Drilling Fluid Rheology Research Articles

Study on the Low-Temperature Rheology of Polar Drilling Fluid and Its Regulation Method

Drilling fluid is the blood of drilling engineering. In the polar drilling process, the ultra-low temperature environment puts high demands on the rheological performance of drilling fluids. In this paper, the effects of temperature, ice debris concentration and weighting agent on the rheological properties of drilling fluids were studied. It was found that the lower the temperature and the higher the ice debris concentration, the higher the drilling fluid viscosity, but when the ice debris concentration was below 2%, the drilling fluid rheology hardly changed. Secondly, the low temperature rheological properties of drilling fluid were adjusted by three different methods: base fluid ratio, organoclay, and polymers (dimer acid, polymethacrylate, ethylene propylene copolymer, and vinyl resin). The results showed that the base fluid rheological performance was optimal when the base fluid ratio was 7:3. Compared with polymers, organoclay has the most significant improvement on the low temperature rheological performance of drilling fluid. The main reason is that organoclay can transform the drilling fluid from Newtonian to non-Newtonian fluid, which exhibits excellent shear dilution of drilling fluid. The organoclay is also more uniformly dispersed in the oil, forming a denser weak gel mesh structure, so it is more effective in improving the cuttings carrying and suspension properties of drilling fluids. However, the drilling fluid containing polymer additives is still a Newtonian fluid, which cannot form a strong mesh structure at ultra-low temperatures, and thus cannot effectively improve the low-temperature rheological performance of drilling fluid. In addition, when the amount of organoclay is 2%, the improvement rate of the yield point reaches 250% at -55 °C, which can effectively improve the cuttings carrying and suspension performance of drilling fluid at ultra-low temperature.

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.

Enhance the Properties of Lignosulfonate Mud by Adding Nanoparticles of Aluminum Oxide and Iron Oxide

Oil well drilling fluid rheology, lubricity, swelling, and fluid loss control are all critical factors to take into account before beginning the hole's construction. Drilling fluids can be made smoother, more cost-effective, and more efficient by investigating and evaluating the effects of various nanoparticles including aluminum oxide (Al2O3) and iron oxide (Fe2O3) on their performance. A drilling fluid's performance can be assessed by comparing its baseline characteristics to those of nanoparticle (NPs) enhanced fluids. It was found that the drilling mud contained NPs in concentrations of 0,0.25, 0. 5, 0.75 and 1 g. According to the results, when drilling fluid was used without NPs, the coefficient of fraction (CoF) was 44%, when added Al2O3 NP and Fe2O3 NP at 0.75g reduced CoF by 31% and 33% respectively. When Al2O3 and Fe2O3 NPs were used, particularly at a concentration of 1g, the amount of mud filtration decreased from 13.5ml to 9.3 ml and 8.5 ml respectively. Additional improvements rheological properties as well as swelling when Fe2O3NPs and Al2O3 NPs were added at 1g. Overall, it was found that adding NPs to the Lignosulfonate-WBM at a concentration of 1g can improve rheological, swelling, and filtration properties as well as lubrication at 0.75g.

Innovative Applications of Red Mud: Converting an Environmental Challenge to a Drilling Asset.

Red mud is generated from alumina production through bauxite digestion with caustic soda. Ma'aden aluminum production estimated the abundance in a million tons as 2.65:1:2 for bauxite, alumina, and red mud, respectively. The real challenge when it comes to red mud pertains to storage capacity; many solutions have been put forward in different industries, and in this study, the utilization of the red mud waste material is presented as a potential weighting material that could be incorporated into the design of drilling fluid systems. This study provides an assessment of the utilization of red mud as a drilling fluid, and it provides directions for the use of red mud in drilling mud systems as a filtration agent and as a finely divided solid used as a weighting material to increase the density of a given drilling fluid system. This study investigates the viability of red mud as an effective additive to drilling fluid and its effect on rheology and filtration. Different techniques are employed in red mud characterization and performance evaluation. The study assesses red mud as an inert solid in a drilling fluid system by investigating the drilling fluid rheology, apparent viscosity (AV), plastic viscosity (PV), and yield point (YP) before and after hot rolling at 150 °F, in addition to filtration properties under low-pressure, low-temperature and higher-pressure, higher-temperature conditions (at 150 °F and a differential pressure of 250 psi). Also, the study highlights the red mud solid characterization, material preparation, and acid dissolution at 150 °F. This study attempts to view the red mud situation from a practical application angle (primarily in the oil and gas industry). Test results show stable drilling mud fluid properties when utilizing red mud solid additives as weighting agents. The drilling mud exhibits relatively low plastic viscosity, gel strength, excellent sag behavior, and reasonable filtration control, even under HPHT conditions in aqueous-based fluids. The material dissolves in acid. Accordingly, red mud provides a viable option for weighting agents and filtration control.

