Annular Pressure Buildup Research Articles

A New Prediction Model of Annular Pressure Buildup for Offshore Wells

Subsea wellheads and Christmas trees are commonly utilized in deepwater oil and gas development. However, the special structure of subsea wellheads makes it difficult to monitor casing–casing annular pressure buildup, which in turn poses a greater risk to the integrity of the wellbore. In order to analyze the effect of changes in the casing-free section and the sealed section on the variation in annulus volume, a new annular pressure buildup model of casing-cement sheath-formation deformation was established and verified according to the elastic deformation theory. Furthermore, the influence of casing deformation on annulus pressure buildup was analyzed. Results indicate that the error of annulus pressure buildup predicted by the multi-string mechanical model proposed in this paper that considers the deformation of the casing sealing section is approximately 13% lower than the one that does not consider this factor. This paper provides guidance for the design of casing strings in deepwater oil and gas wells, ensuring safe production.

Study on the phase state and temperature-pressure distribution of CO2 injection wellbore and its effect on tubing stress conditions

This study investigates the phenomena observed during CO₂ injection processing in wellbores, particularly the annular pressure buildup typically attributed to inadequate packer sealing. We propose that temperature, pressure, and phase changes during CO₂ injection induce equivalent stresses, leading to packer unsealing. A detailed CO₂ injection model was developed, incorporating temperature-pressure coupling and phase transitions using the state equation. The model evaluates the effects of injection temperature, pressure, and volume on CO₂ density, temperature, pressure, phase state, and velocity, and calculates the stress on the tubing at various depths. Validation against actual measurements showed errors of 1.43% for pressure and 0.66% for temperature, confirming the model's accuracy. Key findings reveal that injection temperature significantly affects CO₂ phase changes, while injection temperature and volume respectively impact stress at the wellhead and bottom. The model provides a robust tool for optimizing CO₂-EOR processes, confirming that changes in injection parameters can indeed cause packer unsealing, and its reliance on precise input data highlights the need for accurate field measurements.

Analysis of APB in vertical wells with evaporite layers: A 1D axisymmetric multilayer thermomechanical model

Temperature increases and creep in saline rocks can cause annular pressure buildup (APB), presenting a significant challenge in oil well operations, particularly in deep and ultra-deep pre-salt fields. This paper proposes a one-dimensional axisymmetric multilayer thermomechanical model that accounts for the influence of evaporite layers and thermomechanical effects on APB. We developed a finite element model that integrates heat transfer and thermomechanical interactions, utilizing a double deformation mechanism as a constitutive model to represent the viscous behavior of the rock formation. Additionally, this model enables the iterative calculation of fluid properties based on temperature and pressure conditions. To validate the model, we conducted case studies using widely adopted commercial finite element software. Its consistent results provide a deeper understanding of the pressure increases caused by the influence of saline rock and thermal effects, offering valuable insights into the safe and efficient operation of oil wells using a model with reduced computational complexity.

A coupled model of wellbore-formation thermal phenomena and salt creep in offshore wells

The present work proposes a mathematical framework for calculating heat transport and annular pressure buildup (APB) in petroleum wells, taking into account salt creep in uncemented annular segments. To achieve this, we propose a Laplace Transform-based semi-analytic method to calculate transient heat flow in the wellbore. To estimate wellbore closure due to creep, we developed a Finite Element Method (FEM) formulation to handle the three deformation components that affect salt displacement. In addition to the time-dependent creep deformation of the rock, the model initially considers the elastic deformation of the rock due to geomechanical loads and pressure changes in the exposed annulus. The model was compared against field data from a well that contained an 800-m long uncemented second annulus exposed to halite. Regarding APB, considering creep in the salt layer resulted in a 2.55-MPa increase (approximately 15%) in annulus pressure. The thermal expansion of the salt rock did not significantly affect APB but significantly increased the computational cost of the simulations.

