Introduction
Drilling fluids, also known as drilling muds, play a crucial role in the drilling process for oil and gas wells. They are specially formulated fluids that are circulated down the wellbore during drilling operations. Drilling fluids serve several key functions, including cooling and lubricating the drill bit, removing drill cuttings, maintaining wellbore stability, controlling formation pressure, and sealing permeable formations (Caenn and Chillingar, Reference Caenn and Chillingar1996; Caenn et al., Reference Caenn, Darley and Gray2011; Mahmoud et al., Reference Mahmoud, Gajbhiye and Elkatatny2023; Mahmoud et al., Reference Mahmoud, Gajbhiye and Elkatatny2024a; Mahmoud et al., Reference Mahmoud, Gajbhiye and Elkatatny2024b).
The selection of an appropriate drilling fluid is crucial for ensuring wellbore stability and optimizing drilling operations. Drilling fluids typically consist of a base fluid (water, oil, or synthetic) along with various functional additives tailored to address the specific wellbore challenges (Amani et al., Reference Amani, Al-Jubouri and Shadravan2012). Key factors influencing drilling fluid selection include formation type, anticipated pressure and temperature conditions, and environmental considerations (Fakoya and Ahmed, Reference Fakoya and Ahmed2018).
Water-based drilling fluids (WBDFs) represent a cost-effective and environmentally friendly choice for many drilling scenarios. However, their limitations include potential reactivity with some formations, lower lubricity, and reduced thermal stability (Ali et al., Reference Ali, Jarni, Aftab, Ismail, Saady, Sahito, Keshavarz, Iglauer and Sarmadivaleh2020). Additionally, WBDFs can contribute to formation damage and exhibit greater susceptibility to corrosion. In contrast, oil-based drilling fluids (OBDFs) are often preferred for high-pressure and high-temperature (HPHT) environments due to their superior performance characteristics. OBDFs offer enhanced lubricity, improved thermal stability, effective shale inhibition, minimized fluid loss, and reduced formation damage (Caenn et al., Reference Caenn, Darley and Gray2011; Zhuang et al., Reference Zhuang, Zhang, Fu, Ye and Liao2015).
The effective management of drilling fluids is crucial for the success of drilling operations. It is essential to monitor and control several important properties of drilling fluids to ensure their optimal performance. These properties include density, viscosity, gel strength (GS), and filtrate loss (Zhang et al., Reference Zhang, Xu, Christidis and Zhou2020; Karakosta et al., Reference Karakosta, Mitropoulos and Kyzas2021). To address specific challenges encountered during drilling operations, various additives can be employed to modify the properties of drilling fluids. These additives include weighting agents, viscosifiers, fluid loss control agents, dispersants and thinners, and lost circulation materials (LCMs) (Karakosta et al., Reference Karakosta, Mitropoulos and Kyzas2021).
Clay minerals have favorable rheological properties and are used to increase the viscosity and stability of aqueous dispersions by forming a gel-like structure at low solid contents (Zhang et al., Reference Zhang, Xu, Christidis and Zhou2020). Organoclays (OCs) are clay minerals that have been modified chemically to enhance their properties compared with their natural counterparts (de Paiva et al., Reference de Paiva, Morales and Valenzuela Díaz2008). This modification involves attaching organic molecules, such as quaternary ammonium compounds, to the interlayer surfaces of the clay particles (Ogawa and Kuroda, Reference Ogawa and Kuroda1997; de Paiva et al., Reference de Paiva, Morales and Valenzuela Díaz2008). The incorporation of these organic molecules increases the affinity of the clay for non-polar substances, making OCs particularly effective in various applications, notably in the oil and gas industry (Jordan, Reference Jordan1961). In this industry, OCs are commonly used as additives to control the rheological properties and enhance the performance of drilling fluids. They are particularly advantageous in OBDFs and synthetic-based drilling fluids (SBDFs) due to their ability to adsorb and stabilize oil droplets and other non-polar substances within the fluid (Akkal et al., Reference Akkal, Cohaut, Khodja, Ahmed-Zaid and Bergaya2013; Hermoso et al., Reference Hermoso, Martinez-Boza and Gallegos2014; Zhou et al., Reference Zhou, Zhang, Tang, Wang and Liao2016; Zhuang et al., Reference Zhuang, Zhang, Wu, Zhang and Liao2017; Zhuang et al., Reference Zhuang, Zhang, Peng, Gao and Jaber2018a; Zhuang et al., Reference Zhuang, Zhang, Yang and Tan2018b; Weng et al., Reference Weng, Gong, Liao, Lv and Tan2018; Msadok et al., Reference Msadok, Hamdi, Rodríguez, Ferrari and Srasra2020). The identification and development of novel OCs possessing desirable attributes for OBDFs remains a dynamic and ongoing area of scientific research. A comprehensive overview of studies that have utilized OCs in OBDF applications is shown in Table 1.
Table 1. Overview of studies that used OCs in OBDF applications
Claytone-ER, an organophilic phyllosilicate, is a modified layer silicate with enhanced affinity for organic molecules due to the replacement of inorganic cations with organic ones through ion exchange (Murray, Reference Murray1991; Jaber and Miehé-Brendlé, Reference Jaber and Miehé-Brendlé2008; Brigatti et al., Reference Brigatti, Galán, Theng, Bergaya and Lagaly2013). The resulting properties of hydrophobicity, swelling capacity, thermal stability, thixotropy, and large surface area make it a valuable additive in oil-based drilling fluids, facilitating wellbore stability, fluid viscosity control, and efficient cuttings removal (Zhuang et al., Reference Zhuang, Zhang and Jaber2019a; Mahmoud et al., Reference Mahmoud, Gajbhiye and Elkatatny2023).
