A Cementing Temperature Simulator yo Improve Field Practice

Guillot, Frederic; Boisnault, J.M.; Hujeux, J.C.

doi:10.2118/25696-ms

Cited by 17 publications

(8 citation statements)

References 16 publications

Supporting

Mentioning

Contrasting

Order By: Relevance

“…Bittleston et al 25 used the method of empirical coefficients to modify the models, but the modified models had fewer considerations and were only applicable to a few blocks. Subsequently, after the development of Guillot et al, 26 the accuracy and applicability of the models have been improved, although these models are only applied to conventional cementing.…”

Section: Introductionmentioning

confidence: 99%

A wellbore fluid performance parameters–temperature–pressure coupling prediction model during the managed pressure cementing injection stage

Liu,

Li,

Yang

et al. 2023

Energy Science & Engineering

View full text Add to dashboard Cite

Managed pressure cementing (MPC) is a new technology based on managed pressure drilling, which has a greater advantage in facing narrow density window formations. However, the existing pressure prediction models during MPC injection stage consider fewer factors and have lower accuracy. To this end, combined with the characteristics of the injection stage, a predictive model of the distribution of annular fluid type was first proposed. Then, based on the experimental results, fluid density and rheology as a function of temperature and pressure were fitted. The governing equation of temperature‐pressure field was established. Eventually the fluid performance parameters–temperature–pressure coupling prediction model was developed in this paper. By comparing the predicted pump pressure with the measured pump pressure, the maximum relative error is not more than 10%. Using this model, the fluid type distribution, temperature field distribution, and pressure field distribution were investigated. The results indicated that the distribution of fluid types in the wellbore presented a complex variation, with up to 10 fluids in the casing and up to five fluids in the annulus. The trend of temperature field is complex, with three turning points. The larger the formation temperature gradient, the higher the fluid temperature in the annulus. The influence law of fluid heat conduction coefficient is reversed at 6750 m. Decreasing drilling fluid density will trigger gas channeling, while increasing drilling fluid density will increase the risk of fracturing formation, and safe operation can be realized by MPC. The variation of the static pressure in the casing is more complicated than in the annulus and the annular circulation pressure in the eccentric casing is smaller than that of the concentric casing, which is due to the smaller annular friction pressure. This study can provide a theoretical basis for the prediction of hydrodynamic parameters during the MPC injection stage.

show abstract

Section: Introductionmentioning

confidence: 99%

A wellbore fluid performance parameters–temperature–pressure coupling prediction model during the managed pressure cementing injection stage

Liu,

Li,

Yang

et al. 2023

Energy Science & Engineering

View full text Add to dashboard Cite

show abstract

“…For example, the most commonly used American Petroleum Institute (API) calculation method generally overestimates the BHCT value [4,5]. Over-prediction of temperature generally leads to over-dosing of retarders in cement slurry formulation design, which results in long cement slurry setting times [6,7].…”

Section: Introductionmentioning

confidence: 99%

Enhancing Environmental Protection in Oil and Gas Wells through Improved Prediction Method of Cement Slurry Temperature

Feng

et al. 2023

Energies

View full text Add to dashboard Cite

Accurate cement slurry temperature prediction is a prerequisite for improving cementing quality and ensuring wellbore integrity and sealing of oil and gas wells. It plays a crucial role in preventing “gas migration” and “sustained casing pressure” problems and reducing environmental pollution. The construction links before the start of cementing are neglected by the existing prediction methods, and thus, it is not reasonable to assume initial temperature conditions. In this paper, a two-dimensional transient temperature field model for cementing is developed and its reasonableness is verified. The distribution of wellbore and formation temperature fields at cementing beginning is calculated. In addition, the influence rules of several factors on the cement slurry circulation temperature are calculated and discussed. The results show that the initial temperature varies significantly and that each factor affects the fluid circulation temperature in different ways and to different degrees. If the circulating wash operation before cementing is considered, the temperature field decreases in the downhole section and increases in the uphole section compared to the assumption that the initial condition is the original formation temperature. By correcting the initial conditions, the accuracy of cement slurry circulation temperature prediction can be improved.

show abstract

“…Computer models specific to well cementing have been available for more than 20 years and have been shown to have reasonable accuracy in conventional wells 4 , deviated wells 5 , HTHP wells 6 , and deepwater wells 7,8,9 . Until recently, output from these simulators had been considered adequate for most cementing applications.…”

Section: Introductionmentioning

confidence: 99%

“…For drilling operations, modeling techniques are well developed and generally accepted. As the industry expanded to deepwater environments, additional work documented the cooling effects of the sea and validated modeling techniques that simulate those effects 4 . With the evolution of drilling environments to include combined deepwater and HTHP conditions, it became necessary to accurately predict temperature profiles during well operations to aid in the qualification of drilling tools, selection of fluids, and optimization of hydrate prevention.…”

Section: Introductionmentioning

confidence: 99%

Mathematical Temperature Simulators for Drilling Deepwater HT/HP Wells: Comparisons, Applications, and Limitations

Stiles

Trigg

2007

Proceedings of SPE/IADC Drilling Conference

View full text Add to dashboard Cite

TX 75083-3836 U.S.A., fax 1.972.952.9435. AbstractThe widespread application and acceptance of mathematical simulators to model wellbore temperatures during drilling operations has grown in recent years. The increasing complexity of today's wells makes these physics-based tools invaluable for such tasks as designing successful cementing operations, selecting elastomers for blowout preventers, and selecting proper downhole tools. Limited previous work has validated some of these models against measured well temperatures but no comparison among the results, applications, and limitations of the various models has been published.Part one of this paper presents a comparison of cementing temperature results from three models widely used by the industry today. The input parameters for this study were based upon a typical deepwater well in West Africa. While each of the simulators utilizes similar heat transfer models, the output from the models was found to differ significantly under certain well conditions. In some of the cases studied, differences among the simulated cementing temperatures were significant enough to warrant performance of risk analysis and implementation of risk mitigation measures.Part two of this paper presents the circulating temperature model and temperature surveillance program utilized to drill and test a deepwater high temperature high pressure (HTHP) well. The predictions from the model were used to evaluate design considerations such as the selection of blowout preventer (BOP) elastomers and qualification of downhole drilling and testing tools. The model aided in completion fluid selection to optimize hydrate prevention and influence flowing wellhead and surface temperatures. A comparison of modeled parameters and measured field data is included.In addition to the model results, the functionalities of each of the temperature simulators and how those functionalities may influence the results are discussed. A discussion on the applicability and limitation of the models to the deepwater conditions studied is included as well as recommendations for managing and mitigating the associated risk.

show abstract

A Cementing Temperature Simulator yo Improve Field Practice

Cited by 17 publications

References 16 publications

A wellbore fluid performance parameters–temperature–pressure coupling prediction model during the managed pressure cementing injection stage

A wellbore fluid performance parameters–temperature–pressure coupling prediction model during the managed pressure cementing injection stage

Enhancing Environmental Protection in Oil and Gas Wells through Improved Prediction Method of Cement Slurry Temperature

Mathematical Temperature Simulators for Drilling Deepwater HT/HP Wells: Comparisons, Applications, and Limitations

Contact Info

Product

Resources

About