Thermodynamic Basis of Brine Density on Pressure, Temperature, and Chemical Composition in Ultrahigh Pressure/High Temperature Environments

Summary Temperature change and the pressure/volume/temperature (PVT) response of wellbore annular fluids are the primary variables that control annular pressure buildup in offshore wells. Though the physics of annular pressure buildup is well understood, there is some ambiguity in the PVT models of brines. While custom tests can be performed to determine the PVT response of brines, they are time-consuming and expensive. In this light, our paper presents a method to determine the density of brines from their chemical composition, as a function of pressure and temperature. It compares theoretical predictions with the results of tests on brines used in our industry and available test data from the oil and gas and other industries. In 1987, Kemp and Thomas used the principles of chemical thermodynamics to develop equations for the density of brines as a function of pressure and temperature and their electrolytic actions. However, their paper contained two (inadvertent, and probably typographical) errors. One of the errors lay in the set of the Debye-Hückel parameters, and the other was contained in the coefficients of the series expansion for the infinite dilution molal volume. Furthermore, they (inadvertently) did not mention the role of a crucial parameter that accounts for the interaction between the ionic constituents of the salt. As a result, nearly a generation of engineers in our industry has been unable to reproduce their valuable results or apply their technically rigorous results to other brine chemistries. In this paper, we return to the basic equations of chemical thermodynamics and the principles of stoichiometry and delineate the inadvertent errors that had crept into the Kemp and Thomas equations. We then present the rectified equations and reproduce their example with the corrected results. Further, we compare the predictions from the original Kemp and Thomas work with results from a leading chemical engineering model. Finally, we compare the results of theoretical models with test measurements from the laboratory and characterize the uncertainty inherent in each model. Thereby, we have rendered the Kemp and Thomas (1987) model useful to the well design community.

Evaluating Precision of Annular Pressure Buildup (APB) Estimation Using Machine-Learning Tools

Summary Annular pressure buildup (APB) is caused by heating of the trapped drilling fluids (during production), which may lead to burst/collapse of the casing or axial ballooning, especially in subsea high-pressure/high-temperature wells. The objective of this paper is to apply machine-learning (ML) tools to increase precision of the APB estimation, and thereby improve the fluid and casing design for APB mitigation in a given well. The APB estimation methods in literature involve theoretical and computational tools that accommodate two separate effects: volumetric expansion [pressure/volume/temperature (PVT) response] of the annulus drilling fluids and circumferential expansion (and corresponding mechanical equilibrium) of the well casings. In the present work, ML algorithms were used to accurately model “fluid density = f(T, P)” based on the experimental PVT data of a given fluid at a range of (T, P) conditions. Sensitivity analysis was performed to demonstrate improvement in precision of APB estimation (for different subsea well scenarios using different fluids) using the ML-basedmodels. This study demonstrates that, in several subsea scenarios, a relatively small error in the experimental fluid PVT data can lead to significant variation in APB estimation. The ML-based models for “density = f(T, P)” for the fluids ensure that the cumulative error during the modeling process is minimized. The use of certain ML-based density models was shown to improve the precision of APB estimation by several hundred psi. This advantage of the ML-based density models could be used to improve the safety factors for APB mitigation, and accordingly, the work may be used to better handle the APB issue in the subsea high-pressure/high-temperature wells.

Novel Experimental Method to Determine the Performance of Vacuum Insulated Tubing VIT for Deepwater Applications