OCs, while studied extensively in clay/polymer nanocomposites, remain an area of active research in the oil and gas industry due to their potential in enhancing the performance of OBDFs. Recent studies have demonstrated promising advancements in modifying OCs to improve their rheological and thermal properties in OBDFs (Zhou et al., Reference Zhou, Zhang, Tang, Wang and Liao2016; Zhuang et al., Reference Zhuang, Zhang, Wu, Zhang and Liao2017; Zhuang et al., Reference Zhuang, Zhang, Peng, Gao and Jaber2018a; Zhuang et al., Reference Zhuang, Zhang, Yang and Tan2018b; Zhuang et al., Reference Zhuang, Gao, Peng and Zhang2019b; Ghavami et al., Reference Ghavami, Hasanzadeh, Zhao, Javadi and Kebria2018). However, challenges persist, particularly in ensuring the long-term stability of OCs under harsh downhole conditions, addressing their potential environmental impact, and achieving a balance between performance and cost-effectiveness. Additionally, the complex interplay between OCs and other OBDF components necessitates further research to develop accurate predictive models for optimal fluid design.
A critical review of the existing literature revealed several key challenges and research gaps that must be addressed to fully harness the potential of OCs in OBDFs and ensure their sustainable application. One primary concern is the environmental impact of OCs (Guégan, Reference Guégan2019). While their derivation from natural clay minerals suggests a degree of biodegradability, a comprehensive assessment of their long-term environmental fate and potential toxicity is lacking. Studies investigating the bioaccumulation and ecological effects of OCs in marine environments are particularly crucial, given the potential for OBDF discharge during offshore drilling operations. Furthermore, the development of biodegradable or non-toxic alternatives to conventional OCs could significantly mitigate environmental risks. Another critical area is the optimization of OC performance under extreme drilling conditions (Geng et al., Reference Geng, Qiu, Zhao, Zhang and Zhao2019; Zhuang et al., Reference Zhuang, Zhang and Jaber2019a; Mahmoud et al., Reference Mahmoud, Gajbhiye and Elkatatny2023). While OCs exhibit promising rheological properties at ambient temperatures, their behavior under HPHT conditions remains poorly understood. Research focused on characterizing the thermal stability, shear degradation, and fluid-loss properties of OCs under HPHT conditions is essential to ensure the consistent and reliable performance of OBDFs in challenging drilling environments. In addition, the development of novel OC formulations tailored for specific HPHT conditions could significantly enhance drilling efficiency and wellbore stability. The compatibility of OCs with other OBDF additives is also a crucial consideration (Zhuang et al., Reference Zhuang, Zhang, Peng, Gao and Jaber2018a, Zhuang et al., Reference Zhuang, Zhang and Jaber2019a; Mahmoud et al., Reference Mahmoud, Gajbhiye and Elkatatny2023). The complex interplay between OCs, emulsifiers, wetting agents, and fluid-loss control agents can significantly impact the overall rheological properties and stability of OBDFs. A systematic investigation of these interactions is necessary to optimize OBDF formulations and ensure synergistic effects between components. The development of predictive models for OC compatibility could aid in the design of tailored OBDFs for specific drilling applications. Furthermore, the cost-effectiveness of OCs warrants a comprehensive assessment (Guégan, Reference Guégan2019). While their initial production cost is relatively low, their overall economic viability in OBDFs depends on factors such as optimal dosage, long-term performance, and environmental remediation costs. A comparative analysis of OCs with alternative viscosifiers, considering both technical performance and economic implications, is crucial to guide informed decision-making in the drilling industry.
The objectives of the present study were to determine the effect of Claytone-ER on the rheological and filtration characteristics of OBDFs under HPHT conditions. The study aimed to compare the performance of Claytone-ER with an existing OC (MC-TONE). In MC-TONE, ‘MC’ stands for modified clay, and ‘TONE’ is part of the manufacturer’s chosen trade name and does not have a specific technical meaning beyond branding. This study also aimed to assess the ability of Claytone-ER to improve the suspension, gelling, and filtration capabilities of OBDFs. A further goal was to study mud properties, including mud density, electrical stability, sagging tendency, rheology, viscoelasticity, and filtration, in order to develop a stable and high-performing formulation.
Materials and methods
Materials
A Hamilton beach mixer was used to prepare two invert emulsion samples at ambient conditions. The drilling fluid was formulated as an 80:20 invert emulsion. The experiment used a mud formulation consisting of the components detailed in Table 2. Diesel is a liquid fuel derived from the fractional distillation of crude oil. It is a mixture of medium-weight hydrocarbon chains with hydrophobic properties. The primary emulsifier (MC-PE) is the key agent responsible for the creation and maintenance of the oil-water emulsion. It efficiently distributes and dissolves both polar and non-polar components. The secondary emulsifier (MC-SE), also known as a co-emulsifier, is used in combination with the primary emulsifier to improve emulsion stability and efficacy. It helps in reducing the interfacial tension between the oil and water phases, hence avoiding phase separation. The secondary emulsifier was chosen based on its compatibility with the primary emulsifier and its ability to synergistically enhance the emulsification process. Carboxylic acid-terminated fatty polyamides function as emulsifiers due to their amphiphilic nature. The molecule possesses a polar, hydrophilic carboxylic acid head group (COOH) that associates readily with water. Conversely, the long, hydrophobic fatty acyl chain interacts favorably with oil. This allows its molecules to adsorb at the oil–water interface, with the head group oriented toward water and the tail group residing in the oil phase. This positioning disrupts intermolecular forces between the oil and water, effectively lowering interfacial tension. Additionally, the fatty acyl chains create a steric hindrance effect, preventing oil droplets from coalescing and destabilizing the emulsion (Liu et al., Reference Liu, Zhang, Li, Li, Chen, Yang, Sun and Zhao2021). Carboxylic acid-terminated fatty polyamide is typically considered an anionic emulsifier. Lime is a strong base commonly used as a pH modifier. It acts firstly to react with fatty acid emulsifiers, forming calcium soaps that stabilize the essential water-in-oil emulsion. Secondly, lime serves as a source of alkalinity (OH– ions), promoting the formation of these emulsifiers while also maintaining a slightly high pH for optimal corrosion control and the scavenging of acidic gases such as H2S and CO2 encountered during drilling operations. Claytone-ER is a specific type of OC specifically designed to be used as an additive in OBDFs and SBDFs. The synthesis involves the modification of a smectite clay, typically montmorillonite, through intercalation with a quaternary ammonium compound. The specific gravity of Claytone-ER is 1600 kg m–3 and has a bulk density of 352 kg m–3. This product is supplied by BYK USA Inc. (Wallingford, CT, USA) in the form of a free-flowing powder. MC-TONE is a specific type of organophilic phyllosilicate clay that is used in formulating OBDFs in field formulations in Saudi Arabia. It is a commercial product supplied by Midad Holdings Company, a drilling fluid service company located in Al Khobar, Saudi Arabia. Organophilic lignite is a type of lignite coal that has been modified chemically to make it more compatible with organic solvents and drilling fluids used in the oil and gas industry. Organophilic lignite, prepared by modifying lignite coal with amine groups, enhances its interaction with the oil phase in oil-based drilling fluids. This improved compatibility allows for better dispersion and potentially creates a physical barrier at the oil–water interface, hindering droplet coalescence and contributing to a more stable emulsion with improved filtration control and rheological properties. Barite is a dense, naturally occurring mineral commonly used as a weighting agent in drilling fluids. Stainless-steel cups were used to prepare the drilling fluid samples and the mixing speed was set at 1042.7 rad s–1. To ensure the proper function of the mud components, the additives were added sequentially and mixed for 10 min each except for the secondary emulsifier and lime which were mixed for 5 min. Diesel was obtained from a local gas station and the additives used to prepare the mud recipes were supplied by Midad Holdings Company, a drilling fluid service company located in Al Khobar, Saudi Arabia.