Investigation of the hydraulic integrity of cement plug: Oilwell cementitious materials

The loss of hydraulic integrity in oil and gas wells due to the loss of cement sheath sealability can lead to environmental contamination, annular pressure build-up, and safety threats. In this study, we examine the hydraulic integrity of geopolymers an alternative to cement to be used in well cementing. The hydraulic integrity of geopolymer was compared to conventional API class G and Industrial expansive cement. Down-scaled test specimens representing cement-plug in casing were prepared and tested using an in-house experimental set-up that allows continuous curing and testing of the cementitious materials under undisturbed pressure and temperature conditions. The samples were cured at 90 °C and 172 bar for 7 days after which the hydraulic sealability of the specimens was examined by applying a pressure differential to one end of the specimen and observing the resulting fluid leakage rates on the other end. The leakage rates were then expressed in terms of permeability and microannuli aperture. By injecting nitrogen and water, it was possible to compare the effects of fluid type on the hydraulic sealability of cementitious materials. Lastly, we examined the hypothesis of a linear relationship between plug length and its hydraulic sealability. The results indicate that geopolymer and Industrial expansive cement have higher hydraulic sealability compared to API class G. Geopolymers also have sufficient hydraulic bond strength to perform as much as Industrial expansive cement. The fluid type used in testing does not play a critical role in the loss of hydraulic sealability of cementitious materials. The influence of cement plug length showed varying trends on the hydraulic sealability of the cementitious materials. The results presented in this work help us understand the sealing potential of cementitious materials and the need for standards for performing laboratory-scale hydraulic sealability tests. This can benefit the improvement of cement integrity tests and well abandonment operations.

An Integrated Modeling Approach for Vertical Gas Migration Along Leaking Wells Using a Compressible Two-Fluid Flow Model

Gas migration behind casings can occur in wells where the annular cement barrier fails to provide adequate zonal isolation. A direct consequence of gas migration is annular pressure build-up at wellhead, referred to as sustained casing pressure (SCP). Current mathematical models for analyzing SCP normally assume gas migration along the cemented interval to be single-phase steady-state Darcy flow in the absence of gravity and use a drift-flux model for two-phase transport through the mud column above the cement. By design, such models do not account for the possible simultaneous flow of gas and liquid along the annulus cement or the impact of liquid saturation within the cemented intervals on the surface pressure build-up. We introduce a general compressible two-fluid model which is solved over the entire well using a newly developed numerical scheme. The model is first validated against field observations and used for a parametric study. Next, detailed studies are performed, and the results demonstrate that the surface pressure build-up depends on the location of cement intervals with low permeability, and the significance of two-phase co-current or counter-current flow of liquid and gas occurs along cement barriers that have an initial liquid saturation. As the magnitude of the frictional pressure gradient associated with counter-current of liquid and gas can be comparable to the relevant hydrostatic pressure gradient, two-phase flow effects can significantly impact the interpretation of the wellhead pressure build-up.

A coupling prediction model of annular pressure build-up for deepwater oil and gas wells during transient-state testing

To accurately predict annular pressure build-up of deepwater high pressure-high temperature oil and gas wells during the transient-state testing, a coupling prediction model of trapped & untrapped annular pressure build-up is proposed. For the short-term process of gas well transient testing, a wellbore transient heat transfer model has been established. Then the improved coupling model of trapped & untrapped annular pressure build-up is established, which is not only novelly considering fluid thermodynamic properties (isobaric expansion coefficient and isothermal compression coefficient) under high pressure-high temperature conditions and annulus fluid mass changes of untrapped annulus, but also considering annulus volume changes. For precise coupling calculating the annular pressure build-up, the annulus is divided into infinitesimal grid cells along well depth. The impact of different considering factors, testing times, testing production rates, formation permeability and cement sheath sealing positions on the annular pressure build-up in the model is investigated. The results show that conventional models (high pressure-high temperature properties and mass changes of the fluid are not considered) will greatly overestimate the annular pressure build-up; as the testing time increases, the impact of untrapped annulus fluid mass changes on the annular pressure build-up will gradually take the dominant role; reasonably optimizing the setting of untrapped annulus open hole section in high permeability formations and increasing the distance between cement sheath and the upper casing shoe can effectively relieve the increasing annular pressure build-up. These findings can achieve accurate prediction of trapped and untrapped annular pressure build-up, and play an important role in guaranteeing the wellbore integrity and safety of deepwater oil and gas wells during transient-state testing.