Performance control of high temperature and high density drilling fluid based on fractal grading theory

With the increase of drilling depth, the density of drilling fluid required also increases gradually. Increasing the density of drilling fluid by weighting material usually worsens the performance of drilling fluid. Based on the fractal principle and mathematical fractal, a fractal grading model suitable for the grading calculation of drilling fluid weighting materials was established, and the theoretical proportion of barite with different particle sizes was given. Through drilling fluid performance evaluation, filter cake analysis, oscillatory rheology measurement and circulation simulation, the influence of barite gradation on the rheology, filtration and sag stability of high-density drilling fluid was studied, and the influence of barite gradation on drilling fluid performance was discussed. The results showed that the fractal grading model is suitable for the optimization of weighting materials of high-density drilling fluids, and the graded barite can improve the comprehensive performance of weighting drilling fluids.

Application of machine learning to determine the shear stress and filtration loss properties of nano-based drilling fluid

A detailed understanding of the drilling fluid rheology and filtration properties is essential to assuring reduced fluid loss during the transport process. As per literature review, silica nanoparticle is an exceptional additive to enhance drilling fluid rheology and filtration properties enhancement. However, a correlation based on nano-SiO2-water-based drilling fluid that can quantify the rheology and filtration properties of nanofluids is not available. Thus, two data-driven machine learning approaches are proposed for prediction, i.e. artificial-neural-network and least-square-support-vector-machine (LSSVM). Parameters involved for the prediction of shear stress are SiO2 concentration, temperature, and shear rate, whereas SiO2 nanoparticle concentration, temperature, and time are the inputs to simulate filtration volume. A feed-forward multilayer perceptron is constructed and optimised using the Levenberg–Marquardt learning algorithm. The parameters for the LSSVM are optimised using Couple Simulated Annealing. The performance of each model is evaluated based on several statistical parameters. The predicted results achieved R2 (coefficient of determination) value higher than 0.99 and MAE (mean absolute error) and MAPE (mean absolute percentage error) value below 7% for both the models. The developed models are further validated with experimental data that reveals an excellent agreement between predicted and experimental data.

A Temperature-Sensitive Polymeric Rheology Modifier Used in Water-Based Drilling Fluid for Deepwater Drilling.

