High-Temperature Drilling Fluid Research Articles

Developing a machine learning-based methodology for optimal hyperparameter determination—A mathematical modeling of high-pressure and high-temperature drilling fluid behavior

Drilling fluids exhibit complex rheological behavior due to a non-linear response to shear rate variations and high sensitivity to changes in temperature, time, and pressure conditions. The prediction of drilling fluid rheological behavior is crucial for the success of oil well drilling, and it directly impacts the fluid's performance. The dataset used in this study was obtained from extensive rheometric tests of water-based and olefin-based drilling fluids in steady-state flow curves. The optimal hyperparameters were guided by performance metrics and compared with alternative models such as Power-law and Herschel-Bulkley rheological models. Different configurations with different hidden layers, using neuron sequences of 16, 32, and 64, learning rates of 0.001 and 0.01, and the ReLU activation function were used to improve the model's performance. Additionally, the paper delved into the impact of the number of training epochs on the accuracy of shear stress predictions. Finding this equilibrium was identified as a crucial factor in achieving precise results. The neural network model demonstrated remarkable accuracy when using the ML-C3 configuration, with MAE values of 0.535 and R2 of 0.987 in predicting the steady-state flow curves of drilling fluids, establishing itself as a powerful tool for forecasting the rheological behavior of these fluids under diverse operational conditions. The present research significantly contributes to the field of drilling fluid rheology and provides valuable insights for optimizing drilling operations in HPHT environments.

An Investigation of the Factors Influencing the High Temperature Rheology of Polymers

Introduction: Nowadays, polymers, as an important application material in drilling engineering, have obvious advantages in solving the rock-carrying problem at the bottom of deep wells, and improving the drilling speed due to their excellent viscosity enhancement effect. Method: In this study, the effects of polymer type, concentration, shear time, electrolyte, and clay on the rheological properties of polymer solutions at high temperature and high pressure were investigated using a Fann 50SL rheometer. The experimental results showed that, except for the polymer additive amount and clay, the increase in shear time and the amount of salt both led to a decrease in the viscosity of the polymer solution, with 190°C as the critical temperature above which the viscosity decreased significantly. Results: The polymer solution containing formate showed higher viscosity retention during heating and then cooling compared to chlorides. The presence of clay enhances the reticulation of polymer molecules in the blend, which facilitates the carrying of rock cuttings at high temperatures. In addition, regression analyses showed that the increase in temperature resulted in an enhanced tendency for the polymer solution to evolve from a pseudoplastic to a Newtonian type. Conclusion: This research provides theoretical basis and data support for developing high-temperature polymers and formulating high-temperature drilling fluid systems.

-Effects and mechanisms of acrylamide-based polymer containing N-vinylpyrrolidone on drilling fluids at high temperature

The exploration of ultra-deep oil and gas presents higher temperature resistance requirements for water-based drilling fluids. However, the lack of temperature resistance mechanism of drilling fluid polymers limits the development of key materials and drilling fluids. In this paper, by comparing the preparation of acrylamide polymers for drilling fluids, the influence of cyclic monomer N-vinylpyrrolidone (NVP) on the properties of polymers for drilling fluids was investigated, and the mechanism of NVP was deeply discussed. The results show that the NVP-containing copolymer PAAN has superior viscosity enhancement and filtration control in high-temperature drilling fluids. This is mainly due to the fact that PAAN has a more stable and complex polymer chain structure than PAA, the polymer that does not contain NVP, and its thermal stability is improved by 18.6 % up to 268°C. At the same time, NVP provides more adsorption spots, and the high-temperature clay adsorption capacity of PAAN in drilling fluids is increased by more than 66.9 % compared with that of PAA, which improves clay hydration and promotes clay dispersion, and ultimately reduces filtration of drilling fluids and stabilizes drilling fluids at high temperatures by more than 23.7 %. The introduction of NVP and the in-depth analysis of its action mechanism supplemented the anti-temperature mechanism of drilling fluid polymers, aiming to support the research and development of ultra-deep drilling fluid technology.

