Annular Pressure Losses Research Articles

Development and Application of Drilling Intelligent Assistant Decision System

Abstract In order to systematically harness the substantial volume of data generated during the drilling process and achieve intelligent analysis and auxiliary decision-making for real-time risk monitoring and warnings during drilling, an intelligent drilling auxiliary decision-making system has been developed. This system integrates various technologies, including physical models, intelligent algorithms, and trend analysis. By analyzing the characteristics of logging data under different operating conditions, an intelligent algorithm capable of automatically distinguishing six types of drilling operating conditions has been established. Taking into account the impact of rock cuttings on the stress on the pipe string and annular pressure loss during the drilling process, coupled frictional torque and cyclic pressure loss calculation models were developed under coupled conditions. Building upon this foundation and considering the trend of deviation between predicted and measured parameters, a monitoring algorithm for detecting stuck drilling, wellbore leakage, and overflow incidents was formulated. The development of the drilling intelligent decision-making system was completed based on a C/S three-layer architecture and a data center. This system has been successfully applied in more than 50 exploration wells of various types, including shale oil and gas horizontal wells and deep wells. The static analysis results demonstrated a compliance rate of 91.5% with on-site monitoring, playing a crucial role in drilling parameter optimization and risk monitoring. The practicality and feasibility of the system have been verified, providing essential support for efficient and safe drilling production.

Recognizing the Most Accurate Herschel-Bulkley Fluid Pressure Estimation Method for Annulus: An Update to API RP 13D, 7th Edition

Summary The Herschel-Bulkley (HB) model is widely regarded as highly accurate for modeling non-Newtonian fluid flow, applicable across diverse fields such as chemical, mechanical, and petroleum engineering. The American Petroleum Institute and other references recognize the HB model as the most accurate and recommend the industry use it for drilling hydraulics. Pressure estimation models are beneficial for applying the HB model in field settings, as numerical solutions may not be feasible due to the computational demands and time constraints, especially challenging for high-frequency real-time pressure loss estimation (at least 1 Hz). Past literature has presented four estimation methods for the HB fluid, consisting of Zamora and Lord (1974), Merlo et al. (1995), Gjerstad and Time (2015), and the generalized method. However, the recommended practice API RP 13D (2023), “Rheology and Hydraulics of Oilwell Drilling Fluids,” has considered the most traditional Zamora and Lord (1974) as their chosen estimation method for industry use while neglecting to identify the most accurate model. Therefore, to update API RP 13D (2023), this work addresses this shortcoming by investigating the performance of different methods in estimating pressure losses while providing user-friendly, straightforward procedures applicable for field use. To recognize the most accurate estimation method for industry use, different methods’ pressure losses were estimated and compared with the numerical solution as well as experimental data to find the errors. The results showed that the Merlo et al. (1995) method provides the most accurate estimates, with the least average absolute percent error (APE) of maximum 4% underestimating the numerical solution, followed by Zamora and Lord’s error overestimating the numerical solution. The errors may slightly vary depending on the input parameters used, including diameters, mud properties, and circulation rate. The effect of the circulation rate on the accuracy of different methods was also investigated; except for the generalized method, the accuracy of the other methods increases with increasing the circulation rate. This work is a very innovative practical work for finding annular pressure losses accurately without using complex numerical solutions.

Open-hole extension limit of offshore extended-reach well considering formation collapse

The current extension limit prediction model for offshore extended-reach well (ERW) in mudstone does not consider the formation collapse, which poses a huge risk to offshore drilling construction. To address this problem, this paper presents new open-hole extension limit prediction model for ERW. By considering formation collapse, rate of penetration (ROP), and annular pressure loss, the extension limit models during normal drilling and tripping were derived. The sensitivity of geological and engineering factors was evaluated by analyzing limits for wells 1H and 2H. The research results showed that: (1) The extension limit increases with the ROP and formation collapse duration, but decreases with the increase in mud weight, plastic viscosity, and flow rate. (2) In ERWs, the mud flow rate has a significant impact on the extension limit than the plastic viscosity of mud fluid. However, mud weight has the least impact compared to the two. (3) Considering various parameters, the predicted extension limit of well 1H, when the mud weight is 1.16 g/cm3 [9.67 ppg], is 1593.28 m [5225.96 ft] less than the limit when the collapse period is not considered.