Table 2. Mud formulation used in this study
Experimental work
The following procedure provided a series of tests aimed at examining the influence of Claytone-ER on various drilling fluid properties:
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(1) The drilling fluid mixture was prepared under ambient conditions using a Hamilton Beach mixer.
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(2) Mud density and electrical stability were measured under ambient conditions.
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(3) Static sagging tests were conducted after aging the drilling fluid sample at HPHT conditions (135°C and 3447.38 kPa differential pressure) for 24 h.
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(4) Dynamic sagging tests were performed using a sag shoe and grace viscometer (model M3600) at 65°C and 10.47 rad s–1 to simulate downhole shearing.
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(5) The amplitude sweep tests were conducted after hot rolling (AHR) the samples at 135°C and 3447.38 kPa differential pressure for 16 h to determine the linear elastic region of the fluid.
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(6) Angular frequency tests were performed AHR at 135°C and 3447.38 kPa differential pressure for 16 h to measure the storage modulus of the fluid.
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(7) Time sweep tests were carried out AHR at 135°C and 3447.38 kPa differential pressure for 16 h to assess the thixotropic behavior.
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(8) The rheological properties of the mud samples were measured AHR at 135°C and 3447.38 kPa differential pressure for 16 h. This step involves utilizing the grace viscometer (model M3600) to measure different rheological parameters such as PV, YP, AV, and GS. These parameters determine the drilling fluid’s flow behavior and carrying capacity.
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(9) The filtration properties were measured using the HPHT filter press at 135°C and 3447.38 kPa differential pressure.
Material characterization
The mineralogical, elemental, and textural features of two OCs were studied using particle size distribution (PSD), X-ray diffraction (XRD), X-ray fluorescence (XRF), and scanning electron microscopy (SEM) to gain a complete understanding of the materials.
XRD analysis used a Panalytical Empyrean (Malvern, UK) diffractometer in Bragg-Brentano geometry. The instrument was equipped with a reflection-transmission spinner stage and a Cu X-ray tube source (Kα1=1.54060 Å, Kα2=1.54443 Å). Data were acquired over a 2θ range of 4° to 70° with a step size of 0.013° and a scan step time of 8.67 s. The tube current and voltage were set to 40 mA and 45 kV, respectively. Phase identification and analysis were carried out using HighScore Plus software and the PDF-4 2024 database. The powder sample was prepared using a back-loading method to minimize the preferred orientation. A fine powder of the sample was carefully packed into a 27 mm diameter zero-background silicon sample holder, ensuring a flat sample surface. The holder was then mounted on the reflection-transmission spinner stage of the Empyrean diffractometer. Samples were scanned in step-scan mode from 70°2θ with a step size of 0.0130°2θ and dwell time of 8.6700 s. The sample was spun at 0.4189 rad s–1 during the measurement.
Elemental analysis was performed using a Bruker M4 Tornado micro XRF spectrometer equipped with a rhodium (Rh) anode X-ray tube and a Bruker XFlash silicon drift detector (SDD). The X-ray tube was operated at 50 kV with a current of 199 μA, producing a spot size of 20 μm using poly-capillary X-ray optics. The chamber pressure was maintained at 20 mbar. A sample stage with dimensions of 330×170×120 mm accommodated the specimens. Quantification and elemental distribution analysis were conducted using Bruker M4 software. The M4-Tornado Micro-XRF is a powerful instrument manufactured by Bruker (Billerica, MA, USA). It belongs to the latest generation of μ-XRF spectrometers. Easy sample handling, fast measurements, and a wide range of standardless quantification routines are some of its highlights. Moreover, the system offers several special features including a large vacuum sample chamber, high spatial resolution, and a fast stage for distribution analysis. It is a non-destructive analytical technique used to identify the elemental composition of a sample by measuring the fluorescent X-rays emitted from its atoms when excited by an X-ray source. The powdered samples are compressed in small plastic cups to run through the XRF machine.
SEM was performed using a JEOL JSM-5900LV instrument (JEOL Ltd, Japan), equipped with an Oxford energy dispersive X-ray analysis (EDS) system (Oxford, UK). Samples were cut to 1 mm2 from the center of the collection filters and mounted on SEM stubs using a combination of conductive carbon tape and graphite paint before sputter coating with gold to enhance conductivity. A magnification of 500× was used with instrument operating parameters of 20 kV acceleration voltage, a working distance of 10 mm, and a secondary electron detector (SED) for imaging. The beam current was set to 200 pA.
For particle-size determination, samples were dispersed in 300 mL of DI water at 20°C then analyzed by laser light scattering using a Sympatec HELOS particle size analyzer (Ettlingen, Germany). The optical concentration, which refers to the amount of light obscuration caused by the particles in the dispersed sample, was adjusted to 10.98%. The curvature of the measurement zone was set to 2.0 mm, and the pump speed was 31.4 rad s–1. During analysis, the sample was pulse sonicated for 60 s on, followed by 10 s off. Data were analyzed using Windox 5 software.
