Oil-based Drilling Fluids Research Articles

The Effect of Oil–Water Ratio on Rheological Properties and Sag Stability of Oil-Based Drilling Fluids

Abstract Drilling fluids for oilfield use consist of complex mixtures of natural and synthetic materials. The viscous properties along with the particle size distribution of the applied weight materials are vital in controlling the stability of the microstructure and density of the drilling fluid. Typical oil-based drilling fluids made for North Sea oilfield drilling application with oil–water ratios (OWRs) of 80/20 and 60/40 are examined with respect to their density stability. The stability was analyzed at both rest and dynamic conditions using flow and viscosity tests, oscillatory sweep tests, creep tests, and time-dependent oscillatory sweep tests using a scientific rheometer with a measuring system applying a grooved bob at atmospheric conditions. The quantities used in ranking the stability of the fluids include the yield stress, flow transition index, mechanical storage stability index, and dynamic sag index. We observed that the drilling fluid sample with OWR = 60/40 showed a more stable dispersion with a stronger structure having higher yield stress and flow transition index values, while the mechanical storage stability index and dynamic sag index recorded lower values. Furthermore, the Herschel–Bulkley parameters for yield stress and consistency index increased in fluid with OWR = 60/40, whereas the flow index values for both fluid samples were similar. The results of this study enable drilling fluid engineers to design realistic oil-based drilling fluids with stable microstructure to mitigate weigh material settling and sag of particles for North Sea drilling operation.

Production and Characterization of an Eco-Friendly Oil Based Mud from Synthetic Bio-lubricant Derived from Chrysophyllum Albidum Seed Oil

Sequel to the environmental problems of the none biodegradable nature of the conventional oil-based drilling fluids, it is imperative and urgent for environmental sustainability and for the development of eco-friendly products, that use of petroleum diesel oil as the continuous phase of drilling mud warrant urgent reconsideration. Towards the search to provide a better alternative to petroleum diesel oil as a base oil for drilling mud, vegetable oil from the inedible seeds of the African star apple fruits, was examined In this study, an oil-based drilling mud (OBM) with biodegradable qualities for sustainable environmental applications was developed and characterized. The OBM was produced with chrysophyllum albidum (African star apple) oil methyl ester bio-lubricant to replace petroleum diesel as the continuous phase of the mud. The chrysophyllum albidum oil methyl ester was synthesized from fatty acid methyl ester obtained through transesterification process of none edible oils extracted from chrysophyllum albidum seeds. Tests of physiochemical and rheological properties were carried out on mud samples of chrysophyllum albidum oil biolube-based mud (CAOBBM) and petroleum diesel oil-based mud (PDOBM) to characterise the fluids for performance evaluation and environmental consequences. The findings indicated that CAOBBM was lower in density and less acidic than PDOBM, at barite content of 20 g. Also, CAOBBM had lower viscosity which implies less resistance to flow and lower pressure losses. The low oil to water ratio from the filtration loss test, revealed that CAOBBM is more viable to low fluid loss and consequently enhances wellbore stability and less oil retained on drilled cuttings. Similarly, toxicity test confirmed CAOBBM to be more appropriate and less detrimental to the environment compared to PDOBM. Summarily chrysophyllum albidum oil biolube based muds stands safer and more eco-friendly for a sustainable environment than petroleum diesel oil-based muds.

Research on Low Shear Rheological Properties of Annulus Drilling Fluid For Cementing in Kuqa Piedmont

Aiming at the frequent leakage of cementing casing in the fourth and fifth spuds of ultra deep natural gas wells in Kuqa Piedmont structural belt, Tarim Basin, the actual shear rate of annulus drilling fluid during casing running is analyzed. According to the he Ba rheological model, the test data at full shear rate (1.70–1021.40 s–1) and low shear rate (1.70–340.50 s–1) are used, The total shear and low shear rheological parameters of oil-based drilling fluid are fitted respectively, and the difference of exciting pressure under total shear and low shear rate is analyzed. It is found that the actual drilling fluid shear rate is much lower than the high value of conventional total shear rate of 1021.40 s–1; Under full shear and low shear rate, the rheological parameters vary greatly with temperature and pressure; The casing activation pressure at full shear rate is less than that at low shear rate. With the increase of well depth, the difference between full shear and low shear rate is greater. The results show that for natural gas wells with narrow safety pressure window, the test data should be selected to fit the corresponding rheological parameters according to the actual low shear rate range of drilling fluid, and on this basis, the casing running speed should be reasonably designed according to the allowable casing running exciting pressure, so as to reduce the leakage during casing running.

