API Filtration Loss Research Articles

Polymers marry with carbon nanospheres: A promising strategy to develop high-performance filtrate reducer

Polymeric filtrate reducers have limited uses under high temperature and salinity conditions. The incorporation of nanoparticles to polymeric networks is a popular and effective method for creating high-performance filtrate reducers. However, present nanofillers are costly, have negative environmental consequences, and are difficult or impossible to disseminate. Herein, a simple hydrothermal process using low-cost and renewable glucose as raw ingredients resulted in hydroxy-rich carbon nanospheres (CNs). After modification by acryloyl chloride, the CNs were copolymerized with acrylamide, 2-acrylamido-2-methylpropanesulfonic acid, and sodium p-styrene sulfonate. The obtained CNs-doped polymers (CAAS) were able to maintain high viscosity and colloidal stability even after salt contamination and high temperature aging. CAAS-based drilling fluids can tolerate temperatures of up to 240 °C under 30% NaCl conditions. The API filtration loss (FLAPI) and the high-temperature high-pressure filtration loss (FLHTHP) were 10 and 63.5mL, respectively. Considering the low-cost and renewable raw materials, high dispersibility and high compatibility of CNs as well as significant improvement in thermal-resistance and salt-tolerance, this work provides a simple yet effective approach to developing high-performance filtrate reducers for complex geological conditions.

Development and performance evaluation of high temperature resistant strong adsorption rigid blocking agent

As drilling wells continue to move into deep ultra-deep layers, the requirements for temperature resistance of drilling fluid treatments are getting higher and higher. Among them, blocking agent, as one of the key treatment agents, has also become a hot spot of research. In this study, a high temperature resistant strong adsorption rigid blocking agent (QW-1) was prepared using KH570 modified silica, acrylamide (AM) and allyltrimethylammonium chloride (TMAAC). QW-1 has good thermal stability, average particle size of 1.46 μm, water contact angle of 10.5°, has a strong hydrophilicity, can be well dispersed in water. The experimental results showed that when 2 wt% QW-1 was added to recipe A (4 wt% bentonite slurry+0.5 wt% DSP-1 (filtration loss depressant)), the API filtration loss decreased from 7.8 to 6.4 mL. After aging at 240 °C, the API loss of filtration was reduced from 21 to 14 mL, which has certain performance of high temperature loss of filtration. At the same time, it is effective in sealing 80–100 mesh and 100–120 mesh sand beds as well as 3 and 5 μm ceramic sand discs. Under the same conditions, the blocking performance was superior to silica (5 μm) and calcium carbonate (2.6 μm). In addition, the mechanism of action of QW-1 was further investigated. The results show that QW-1 with amide and quaternary ammonium groups on the molecular chain can be adsorbed onto the surface of clay particles through hydrogen bonding and electrostatic interaction to form a dense blocking layer, thus preventing further intrusion of drilling fluid into the formation.

Key Technology of 240°C High-Temperature Drilling Fluid

Hot dry rock (HDR) is a renewable green and clean energy source from the depths of the earth. It has the characteristics of high efficiency, environmental protection, safety, and stability, and is not restricted by seasons and climates. Difficulties in exploration and development include deep burial, formation fragmentation, abnormal pressure, high well temperature gradient, and high hole bottom temperature (usually >200°C), key technical issues such as sticking. This paper analyzes the difficulties of high-temperature resistant drilling fluid in dry hot rock: temperature resistance of treatment agents and systems, foaming, leakage, wellbore instability, and other problems. The optimization and experiment of treatment agents such as loss reducers, high-temperature protective agents, etc., and research on drilling fluid technology resistant to high temperature of 240°C in hot dry rock drilling has been carried out, through the optimization experiment of pulping materials and high temperature treatment agent. The main formula is: 3%-4% Sodium bentonite + 2%-3% HPS + 3%-4% SPNH + 2%-4% GJA + 3%-4% JSJ-1 + 0.5%-1.0% GGDP + 1% GBHJ. The drilling fluid formula has good rheology after hot rolling at 240°C, API filtrate loss<5ml, the viscosity recovery rate is over 90%. It provides effective technical support guarantee for promoting the exploration and development of hot dry rock resources in China.