Forced convective rate and pressure drop through a packed annulus: a numerical simulation

Porous materials are used in engineering and industry due to their heat transmission qualities. This study examined forced convection flow through an annular tube packed with sphere balls of various materials and sizes using numerical analysis. The sphere balls were permeable. Ceramic, plastic, and steel with spherical diameters of 3, 5, and 6 and porosity of 0.4 were tested for heat dissipated and fluid flow. Also, test the impact of steel balls of diameter 6mm with 0.6 and 0.8 porosity. The numerical simulation results are used to analyze the forced convection and fluid flow parameters of a three-dimensional annular tube with continuous heat flux in the Reynold number range (5000-14000). Steel balls had an 80% higher heat transfer coefficient than annular tubes without porous mediums. The simulation showed that inserting the porous media increased annular tube pressure loss. The maximum heat transfer coefficient improved by about 80% when the spherical diameter is 3 mm. Also, the result illustrated the heat transfer coefficient of steel balls Increased by about 79%, 69%, and 49%, with 0.4, 0.6, and 0.8 respectively

MODELLING OF DEEP WELL CEMENTING PROCESS

The research aims to simulate Managed Pressure Cementing (MPC) for a deepwater field, focusing on optimizing the cementing process to ensure structural integrity and wellbore stability. The study addresses the challenges associated with conventional cementing methods, providing insights into the pressure dynamics, fluid properties, and pump performance crucial for deep well cementing operations. The methodology involves conducting a simulation to model the cementing process for a deep well with a total length of 9144 meters, where the previous casing's shoe is located at a depth of 6096 meters. Real data is utilized to obtain profiles of reservoir pressure, hydraulic fracturing pressure, and viscosities of essential fluids, including cement, drilling fluid, and buffer fluid. The simulation considers factors such as annular pressure loss, Equivalent Circulating Density (ECD) calculation, and pump performance under varying conditions. Additionally, the density of the cement slurry in the annulus during pumping is established. The study reveals that pump performance under the given conditions is 57 m³/h for drilling and buffer fluids, while for cement solutions, it can vary from 19 m³/h to 38 m³/h. These results offer actionable insights for operational planning and optimization of the cementing process in deep wells. The simulation successfully models the cementing process for a deep well, providing valuable data on equivalent circulation density and cement slurry density in the annulus. The determined pump performance under different conditions is critical for understanding the dynamics of fluid circulation during cementing operations. Practical implications of the research include the optimization of cementing processes, contributing to enhanced structural integrity, reduced wellbore instability, and improved efficiency in deepwater field operations. In conclusion, the study not only contributes to theoretical understanding but also provides practical data for optimizing the cementing process in deep wells, reflecting the industry's commitment to continuous improvement in drilling technologies and ensuring the reliability and efficiency of wellbore operations in challenging environments. Keywords: managed pressure drilling (MPD), wellbore stability, downhole conditions, real-time monitoring, managed pressure cementing (MPC), zonal isolation.

A new real-time hole cleaning monitoring method based on downhole multi-point pressure measurement and data driven approach

During the construction of long horizontal wells and extended reach wells, inadequate hole cleaning can lead to a series of drilling problems. Traditional hole cleaning analysis is simply based on theoretical models or surface vibrating screen data, and cannot accurately assess downhole cuttings distribution and existing problems. This paper introduces a novel research idea that combines the traditional drilling hydraulic model with the artificial intelligence method. A downhole true cuttings distribution technology based on measurement data, the inversion of flow characteristics from pressure in the hole cleaning field, and a new method for quantitatively evaluating the dynamic distribution of downhole cuttings using along-string measurement (ASM) data were proposed. The results depict that, the relationship between hole cleanliness and annular pressure loss in different hole sections under different working conditions is proportional. Second, under given flow conditions, a pressure-driven hole-cleaning model exerted a reverse pressure drop by inferring the effect of cuttings on the borehole. Third, downhole multipoint measurement indicated an accurate evaluation of the hole cleaning condition and provide detailed downhole information that avoided and solve inadequate hole cleaning of long horizontal wells and extended reach wells. In conclusion, the combination of these methods can overcome the defects of traditional hole cleaning analysis. The integrated approach is helpful in improving the practical technique in hole cleaning and promotes the large-scale application in the oil and gas industry.