The effect of oil-based drilling mud (OBM) on the assessment of hydrocarbon charge potential

Foundational to source rock assessment in exploration is an understanding of organic enrichment and hydrocarbon generation potential. With an increased use of oil-based drilling mud, particularly in deep water drilling, problems associated with contamination have complicated source rock assessment. Drilling fluid contamination is assumed to increase the apparent values of the basic screening source rock parameters such as total organic carbon (TOC) and total hydrocarbon generation (S1 + S2).It has been commonly assumed that the effect of contamination can be reduced or eliminated by pre-treating samples with organic solvents (i.e., extraction of the sample) prior to analysis. In this study, an attempt is made to characterize this extraction process on a suite of simulated cuttings samples that were contaminated and extracted prior to analysis to validate the assumptions presented in the literature.Results from these experiments show significant differences between values measured on the original and oil-based drilling fluid contaminated samples before and after extraction. After contamination and before extraction, measured TOC and Rock-Eval parameters indicate that the oil-based drilling fluids appear to be acting as an aggressive solvent, altering the apparent source rock potential. Contamination by oil-based drilling fluid appears to reduce the total organic carbon content and the residual generation (S2) potential, while increasing the free hydrocarbon content. This may be a result of the presence of solid bitumen or bituminite in the original sample, which are acted on by the oil-based drilling fluid. Following extraction of the contaminated samples, the TOC and residual generation potential undergo further reduction and the free hydrocarbons were nearly eliminated. It was also observed that uncontaminated samples, when extracted, experienced an increase in TOC and the S3 (CO2) peak. These increases may have resulted from the retention of small amounts of solvent.Unlike the common assumption in the existing literature, these data indicate that once oil-based drilling fluids contaminate a sample, pre-treatment extraction does not provide an accurate measure of either the original organic carbon or residual generation potential. The data indicate that the use of Rock-Eval pyrolysis results from extracted samples that have been contaminated by oil-based drilling fluid can result in a significant underestimation of the system's hydrocarbon source rock potential.

Development a new type of oil based drilling fluid with good temperature resistant

ABSTRACT The complexity of reservoir conditions puts forward higher requirements for drilling fluid performance. The existing water-based drilling fluids (WBFDs) are difficult to meet the requirements at high temperature reservoirs. Oil-based drilling fluids (OBDFs) are suitable for deep and ultra-deep wells because of its good temperature resistant. In this paper, the plastic viscosity (PV), apparent viscosity (AV), yield point (YP), dynamic shear ratio, filtration loss (FL) and other properties are measured to investigate the type and concentration of bentonite, emulsifier, filtration reducer, wetting agent, and barite in the OBDF. The final formula of the OBDF is: No. 5 white oil + 4% sodium dodecyl-benzenesulfonate (SDBS) + 5% bentonite + 4% 180°C oxidized asphalt powder + 10% Tween-80 + 1.5% BaSO4. The PV, AV, and YP of No. 5 white OBDF increase by 22.4%, 17.0%, and 12.8% respectively, also the demulsification voltage can keep above 2000 V after aging at 220°C for 24 h. Compared with the drilling fluid used in Shanxi Oilfield, the properties of the No. 5 white OBDF have greatly improved the properties. The No. 5 white OBDF preparation provides new ideas for the development of OBDFs with good temperature resistant and environmental feasibility.

Experimental Investigation of the Rheological Behavior of an Oil-Based Drilling Fluid with Rheology Modifier and Oil Wetter Additives.