Rheology modifiers are essential for the flat rheology of water-based drilling fluids in deepwater. The low temperature thickening of deepwater water-based drilling fluids results in dramatic rheological changes in the 20–30 °C range. To address such problems, NIPAM with a self-polymerized product LCST of 32–35 °C was selected as the main body for synthesis. While introducing the hydrophilic monomer AM to enhance the thickening properties, the hydrophobic monomer BA was selected to reduce the LCST of the product. In this paper, a temperature-sensitive polymeric rheology modifier (PNBAM) was synthesized by emulsion polymerization using N-isopropyl acrylamide, acrylamide, and butyl acrylate as monomers. The PNBAM was characterized using infrared spectroscopy (FT-IR), thermogravimetric analysis (TGA), and nuclear magnetic resonance hydrogen spectroscopy (NMR). The rheological properties, temperature resistance, and salt resistance of PNBAM in the base fluid (BF) were tested. The performance of PNBAM in the drilling fluid system was also evaluated, and a water-based drilling fluid system of flat rheology for deepwater was formulated. The rheological modification mechanism of PNBAM was analyzed by turbidity analysis, particle size analysis, and zeta analysis. Experimental results show that PNBAM has good rheological properties. PNBAM is temperature resistant to 150 °C, salt-resistant to 30 wt%, and calcium resistant to 1.0 wt%. PNBAM also has good flat rheology characteristics in drilling fluid systems: AV4°C:AV25°C = 1.27, PV4°C:PV25°C = 1.19. Mechanistic analysis showed that the LCST (Lower Critical Solution Temperature) of 0.2 wt% PNBAM in an aqueous solution was 31 °C. Through changes in hydrogen bonding forces with water, PNBAM can regulate its hydrophilic and hydrophobic properties before and after LCST, which thus assists BF to achieve a flat rheological effect. In summary, the temperature-sensitive effect of PNBAM has the property of enhancing with increasing temperature. While the tackifying effect of conventional rheology modifiers diminishes with increasing temperature, the temperature-sensitive effect of PNBAM gives it an enhanced thickening effect with increasing temperature, making it a more novel rheology modifier compared to conventional treatment additives. After LCST, compared to conventional rheology modifiers (XC), PNBAM has a more pronounced thermo-thickening effect, improving the main rheological parameters of BF by more than 100% or even up to 200% (XC less than 50%). This contributes to the flat rheology of drilling fluids. PNBAM has good application prospects and serves as a good reference for the development of other rheology modifiers.

Machine Learning Model for Monitoring Rheological Properties of Synthetic Oil-Based Mud.

The drilling fluid rheology is a critical parameter during the oil and gas drilling operation to achieve optimum drilling performance without nonproductive time or extra remedial operation cost. The close monitoring for rheological properties will help the drilling fluid crew to take quick actions to maintain the designed profiles for the drilling fluid rheology, especially when it comes to the flat rheology drilling fluid system, which is a new generation for harsh and specific drilling conditions that require flat profiles for the mud rheology regarding the temperature condition changes. The current study introduces a machine learning application toward predicting the rheology of synthetic oil-based mud (flat rheology type) for the full automation system of monitoring the mud rheological properties. Four models are developed, for the first time, to determine the rheological characteristics of flat rheology synthetic oil-based system using artificial neural networks. The developed models are capable of predicting the plastic and apparent viscosities, yield point, and flow behavior index from only the mud density and Marsh funnel as model inputs. The proposed models were trained and optimized from a real field dataset (369 measurements) with further testing the models using an unseen dataset of 153 data points. The predicted rheological properties achieved a high degree of accuracy versus the actual measurements and showed a coefficient of correlation range from 0.91 to 0.97 with an average absolute percentage error of less than 9.66% during the training and testing phases. Besides, machine learning-based correlations are proposed for estimating the rheological properties on the rig site without running the machine learning system for easy field applications.

Removing cuttings from inclined and horizontal wells: Numerical analysis of the required drilling fluid rheology and flow rate

Inclined and horizontal wells are prone to the accumulation of drilling cuttings. Determination of the optimal drilling parameters that facilitate cuttings removal is a key problem. Existing experimental, theoretical and field-based empirical analyses of the hole cleaning problem have failed to fully reveal the processes of cuttings transport, settlement, and accumulation concerning drilling string rotation in large annuli with high-density non-Newtonian drilling fluids. In this study, a coupled computational fluid dynamics-discrete element method (CFD-DEM) simulation model of the interaction between cuttings and drilling fluid was established. This allows the influences of well inclination, drill pipe rotational rate, flow rate, fluid density, and rheological properties on hole cleaning efficiency to be analyzed. A multi-parameter correlation equation between wellbore cleaning efficiency and wellbore size, inclination angle, drill string eccentricity, drill string rotational speed, rate of penetration, cuttings size, flow rate, and fluid density was obtained using dimensional analysis and multivariate nonlinear regression of simulation data. Finally, with consideration of wellbore cleaning characteristics, formation pressure bearing capacity, and pump condition constraints, the proposed multi-parameter correlation model was used to provide optimal wellbore cleaning parameters. The cleaning efficiency of horizontal wells is lowest in the inclined section. Hole cleaning efficiency increases significantly with drill pipe rotational rate, flow rate, and 6 RPM Fann dial reading. The proposed model can correlate hole cleaning efficiency with the 6 RPM Fann dial reading of drilling fluid and flow rate. At a given hole cleaning efficiency, the required minimum flow rate decreases with increases in the 6 RPM Fann dial reading. Similarly, the required minimum 6 RPM Fann dial reading decreases with increases in flow rate. The models and design layout proposed in this paper provide a new approach to solving hole cleaning parameter design problems in highly inclined and horizontal wells.