Construction of coal pitch-based HA-K grafted poly condensates and their excellent anti-temperature and viscosity-reducing properties

Humic acids (HAs) are widely used as filtrate and viscosity reducers in drilling fluids. However, their practical utility is limited due to poor stability in salt resistance and high-temperature resistance. High-temperature coal pitch (CP) is a by-product from coal pyrolysis above 650 °C. The substance's molecular structure is characterized by a dense arrangement of aromatic hydrocarbon and alkyl substituents. This unique structure gives it unique chemical properties and excellent drilling performance, surpassing traditional humic acids in drilling operations. Potassium humate is prepared from CP (CP-HA-K) by thermal catalysis. A new type of high-quality humic acid temperature-resistant viscosity-reducer (Graft CP-HA-K polymer) is synthesized with CP-HA-K, hydrolyzed polyacrylonitrile sodium salt (Na-HPAN), urea, formaldehyde, phenol and acrylamide (AAM) as raw materials. The experimental results demonstrate that the most favorable conditions for the catalytic preparation of CP-HA-K are 1 wt% catalyst dosage, 30 wt% KOH dosage, a reaction temperature of 250 °C, and a reaction time of 2 h, resulting in a maximum yield of CP-HA-K of 39.58%. The temperature resistance of the Graft CP-HA-K polymer is measured to be 177.39 °C, which is 55.39 °C higher than that of commercial HA-K. This is due to the abundant presence of amide, hydroxyl, and amine functional groups in the Graft CP-HA-K polymer, which increase the length of the carbon chains, enhance the electrostatic repulsion on the surface of solid particles. After being aged to 120 °C for a specified duration, the Graft CP-HA-K polymer demonstrates significantly higher viscosity reduction (42.12%) compared to commercial HA-K (C-HA-K). Furthermore, the Graft CP-HA-K polymer can tolerate a high salt concentration of 8000 mg·L−1, measured after the addition of optimum amount of 3 wt% Graft CP-HA-K polymer. The action mechanism of Graft CP-HA-K polymer on high-temperature drilling fluid is that the Graft CP-HA-K polymer can increase the repulsive force between solid particles and disrupt bentonite's reticulation structure. Overall, this research provides novelty insights into the synthesis of artificial humic acid materials and the development of temperature-resistant viscosity reducers, offering a new avenue for the utilization of CP resources.

Polymer nanocomposite ADA@SM as a high-temperature filtrate reducer for water-based drilling fluids and its filtration loss mechanism

High temperatures degrade drilling fluid performance and endanger drilling safety when drilling deep and ultra-deep wells. The development of a new high-temperature drilling fluid additive to maintain drilling fluid performance in high-temperature environments is critical. A polymer nanocomposite (ADA@SM) was synthesized from the monomers styrene (St), methyl methacrylate (MMA), acrylamide (AM), 2-acrylamido-2-methyl-1-propanesulfonic acid (AMPS), and diallyldimethylammonium chloride (DMDAAC) through a free-radical copolymerization reaction. Fourier transform infrared spectroscopy (FT-IR) and nuclear magnetic resonance (1H NMR) were used to characterize the structure of ADA@SM, and transmission electron microscopy (TEM) and scanning electron microscopy (SEM) were used to characterize the microstructure of ADA@SM, indicating that it had a "star-net" structure. TGA analysis showed that the thermal decomposition temperature of ADA@SM was above 274 °C. The rheological and filtration properties of drilling fluids with ADA@SM were studied before and after aging at high temperatures (150–240 °C). The rheological model of the drilling fluid containing 2.5 wt% ADA@SM was found to be consistent with the Herschel-Buckley model. After aging at 220 °C, the filtration loss for API and HTHP was 8.4 mL and 29.8 mL, respectively. Using particle size analysis and zeta potential analysis, ADA@SM produced a drilling fluid with good particle size distribution and colloidal stability in high temperature environments. SEM analysis showed that ADA@SM adsorbed on the surface of the bentonite particles, which improved the compactness of the filter cake. The relative molecular weight (Mn) of ADA@SM decreased from 59671 to 5908 after degradation at high temperatures, and ADA@SM released polymer nanospheres, which effectively reduced the filtration loss of the drilling fluid.