Drilling issues such as shale hydration, high-temperature tolerance, torque and drag are often resolved by applying an appropriate drilling fluid formulation. Oil-based drilling fluid (OBDF) formulations are usually composed of emulsifiers, lime, brine, viscosifier, fluid loss controller and weighting agent. These additives sometimes outperform in extended exposure to high pressure high temperature (HPHT) conditions encountered in deep wells, resulting in weighting material segregation, high fluid loss, poor rheology and poor emulsion stability. In this study, two additives, oil wetter and rheology modifier were incorporated into the OBDF and their performance was investigated by conducting rheology, fluid loss, zeta potential and emulsion stability tests before and after hot rolling at 16 h and 32 h. Extending the hot rolling period beyond what is commonly used in this type of experiment is necessary to ensure the fluid’s stability. It was found that HPHT hot rolling affected the properties of drilling fluids by decreasing the rheology parameters and emulsion stability with the increase in the hot rolling time to 32 h. Also, the fluid loss additive’s performance degraded as rolling temperature and time increased. Adding oil wetter and rheology modifier additives resulted in a slight loss of rheological profile after 32 h and maintained flat rheology profile. The emulsion stability was slightly decreased and stayed close to the recommended value (400 V). The fluid loss was controlled by optimizing the concentration of fluid loss additive and oil wetter. The presence of oil wetter improved the carrying capacity of drilling fluids and prevented the barite sag problem. The zeta potential test confirmed that the oil wetter converted the surface of barite from water to oil and improved its dispersion in the oil.

Application of Anhydrous Calcium Sulfate as a Weighting Agent in Oil-Based Drilling Fluids.

The hydrostatic pressure exerted during the drilling operation is controlled by adding a weighting agent into drilling fluids. Various weighting materials such as barite, calcium carbonate, hematite, and ilmenite are used to increase the density of drilling fluids. Some weighting additives can cause serious drilling problems, including particle settling, formation damage, erosion, and insoluble filters. In this study, anhydrite (calcium sulfate) is used as a weighting additive in the oil-based drilling fluid (OBDF). Anhydrite is an abundantly available resource used in the preparation of desiccant, plaster of Paris, and Stucco. Anhydrite application in drilling fluids is discouraged because of its filter cake removal issue. This study investigated anhydrite (anhydrous CaSO4) as a weighting agent and its filter cake removal procedure for OBDFs. The anhydrite performance as a weighting agent in OBDFs was evaluated by conducting several laboratory experiments such as density, rheology, fluid loss, and electrical stability and compared with that of commonly used weighting materials (barite, calcium carbonate, and hematite). The anhydrite was mixed in three different concentrations (62, 124, and 175 ppb) in a base-drilling fluid. The results showed that calcium sulfate enhanced rheological parameters such as plastic viscosity, yield point, apparent viscosity, and gel strength. CaSO4 reduced the fluid loss and provided better control over the fluid loss than other tested weighting materials tested at the same concentration of 124 ppb. Similarly, the emulsion stability was decreased with the increase in the amount of calcium sulfate in the OBDF. The calcium sulfate filter cake can be removed easily from the wellbore with an efficiency of 83 to 91% in single-stage and multistage removal processes, respectively using the newly developed formulation consisting of 20 wt % potassium salt of glutamic acid-N,N-diacetic acid (K4GLDA) as a chelating agent, 6 wt % potassium carbonate, and 10% ethylene glycol monobutyl ether. The introduction of anhydrite as a weighting agent can be more beneficial for both academia and industry.

Gas-Kick Simulation in Oil-Based Drilling Fluids with Nonequilibrium Gas-Dissolution and -Evolution Effects

SummaryThe nonequilibrium dissolution and evolution characteristics of gas in oil-based drilling fluids (OBDFs) greatly affect the ratio of free gas to dissolved gas in the wellbore, thus influencing the prediction accuracy of the wellbore-pressure and surface responses. Previous equilibrium-state models can result in the incorrect estimation of the multiphase-flow parameters during a gas kick in OBDFs. Therefore, a nonequilibrium gas/liquid two-phase-flow model is developed for simulations of gas kicks in OBDFs. Nonequilibrium gas-kick behaviors in OBDFs are investigated using the proposed model, and it is concluded that there is a unique gas-dissolving stage in comparison to the equilibrium gas-kick conditions. In this stage, the pit gain decreases to a large extent, and this phenomenon can be misinterpreted by the drilling crew as a loss of circulation or a decrease in the gas-kick intensity. The drilling-fluid-outflow rate is not a reliable gas-kick indicator because of the lower increment in the drilling-fluid-outflow rate under both nonequilibrium and equilibrium gas-dissolution conditions. Neglecting the gas-evolution rate in OBDFs could lead to overestimations of the maximum pit gain and the drilling-fluid-outflow rate. More gas moves from the wellbore in the form of dissolved gas under noninstantaneous gas-evolution conditions. The results of this study provide a theoretical basis for the safe and efficient treatment of gas kicks in OBDFs.