Rheological effects of air drilling fluids on cuttings transportation in underbalanced drilling

This research investigates factors influencing cuttings transport efficiency in air drilling operations, aiming to understand the underlying mechanisms, identify critical factors, and optimize drilling parameters for enhanced performance. The methodology includes a literature review, computational fluid dynamics (CFD) simulations, and sensitivity analysis of air velocity, drilling fluid properties, cuttings size, and outlet pressure. CFD simulations were employed to model the multi-phase flow in the annulus during air drilling, examining the effects of varying air velocities, cuttings sizes, and outlet pressures on cuttings transport and hole cleaning efficiency. Results show that increased air velocity improves cuttings transport and hole cleaning but may cause higher pressure drops and borehole erosion. Air drilling fluids' unique rheological properties significantly impact cuttings transportation, requiring careful consideration of factors like air velocity, aerodynamic lift, hole cleaning efficiency, annular pressure losses, and potential cuttings accumulation. The study reveals that cuttings size is crucial for transport efficiency, with larger cuttings necessitating higher air velocities for effective transport and being more prone to settling and accumulation. Moreover, the research demonstrates that increasing outlet pressure typically enhances cuttings transport efficiency in horizontal wells. In conclusion, this study offers valuable insights into factors affecting cuttings transport efficiency in air drilling operations, providing recommendations for optimizing drilling parameters to balance efficient cuttings removal, hole cleaning, and minimal pressure drop. The findings hold practical implications for air drilling operations' design and execution, with the potential to improve drilling performance and reduce operational risks.

Flow Field and Pressure Loss Characteristics at Rotary Drillstring Joints

A thorough understanding and accurate calculation of the annulus pressure losses are paramount to drilling design and construction. However, due to the influence of the drillstring rotation and the abrupt dimensional variation at the joint, it is difficult to calculate the pressure loss by theoretical analysis in the annulus at the drillstring joints. Considering the geometric nonlinearity of drillstring joints and the unsteady flow of annular fluid caused by pipe rotation, based on the turbulence model k − ε , the flow field characteristics demonstrate the annulus pressure losses at the drillstring joint are studied by numerical simulation. Simulation results indicate that drillstring rotation speed, annular gap, and eccentricity greatly influence flow field and pressure losses at drillstring joints. The annular pressure loss would increase with the decrease of the annular gap and eccentricity but decrease with the increase of the drillstring rotation rate. The investigation method and results would help guide the design of drilling hydraulic parameters.

Application of soft computing approaches for modeling annular pressure loss of slim-hole wells in one of Iranian central oil fields

Application of soft computing approaches for modeling annular pressure loss of slim-hole wells in one of Iranian central oil fields

Numerical study of temperature and pressure effects of a yield-power law fluid flow on frictional pressure losses for laminar and turbulent regimes

The effective determination of pressure losses depends on accurate knowledge of the drilling fluid rheology. As the fluid circulates deeper around the wellbore, its rheological behavior undergoes significant alterations due to the variations in downhole conditions encountered. The present study investigates the effects of the rheological properties of Yield-power law fluid at various pressures and temperatures on annular pressure losses and velocity profiles. Simulations were performed using Computational Fluid Dynamics to examine the fluid flow in turbulent and laminar regimes. Comparison between numerical, experimental and slot approximation model results showed a good agreement. Results indicated that pressure losses have reduced in both regimes with increasing temperature, at a constant pressure. However the pressure has the opposite effect at a constant temperature. For a drilling fluid flow velocity of 1 m/s, the elevation of temperature from 25 °C to 90 °C, decreases the pressure drop gradient by (31% to 48%) at low and high- pressure conditions respectively. Whereas, the influence of increasing pressure on pressure losses is more apparent at 25 °C. Earlier transition from laminar to turbulent is observed with temperature rise. Therefore, the temperature effect on pressure losses in the turbulent region; is shown for different Generalized Reynolds numbers.

A mechanistic model for minimizing pressure loss in the wellbore during drilling by considering the effects of cuttings

Because of the existence of cuttings in the flow, the pressure loss in the wellbore can increase significantly. Minimization of the flow pressure loss greatly benefits the drilling process. This work investigates the most important factors to the pressure loss in the wellbore during the hole cleaning process. It is found that, for the solid–liquid, two-phase flow, the fluid flow rate is not always proportional to annular pressure loss as the single-phase flow. The mechanisms behind this effect are studied, and a mechanistic model based on the solid–liquid, two-phase flow is proposed to simulate the hole cleaning process and predict the critical fluid flow rate, which gives the minimum pressure loss in the wellbore. The effect of the inclination angle, fluid rheological parameters, annulus geometry, and the rate of penetration on the critical value are investigated by using the proposed model. Results show that the critical flow rate value increases as the inclination angle increases under 60° and decreases once the inclination angle goes beyond 60°. The critical flow rate increases as the fluid viscosity and the wellbore geometry increase. This proposed model can be used to minimize the pressure loss in the wellbore in the given operational conditions and optimize the drilling parameters.

