This paper wee presented et the SPE 198S California Regional Meeflng, held in Sekerefield, Callfomia, Mamh 27-S9, 1985. The materiel is eub@f to oorradon by the author. Permieekm to copy ie reefriofedto an ebafmcf of rsd more than S00 words. Write SPE, P.O. BOXSSS8S6, Richardson,Texae 750SSWS6. Telex: 7S0989 SPE DAL. In the late 60"s lkrlougher [4] advanced Mode 1ling of the pressure drop end heat loss eteam injection modelling greatly by emphasizing the importanceof pressure drop in the injection in steam injectionwells haa undergone a gradual string. Iiisinclusion of both static and fricevolution since the heavy intereet in enhanced oil tional preesure drop allowed him to make a recovery by steam injection in the mid-66's. After briefly reviewing the evolution of steam thorough anaiysis for a variety Gf car@~etiQQ geometries. Earlougher,however, recognized the models this paper preeente a model which advances the state-of-the-art of steam modeiling. significance of ignoring slippagebetween phases . . . -~+tiehn{ames became and polntea out that tihaa gov. ..-.---=---1 year J 3 _-. _--------.--
Summary This paper presents an analysis of the behavior of diesel-oil- based muds with an advanced thermal and hydraulic wellbore mathematical simulator. Recent diesel-oil-mud rheological correlations have been incorporated into the model to account for viscosity and density variations of oil mud with temperature and pressure. As rheological correlations are developed for other oil-based muds, such as mineral-oil-based muds, they can also be incorporated into the model. A specific deep-well application of the model illustrates the behavior of oil-based muds and shows the differences between water-based mud and oil-mud local fluid densities during drilling, circulating, and static conditions. Temperature and density profiles are presented for various operating conditions to show that modeling improves the understanding of oil-mud behavior downhole. Advantages and Disadvantages of Oil Muds Oil-based muds have become more widely used because of their distinct advantages over water-based muds. Boyd el al. list (1) thermal stability in deep, high-temperature wells, (2) increased lubricity in deviated offshore wells, and (3) hole stability in thick, water-sensitive shales as advantages of oil-based muds. The advantages of oil muds over water muds in drilling clay formations are discussed in detail by Holder. He attributes the hole stability achieved with oil muds to their restriction of the clays' natural tendency to imbibe water from water-based muds. With oil-based muds, even water emulsified in the continuous oil phase can be used to advantage by increasing the salinity of the water phase, thus driving water from the formation into the oil mud by osmotic forces. This further stabilizes and strengthens the borehole. The advantages discussed earlier have been documented by case studies that monitored reduced drilling times and mud costs with oil muds. Disadvantages of oil muds focus on the toxicity of certain aromatic compounds found in deisel-based muds. In offshore applications, tighter environmental regulations are forcing the transport of diesel-based oils to shore or the development of special cuttings-handling equipment. Toxic effects of diesel-oil mud and other oil muds are discussed in Refs. 4 and 5. Low-toxicity oil-based muds have been developed to avoid environmental problems with diesel-based muds. Details of the characteristics of these oils have been well-documented by Cowan and Brookery. Another disadvantage of oil-based muds is the higher incidence of lost circulation experienced by some operators when they use oil-based muds. Morita reported that in some cases lost-circulation problems were observed to be stopped once oil-based muds were replaced by water-based muds in the same well. Certain Drilling Engineering Assn. members are currently funding a research effort involving controlled laboratory tests of oil muds to investigate further the behavior of oil muds as related to lost circulation. Previous Oil-Based Mud Previous Oil-Based Mud Modeling Techniques Unlike water-based muds, oil-based muds show significant density dependence on temperature and pressure. Oil-based muds are compressible, and their densities can vary in proportion to the amount of solids, oil, and water in the oil/mud mixture. Sorelle et al. published equations describing a mud-density model for static-mud columns. Their work, based on curve fitting of laboratory data for Diesel No. 2, shows the importance of considering both temperature and pressure effects. Although density generally decreases with a temperature increase and increases with a pressure increase, the rates of change depend on the amount of water and solids in the oil/mud mixture. Hoberock et al. present results from a similar model for fluid columns in which density variations are compared at elevated temperatures and pressures for water, seawater, saturated salt water, and diesel pressures for water, seawater, saturated salt water, and diesel oil. This model has steady-state circulating temperatures and hydrostatic pressures and does not consider pressures caused by flowing fluids. The above-mentioned techniques for estimating downhole oil-mud densities are useful engineering tools. However, they are limited to density evaluation for static or steady-state mud columns with frictional pressure losses ignored. These conditions tell only a partial story about the behavior of oil muds. The real drilling problems occur while the mud is being circulated either to drill or to clean hole. These are the times when lost circulations and kicks are of most concern. The behavior of any drilling fluid under flowing conditions is a complex function of the sizes of the drillstring, return annulus, and bit nozzles, and of the flow rate. Related papers:SPE 13001, SPE 11356, SPE 13158 Related discussions and replies:SPE 15965, SPE 16445, SPE 16456, SPE 17012
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.
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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