Vacuum insulated tubing (VIT) is a specialized tubular designed to minimize heat loss from production or injection fluids to the environment in oil, gas and geothermal wells. VIT strings are used in deepwater wells for flow assurance or to mitigate annular pressure buildup. VIT use requires accurate knowledge of its insulating performance. Although VIT performance can be estimated from analytical tools, such as finite element analysis (FEA), an experimental approach provides a more direct measurement and can be used to validate analytical tools. We have developed a new experimental method to address this need. In this method, one or two VIT joints are placed in an ice-water bath. A precisely measured flow of heated air flows inside the VIT. The temperature change of the flowing air is measured between the inlet and outlet of the VIT test specimen. The insulating performance of the VIT is then calculated from this temperature difference using heat exchanger theory with effectiveness-number of transfer units (&#ξ03B5;-NTU) approach. A proportional-integral-derivative (PID) controller is used to control the air temperature at the VIT inlet by regulating power to the heater. This paper illustrates the data reduction method and uncertainty analysis using sample test data. The method allows for rapid measurement of VIT performance at many different temperatures, with the air flow rate being used to optimize the test sensitivity and to reduce experimental uncertainty. As currently designed, the apparatus is able to test single- and double-joint VITs with effective body conductivities between 0.002-0.1 W/m/°C (0.001-0.06 Btu/hr/ft/°F) and temperatures up to 400°C (750°F); however, the design allows the apparatus to be modified easily for higher or lower conductivities. Although designed for VIT, this method may be applied to other types of tubulars. Currently, there is no widely accepted standard method for experimental testing of VIT performance, and it is hoped that this new method may evolve to an industry standard.

Study on Annular Pressure Buildup in Offshore Heavy Oil Thermal Recovery Wells Considering Dissolved Gas Contained in Annuli

In the offshore industry, especially heavy oil thermal recovery wells, due to the great temperature difference between the low-temperature seawater and high-temperature heavy oil, it is easy to cause the temperature increase of annular fluid in the operation process which will result in the annular pressure buildup phenomenon (APB). The increase of annulus pressure may lead to the failure of the casing and wellbore integrity, which will seriously affect the normal production and lead to great economic loss. In order to study the formation of APB and provide a basis for the field operation design, a radial full-size physical experiment of APB was carried out in this work and an annular pressure prediction model in the presence of dissolved gas was proposed based on the experimental results. The verification and comparison analyses of the full-liquid model and the dissolved gas model were conducted with the experimental data. Furthermore, the sensitivity analysis of the influence of the dissolved gas volume fraction and casing deformation on APB was carried out. The results show that the prediction results calculated by the dissolved gas model are in good agreement with the experimental data and the prediction accuracy is higher than that of the full-liquid model. When the annular dissolved gas volume fraction is less than 0.1%, the full-liquid model can be used to simplify and approximate calculations. Ignoring casing deformation will produce prediction error in each annulus, which means this simplification should be used with extreme caution. This work provides a valuable experimental reference for the study of APB, as well as a novel model for APB prediction in the field.

Field Measurements Validate Transient Annular Pressure Buildup Model

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 199561, “Validation of Transient Annular Pressure Buildup (APB) Model Predictions With Field Measurements in an Offshore Well and Characterization of Uncertainty Bounds,” by Rahul Pai, Anamika Gupta, and Udaya B. Sathuvalli, Blade Energy Partners, et al., prepared for the 2020 IADC/SPE International Drilling Conference and Exhibition, Galveston, Texas, 3-5 March. The paper has not been peer reviewed. The average geothermal gradient in the subject deepwater field in Nigeria is 4.37°C/100 m, nearly twice the gradient in most fields. As a result, the magnitude of the expected annular pressure buildup (APB) during steady-state production is large enough to threaten well integrity. Therefore, an insulating packer fluid (IPF) was used in Annulus A to reduce heat transfer to the outer annuli and to regulate the APB within acceptable values. The complete paper reports the results of a study that compares the temperature and pressure measurements from these wells with model predictions. Introduction Though APB has been studied by well designers for decades, the use of downhole measurements to study APB has been somewhat limited. Previous uses of downhole instrumentation to study APB phenomena principally have centered on monitoring the magnitude of the APB and managing the risk. None, as far as the authors are aware, use the results gathered from downhole measurements to verify the results of the models that routinely are used in the design of the wellbore tubulars and APB-mitigation technologies. Notwithstanding the wealth of literature on the subject of APB, several crucial and fundamental questions remain unanswered. Chief among these are: What is the accuracy of thermal-model temperature predictions during various well operations? How do temperature uncertainties influence APB predictions? When APB magnitudes are large enough to require installation of APB mitigation devices? How do the mitigation devices perform over the life of the well? The complete paper seeks to address these questions through an examination of downhole pressure and temperature measurements and a parallel analysis of model predictions. Furthermore, field data and model predictions are juxtaposed, sources of uncertainties in the measurement data and model inputs are considered, and overall uncertainties in the APB predictions (i.e., model estimates) are characterized.