Prediction of Cuttings-Induced Annular-Pressure Loss in Extended-Reach Wells

Prediction of Cuttings-Induced Annular-Pressure Loss in Extended-Reach Wells

Transient cutting transport model for horizontal wells with a slim hole

AbstractCompared with conventional drilling methods, the method of drilling horizontal wells with a slim hole (HW‐SH) has advantages, such as high productivity, environment‐friendliness, and low costs. However, during the drilling process, the narrow annulus may become blocked, which may lead to an increase in the annulus pressure if the wellbore is not clean. This often leads to serious drilling accidents, such as sticking and leaking formations. Many models have been used to study the cutting transport law in an annulus, but the influence of drill‐pipe rotation on cutting transport is often ignored and weakened in these models. None of the existing models can effectively simulate the cutting transport law of an entire well section. Therefore, using these models to predict the cutting transport law in the annulus of the HW‐SH will cause significant errors. In this study, the authors first establish a pipeline model of the same size as the on‐site annulus using computational fluid dynamics (CFD). Subsequently, a one‐dimensional (1D) two‐layer model that uses three correction factors to express the influence of drill‐pipe rotation on cutting transport and annulus pressure loss is developed. Finally, the parameters in the 1D model are calibrated using the CFD simulation results to accurately predict the cutting transport behavior and annular pressure loss. From the calculation results of the annulus cutting quality, annulus section‐cutting concentration, and annulus pressure drop, it was observed that the two algorithms proposed in this study have a high degree of coincidence, thereby confirming the reliability of the model. The 1D model provides close to three‐dimensional (3D) accuracy at a much shorter central processing unit time than the 3D CFD models. In addition, the accuracy of the developed model was verified using the results of an indoor pipeline two‐phase flow experiment conducted at the University of Tulsa, without considering the rotation of the drill pipe.

Modeling fluctuating pressure in the eccentric annulus with a four-parameter rheological method

The existing calculation models of fluctuating pressure are mainly based on Bingham fluid, power-law fluid and Heba fluid. These rheological models have certain limitations in the scope of application, and it is difficult to accurately describe the actual rheological curves of most drilling fluids. Based on evaluating the calculation model of power-law fluid pressure in eccentric annulus, the constitutive equation of the four-parameter rheological model is extended, and the calculation formula of annular pressure loss is established. In this research, we consider the calculation formula of annular flow under different boundary conditions. The model of fluctuating pressure in the eccentric annulus is obtained using cubic spline interpolation and Gauss integral equation. Compared with the experimental data from concentric annulus and eccentric annulus, the calculated results are in good agreement with the experimental results, compared with the laboratory test data, the error is within the range of ±10%, indicating that the model is sufficiently accurate to meet the requirements of field operations. In addition, the sensitivities of trip rate, drilling fluid flow index and drill string to wellbore size ratio are analyzed. Under the condition of totally eccentric annulus, the gradient of surge pressure decreases to around 50% of that for concentric annulus. The tripping velocity should be strictly limited for operations in the narrow annular space.

Numerical Study on the Impact of Spiral Tortuous Hole on Cuttings Removal in Horizontal Wells

SummaryHorizontal wells are designed to have smooth (straight), curved, and lateral sections. However, the actual drilled path usually suffers from unwanted undulations from the planned well trajectory known as wellbore tortuosity. Wellbore tortuosity can slow the drilling penetration rate, aggravate drillstring vibration and buckling, complicate the casing and cement job, and lead to inaccurate wellbore position. This paper presents a validated computational fluid dynamics (CFD) model to investigate the impact of wellbore tortuosity on hole cleaning. The Eulerian-Eulerian approach is used to simulate solid-liquid laminar flow in annular geometry using polyhedral mesh. Then, the impact of wellbore tortuosity on cuttings accumulation, annular pressure loss, and fluid velocity was investigated and compared with the flow behavior in a straight horizontal well. A parametric analysis of spiral period length, spiral amplitude, drillstring rotation, flow rate, annular eccentricity, drilling rate of penetration (ROP), and cuttings size was conducted to assess their influence on cuttings transport in spiral tortuous holes and their relative magnitude to other design or operating factors.Simulation results show that polyhedral mesh is an optimum meshing technique for spiral profile geometry. Wellbore tortuosity aggravates hole cleaning in lateral sections based on the length of the spiral period and/or the spiral amplitude. Reduction in cuttings velocity was observed in the top part of the spiral geometry (crest), causing large deposition of cuttings in this area compared to the spiral lower part (trough). Drillstring rotation from 0 to 200 rev/min is the critical range for efficient hole cleaning in spiral geometry. Cuttings size can improve cuttings accumulation if the particle size is larger than the viscous layer located near the bed velocity profile. The drilling ROP and annular eccentricity aggravate cuttings accumulation and bed deposition in a spiral hole, similar to what is normally observed in straight horizontal wells.