Study on Casing Safety Evaluation in High-Temperature Wells with Annular Pressure Buildup

In high-temperature wells, annular pressure buildup (APB) caused by temperature increase is a widespread phenomenon in production, especially in offshore thermal recovery wells. It increases the load on the tubing and casing and consequently threatens the wellbore integrity. Hence, research on casing safety evaluation and APB management has great significance for field production. In this paper, the tubing and casing safety evaluation and APB limit determination methods are presented considering the effect of thermal stress and APB. Based on the case study of an offshore thermal recovery well, an APB-management chart and the recommended optimal range of APB are provided. Finally, an analysis of three commonly used mitigation methods is presented. The effect and the recommended parameters of these mitigation methods are further discussed. The research results show that the thermal stress and APB phenomena affect the stress distribution of the casing and may bring great danger to the wellbore integrity. Maintaining the APB in the safety range is necessary for field production. It is recommended that the annular pressure be kept below the critical value given in this paper. Injecting nitrogen in annulus A and installing rupture disks are both effective methods to improve casing safety. In the case study, the APB decrease percentage is more than 75% when nitrogen is injected in annulus A. However, the nitrogen pressure, the rupture pressure and the installation depth of the rupture disk need to be determined via casing safety evaluation. The effect of optimizing the steel grade and thickness of the tubing and casing is not significant. They can be used as assistance methods when other mitigation methods are adopted.

Predicting the annular pressure behavior during water injection in offshore wells with a transient, multiphysics model

Predicting the pressure behavior of annular fluids during production and injection operations in oil wells became a major research topic in the exploration of deep-water reservoirs. Although pseudo-steady-state models can predict annular pressure buildup in most production scenarios, more robust transient approaches are required in injection operations due to the short time scales involved. This paper presents a new transient thermo-structural model that calculates temperature and pressure profiles during a recycled saltwater injection operation in a well with three concentric annuli. The model was compared with field data acquired uninterruptedly for a seven-day period containing two consecutive well shutdowns. The maximum relative deviation between the numerical results and the field down-hole pressure was lower than 4%. Absolute down-hole temperature deviations were smaller than 5 °C. Furthermore, simulations based on a newly proposed dimensionless inter-annular pressure difference parameter facilitated identifying the risk of thermally-induced casing collapse due to contrasting rates of pressure change between neighboring annuli. The effectiveness of mitigating such risks using rupture disks was evaluated numerically, and the most favorable scenario consisted of rupture disks installed in the two casings connecting the three annuli.

Coupling effect of annular volume change and non-linear fluid thermal property on annular pressure buildup in multi-layer annuluses of deepwater well

Coupling effect of annular volume change and non-linear fluid thermal property on annular pressure buildup in multi-layer annuluses of deepwater well

Effect of previous sedimentation time in filtration rate for shear-thinning suspensions

In oil well drilling, the Annular Pressure Build-up (APB) phenomena may lead to several damages in the formation and, in some cases, the well losing. Open shoes are generally used to mitigate this phenomenon, in which some spaces are maintained opened under the wall coating, at the well bottom. After the fluid expansion and pressure raising, the confined fluid flows directly to the rock formation. The sedimentation of the weighting material in the drilling mud in confined annular regions provides a thicker cake which may clog the shoe, turning the mitigation process inefficient. This research aims to study the effect of previous sedimentation and temperature on the filtrate volume and the mud cake properties for shear-thinning suspensions. To study the particles settlement, the falling dynamics were monitored by an online microscope coupled in a sedimentation test apparatus. Filtration experiments with and without previous sedimentation were performed. It was possible to conclude from experimental data that, for non-Newtonian fluids, filtration and sedimentation rates are increased with previous sedimentation. The main responsible factor is the presence of agglomerated particles vertically chained, increasing the permeability of the sedimentation cake. The observed mechanics are favorable to the annular pressure relief.

Predicting thermal expansion pressure buildup in a deepwater oil well with an annulus partially filled with nitrogen

This article proposes a comprehensive multiphysics routine for calculating Annular Pressure Buildup (APB) in vertical oil wells. The routine couples three key aspects influencing the occurrence of APB: (i) the flow of heated hydrocarbons through the well production tubing, which is accounted for with a multi-component, two-phase hydrodynamic model, (ii) a radial, resistance-based thermal model, which determines the multi-modal heat transfer between the production tubing and the surrounding formation, and (iii) a mechanical model which, when coupled to the previous models, allows the calculation of the APB within each wellbore annulus. The developed routine was compared with actual temperature and pressure field data from a 4,700-m (15,420-ft) deep offshore well composed of three concentric annuli. The innermost annulus (Annulus 1) was partially filled with nitrogen to reduce the buildup of pressure due to thermal expansion. A good agreement is observed between the numerical predictions and the field measurements, which included pressure buildup data for the innermost annulus.

