970's, the API upgraded the correlation with field data from approximately 80 gulf coast wells by presenting the circulating temperature as a function presenting the circulating temperature as a function of both depth and static gradient. In an API technical paper on the enhanced correlations, Art Tragesser, Chairman, and Frank Shell, member, of the API Task Group noted that well temperatures depend on many variables besides depth and gradient. Tragesser and Shell state: "Certainly, varying well conditions such as depth, mud properties, circulation rates, hole sizes, pipe sizes and thermal status can affect circulating temperatures." In 1984, Venditto and George compared the API schedules to measurements from 52 additional wells. Only 60% of the wells agreed with the API schedules within 10 F. Twenty-six percent differed by 10–20 F, and 13% differed by more than 20 F. Drilling in different regions of the world, such as Alaska or the North Sea, presents different sets of drilling conditions. Deeper wells, highly deviated wells, and drilling with oil base systems present conditions where the API standards may not present conditions where the API standards may not apply. Measurements with downhole gages on drill pipe have shown that circulating temperatures can be pipe have shown that circulating temperatures can be off by as much as 50–100 F from the API guidelines. Results from wellbore thermal simulation demonstrate that flow rate, mud type, inlet temperature, and casing size can significantly affect bottomhole circulating temperatures. For liner tops and squeeze cementing, it has been recognized that the API charts need to be extended. In 1983, a joint industry project was launched to develop improved cementing temperature correlations. Nine companies participated in the project, including three North Sea operators. The project, including three North Sea operators. The project was divided into three phases. Phase 1 project was divided into three phases. Phase 1 compared measured data from 10 wells supplied by participants to predicted temperatures using a participants to predicted temperatures using a wellbore thermal simulator. Phase 2 quantified the differences in circulating temperatures due to different parameters. Results confirmed that while depth and static gradient are the two most important parameters, many other variables can significantly parameters, many other variables can significantly impact circulating temperatures, particularly for deeper wells. Phase 3 developed improved circulating temperature correlations with the wellbore simulator. P. 125
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