Box–Behnken response surface method for the synthesis of high‐temperature‐ and salt‐resistant filter loss reducers

AbstractWellbores are destabilized by the immersion of a formation in drilling fluid during deep well drilling. To address this issue, in the present study, trimethylolethane triallyl ether (TMETE), 2‐acrylamide‐2‐methylpropanesulfonic acid (AMPS), acrylamide, and N‐vinylpyrrolidone undergo free radical copolymerization to produce a PTAAN filter loss reducer. The Box–Behnken response surface method is used to optimize the synthesis of PTAAN; the optimal conditions are 1 wt% TMETE and 0.1111 wt% initiator at 60°C. Fourier transform infrared spectroscopy, transmission electron microscopy, and thermogravimetric analysis are used to characterize the composition, micromorphology, and thermal stability of the PTAAN product, respectively. The synthesized product is resistant to high temperatures and salt under the optimal synthesis conditions. It has an API filtration loss of 8.2 mL for freshwater‐based mud, an API filtration loss of 13.8 mL for 20% by weight brine mud after aging at 220°C, and an API filtration loss of 29.5 mL at 150°C under high temperatures and pressures. Incorporating PTAAN into the base slurry prevents clay particle agglomeration at elevated temperatures and high mineralization, resulting in a broader clay particle size distribution and ultimately leading to the formation of a thin and compact filter cake.

Use of modified polystyrene micro-nano spheres to improve the inhibition and plugging performance of water-based drilling fluids

Wellbore instability is a challenging issue in drilling engineering, especially in shale formations. The objective of this paper is to achieve wellbore stability by changing the hydrophobicity of the shale surface and plugging the micro-nano pores through the synthesis of modified polystyrene micro-nano spheres (MPS). The MPS was characterized through Fourier transform infrared spectroscopy (FTIR), thermogravimetric analysis (TGA), particle size distribution, and transmission electron microscopy (TEM). The inhibition and plugging performance of MPS were evaluated through linear expansion, shale recovery, and plugging of polytetrafluoroethylene (PTFE) microporous membrane. To study the inhibition and plugging mechanisms of MPS, contact angle, pore size distribution, and SEM analysis were performed. The results showed that MPS was spherical with a particle size distribution of 91–712 nm and had good thermal stability. The MPS had excellent compatibility with drilling fluids and better inhibition than KCl, polyamines, and SiO2. When using PTFE microporous filter membrane as a filtration medium, the API filtration loss volume of 3 wt% MPS aqueous solution was only 42 mL, while that of the solution without MPS was 260 mL. The pore size of the PTFE microporous membrane was decreased after plugging. The MPS adsorbed on the shale surface to form a hydrophobic layer, which could weaken the hydrophilicity of shale. The contact angle of shale slices treated with 2 wt% MPS was 108.2°. Furthermore, SEM observations indicated that MPS can improve the quality of mud cakes and plug the small pores. MPS has potential applications in improving wellbore stability.

Composition, Properties, and Utilization of Fumaric Acid Sludge By-Produced from Industrial Phthalic Anhydride Wastewater Treatment