How to Improve Accuracy of a Kick Tolerance Model by Considering the Effects of Kick Classification, Frictional Losses, Pore Pressure Profile, and Influx Temperature

Summary Kick tolerance (KT) calculation is essential for a cost-effective well design and safe drilling operations. While most exploration and production operators have a similar definition of KT, the calculation is not consistent because of different assumptions that are made and the computational power of KT calculators. Dynamic multiphase drilling simulators usually provide KT estimates with a minimum number of assumptions. They are much more accessible nowadays for use in predicting the behavior of multiphase flow in drilling and well control operations. However, as far as we observed, the simulation services are mainly used for complex and marginal wells in which low KT may impose additional casing strings, unconventional costly drilling practices, or a high risk of major well control events. Thus, companies often use simplified steady-state models for relatively uncomplicated wells through their own KT calculation worksheets. This practice is usually justified by the misconception that simplified models are always conservative and give less KT than actual conditions. In contrast, some simplifications may lead to higher operational risks due to an overestimated KT, depending on well conditions and parameters. The primary objective of this work was to perform a quality assurance/quality control on KT calculation practices in Company P. Later on, based on our findings, we determined some solutions to improve accuracy in the simplified KT worksheets commonly used by engineers across the company. This became a driver for generating a new KT worksheet (Company Model), in particular for situations in which engineers do not have access to a kick simulator. However, it should not mislead readers about the requirements of the simulator for complex and low-KT wells. Quality assurance/quality control and subsequent investigations found that there are some important criteria and parameters that affect KT calculations, but they are missing in many simplified models or ignored by engineers because they are unaware of or lack adequate references. After reviewing relevant academic literature, common practices and assessing several off-the-shelf software programs, we generated a computer program using Visual Basic for applications to address KT sensitivity to different parameters in steady-state conditions. The newly developed program is based on a single gas bubble model that applies the effect of annular frictional losses, influx temperature, gas compressibility factor, well trajectory, and bottomhole assembly (BHA). Moreover, the program differentiates between swabbing and underbalanced conditions. A logical test is applied to determine the type of kick before computing the relevant influx volume. This kick classification concept is ignored in many KT models; this is a common mistake that leads to misleading results. The annular pressure loss (APL) parameter is sometimes assumed to be zero in KT spreadsheets, while as an additional stress load on the wellbore, it affects the kick budget and must be considered.

A model for investigating wellbore hydraulics of thermo-thixotropic drilling fluids

In high-temperature drilling environments, accurate management of wellbore hydraulics is made more difficult due to complex fluid viscosity-temperature profiles. Although most of the fluid samples reported in the literature have monotonically decreasing viscosity with temperature, several studies have found the relationship much more complicated. This study investigates thermal effects on annular pressure loss and cuttings transport for fluids with non-monotonic viscosity-temperature profiles while modeling the thixotropic behavior of the drilling fluid. To this end, three fluid samples have been studied that have distinctly different viscosity-temperature profiles: monotonically decreasing, parabolic and inverted parabola. The mathematical framework is based on the drift flux approach and is numerically solved using the computational fluid dynamics (CFD) methodology. The recently proposed rheological algorithm by the authors has been extended to model thixotropy. The results are presented for different inclinations and eccentricities. It is observed that for fluids with parabolic or inverted parabolic viscosity-temperature profiles, annular pressure loss is highly non-linear, and a single equivalent density value cannot be ascribed to the wellbore. The annular pressure loss near the inlet is significantly higher than that near the outlet. The fluid with a monotonic decrease in viscosity yields the lowest pressure loss but worst cuttings transport whereas, the fluid with a parabolic viscosity-temperature profile has best cuttings transport but causes extremely high-pressure loss.