Effect of Qusaiba shale formation on high-pressure high-temperature drilling fluids properties

Drilling operations encounter various problems, many of which affect mud quality and may delay or suspend drilling. Wellbore instability is one of the many problems that drilling engineers face while using water-based drilling fluids (WBDF). When WBDFs contact active clay minerals, they may hydrate and swell, damaging the wellbore. In this study, the effects of Saudi Qusaiba shale kaolin clay on WBDF characteristics were examined. Kaolin clay was used as drilled formation cutting at different concentrations (5, 10, 20, and 30 lb/bbl). A detailed study examined how kaolin clay affects mud. Drilling fluid density, alkalinity, rheological, viscoelasticity, filtration behavior, and particle settling were examined before and after adding kaolin clay particles. Experimentally, the higher temperature of the practical environment was simulated by bringing the temperature up to 250 °F. The results showed that there are two clusters of kaolin clay below and above 10 lb/bbl. Kaolin clay concentrations over 10 lb/bbl had a negative effect on fluid characteristics, whereas lower amounts had very little effect. The apparent viscosity (AV) increased by 3% and 16% at 5 and 10 lb/bbl, but it jumped to 72% and 89% after 20 and 30 lb/bbl of kaolin clay. At 20 and 30 lb/bbl of kaolin clay, the yield point (YP) increased by 213% and 377%, respectively. Time sweep indicated continual gel strength increase. The addition of kaolin clay reduced the alkalinity of the WBDF which allowed the clay minerals to swell. Furthermore, the filter cake thickness and filtration volume showed a gradual increment as the concertation of the kaolin clay increased due to the accumulation of the clay solid in the filter cake layer.

Application of Hybrid Silicate as a Film-Forming Agent in High-Temperature Water-Based Drilling Fluids.

Effective control of shale swelling and lost circulation using drilling fluid is considered the dominant strategy for maintaining borehole stability, especially drilling operations in deep oil and gas wells. In this work, a hybrid silicate that contains lithium silicate and potassium methyl silicate (PMS) was employed as a film-forming additive to reduce shale hydration and filtration loss in the high-temperature drilling fluid. Scanning electron microscopy (SEM) results revealed that a dense quartz crystal film coating on the shale can be formed in a hybrid silicate solution when the temperature exceeds 150 °C. The in situ-formed film on the shale surface with a thickness of 60–130 μm was composed of fibrous crystalline silica. Furthermore, the aqueous hybrid silicate exhibited enhanced hydration inhibition ability by preventing water invasion of the formation. Aqueous hybrid silicate with a concentration of 0.5–3 wt % lithium silicate and 0.1–0.2 mol/L PMS was first chosen to obtain the optimum concentration according to the hydration inhibition ability and film formation characteristics. The hybrid silicate was added into a drilling fluid formulation applicable in high-pressure and high-temperature conditions, and the rheological characteristics and filtration properties were investigated. The results confirmed that drilling fluids with the addition of hybrid silicate can mitigate variation of viscosity and yield point before and after aging at 180 and 220 °C. Besides, the filtration behavior was also improved by adding hybrid silicate into the drilling fluid. A lower filtration loss was observed at the concentration of 1.0 wt % lithium silicate and 0.2 mol/L potassium methyl silicate, which showed 63 and 50% HPHT fluid loss reduction for unweighted and weighted formulations at 205 °C and 3.5 MPa, respectively. In addition, the drilling fluid featured stable rheological and filtration properties and excellent shale hydration inhibition characteristics when exposed to high temperatures, making it a promising candidate for drilling in deep oil and gas wells.