Synthesis and application of a temperature sensitive poly(N-vinylcaprolactam-co-N,N-diethyl acrylamide) for low-temperature rheology control of water-based drilling fluid

During deepwater drilling operation, the wellbore temperature decreases with the increase of water depth, and increases rapidly with the increase of formation depth. Temperature sensitive polymers can change the molecular conformation with temperature, and then change its hydrophobicity, to adjust the network structure between solid particles and polymer in drilling fluid. In this paper, a novel temperature sensitive copolymer poly(N-vinylcaprolactam-co-N,N-diethyl acrylamide) (PNVDE) was synthesized. Its molecular structure, molecular weight and molecular weight distribution were characterized. The effects of salinity, pH value and copolymer concentrations on lower critical solution temperature (LCST) were studied. Based on the temperature sensitive property of the copolymer, the ability to control the low-temperature rheology of water-based drilling fluid (WBDF) was studied. The results showed that PNVDE can effectively control the rheology of deepwater WBDF in the range of 4~ 60 ℃. At the same time, the experiments of temperature and salt resistance showed that the copolymer has strong ability of temperature resistance and salt resistance, and can withstand the temperature alternation of drilling fluid. The synergistic effect of PNVDE and bentonite made the rheology of deepwater drilling fluid stable, which can be explained by “SASA Hydrogen Bond Network”.

Synthesis of hydrophobic associative polymers to improve the rheological and filtration performance of drilling fluids under high temperature and high salinity conditions

With the acceleration of deep oil and gas development, the problem of high temperature and high salinity in the formation is prominent, which seriously affects the rheology and filtration performance of water-based drilling fluid and causes drilling accidents such as formation collapse and wellbore instability. Therefore, in this work, a novel thickening and fluid loss control additive (i.e., ASML) with significant hydrophobic association characteristics as well as outstanding temperature- and salt-resistance was synthesized using acrylamide, sodium p-styrenesulfonate, maleic anhydride and lauryl methacrylate as monomers. The experiments of fluorescence spectroscopy, SEM, Zeta potential, rheology and filtration show that ASML makes the drilling fluid have more networked structure under the conditions of high temperature and high salt through hydrophobic association. At the same time, it also brings more negative charge to the bentonite by adsorbing ASML on the surface of bentonite, which effectively maintains its uniform colloidal dispersion, leading to higher viscosity, denser mud cake, and lower fluid loss under high temperature and high salinity conditions. Under the condition of 200 °C and 30 wt% NaCl, the fluid loss of ASML-based drilling fluid is only 5 ml, which is 94.3% lower than that of carboxymethyl cellulose-based drilling fluid. This study provides a new strategy for the development of temperature- and salt-resistant drilling fluid treatment agent, which is important for accelerating the efficient development of deep oil and gas. • One kind of filtration reducer (i.e., ASML) with hydrophobic association properties was developed. • The hydrophobic association structure of ASML and its promotion by NaCl were observed by TEM. • The performance of the filtration reducer for water-based drilling fluids has been improved to 200 °C and 30 wt% NaCl. • The mechanism of ASML in drilling fluids was revealed.