Prediction Model and Distribution Law Study of Temperature and Pressure of the Wellbore in drilling in Arctic Region

The low temperature condition of permafrost in Arctic region affects the rheology of drilling fluids and the distribution of temperature and pressure in the wellbore during drilling. In order to understand the influence law of permafrost in Arctic region on the temperature and pressure distribution in wellbore and provide a basis for the design and construction for drilling in Arctic region, a model to predict the wellbore temperature and pressure of drilling in Arctic region was built. It was based on the analysis of the influence of low temperatures on the rheology of water-based and oil-based drilling fluids, considering the coupling between permafrost and wellbore. By comparing the measured and test results, it was verified that the prediction accuracy of the proposed model met the requirements of drilling in Arctic region. The model was used to simulate the temperature and pressure distribution in a wellbore in Arctic region under the conditions of no circulation or pump function. The results showed that the drilling fluids absorbed the heat of the high-temperature formation and returned to the annulus transferring the heat to the permafrost in shallow part of the wellbore during the circulation. This process thawed the permafrost near the wellbore and the wellbore temperature was lowered due to the heat consumed by thawing. The circulating friction in annulus increases with the increase of circulation time. The longer the pump shutdown lasts, the closer the temperature of drilling fluid to the formation temperature in the wellbore. The larger the annular circulation pressure loss, and the higher the pump pressure. The research results can provide a basis and guidance for design and construction of drilling in Arctic region.

The Effects of Fluid Rheology and Drillstring Eccentricity on Drilling Hydraulics

Accurate determination of hydraulic parameters such as pressure losses, equivalent circulation density (ECD), etc. plays profound roles in drilling, cementing and other well operations. Hydraulics characterization requires that all factors are considered as the neglect of any could become potential sources of errors that would be detrimental to the overall well operation. Drilling Hydraulics has been extensively treated in the literature. However, these works almost entirely rely on the assumption that the drill string lies perfectly at the center of the annulus—the so-called “concentric annulus”. In reality, concentricity is almost never achieved even when centralizers are used. This is because of high well inclination angles and different string geometries. Thus, eccentricity exists in practical oil and gas wells especially horizontal and extended reach wells (ERWs) and must be accounted for. The prevalence of drillstring (DS) eccentricity in the annulus calls for a re-evaluation of existing hydraulic models. This study evaluates the effect of drilling fluid rheology types and DS eccentricity on the entire drilling hydraulics. Three non-Newtonian fluid models were analyzed, viz: Herschel Bulkley, power law and Bingham plastic models. From the results, it was observed that while power law and Bingham plastic models gave the upper and lower hydraulic values, Herschel Bulkley fluid model gave annular pressure loss (APL) and ECD values that fall between the upper and lower values and provide a better fit to the hydraulic data than power law and Bingham plastic fluids. Furthermore, analysis of annular eccentricity reveals that APLs and ECD decrease with an increase in DS eccentricity. Pressure loss reduction of more than 50% was predicted for the fully eccentric case for Herschel Bulkley fluids. Thus, DS eccentricity must be fully considered during well planning and hydraulics designs.

Thixotropy effects on drilling hydraulics

Thixotropy is the reversible breakdown of fluid microstructure when sheared. The microstructure achieves a new steady-state once shearing stops. Drilling fluids are thixotropic due to their rheological makeup which means that fluid microstructure has a time-dependent response to changes in applied shear rate. In contrast to the literature focusing on the time-independent nature of drilling fluid, few studies have focused on the time-dependent response and even fewer have considered cuttings transport while doing so. The purpose of this study is to investigate the fundamental relationship between thixotropy and drilling hydraulics. An algorithm is developed to model thixotropy using flow history. The results show that the addition of drill cuttings does not directly affect the thixotropic behavior, rather the steady-state response is impacted which consequently changes the thixotropic response. Since the fluid microstructure takes time to respond to shear rate variations, viscosity lags behind shear rate variations causing annular pressure loss to fluctuate. The magnitude of pressure fluctuations is inversely proportional to characteristic time and directly proportional to stretching exponent. At smaller characteristic time coupled with smaller stretching exponent, high yield stress deteriorates cuttings transport. For larger values of characteristic time and stretching exponent, a clear trend is not observed, and further investigation is recommended. Nevertheless, when the thixotropic behavior of drilling fluid is considered, the results show that high flow rates and yield stresses do not guarantee efficient hole cleaning. Out of the two industrial fluid samples discussed, WBM yields higher pressure fluctuations and better cuttings transport compared to OBM. Since the proposed algorithm does not differentiate between the types of drilling fluids, this is due to WBM's smaller characteristic time and larger stretching exponent. It is suggested that a fluid exhibiting a slower response to shear rate changes causes higher pressure fluctuations and better cuttings transport.