Rectorite drilling fluid: high-temperature resistance for geothermal applications

This study aims to resolve some existing limitations of geothermal drilling and exploration of high-temperature drilling fluid systems, such as complex formulation, inconvenient preparation, inappropriate selection of additives, unstable high-temperature performance, and high costs, through theoretical, experimental, and microstructural analysis. The slurry-making ability of several relevant clay minerals were theoretically analyzed based on their slurry-making performance and rheological behavior under various high-temperature environments (i.e., 180, 200, and 220 °C). Rectorite was selected as the appropriate slurry-making clay mineral and was modified organically using a single colloidal material (LP). In addition, suitable high-temperature additives were selected to improve the performance of the drilling fluid system by reducing filtration loss and preventing borehole collapse during geothermal drilling. The proposed drilling fluid system exhibited a simple system structure, excellent rheological performance under high temperatures, reduced filtration loss, and inhibitory and anti-pollution characteristics. The microstructure of rectorite was analyzed using x-ray diffraction, infrared spectrometry, and environmental scanning electron microscopy. It was verified that the microstructural mechanisms improved the temperature resistance of the drilling fluid system, thus helping to solve the critical problems in high-temperature geothermal well drilling and other production processes.

Numerical modeling for drilling fluid invasion into hydrate-bearing sediments and effects of permeability

Drilling fluid invasion into hydrate-bearing sediments could induce hydrate dissociation and complicate heat and mass transfer around wellbore, and further affect mechanical strength of hydrate-bearing sediments and accurateness of wellbore logging interpretations. In this study, a cylindrical numerical model was established to study the characteristics of drilling fluid invasion into hydrate-bearing sediments and the effects of permeability on this process. The distributions of temperature, pressure, saturation, and salinity of pore water around wellbore at different time were obtained. The pressure and temperature around wellbore gradually increase, and the hydrate around wellbore dissociates with the high-temperature drilling fluid invasion. Meantime, water and gas generated from hydrate dissociation gradually migrate outward and then form ‘secondary hydrate’ in some areas outside wellbore. Dissociation and formation of hydrate can sharply change the salinity of pore water around wellbore. The drilling fluid invasion and hydrate dissociation ranges become larger when the intrinsic permeability is higher. The salinity in sediments decreases sharply while the dilution range is narrow when drilling fluid invasion into hydrate-bearing sediments with low permeability. In addition, the permeability decline exponent of the Masuda model has a significant influence on drilling fluid invasion. However, the Corey exponents of the relative permeability model only have a limited influence on drilling fluid invasion into hydrate-bearing sediments with low intrinsic permeability (e.g., 5.5 mD), while they have a noticeable influence on hydrate-bearing sediments with high intrinsic permeability (e.g., 75 mD).

Experimental study of the drilling process in hydrate-bearing sediments under different circulation rates of drilling fluid

Natural gas hydrate (NGH) is widely considered a potential alternative to traditional energy resources. Some countries are trying to exploit and utilize NGH. However, due to the sensitivity of the hydrate, and a lack of exploitation experience with the NGH, drilling in hydrate reservoirs is considered risky. In order to understand the disturbance effects of drilling fluid with different circulation rates on the hydrate-bearing sediments during the drilling process, a novel hydrate drilling experimental apparatus was used to study the drilling process in the hydrate-bearing sediments. Four drilling experiments were carried out in consolidated sediments containing Tetra-n-butyl ammonium bromide (TBAB) hydrate. The drilling fluid injection rate ranges from 500 to 1800 g/min. The results show that hydrate dissociation can be induced by the circulation of relatively high-temperature drilling fluid when drilling in hydrate-bearing sediments, and that the hydrate dissociation rate is greatly influenced by the circulation rate of the drilling fluid. The drilling fluid invasion area has a maximum as the experiment progresses. Increasing the drilling fluid circulation rate can enhance the sediment temperature rise rate, enlarge the hydrate dissociation region, and increase cumulative TBAB production. Drilling fluid with a relatively low circulation rate is beneficial to wellbore stability. These findings will provide help with drilling design suitable for hydrate-bearing sediments, and provide a scientific basis for achieving safe drilling in hydrate-bearing sediments.