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.

Real-Time Prediction of Plastic Viscosity and Apparent Viscosity for Oil-Based Drilling Fluids Using a Committee Machine with Intelligent Systems

Real-Time Prediction of Plastic Viscosity and Apparent Viscosity for Oil-Based Drilling Fluids Using a Committee Machine with Intelligent Systems

Field tests of high-density oil-based drilling fluid application in horizontal segment

The operational experience of a horizontal segment well within the hard brittle shale layer of Longmaxi Formation in the southern Sichuan area demonstrates that the high-density oil-based drilling fluid (HDOF) induced down-hole working conditions(high-temperature, high-pressure, and solid-phase-dominance)directly impact the stability of the wellbore wall. Focusing on the impact of bottom-hole osmotic pressure and solid phase content and a series of density-reduction field tests, we identified suitable countermeasures. In this paper, we discuss the impact of high osmotic pressure and operational measures, and provide details of the field tests, which indicate that maintaining a higher osmotic pressure at the bottom-hole can reduce the formation pore pressure of the bottom-hole, widen the fluid density window, and maintain the stability of the wellbore wall. By improving the HDOF formula, such as using new treatment agents (e.g., polymer-modified nano-sealing agent and ultra-micro barite weight additive) and optimizing the solid particle size distribution of HDOF, we can effectively address the down-hole problems. The field test of “pressure-controlled drilling + density reduction” in horizontal drilling operations was found to reduce the complexity of down-hole faults, improve the rate of penetration, and reduce overall costs.

Dynamic Covalent Nanoparticles for Acid-Responsive Nonaqueous Pickering Emulsions.

Acid-responsive nonaqueous (glycerol in n-decane) Pickering emulsions were prepared using preferentially oil-wetted dynamic covalent silica (SiO2-pDB) nanoparticles as the Pickering emulsifiers. The acid-responsive Pickering emulsifier SiO2-pDB was prepared based on a Schiff base reaction between amino silica (SiO2-NH2) and p-decanoxybenzaldehyde (pDBA). The formation of SiO2-pDB was characterized by Fourier transform infrared spectroscopy, thermogravimetric analysis, and elemental analysis. The preferentially oil-wetted character of SiO2-pDB was indicated by contact angle measurement. Stable nonaqueous Pickering emulsions were prepared using preferentially oil-wetted SiO2-pDB as the Pickering emulsifier. However, after adjusting the nonaqueous Pickering emulsions to an acidic environment, complete phase separation occurred. In the acidic environment, preferentially oil-wetted SiO2-pDB decomposed into hydrophilic SiO2-NH2 and hydrophobic pDBA due to the decomposition of the dynamic imine bond in the SiO2-pDB. Then, the hydrophilic SiO2-NH2 and hydrophobic pDBA desorbed from the two-phase interface, resulting in complete phase separation of the initially stable nonaqueous Pickering emulsions. The acid-responsive nonaqueous Pickering emulsions show great potential in application in water sensitive systems, such as oil-based drilling fluids.

Synergistic Effect of Polyaspartate and Polyethylene Glycol on Lubrication Performance of the Water-Based Drilling Mud.

The poor lubrication performance of water-based drilling mud hinders its application in the drilling process of extended, reach horizontal wells. To overcome this shortcoming, polyaspartate (PA) and poly(ethylene glycol) (PEG) were used to improve the lubrication performance of the water-based drilling mud. The conventional performances, lubrication performance, and micro-image of antiwear steel balls of the modified water-based drilling mud were analyzed. The results show that the coefficient of friction (COF) of the water-based drilling mud mixed with 10% PA and 5% PEG was the lowest, reaching 0.094, the reduction rate of COF was 63.1%, and the drilling mud cake stuck factor was also the lowest. The addition of PA and PEG had no effect on the rheological properties of water-based drilling mud and also can significantly reduce the filtrate volume; the reduction rate of the filtrate volume reached 43.5%. All of these result from the synergistic effect of PA and PEG; they are adsorbed on the metal surface and the mud cake to form a lubricating film. At the same time, the lubricants also changed the appearance of the solid particles in the mud cake, which reduced the friction between the mud cake and the drilling tool. Moreover, effects of the influence of drilling mud properties on lubricants (alkali metal ions, pH, temperature, and drilling mud density) were examined. The water-based drilling fluid with the synergistic effect of PEG and PA shows similar lubrication performance as the oil-based drilling fluid and can meet the technical requirements of corresponding horizontal wells.