Density and electrical stability
The drilling fluid density was determined gravimetrically using a Fann Model 140 mud balance (Fann Instrument Company, Houston, TX, USA). The balance was zeroed on a level surface before measurement. Following standard operating procedure, the sample cup was filled with the drilling fluid, ensuring no air entrapment. The balance arm was placed on the base, and the rider adjusted until equilibrium was achieved. Density was recorded directly from the graduated scale.
The electrical stability of the drilling fluids was assessed via a Fann Model 23D Electrical Stability Tester (Fann Instrument Company, Houston, TX, USA) under ambient conditions. Following a 30 s stirring period to ensure sample homogeneity, the instrument’s probe was immersed in the fluid contained within the provided stainless steel cup. Care was taken to avoid probe contact with the cup walls. The sinusoidal alternating voltage applied across the probe’s parallel plate electrodes was incrementally increased until breakdown occurred. The corresponding breakdown voltage, indicative of electrical stability, was recorded. This measurement was repeated three times, and the average voltage was calculated. A minimum electrical stability of 400 V is generally recommended for adequate performance in OBDFs (Zanten et al., Reference Zanten, Miller and Baker2012).
Sagging tests
Static sagging tests
To evaluate the static sagging behavior of the drilling fluids, an HPHT aging test was conducted. Drilling fluid samples were aged at 135°C and 3447.38 kPa for 24 h in an M1741 aging cell (Grace Instrument Company, Houston, TX, USA). Following the aging period, the sag factor (SF), a dimensionless parameter indicative of barite sag tendency, was determined. This involved measuring the drilling fluid density at both the top and bottom of the aging cell and calculating the SF according to Eqn 1. This procedure was performed with the aging cell oriented both vertically and at a 45° inclination to assess sagging behavior under different wellbore conditions. The acceptable range for the SF is typically between 0.50 and 0.53 (Maxey, Reference Maxey2007).
$$ \mathrm{SF}=\frac{\unicode{x03C1}_{\mathrm{bottom}}}{\unicode{x03C1}_{\mathrm{bottom}}+{\unicode{x03C1}}_{\mathrm{top}}} $$
Dynamic sagging tests
The dynamic sagging tendency of the drilling fluids was evaluated using a Grace M3600 viscometer (Grace Instrument Co.) equipped with a sag shoe attachment. The test procedure, conducted at atmospheric pressure and 65°C, was as follows:
Dynamic sagging tests are commonly used to evaluate the rheological properties of drilling fluids. These tests help to determine the ability of the fluid to suspend and carry cuttings during drilling operations (Amighi and Shahbazi, Reference Amighi and Shahbazi2010). The sagging behavior of a drilling fluid refers to its tendency to settle or separate under the influence of gravity. The dynamic sagging test was performed at atmospheric pressure and 65°C using a grace viscometer (model M3600, Grace Instrument Co.) to provide the required rotation. The recommended range for the viscometer sag shoe test (VSST) value is between 0 and 119.8 kg m–3 (Aldea et al., Reference Aldea, Growcock, Lee, Friedheim and Oort2001; AlAbdullatif et al., Reference AlAbdullatif, Al-Yami, Wagle, Bubshait and Al-Safran2014).
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(1) The sag shoe was immersed in the viscometer’s thermocup, and the drilling fluid sample was added until its upper surface reached the lower edge of the viscometer sleeve. The thermocup was then lowered by 7 mm.
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(2) The drilling fluid (140 mL) was heated to 65°C to simulate downhole temperature conditions.
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(3) The viscometer was operated at a rotational speed of 10.47 rad s–1 for 30 min to simulate shear conditions experienced during drilling operations.
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(4) A 10 mL fluid sample was extracted from the thermocup at the beginning and end of the test period using a syringe with a cannula. The mass of each sample was recorded (W 1 and W 2, respectively).
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(5) The viscometer sag shoe test (VSST) value was calculated using Eqn 2:
$$ \mathrm{VSST}=0.833\times \left({W}_2-{W}_1\right) $$
The VSST value quantitatively measures the drilling fluid’s dynamic sagging behavior. Acceptable VSST values typically fall from 0 to 119.8 kg m–3 (Aldea et al., Reference Aldea, Growcock, Lee, Friedheim and Oort2001; AlAbdullatif et al., Reference AlAbdullatif, Al-Yami, Wagle, Bubshait and Al-Safran2014).
Amplitude, frequency, and time sweep tests
Amplitude sweep tests
The linear viscoelastic (LVE) properties of the drilling fluids were investigated using an Anton-Paar MCR-302 rheometer (Anton Paar GmbH, Graz, Austria). Oscillatory amplitude sweep tests were conducted at a constant frequency of 10 rad s–1. The shear strain amplitude was incrementally increased from 0.01% to 100% to determine the LVE range and assess the impact of the novel OC on the storage modulus (G′) and loss modulus (G′′). The LVE region, defined as the range of strain amplitudes over which G′ and G′′ remain constant, provides insights into the fluid’s elastic and viscous behavior, respectively, under small deformation conditions.
Frequency sweep tests
A frequency sweep test involves applying a constant amplitude or shear strain to the drilling fluid while varying the frequency of oscillation. This test measures the fluid’s response to different shear frequencies and provides information about its viscoelastic behavior at varying rates of deformation. This helps understand the fluid’s flow behavior under various drilling conditions and optimize its performance. The frequency test was carried out at different frequencies (0.1–100 rad s–1) and the constant shear strain was selected from the linear range to study the elasticity behavior of the inner structure. To avoid sagging, which happens when the heavier parts move down and the lighter parts stay on top, the frequency went from 100 s–1 to 0.1 s–1 in steps.
Time sweep tests
The evolution of viscoelastic properties over time was monitored via time sweep tests. A constant shear stress, within the LVE range, was applied for 60 min, and the corresponding G′ and G′′ values were recorded at regular intervals. This provided insights into the fluid’s structural stability, resistance to settling, and potential for shear-thinning or shear-thickening behavior under constant shear conditions.