Research and application of high−temperature drilling fluid designed for the continental scientific drilling project of Songliao Basin, China

ABSTRACT Well Songke−2 is the main hole of the Continental Scientific Drilling Project of Songliao Basin, China, and its bottom hole temperature is estimated to exceed 240°C in the fourth spud at the well depth of 5800 m. To ensure that the drilling fluid could meet the demand of high temperature resistance, different components, including clay, filtration reducers and anti−collapse additives, of the high–temperature drilling fluid system were optimized through thermal stability tests. Comprehensive test results suggested that the optimal bentonite content to be 4% (w/v). Compared with other materials of the same type, polymer filtration reducers SO−1 and HLW−1, as well as sulfonation additive LOCKSEAL were demonstrated to have stronger resistance to high temperature. The proposed high temperature drilling fluid formula exhibited good thermal stability, rheological behaviour, anti−contamination capacity and shale inhibition property. Finally, a great success of the formula was practically obtained in the field application during the following−up core drilling project.

Experimental study on heat transfer in hydrate-bearing reservoirs during drilling processes

Heat transfer is difficult to predict in hydrate-bearing reservoirs during drilling, especially during drilling fluid invasion, which may induce hydrate dissociation and cause accidents such as wellbore instability, landslide, and collapse. In this research, we simulated the real drilling process in a three-dimensional large-scale hydrate-bearing reservoir with circulating drilling fluid. The real-time temperature variations at different positions in the sediments were measured under different reservoir's initial temperatures to reflect the processes of drilling fluid invasion and hydrate phase transitions. The results indicate that the heat transfer process in hydrate-bearing reservoirs can be divided into six periods and thus, is more complex than that in conventional reservoirs, where heat transfer processes can be divided into three periods; this is due to the coupled effects between drilling fluid invasion and hydrate phase transitions. On the one hand, high-temperature drilling fluids can decompose the original hydrates, while hydrate dissociation can absorb heat and reduce the surrounding temperature. Further, the local pressure increase due to the fluid discharged from hydrate dissociation may also delay drilling fluid invasion. Hydrate dissociation and reformation can also alter the original pore structure and change the flow state. In this study, a temperature profile close to the equilibrium temperature corresponding to the reservoir pressure was observed, indicating the period of hydrate phase transitions. In addition, hydrate dissociation occurred earlier and faster when the reservoir's initial temperature was higher. Therefore, it was suggested that a suitable temperature (not much higher than the reservoir's initial temperature and as much as possible below the phase equilibrium) of the drilling fluid should be chosen to maintain the hydrate-bearing layer stability and avoid unnecessary accidents during deepwater drilling.

Rheological property measurement of drilling fluids used in geothermal wells

With the goal of increasing understanding of drilling fluid temperature behaviour during geothermal well drilling operations, and for providing a database for a better development of numerical wellbore simulators, an experimental work based on a rheological evaluation of drilling fluids was carried out. High-temperature drilling fluid systems (HTDFS) which are most commonly used in the Mexican geothermal well drilling industry were selected and evaluated. Eleven water-based drilling fluids were formulated and chemically characterised in order to carry out the rheological evaluation. Dynamic experimental tests considering the non-Newtonian behaviour of such HTDFS were performed using a coaxial cylinder-type viscometer (Fann 50C). Drilling fluid viscosities in a programmed temperature range of 25–180°C (at a constant reservoir pressure and a shear rate of 3448.2 kPa and 170 s −1, respectively) were measured. These dynamic viscosity measurements were then fitted to derive correlating equations for determining the drilling fluid viscosity as a function of temperature. Details of the experimental rheological tests including a complete description of the equipment and all the HTDFS used as well as the derived viscosity–temperature equations are presented.