Effect of particle number density on rheological properties and barite sag in oil-based drilling fluids

The effect of barite particle mass fraction and of particle size distribution on the settling and sag potential in oil-based drilling fluid samples is investigated for four fluids with densities of 1.43, 1.55, and 1.60 specific gravity (S.G). The fourth fluid sample, with density 1.60 S.G., had sieved barite particles of sizes less than 40 μ m . The settling potential in a liquid column under static condition has been characterized using light scattering measurements whereas sag potential in a sheared liquid column has been characterized under a dynamic condition using a rotating cylinder rheometer to produce rotational shear. Extensive rheological characterization of the drilling fluid samples is carried out where the Herschel-Bulkley fluid parameters were defined. We observed that the rate of particle settling under static condition was faster in the fluid sample of S.G = 1.43 having the least barite concentration. There was longer suspension of particles within the fluid sample of S.G = 1.60. Fluid sample with the sieved barite recorded weak destabilization of particles within the middle and bottom column of the sample after 7 days. The viscosity and viscoelastic-linear elasticity also increased with increasing barite concentration which contributed to lower dynamic sag for all shear rates. Time-dependent oscillatory shear measurements provide new insights on the structural character of drilling fluids to predict barite sag tendencies during the fluid design phase. • Barite sag in typical North sea oil-based drilling fluids is investigated. • Fluid viscosity and viscoelastic-linear elasticity increase with increasing barite concentration. • Yield stress values are strongly dependent on barite particle concentration. • The rate of particle migration is much faster in fluid sample with low barite concentration. • Time-dependent oscillatory shear analysis provide valuable information on the breakdown and growth of fluids' microstructures.

Impact of Drilling Fluid Contamination on Performance of Rock-Based Geopolymers

Summary Our objective is to present selected rheological and mechanical properties of rock-based geopolymers contaminated with different concentrations of drilling fluids. The possible flash setting and the maximum intake of drilling fluids before seeing a dramatic deterioration of the geopolymers are presented. Rock-based geopolymers designed for cementing conductor and surface casing were prepared and cured for up to 28 days at 22°C and atmospheric pressure. Water-based drilling fluids (WBDFs) and oil-based drilling fluids (OBDFs) were designed in accordance with the recommendations from the petroleum industry. The fluid samples were prepared, and their viscous behavior was characterized before and after hot-rolling. The geopolymeric slurries were mixed and then blended with the prepared drilling fluid volumes. The contaminated geopolymeric slurries were cured and tested at different time intervals. American Petroleum Institute (API) Class G neat cement was used as a reference. These samples were cured and contaminated with the same drilling fluids. The properties of contaminated geopolymer slurries were benchmarked with those of the contaminated Class G cement. The obtained mechanical properties showed that the rock-based geopolymers are more sensitive to WBDFs than to OBDFs. However, for contaminated Portland cement samples, the obtained results were opposite, and the contamination effect of OBDF on cement was more noticeable than WBDF. The impact of geopolymer contamination is a function of curing time. Although geopolymeric samples showed dramatic strength retrogression at the early time, strength buildup of the samples compensated for the impact of contamination.