A Deep Eutectic Solvent based novel drilling mud with modified rheology for hydrates inhibition in deep water drilling

Ionic liquids are well-liked drilling fluid additives for inhibiting hydrates and modifying mud rheology. However, preparation of ionic liquid is costly and imidazolium based ionic liquids have been found to be severely toxic. Deep Eutectic Solvent (DES) is a non-toxic and cheaper alternative of traditional ionic liquids. In this research, in-house prepared, Choline chloride and Urea based DES has been used as a drilling fluid additive in water based mud. Micro-DSC has been used to study the induction time of methane gas hydrates at 114 bar between −20 °C to 20 °C. Drilling fluid rheology and properties have been determined by following AP1 13B-1 standards. The results of Micro DSC evidenced that the addition of DES delayed the induction time of the hydrates up to 24.3%, improved the YP/PV of the drilling fluid and also resulted into 20% and 14.5% reduction in filtrate volume and mud cake thickness respectively. Moreover, based upon the outcomes of characterizations i.e. Zeta potential, XRD and FTIR, it is proposed that the improvement in mud rheology is due to the change in clay's size and structure on interaction with DES. Consequently, the DES inhibits the hydrate formation and alters the mud rheology by its excellent ability to form hydrogen bonds with hydrates' crystals and clay granules respectively.

Investigation of regulating rheological properties of water-based drilling fluids by ultrasound

Regulating rheological properties of water-based drilling fluids has always been a hot topic. This paper proposed a new method for regulating rheological properties of water-based drilling fluids by ultrasonic field. The experimental results showed that the ultrasound increased the viscosity and yield point of bentonite suspension by reducing the particle size of clay, destroying the network structure between clay particles, increasing the mud yield and the cation exchange capacity of bentonite, and promoting the hydration dispersion of bentonite. The change of rheological property showed a memory effect at room temperature and high temperature. Besides, the ultrasonic energy affected the network structure between clays and polymer chains, thus regulating the rheological properties of the bentonite-polymer system. For two types of drilling fluids investigated, the rheology of the poly-sulfonate drilling fluid was regulated by damaging the grid structure between additives and clays by low-power ultrasound and reducing the clay particle size by high-power ultrasound, while the rheology of the deep-water drilling fluid was mainly regulated by disentangling the spatial grid structure between additives. Additionally, ultrasound showed no effect on the lubricity, inhibition and stability of drilling fluids, which proved the feasibility of ultrasound to regulate rheological properties of water-based drilling fluids.

Synthesis of Asphalt Nanoparticles and Their Effects on Drilling Fluid Properties and Shale Dispersion

Summary Asphalt nanoparticles (ANs) were developed by synthesizing asphalt powders with chloroacetic acid (ClCH2COOH). The objective of this synthesis was to develop engineered ANs with a cationic point capable of adsorbing on the net negatively charged clay platelets, thereby improving drilling fluid functionality and pore-plugging performance, reducing shale dispersion, and ultimately enhancing shale stability. Tests carried out to study the performance of the synthesized ANs include particle size analysis, Fourier transform infrared (FT-IR) spectroscopy, scanning electron microscopy, drilling fluid rheology, and filtration rate and shale dispersion tests. FT-IR spectrum results confirming the occurrence of a chemical reaction between asphalt and ClCH2COOH showed a shift in NH vibration from 3,439.95 cm−1 (before synthesis) to 3,435.05 cm−1 (after synthesis). Based on particle size analysis, an average particle size diameter of 92.9 nm was observed, suggesting the tendency of ANs to invade and seal nanopore spaces. The shape of ANs ranged from spherical to irregular, because intercalated structures were observed from the scanning electron microscopic analysis on the interaction between ANs and sodium bentonite (Na-Bent). An increase in attracting force between the Na-Bent particles caused by the adsorption of ANs cationic point on bentonite clay particles led to an increase in drilling fluid rheological properties as the ANs %w/v increased. The drilling fluid filtration rate was, however, not significantly affected by the %w/v increase in ANs because results indicated slight decrease in fluid loss when compared with the base mud (BM). According to the shale dispersion test, the shale cuttings percentage recovery of the 2%w/v ANs sample was 76.5%, owing to the decrease in fluid-rock interaction caused by ionic adsorption and encapsulation of shale surfaces by the ANs. Experimental results from this investigation indicate that the likely mechanisms of the effect of ANs on shale formations would be sealing off nanopore spaces in formations because of its ultratiny particle size; adsorption of the net negatively charged shale cuttings by the ANs cationic point, thereby reducing drilling cuttings dispersion; and improving hole-cleaning performance due to its effect on the drilling fluid rheological properties.