Rheology tests
Drilling fluid samples were aged in an M1750 Roller Oven (Grace Instrument Co.) at 135°C and 3447.38 kPa. Rheological properties were then measured using a Grace M3600 viscometer (Grace Instrument Co.) at the aging temperature. The viscometer was programmed to execute a 16-step test sequence, incorporating varying shear rates and rest periods, to comprehensively assess the fluid’s rheological profile.
GS was determined directly from the viscometer dial readings at 0.314 rad s–1 after 10 s, 10 min, and 30 min. PV, YP, and AV were calculated from the viscometer data using the following equations:
$$ \mathrm{PV}={\varnothing}_{600}-{\varnothing}_{300} $$
$$ \mathrm{YP}={\varnothing}_{300}-\mathrm{PV} $$
$$ \mathrm{AV}=\frac{\varnothing_{600}}{2} $$
This comprehensive rheological analysis allowed for the evaluation of the novel OC’s impact on the fluid’s flow behavior and its ability to suspend cuttings and maintain wellbore stability under simulated downhole conditions.
Filtration tests
Filtration properties were evaluated using an Ofite HPHT filter press (OFI Testing Equipment Inc., Houston, TX, USA) with a 63.5 mm diameter filter paper. The test procedure involved placing a pre-weighed filter paper in the filtration cell, adding 350 mL of the drilling fluid, and sealing the cell. A pressure of 3447.38 kPa was applied using nitrogen gas, and the temperature gradually increased to 135°C under static conditions. The filtrate collection valve was then opened, and the filtrate volume was recorded at designated intervals over a 30 min test period. After the test, the cell was cooled, de-pressurized, and the filter cake was removed. The filter cake’s weight and thickness were measured using a digital Vernier caliper.
Results and Discussion
Material characterization
The mineral composition of Claytone-ER and MC-TONE was determined using XRD, which revealed 67.9% illite and 32.1% montmorillonite in Claytone-ER (Fig. 1) and 35.9% feldspar, 29.4% orientite, 25.1% cristobalite, and 9.6% calcite in MC-TONE (Fig. 2). XRF analysis (Table 3) revealed 52.37% Si, 36.17% Al, 10.01% Mg, and 1.45% Fe in Claytone-ER, while MC-TONE OC consisted of 53.67% Si, 14.67% Al, 11.84% Cl, 11.09% Fe, and 7.08% Ca.
Figure 1. XRD pattern of Claytone-ER showing the presence of montmorillonite (Mnt) and illite (Ilt).
Figure 2. XRD pattern of MC-TONE showing the presence of orientite (Ort), cristobalite (Crs), feldspar (Fsp), and calcite (Cal).
Table 3. XRF analysis results for the OCs used in this study
The particle-size analysis of samples Claytone-ER and MC-TONE (Fig. 3) showed that the average particle size (D50) of Claytone-ER was 28.94 μm and that of MC-TONE was 40.01 μm, and the particle-size distribution (PSD) for Claytone-ER was narrower than for MC-TONE. The narrower PSD for Claytone-ER contributed to its desirable properties such as large surface area, good dispersion, and high brightness. It also contributed to enhanced dispersion and stability in non-polar fluids, such as OBDFs, thereby expanding its potential applications.
Figure 3. Particle-size distribution for Claytone-ER and MC-TONE.
The morphology of Claytone-ER and MC-TONE, as observed using SEM (Fig. 4), revealed differences between the two OCs, while the EDS (Fig. 5) determined semi-quantitatively the elemental composition for the visually analyzed particles of Claytone-ER and MC-TONE. In the SEM images of Claytone-ER, the incorporation of quaternary ammonium compounds in the surface modification treatment resulted in distinct morphological characteristics on the particle surfaces, facilitating their dispersion in non-polar fluids. In addition, the presence of numerous small, irregularly shaped particles with a relatively smooth surface texture was observed. These particles appeared to be loosely packed together, forming a porous structure with multiple small voids and channels. Furthermore, the particles exhibited a platelet-like or stacked configuration, held together in various ways such as hydrogen bonds, ion-dipole interaction, acid-base reactions, charge transfer, electrostatic interaction, and van der Waals forces (de Paiva et al., 2008; Zhuang et al., Reference Zhuang, Zhang, Wu, Zhang and Liao2017; Guégan, Reference Guégan2019). The SEM images also revealed a high level of uniformity and small size distribution, indicating that Claytone-ER is effectively dispersed within non-polar fluids such as OBDFs. In comparison, MC-TONE exhibited greater irregularity and sharper particle edges, which contributed to an increased tendency for sagging.
Figure 4. SEM images of (A) Claytone-ER and (B) MC-TONE.
Figure 5. Elemental composition from EDS for (A) Claytone-ER and (B) MC-TONE.
Density and electrical stability
Adding Claytone-ER instead of the base OC did not alter the mud density, as it remained at 1797.4 kg m–3. Compared with the base OC formulation (863 V), the electrical stability of the Claytone-ER inverted emulsion improved demonstrably by 3% to 891 V (Fig. 6). This was attributed to the relatively small size of Claytone-ER particles, which exhibited a relatively small scale and possessed a large surface area (Sinha Ray and Bousmina, Reference Sinha Ray and Bousmina2005). The quaternary ammonium compounds used in surface-modification treatments made the clay particles more hydrophobic, which reduced their tendency to flocculate under conditions of high salinity or high temperature. This enhanced stability is crucial because flocculation in such environments can lead to a range of drilling problems, including increased viscosity, reduced flowability, poor hole cleaning, increased friction, formation damage, and equipment wear. By mitigating flocculation, Claytone-ER contributes to maintaining desirable drilling fluid properties, such as stable rheology, enhanced lubricity, and improved shale inhibition, even under challenging conditions. This ensures efficient and successful drilling operations, even in demanding environments with high salinity or high temperature. Also, the small average particle size of Claytone-ER contributed toward improved electrical stability by reducing sedimentation rates in suspensions when subjected to an electric field. Due to their reduced mass, smaller particles exhibit lower settling velocities compared with larger particles, resulting in extended suspension periods (Fakoya and Ahmed, Reference Fakoya and Ahmed2018; Ofei et al., Reference Ofei, Lund, Saasen and Sangesland2022). In addition, Claytone-ER exhibited a diminished affinity for water droplets at its solid surfaces within the fluid system. This reduction in water wetting reduced contact between water and conductive solids, thereby mitigating potential issues related to electrical conductivity and stability (Growcock et al., Reference Growcock, Ellis and Schmidt1994; Magalhães et al., Reference Magalhães, Calçada, Scheid, Almeida and Waldmann2016; Borges et al., Reference Borges, De Souza, Vargas, Scheid, Calçada and Meleiro2022).