Treating Drill Cuttings Waste with Oil Contamination by Microwave Treatment then by Earthworms Technique

In this research paper, two techniques were used to treat the drill cuttings resulting from the oil-based drilling fluid. The drill cuttings were taken from the southern Rumaila fields which prepared for testing and fixed with 100 gm per sample and contaminated with two types of crude oil, one from Rumaila oilfields with Sp.gr of 0.882 and the other from the eastern Baghdad oilfield with Sp.gr of 0.924 besides contamination levels of 10% ​​and 15% w/w in mass. Samples were treated first with microwave with a power applied of 540 & 180 watts as well as a time of 50 minutes. It was found that the results reached below 1% w/w in mass, except for two samples they reached below 1.5% w/w in mass. Then, the sample of 1.41% w/w in mass, which has the highest contamination level after microwave treatment, was treated on three groups of earthworms. After the appropriate conditions, samples were prepared for treating by earthworms and for an incubation period of 21 days, the results highlighted the effectiveness of the succession process by reaching concentrations below 0.92%, 0.65%, and 0.42% w/w in mass.

Drilling oil-based mud waste as a resource for raw materials: A case study on clays reclamation and their application as fillers in polyamide 6 composites

• Reclaimed nanoclay from oil-based drilling fluid waste used as nanofiller in polyamide 6 composites. • Improvement in interfacial adhesion between OBMFs and PA6 displaying material tailorability for significant increase mechanical properties. • Storage modulus of PA6 with 10 wt% OBMFs was 56% higher than that of neat PA6. • Clear circular economy demonstration on raw materials recovery and reuse from waste drilling fluids as waste management strategy. To convert the hazardous oil-based mud waste into a resource, this study has addressed reclaimed nanoclays and its application as a filler material for reinforcing polyamide 6 polymer matrix into a novel polymer composite material. This work focuses on the synergistic effect of complex mixture of various clay minerals reclaimed from oil-based mud waste on different mechanical properties in polyamide-6 (PA6)/oil-based mud fillers (OBMFs) nanocomposites. PA6/OBMFs nanocomposites were manufactured through the melt compounding of OBMFs with PA6 in a twin-screw extruder followed by injection moulding. The study shows significant improvement for mechanical properties. For instance, the tensile properties increased with the incremental loadings of OBMFs in PA6 matrix. The Young's moduli were increased by 42% and 35% in PA6 with 7.5 and 10 wt% OBMFs nanocomposites respectively whereas the tensile strengths were increased by 24% and 16% in PA6 with 7.5 and 10 wt% OBMFs nanocomposites respectively. The flexural strength increased by 26% with the addition of OBMFs from 0 to 10 wt% in PA6. The storage modulus of the nanocomposite containing 10 wt% OBMFs was 16% higher than the storage modulus of neat PA6 at 30 °C, whereas at 60 °C (glass transition temperature, T g of neat PA6) the storage modulus of PA6 with 10 wt% OBMFs was 56% higher than that of neat PA6. The study shows that the oil-based mud waste can be appropriately management to develop a new raw materials resource for polymer technology.

Oil-Based Drilling Fluid's Cuttings Bed Removal Properties for Deviated Wellbores

Abstract Results from cuttings transport tests in the laboratory using different field-applied oil-based drilling fluids with similar weight and varying viscosities are presented in this paper. The fluids are designed for highly deviated wells, and the cuttings transport performance at relevant wellbore inclinations was investigated. The experiments have been performed in a flow loop that consists of a 10-m-long test section with 50.4 mm (2″) diameter freely rotating steel drill string inside a 100-mm (≈4″) diameter wellbore made of cement. Sand particles were injected while circulating the drilling fluid through the test section. Experiments were performed at three wellbore inclinations: 48, 60, and 90 deg from vertical. The applied flow loop dimensions are designed so that the results are scalable to field applications; especially for the 12 ¼″and 8 ½″ sections. The selected setup provides correct shear rate ranges and similar Reynolds numbers to the field application when the same fluids are applied. Results show that hole cleaning abilities of the tested fluids vary significantly with well angle, drill string rotation, and flowrate. Results support field experience showing that low viscous fluids are more efficient than viscous fluids at higher flowrates and low drill string rotation. As well as per field experience, more viscous fluids are efficient in combination with high drill string rotation rates. The results show the effect of cuttings transport efficiency as a function of hydraulic frictional pressure drop, demonstrating methods to achieve a more optimal hydraulic design in the tested conditions. The key findings have direct relevance to drilling operations.