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.

Study on annular pressure buildup phenomenon in subsea wells considering the effect of cement

AbstractIn marine fossil energy production, annular pressure buildup (APB) caused by temperature increase is a widely concerned problem and needs to be solved urgently in subsea wells. To study and predict APB and avoid consequent safety accidents and economic losses, a novel model is proposed to predict APB considering the effect of cement. The model has a wider application range by considering the dynamic change of thermal properties and mass change of the annular fluid. Laboratory experiments were conducted to verify the accuracy of the proposed model. Then a case study and mitigation evaluation were conducted to make the further analysis. Research results show that cement has a significant effect on APB, ignoring the cement may bring potential danger. The height of cement affects APB differently when the top of cement (TOC) is above and below the previous casing shoes. Making the TOC below the previous casing shoe could provide a leakage surface for annular fluid. It is an effective method for APB mitigation but a balance needs to be struck between wellbore integrity and mitigation effect. Gas or foam injection is another effective method to mitigate APB. The necessary gas volume varies with the annular pressure and initial gas pressure and needs to be determined according to the actual condition, especially in deepwater wells.

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.

Seal Qualification and Single-Trip Lockdown Sleeve Reduce Risk

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 29943, “Seal Qualification and Single-Trip Lockdown Sleeve Reduce Risk Through Innovative and Advanced Technology,” by Scott Patrick Ellisor, Rodrigo Albani Queiroz, and Carlos Eduardo Martins Gaban, Dril-Quip, et al., prepared for the 2019 Offshore Technology Conference Brasil, Rio de Janeiro, 29-31 October. The paper has not been peer reviewed. Copyright 2019 Offshore Technology Conference. Reproduced by permission. Traditionally, a wellhead system requires a drilling lockdown sleeve (LDS) during drilling operations to ensure that the seal assembly is rigid and prevents dynamic movement. By eliminating the LDS, however, the operator will save multiple trips into the well. Because of a seal-assembly design outlined in the complete paper, development of a single-trip LDS was possible for wellhead systems requiring extremely high lockdown requirements, allowing the user to save trips required by legacy designs. New Subsea Challenges In high-pressure/high-temperature subsea wells, annular pressure buildup, caused by thermal expansion of fluid, endangers well integrity. This phenomenon is caused by the increase of pressure during the production phase, temperature differential during the drilling phase, and fluid parameters. This type of annuli pressure buildup causes uplift as high as 3,200,000 lbf. The number of times the system needs to be shut down could be as many as eight per year for a 25-year well life; the life of the field during the production phase, therefore, could see as many as 200 total cycles. Saving Rig Time by Implementing New Technologies The technologies presented in the complete paper are the single-trip LDS and the dynamic casing hanger seal assembly. The single-trip LDS is used if an extremely high lockdown capacity is required. When this LDS is used, the need to run a lead impression tool (LIT) before running the lockdown sleeve is eliminated. Thus, an extra tool on the rig floor is eliminated, as well as a trip into the well. By eliminating the LIT run, between 5 and 10 hours could be saved, depending on water depth. Similar to the way in which LDS saves operators both operating expense and capital expenditure, the dynamic casing hanger seal assembly does as well. The dynamic casing hanger seal assembly has a higher lockdown capacity than the industry-standard seal assembly, which allows this seal to be run downhole without installation of an LDS. Because of this design, running the casing hanger seal assembly could save between three and five trips into the well, reducing overall risk.