Figure 6. Effect of Claytone-ER on electrical stability.
Sagging tests
Static sagging tests
The impact of Claytone-ER on settling behavior under vertical and inclined wellbore conditions was evaluated by examining the sag factor (Fig. 7). The results showed that Claytone-ER increased the vertical sag factor to 0.524 compared with 0.515 for the base fluid, but this increase was still within the acceptable range. Also, Claytone-ER decreased the inclined sag factor from 0.531 in the base fluid to 0.50–0.53, which is within the recommended safe range (Maxey, Reference Maxey2007) to 0.521. Claytone-ER had a hydrophobic nature due to its organic modification. When incorporated into OBDFs, it dispersed uniformly throughout the fluid phase and interacted with the oil molecules. This dispersion aided in preventing the settling of solid particles and maintained their suspension within the drilling fluid. In addition, Claytone-ER enveloped and encapsulated solid particles, such as drilled cuttings and other impurities, present in the drilling fluid. This encapsulation enhanced the suspension properties of the particles by reducing their tendency to aggregate and settle. Furthermore, Claytone-ER improved the rheological properties of the drilling fluid. It elevated the viscosity and GS of the fluid, thereby increasing its resistance to settling. Moreover, Claytone-ER exhibited thixotropic behavior, meaning that the viscosity of the fluid decreased when agitated or circulated, and returned to its original viscosity when left undisturbed. This thixotropic behavior ensures that the drilling fluid remains easily pumpable and circulatable during drilling operations, while simultaneously thickening and suspending solids when at rest, thus preventing static sag. Moreover, Claytone-ER enhanced the yield stress of the fluid system, augmenting its resistance against gravitational forces on suspended particles, thus mitigating static sag and promoting stable suspension (Maxey, Reference Maxey2007). The interaction between Claytone-ER and other fluid components influenced the overall suspension stability. Claytone-ER forms a network structure within the fluid, supporting and stabilizing suspended particles and preventing settling or separation (Agarwal et al., Reference Agarwal, Phuoc, Soong, Martello and Gupta2013). In addition, Claytone-ER adsorbs onto particle surfaces, modifying their properties and enhancing overall suspension stability. This adsorption hinders particle aggregation and settling, contributing to static sag prevention (Ghavami et al., Reference Ghavami, Hasanzadeh, Zhao, Javadi and Kebria2018).
Figure 7. Sag factors under static conditions.
Dynamic sagging tests
The influence of dynamic conditions on settling behavior was investigated by analyzing the sag factors. The dynamic sag test data (Fig. 8) showed the advantages of using Claytone-ER as the OC as the VSST decreased significantly from 104.13 to 40.26 kg m–3. This improvement can be attributed to the high dispersion of Claytone-ER. In addition, the use of Claytone-ER in drilling fluid enhanced the suspension of solid particles, such as weighting agents and cuttings. This was achieved through the adsorption of Claytone-ER onto these particles, resulting in the formation of a stable network structure. By doing so, the settling or sagging of these particles under high shear or dynamic conditions is prevented. It is worth noting that fluids with greater viscosity are more resistant to particle settling, even under dynamic conditions. This is due to the increased internal resistance, which makes it more challenging for solid particles to move and settle under the influence of gravity. Moreover, Claytone-ER increased the viscosity and GS of the drilling fluid. This is beneficial as it helps maintain the integrity of the fluid and its resistance to sagging. The interaction between the particles and the constituents of the fluid results in the creation of a three-dimensional structure, which hinders settling and provides improved suspension properties. Furthermore, Claytone-ER possessed a large surface area and adsorption capacity, which further enhanced the suspension properties of the particles. This is achieved by reducing their tendency to aggregate and settle, even during fluid circulation. These enhanced suspension properties contribute to maintaining a homogeneous distribution of solids in the drilling fluid, thereby reducing the risk of dynamic sag. Also, Claytone-ER increased the GS and thixotropic properties of the drilling fluid. Thixotropy refers to the property of a fluid to become more viscous under shear and less viscous when shear is removed (Maxey, Reference Maxey2007; Werner et al., Reference Werner, Myrseth and Saasen2017). Drilling fluid with greater GS and thixotropic properties can better support and suspend solid particles under varying shear rates experienced during drilling operations. This helps to prevent particles from settling and causing dynamic sag. It is worth noting that Claytone-ER exhibited shear thinning behavior, meaning its viscosity decreased under shear stress. This property allowed the drilling fluid to flow more easily during circulation, thereby reducing the tendency to sag. Importantly, the fluid retains its greater viscosity and suspension properties when not subjected to shear forces. The addition of Claytone-ER to drilling fluid enhances the suspension and stability of solid particles under dynamic conditions. Due to its organophilic nature, Claytone-ER interacts with the oil phase, establishing a three-dimensional network that hinders settling and maintains particles in suspension (Ruiz-Hitzky et al., Reference Ruiz-Hitzky, Darder, Alcântara, Wicklein, Aranda, Kalia and Haldorai2015; Zhang et al., Reference Zhang, Xu, Christidis and Zhou2020). This interaction with solid particles forms a network that impedes their settling, particularly significant under dynamic conditions where fluid movement promotes settling. By mitigating settling rate and sedimentation, Claytone-ER contributes to enhanced stability and reduced sagging of the drilling fluid during dynamic operations. Finally, Claytone-ER mitigates the formation of gels or flocculation in OBDFs, which can contribute to sagging and impede fluid flow. By acting as a stabilizer, Claytone-ER prevents interactions between solid particles and other fluid components that lead to gelation or flocculation. This stabilizing effect preserves fluid integrity and reduces sagging tendencies during dynamic conditions.