Performance evaluation of esters and graphene nanoparticles as an additives on the rheological and lubrication properties of water-based drilling mud

In the practice of drilling horizontal, directional, and unstable well profiles, the friction produced by bit balling, wellbore instability, cavings, and dog-legs resulted in excessive torque and drag. The friction along with high torque and drag, which results from the drill string, casing, and wellbore contact, leads to pipe stucks, overpulls during tripping-outs, and even closure of the oil and gas well. Heat generated from metal contact between casing and drill string is the cause of wear of drill string and casing. Oil-based drilling fluids are identified to produce minimum friction and torque than that of water-based drilling fluid/mud (WBM). However, the use of oil-based drilling fluids is becoming obsolete due to stringent environmental regulations. Therefore, it is critical to identify and design a water-based drilling mud with lubricant additives that are environmentally friendly, cost-effective, and give better lubrication similar to oil-based and synthetic-based drilling fluid. The objective of this study is to investigate the effect of two additives PC60 (the product of the reaction of glycerol ​+ ​tall oil fatty acid) and graphene nanoparticles on the rheological and lubrication properties of water-based drilling fluid. All together total 14 drilling fluid samples have been prepared for the detailed analysis. Extensive experimental work has been done to study the effect of lubricant additives (PC60 and graphene nanoparticles) on the rheology and lubrication of various WBMs with different additive concentrations (1, 2, and 3% by volume) at 30, 60, and 90 ​°C. All samples were investigated for their rheology, viscoelastic behavior, and lubrication properties before and after hot rolling. The experimental data generated in this work have been successfully utilized to find various fitting parameter for the Bingham plastic rheological model, followed by a discussion on foaming tendency of the samples and effect of pH on the rheological stability of drilling fluid. Subsequently, a relationship between the coefficient of friction (in the presence of different lubricant additives in the mud) and rheological properties (plastic viscosity and yield point) of different drilling fluid samples have been proposed. • Rheological/lubrication properties of water-based drilling muds (WBMs) investigated. • The effect of two additives ester and graphene nanoparticles on WBM studied. • Ester-based WBMs shown better rheological performance/stability after hot rolling. • A relationship between coefficient of friction and rheological properties proposed. • Ester-based WBMs exhibit more foaming tendency than nano-graphene-based WBMs.

Research and Application of Evaluation Methods for Functional Characteristics of Oil-Based Drilling Fluid in Shale Gas Wells

Intelligent unconventional reservoir optimal production control technology is a comprehensive technology, involving geology, reservoir simulation, and efficient drilling and completion. Efficient drilling and completion provides a flow channel for unconventional oil and gas exploitation and a wellbore with good integrity for reservoir transformation, which is an important link in the efficient development of unconventional oil and gas. The application of industry standard method to evaluate the performance of oil-based drilling fluid has the problem of poor correlation. It cannot reflect the difference of performance among oil-based drilling fluid systems, which lacks the significance for field construction. Based on shale expansion, rolling dispersion experiment, and microporous membrane filtration loss test, the physicochemical mechanism of borehole wall instability in shale formation was investigated. The evaluation methods of shale lubrication, antiaccretion test, slake durability, buck hardness test, etc. are put forward, and the formula of oil-based drilling fluid is optimized. The lubrication and antiaccretion experiment method can effectively and intuitively characterize the cleaning and lubrication effect of drilling fluid on drilling tools. The slake durability evaluation method simulates the collision between drill cuttings and the drill string and well wall. The bucking hardness experiment is through testing the cuttings and the hardness change after drilling fluid action reflects its inhibitory effect. The new methods were used to evaluate the oil-based drilling fluid used in 4 wells in the Changning block. It was found that the drilling fluid of CN209H2 well adhered to the steel column with at least 0.41 g of cuttings; the recovery rate of the drilling fluid resistance of CN209H1 was up to 87.70%, and YX1200 oil-based drilling fluid plugging agent was selected through the microporous membrane experiment. In the process of drilling the well CN209H5, the new oil-based drilling fluid formulation improved the lubrication performance by 44%, accompanied by 95.48% recovery rate and less than 10 mL HTHP fluid loss at the same time. The research results show that the oil-based drilling fluid system optimized according to the new method can significantly inhibit shale hydration and dispersion and can effectively solve the problem of unstable performance of traditional oil-based drilling fluids in the Changning block.