Mesoscopic theoretical modeling and experimental study of rheological behavior of water-based drilling fluid containing associative synthetic polymer, bentonite, and limestone

Employing an effective rheological model for the flow of drilling fluid that can accurately predict changing conditions is of significant importance in drilling fluid optimization. Traditional generalized Newtonian models cannot predict the time change condition, viscoelastic behavior, role of each component, or microstructural behaviors within the fluid. Consequently, the present research aims to develop constitutive equations in the framework of generalized bracket formalisms and the extra tensor concept that connect the microscopic and macroscopic properties and can overcome the aforementioned problems of traditional rheological models. The developed model is applicable for drilling fluid as a suspension system containing associative synthetic polymer, bentonite, and limestone suspended in water; where simple structures of flexible dumbbells, disks, and hard spheres, respectively, are representative of each component in the system. Five samples of drilling fluid with different additive concentrations were prepared and rheological testing was performed on these samples. To obtain the fixed parameters of the model, scanning electron microscope and particle size analyses were conducted on the dried powder and dispersed particles of bentonite and limestone to characterize the shape and size of the particles. The adjustable parameters of the model were then obtained by fitting it using the gathered experimental rheological data. The outcomes of the study revealed that the novel developed model can accurately predict rheological material functions, including shear viscosity and the first normal stress coefficient under transient and steady-state conditions. Furthermore, the presented model is capable of distinguishing the contribution of each component in the drilling fluid rheology.

Technology Focus: Drilling and Completion Fluids (November 2021)

Design and development of optimal drilling-fluid systems, as well as their proper maintenance while drilling, are essential components of any successful drilling campaign. As the oil and gas industry is drilling in more-challenging areas (e.g., unconventional shale oil/gas wells, deepwater offshore wells, and deep high-pressure/high-temperature sour gas wells), the demand for more-accurate real-time assessment of the downhole state of the drilling fluids during drilling operations increases. Recent developments in drilling systems automation provide a multitude of opportunities to have real-time monitoring of drilling-fluid properties and early diagnosis of drilling-fluid-related complications that might arise while drilling. Coupled with closed-loop control of surface and downhole drilling-fluid properties, automated monitoring of fluid properties would allow rig personnel to make timely corrections to the drilling-fluid program, which eventually would lead to more-cost-efficient and safer drilling operations. This feature provides examples of such new technologies that can be used as part of the automated drilling-fluid monitoring system, allowing real-time control of drilling-fluid rheological properties (i.e., density and viscosity) and management of solids content with potential benefits of real-time management of equivalent circulating density, effective hole cleaning/cuttings transport, increasing drilling rate, and reducing nonproductive time, resulting in safer wells drilled at minimum costs. Recommended additional reading at OnePetro: www.onepetro.org. SPE 199101 - Field Results of a Real-Time Drilling-Fluid Monitoring System by Sérgio Magalhães, Universidade Federal Rural do Rio de Janeiro, et al. SPE 200990 - Intelligent Pressure-Control System for Managed-Pressure Drilling by Zhao Hui Song, Engineering Technology Research Institute of XDEC, et al. SPE 203389 - Real-Time Measurement of Drilling-Fluid Rheology and Density Using Acoustics by Paul Ofoche, Texas A&M University, et al.

A novel hyper-cross-linked polymer for high-efficient fluid-loss control in oil-based drilling fluids

In order to control filtrate at high-temperature and high-pressure condition in oil-based drilling fluid for drilling process of oil and gas wells, an amine cross-linked polymeric fluid-loss-control material (ACP) was designed and synthesized. This material was synthesized through cross-linking poly (maleic anhydride- alt -1-octadecene) (PMAO) with amine. The structure of hyper-cross-linked copolymer enables the ACP polymers to withstand higher aging temperatures and less affect the rheology of oil-based drilling fluid. The structures of ACP polymers we synthesized were confirmed by FT-IR spectra and elemental analysis. TGA results showed that the decomposition temperature of ACP polymers exceeds 400 °C. And the amphiphilic nature of ACP polymers makes them enhance the stability of water-in-oil emulsion of oil-based drilling fluid. In addition, combining the viscoelasticity data of amine cross-linked PMAO suspensions and the fluid-loss control performance of ACP in oil-based drilling fluid, it was found that the increase of amino number in the cross-linker can effectively reduce the filtrate permeating, which is because the aggregation of hydrophilic amino makes ACP polymer form a dense structure to prevent oil from passing through. After screening of ACP polymers, the preferred one (ACP-5) can reduced filtrate volume of oil-based drilling fluid by over 90% with small dosage (3 g in 400 mL drilling fluid) after hot rolling for 16 h at 232 °C. • A series of novel amine cross-linked ACP polymers were prepared. • ACP polymers are resistant to high temperature and high pressure condition. • Emulsion stability of oil-based drilling fluid increases with ACP polymers added. • Fluid loss was efficiently reduced with a small dosage of ACP polymers.