Factors Involved in High-Temperature Drilling Fluids

Abstract Statistics show an increase in the average depth of wells drilled in recent years. As a corollary to this trend, drilling fluids have been improved in an effort to meet the problems inherent at temperatures approaching 500F. Of importance are (1) deterioration of mud components and (2) the effect of solids on filtration and rheological properties. High-temperature, stable water-base and oil-base muds are discussed. Those areas in which differences exist are pointed out. Results are based on data taken from the Fann consistometer, rheometer and shear-strength measurements, static and dynamic filtration tests, methylene blue test for bentonite solids and specific heat measurements of muds. Introduction Higher well temperatures go along with the fact that the average depth of wells continues to increase. Recent data by Gardner lists 137 completions deeper than 15,000 ft for the first half of 1964 with a record second-half total of 167 wells drilling or proposed, In addition, there has been an increase in drilling for steam for power production or mineral recovery. In this application the depths are modest, but the mud may approach the critical pressure and temperature of water. Scearce and Magnon report drilling mud used at temperatures of about 700F in the Salton Sea area of California. Most deep wells have been drilled with water-base muds. In recent years, however, there has been a substantial increase in the use of oil-base muds because of technological advances in effective additives. The significance of this development was dealt with in considerable detail by Simpson and his co-workers. Additional field data have now been obtained to indicate that oil muds are competitive in control, performance and cost with the best types of water muds for use at high temperature. This parallel offer of two very different fluid systems, each offering a similar variability in performance, cost and convenience, has created the need to evaluate the merits of these fluids under specified conditions so that the advantages and disadvantages of each can be weighed in relation to the over-all drilling program. This paper is not intended as a review of all the factors. Rather, it attempts to emphasize:important conditions and facts peculiar to high-temperature drilling muds,that more than one imposed test condition or testing method is necessary to describe the quality of a mud at high temperature andthat elaborate experimental precautions are necessary whenever laboratory data are used in selection of a mud for field use. WHAT IS A HIGH-TEMPERATURE DRILLING FLUID? For the purpose of this discussion, a high-temperature drilling fluid is any system so formulated or treated to economically minimize the effects of temperature on the properties of the fluid. Our experience in drilling fluids suggests that these effects become obvious for many mud materials at temperatures of 300F or higher. It is understood that hydrolysis of starches, depolymerization of certain organic thinners, or irreversible chemical reactions (such as that of clay and lime) can affect filtration, viscosity and shear strength at less than 300F. However, the temperature level is not a serious point and in no way affects the precautions and techniques used in this study. An up-to-date review of the literature on high-temperature drilling fluids and the many variations was treated by Rogers in 1963. EXPERIMENTAL REQUIREMENTS TESTING EQUIPMENT AND PROCEDURES With the advent of deeper drilling and increased demand for temperature-stable drilling fluids, new testing equipment and laboratory techniques were devised for the evaluation of drilling fluids subjected to elevated temperature and pressure. While the equipment has not been standardized, it is in widespread use. Milligan et al. describe a filtration cell for determining the filtration properties of drilling fluids at temperatures in excess of 300F. They showed the effect of variations in temperature and pressure on oil and water muds filtered in the 300 to 400F range. The dynamic filtration apparatus described by Simpson permits the study of the filtration properties to temperatures of 350F for drilling fluids circulated over sandstone cores. Watkins et al. describe the use of pressure bombs for studying the effect of prolonged periods of elevated temperature upon the gelation or solidification of drilling fluids. Chisholm et al. describe the use of a modified cement consistometer adapted for use in drilling fluid evaluations. A similar consistometer is used in this study, although the application and data-recording method have been changed. The consistency of a mud sample is measured by timing the movement of a soft iron bob which is magnetically moved up and down in the sample container.* Changes in the time of travel and the temperature of the mud at that moment are plotted with a two-point Brown Electronik Recorder. A 10-in. chart with a speed of 4-in./hr is used. JPT P. 707ˆ