Figure 8. Comparison of VSST values for MC-TONE and Claytone-ER. The dashed line indicates the upper limit of the safe operating range for optimal drilling fluid performance.
Amplitude, frequency, and time sweep tests
Amplitude sweep tests
The amplitude sweep test results (Fig. 9) illustrated the impact of Claytone-ER on the storage modulus (G′) and loss modulus (G′′) of the drilling fluid. Compared with the base OC fluid, Claytone-ER demonstrably increased both G′ and G′′, particularly within the linear viscoelastic (LVE) region at low shear strains (up to 0.1%). This indicated a solid-like behavior and sagging resistance. Claytone-ER improved the amplitude sweep test performance of OBDFs as greater viscosity fluids have enhanced resistance to deformation and flow, which can improve the fluid’s structure and stability under varying stress amplitudes. By increasing the fluid’s viscosity, Claytone-ER helped maintain a more stable structure, leading to better amplitude sweep test performance. Also, a drilling fluid with enhanced viscoelastic properties can better absorb and dissipate energy under varying stress conditions, as experienced in an amplitude sweep test. This led to improved fluid stability and suspension of solids. Moreover, the addition of Claytone-ER increased the yield stress of the fluid. This means the fluid can carry more cuttings and withstand greater pressure variation, making the drilling process more efficient and stable. In addition, Claytone-ER affected the thixotropic behavior of the fluid, potentially leading to changes in shear thinning characteristics. This property helps suspend cuttings and maintains wellbore stability (Bui et al., Reference Bui, Saasen, Maxey, Ozbayoglu, Miska, Yu and Takach2012; Werner et al., Reference Werner, Myrseth and Saasen2017).
Figure 9. Oscillatory amplitude tests.
Frequency sweep tests
The frequency sweep test results (Fig. 10) suggested enhanced stability of the mud’s inner gel structure with Claytone-ER. This is demonstrated by slightly larger G′ and a more significant increase in G′′ compared with the base fluid. Higher-viscosity fluids have enhanced resistance to deformation and flow, which can improve the fluid’s structure and stability under varying shear rates experienced during the frequency sweep test. By increasing the fluid’s viscosity, Claytone-ER helped maintain a more stable structure, leading to better frequency sweep test performance. Also, Claytone-ER contributed to the gelling behavior of the drilling fluid at lower frequencies. This helps prevent fluid invasion into permeable formations and aids in solids suspension. Furthermore, Claytone-ER induces shear thinning behavior in OBDFs during frequency sweep testing, facilitating flow and pumpability at elevated shear rates or frequencies while maintaining adequate suspension properties (Bui et al., Reference Bui, Saasen, Maxey, Ozbayoglu, Miska, Yu and Takach2012; Ettehadi et al., Reference Ettehadi, Ülker and Altun2022). In addition, Claytone-ER enhances the stability of OBDFs by preserving rheological properties such as viscosity and elasticity across a wide frequency range, ensuring consistent fluid behavior and performance under varying drilling conditions. Finally, the addition of Claytone-ER modifies the frequency-dependent rheological behavior of the fluid, promoting stable viscoelastic properties over a broad frequency spectrum.
Figure 10. Oscillatory frequency tests.
Time sweep tests
The time sweep test results (Fig. 11) revealed a stronger gel structure for the Claytone-ER fluid compared with the base fluid. This is indicated by the larger values of both G′ and G′′ observed for the Claytone-ER formulation. Claytone-ER showed a progressive gel structure due to an increase in the storage modulus over time (Fakoya and Ahmed, Reference Fakoya and Ahmed2018). This is essential for maintaining hole stability during extended drilling periods. By increasing the overall viscosity of the drilling fluid, Claytone-ER helped to maintain a stable structure over time, necessary for suspending solids and avoiding sedimentation. Also, the improved viscoelastic properties provided by Claytone-ER contribute to better energy absorption and dissipation, which can help to maintain the fluid’s stability over longer periods. Moreover, larger GS values resulting from the addition of Claytone-ER assisted the fluid in maintaining its structure and suspending solids even under low or no shear conditions, which is important for long-term stability (Ofei et al., Reference Ofei, Lund, Saasen, Sangesland, Richard and Linga2019). In addition, Claytone-ER improved the thixotropic behavior of the OBDFs, allowing them to recover their structure more quickly after being sheared. Also, Claytone-ER contributes to the stability of OBDF rheological properties during time sweep testing. By forming an internal network, the OC helps maintain viscosity and elasticity over extended periods, ensuring consistent fluid behavior throughout drilling operations. Furthermore, Claytone-ER mitigates changes in viscosity and elasticity by enhancing the fluid’s resistance to shear and deformation. Finally, Claytone-ER imparts shear thinning behavior to OBDFs, facilitating flow and pumpability at greater shear rates while retaining adequate suspension properties (Bui et al., Reference Bui, Saasen, Maxey, Ozbayoglu, Miska, Yu and Takach2012).
Figure 11. Time sweep tests.