Assessing the hyperbolic trend in well response involving pressure, fluid and heat-flow rates

This paper explores the application of the Arps’ hyperbolic relation beyond the rate-decline analysis for reserves assessment in conventional reservoirs. Although intended for the late-time boundary-dominated flow, the hyperbolic approach appears to work well for both the transient temperature and -pressure responses to attain the equilibrium condition. Given the simplicity and ease of use, this approach should gain traction among practitioners.The temperature responses remain in a transient state in a typical shut-in period, given the slow nature of heat diffusion compared to its fluid counterpart. Also, in a complex reservoir geometry, pressure transients may take a substantial period to reach all the boundaries to convey the desired average-reservoir pressure. More importantly, the admixture of no-flow and constant-pressure boundaries in a reservoir flood environment virtually negates the application of the conventional analytical tools, unless rate-transient analysis or related methods can be applied in the reservoir-depletion stage.This paper attempts to provide credence to the proposed solution approach by way of using the simulated pressure-transient responses in various reservoir geometries, and temperature buildup and falloff responses obtained from field data. In both cases, we show that the Arps’ method, initially intended for analyzing rate decline in a boundary-dominated system, can be used for analyzing transient pressure and temperature responses for estimating their respective current conditions. Overall, we used several synthetic cases involving both oil and gas reservoirs. Field examples included gas leakage for annular pressure buildup, gas decline rate in a coalbed-methane reservoir, and studying temperature transients in a gas well.

Technology Focus: Completions (April 2020)

Technology Focus We must standardize our completion configuration for all our wells. We cannot wait 6 months to accumulate production data to use in optimizing treating parameters on future wells. Can you predict first-year oil production? Can you predict annular pressure buildup in your high-pressure/high-temperature well? Sound familiar? Today, completion optimization relies heavily on our experience with the last well, domain knowledge [subject-matter experts (SMEs)], or perhaps simple curve fitting using the data from multiple wells. All are time-honored methods but have fundamental limitations. As SMEs, humans can articulate the “what” but, when many variables are in play (e.g., unconventional completions), are frequently challenged in pinpointing the “whys.” Historical mathematical models are better but suffer from multiple assumptions about second- and third-order effects. While adequate in some cases, historical models are challenged when predicting outcomes in highly complex completions. Enter machine learning. Digitization, big data, artificial intelligence, analytics, machine learning (ML), and automation are mentioned frequently as solutions for today’s complex technical challenges. ML is particularly fascinating because numerical models are used that can learn and be trained to predict future outcomes accurately. The synopses in this feature show how ML can provide accurate prediction of annular pressure buildup, first-year oil production, and (in conjunction with novel casing accessories) the time and location of water breakthrough along a lateral wellbore. Digitization is a trend that will forever change how engineers and scientists tackle the most complex problems in our industry. ML can advance optimization in many complex completions significantly by delivering high-accuracy predictions. When ML is applied successfully, the numbers do not lie. Recommended additional reading at OnePetro: www.onepetro.org. SPE 196169 Subsurface-Driven Connectivity Descriptions in the Montney and the Duvernay Inform the Applicability of Single-Point vs. Multipoint Well Architectures by Ben Stephenson, Shell, et al. SPE 197968 Strategic Engineering Application for Long Lateral Wells by Ahmed Kiyoumi, Abu Dhabi National Oil Company, et al. SPE 196179 Evaluating Precision of Fluid/Casing Design for Annular Pressure Buildup Application Using Machine-Learning Tools by Sandeep D. Kulkarni, Indian Institute of Technology, et al.

Experimental Determination of Drilling Fluid Thermal Parameters When Calculating APB

Thermal parameters of the drilling fluid affect the prediction of annular pressure buildup (APB) and play an important role in the type selection of casing. The high-temperature and high-pressure PVT tester is used to measure the volume increment of the salt water, water-base drilling fluid, and oil-base drilling fluid. According to the equation of state, the thermal expansion coefficient and compressibility coefficient of annular fluid at different temperatures and pressures are obtained. The results show that the expansion coefficient and compressibility coefficient of the salt water and oil-base fluid are directly proportional to temperature and inversely proportional to pressure; the expansion coefficient of the water-base fluid is directly proportional to temperature, but the compressibility coefficient is inversely proportional to temperature; the expansion coefficient of the water-base drilling fluid is inversely proportional to the density of the drilling fluid, while the density has little effect on the compressibility coefficient of the water-base drilling fluid; the expansion coefficient of the oil-base drilling fluid with oil-water ratio of 8:2 tends to be stable for temperatures over 50°C, and the thermal expansion coefficient of the oil-base drilling fluid with oil-water ratio of 7:3 is stable for temperatures over 75°C. Determination of the drilling fluid thermal parameters provides a theoretical basis for the APB prediction and the type selection of casing.