Prediction of High-Pressure/High-Temperature Rheological Properties of Drilling Fluids from the Viscosity Data Measured on a Coaxial Cylinder Viscometer

SummaryDetermining the rheology of drilling fluid under subsurface conditions—that is, pressure > 103.4 MPa (15,000 psi) and temperature > 450 K (350°F)—is very important for safe and trouble-free drilling operations of high-pressure/high-temperature (HP/HT) wells. As the severity of HP/HT wells increases, it is challenging to measure downhole rheology accurately. In the absence of rheology measurement tools under HP/HT conditions, it is essential to develop an accurate rheological model under extreme conditions. In this study, temperature- and pressure-dependence rheology of drilling fluids [i.e., shear viscosity, apparent viscosity (AV), and plastic viscosity (PV)] are predicted at HP/HT conditions using the fundamental momentum transport mechanism (i.e., kinetic theory) of liquids. Drilling fluid properties (e.g., density, thermal decomposition temperature, and isothermal compressibility), and Fann® 35 Viscometer (Fann Instrument Corporation, Houston, USA) readings at surface conditions, are the only input parameters for the proposed HP/HT shear viscosity model. The proposed model has been tested using 26 different types of HP/HT drilling fluids, including water, formate, oil, and synthetic oil as base fluids. The detailed error and the sensitivity analysis have been performed to demonstrate the accuracy of the proposed model and yield comparative results. The proposed model is quite simple and may be applied to accurately predict the rheology of numerous drilling fluids. In the absence of subsurface rheology under HP/HT conditions, the proposed viscosity model may be used as a reliable soft-sensor tool for the online monitoring and control of rheology under downhole conditions while drilling HP/HT wells.

Implementation of artificial intelligence and support vector machine learning to estimate the drilling fluid density in high-pressure high-temperature wells

One of the challenging conditions in wellbore management is high-pressure, high-temperature wells that apply large expenditures and maintenance costs to petroleum industries. In this regard, drilling fluid rheology and its crucial factors would help engineers to have a fundamental understanding of the most appropriate wellbore management. Moreover, it can help engineers to control the fluid loss phenomenon. This paper aimed to consider different artificial intelligence and machine learning models to predict the drilling fluid density and select the optimum model, which can be extended to field applications. These models are ANFIS (adaptive neuro-fuzzy inference system), PSO-ANFIS (particle swarm optimization-adaptive​ neuro-fuzzy inference system), LSSVM-GA (least square support vector machine-genetics algorithm), and RBF (radial basis function) algorithm were modeled in the programming era. In LSSVM-GA model, it is evident that the proper linear equation for the prediction of drilling fluid density is “y = 1.0041x + 0.0019” with the correlation factor of (R2=0.9966). Due to the advantages of RBF algorithm to other genetics algorithm, this algorithm was used in this part to predict the drilling fluid density. Therefore, it is evident that the proper linear equation for the prediction of drilling fluid density is “y = 1.0009x + 0.0034” with the correlation factor of (R2=0.9999). Consequently, RBF model was selected as the optimum method in drilling fluid prediction. Furthermore, there is a proper match with training and experimental data and the maximum deviation is about -0.006. In ANFIS algorithm, exponential derivation would be preferred to predict the drilling fluid density instead of linear equation. Consequently, the RBF model provide has a good agreement with the experimental drilling fluid density. It is indicated that the model have appropriate accuracy and validity with experimental data.

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.