Rheology tests
Claytone-ER demonstrably enhanced the drilling fluid’s rheological properties at low shear rates, as evidenced by the greater shear stress and viscosity (Fig. 12) compared with the base OC fluid. This resulted in better sag, gelling, and suspension performance. Claytone-ER was used to adjust the rheology of the drilling fluid. It increased the viscosity and YP of the fluid, helping it carry drill cuttings to the surface more effectively. It also improved the suspension properties of the fluid, preventing solids from settling when drilling operations are paused. The incorporation of Claytone-ER increased significantly the PV of the drilling fluid at low shear rates (Fig. 13). The PV rose by 26.5%, from a baseline value of 22.45 mPa·s to 28.40 mPa·s. This increased flow resistance improved the suspension and transport of drill cuttings, facilitating efficient hole cleaning. In addition, the additive promoted thixotropic behavior, enabling the fluid to thin under shear stress for optimal flow during circulation and subsequently regain viscosity for enhanced carrying capacity and stability (Werner et al., Reference Werner, Myrseth and Saasen2017). The organophilic modification of Claytone-ER enables preferential interaction with non-aqueous components while maintaining a partial affinity for the aqueous phase. This dual affinity facilitates the establishment of an extensive, interlinked network structure within drilling fluids. The resulting house-of-cards arrangement restricted particle movement significantly, leading to elevated internal friction and a marked increase in PV (Shi et al., Reference Shi, Jiang, Shi and Luo2020; Yang et al., Reference Yang, Wang, Sun, Qu, Ren, Zhao, Wang, Li and Liu2024). YP increased significantly by a 98% increment from 12 Pa to 23.72 Pa and the AV increased by a 36.5% increment from 16.75 Pa to 22.85 Pa due to the high particle dispersion and interaction (Fig. 14). Claytone-ER elevated the YP of drilling fluids, enhancing the suspension and transport of drill cuttings and promoting efficient hole cleaning. The increased yield point also contributed to borehole stability by augmenting wall support and resistance to deformation under low-stress conditions (Yang et al., Reference Yang, Sun, Bai, Lv, Zhang and Li2022). Furthermore, the additive’s influence on thixotropic behavior ensures optimal viscosity recovery, contributing to the fluid’s capacity to maintain YP and carrying capacity under dynamic drilling conditions (Vryzas and Kelessidis, Reference Vryzas and Kelessidis2017). The particles interact with one another and other components in the drilling fluid through van der Waals forces, hydrogen bonding, and other intermolecular interactions (de Paiva et al., 2008; Zhuang et al., Reference Zhuang, Zhang, Wu, Zhang and Liao2017; Guégan, Reference Guégan2019). Due to these interactions, fluid particle mobility became hindered and resulted in a heightened resistance to flow at relatively small applied shear stresses. This led to an increase in the PV, which can be adjusted by modifying the concentration of Claytone-ER in the drilling fluid. These results can lead to greater stability, surge and swap pressures, equivalent circulating density, and hole cleaning (Caenn and Chillingar, Reference Caenn and Chillingar1996; Caenn et al., Reference Caenn, Darley and Gray2011). The high viscosity of the Claytone-ER fluid at low shear rates (Fig. 15) probably contributed to its enhanced suspension capability and improved GS development. The GS at 10 s, 10 min, and 30 min increased from 5.15, 5.06, and 5.34 Pa for the base mud to 8.43, 8.52, and 8.62 Pa with Claytone-ER, respectively. Claytone-ER enhanced the stability of the oil-in-water emulsion, which is crucial in drilling operations. A stable emulsion prevents the separation of the oil and water phases, which could otherwise lead to drilling complications. Also, the addition of Claytone-ER helped in the suspension of solids in the drilling fluid. It means that the cuttings from the drilling process are kept in suspension, preventing them from settling down and causing problems such as blocked pipes, or bit balling (when cuttings stick to the drill bit surface when drilling in sticky or water reactive clay), etc.
Figure 12. Effect of Claytone-ER on stress–strain relationship at 135°C.
Figure 13. Effect of Claytone-ER on plastic viscosity at 135°C.
Figure 14. Effect of Claytone-ER on yield point and apparent viscosity at 135°C.
Figure 15. Effect of Claytone-ER on gel strength at 135°C.
Filtration tests
The filtration test results indicated that Claytone-ER enhanced the filtration properties of the drilling fluid. Claytone-ER improved the filtration properties of the drilling fluid demonstrably, as shown by the data in Fig. 16 and 17. Compared with the base fluid, the filtration volume after 30 min decreased by 8% (from 5.0 cm³ to 4.6 cm³), and the filter cake thickness showed a 6% reduction (from 2.60 mm to 2.45 mm). Claytone-ER contributed to fluid loss control, minimizing the amount of drilling fluid that enters the formation. This is crucial for maintaining well control and preventing damage to the formation. In the drilling process, it is essential to keep the fluid within the wellbore and prevent it from being absorbed into the formation. Claytone-ER accomplished this by increasing the viscosity of the fluid and creating a low-permeability filter cake on the wall of the drill hole, both of which help reduce fluid loss. Also, by forming a strong, low-permeability filter cake, Claytone-ER helped to stabilize reactive shales, preventing them from swelling or sloughing off into the wellbore. The additive’s ability to establish a network structure within the drilling fluid contributes to the development of a stable and uniform filter cake, minimizing fluid invasion and subsequent formation damage, thereby optimizing drilling efficiency. This can improve the overall stability of the well and reduce the risk of drilling problems.
Figure 16. Effect of Claytone-ER on filtration volume at 135°C.
Figure 17. Effect of Claytone-ER on filter cake thickness at 135°C.
Conclusions
This study demonstrated the significant potential of Claytone-ER as an additive for enhancing the performance of invert emulsion drilling fluids under HPHT conditions. The observed improvements in electrical stability, sag resistance, rheological properties, viscoelastic properties, and filtration control highlight its multi-faceted benefits and its potential to optimize drilling fluid performance in demanding HPHT environments.
Specifically, Claytone-ER enhanced the electrical stability by 3% compared with the conventional OC (MC-TONE) due to its lower conductivity. It also mitigated effectively the static and dynamic sag, critical for maintaining drilling fluid integrity. The observed improvements in rheological properties, specifically a 26.5% increase in PV, a remarkable 98% increase in YP, and a 36.5% increase in AV, coupled with significant enhancements in GS and viscoelastic properties, translated into superior suspension, hole-cleaning capabilities, and improved cuttings-carrying capacity, ensuring efficient cuttings removal and minimizing the risk of a blocked pipe. Furthermore, the reduction in filtration volume by 8% and filter cake thickness by 6% underscored its potential for minimizing fluid loss and enhancing wellbore stability, contributing to reduced formation damage and improved drilling efficiency.
These findings collectively position Claytone-ER as a promising additive for the oil and gas industry, offering substantial value in terms of improved drilling efficiency, reduced non-productive time, and enhanced wellbore integrity. The enhanced performance facilitated by Claytone-ER has the potential to translate into significant cost savings and improved operational outcomes in HPHT drilling operations. Further research exploring the long-term effects and broader applicability of Claytone-ER in diverse drilling scenarios could unlock even greater potential for this additive.