To understand fumaric acid sludge (FAS) systematically and comprehensively and find out how to utilize it, we conducted a series of characterization analyses on FAS. Fourier transform infrared (FT-IR) Spectra shows that the main component of FAS is fumaric acids and also contains a small amount of silicate. The nuclear magnetic resonance hydrogen (1H-NMR) spectrum also shows that fumaric acid accounted for a large proportion of FAS. The X-ray diffraction (XRD) shows that the main phase in FAS is fumaric acid, and there is also a small amount of Kaliophilite. After gas chromatography and mass spectrometry (GC-MS) and pyrolysis gas chromatography and mass spectrometry (Py-GC-MS) analysis, it indicates that the possible volatiles and pyrolysis products in FAS are fumaric acid, maleic acid, maleic anhydride, phthalic acid, etc. In the test of Liquid chromatography and mass spectrometry (LC-MS), we determined the contents of phthalic acid, fumaric acid, and maleic acid in FAS. The detailed mass content of each component in FAS is as follows: phthalic acid is about 0.10-0.15%; maleic anhydride is about 0.40-0.80%; maleic acid is about 18.40-19.0%; fumaric acid is about 55.00-56.90%; succinic anhydride is about 0.06-0.08%; acrylic acid is about 0.06-0.08%; malic acid is about 0.90-1.00%; acetic acid is about 0.10-0.20%; silicate is about 0.25-0.30%; phthalic anhydride is about 0.20-0.30%; water is about 24.30-24.80%. The filtrate loss reducer (PAAF) used in oilwell drilling fluids synthesized by FAS not only has excellent temperature and complex saline resistance, the API filtration loss (FL) was only 13.2 mL/30 min in the complex saline based mud, but is also cost-effective.

Study of a High-Temperature and High-Density Water-Based Drilling Fluid System Based on Non-sulfonated Plant Polymers.

The environment-friendly water-based drilling fluid system developed for the petroleum development industry cannot successfully withstand temperatures up to 180 °C, and most high temperature-resistant additives with sulfonic acid groups that have been successfully applied to water-based drilling fluid are not good for environmental protection. In order to solve the above technical problems, a non-sulfonated filtrate reducer and viscosity reducer with resistance to high temperature were prepared by using humic acid, lignin and a multifunctional monomer as raw materials. In laboratory experiments, the molecular weights of the FLO-H filtrate reducer and the VR-H viscosity reducer were 5.45 × 105 g/mol and 8.51 × 103 g/mol, respectively, and all of them showed good high-temperature resistance. The API filtration loss of the bentonite-base slurry with 3.0 wt% FLO-H was only 6.2 mL, which indicated that FLO-H had a prominent reduction in filtration loss after aging at high temperature. When the dosage of VR-H was 1.0 wt%, the plastic viscosity of the water-based drilling fluid after aging at 200 °C decreased from 71 mPa·s to 55 mPa·s, which provided excellent dispersion and dilution. The high-temperature and high-density water-based drilling fluid containing the FLO-H filtrate reducer and the VR-H viscosity reducer had good suspension stability and low filtration performance at the high temperature of 200 °C, which can meet the requirements of high-temperature deep well drilling.

Performance and mechanism of new silicone polymer as filtrate reducer with inhibitory effect for water-based drilling fluid

An organic silicon filtrate reducer (AATN) with inhibitory effect, which can resist temperature up to 180 °C, was synthesized by using acrylamide (AM), vinyl trimethoxysilane (A-171), allyltrimethylammonium chloride (TM) and N-vinyl pyrrolidone (NVP) as monomers. AATN can effectively reduce the filtration loss of drilling fluid and inhibit the hydration expansion and hydration dispersion of the clay, which was beneficial to wellbore stability. Experimental results showed that the API filtration loss (FLAPI) of the drilling fluid containing 2 wt% AATN was only 7.8 ml. The siloxane groups of AATN were hydrolyzed in aqueous solution to generate Si–OH bonds, which can react with Si–OH bonds on hydrated clay surface to form a strong chemical adsorption. It was conducive to maintaining the dispersion of clay particles in the drilling fluid. The stable grid structure was formed by AATN and clay particles to reduce mud cake permeability, which can reduce the damage of drilling fluid filtrates to borehole stability. In addition, AATN can adsorb on the surface of sodium bentonite, thus forming a hydrophobic adsorption film on its surface, which effectively enveloped bentonite and inhibited the hydration expansion of bentonite.

Formulation of novel ecofriendly microemulsion-based drilling fluids for improving rheological and filtration characteristics

The main objective of this work was to formulate not environmentally harmful drilling fluids obtained from microemulsion systems, using an aqueous phase (water-glycerol solution 1:1), an oil phase (pine vegetable oil), and varying nonionic surfactants (Tween 80, nonylphenol ethoxylates 100 and 150). Two types of clays (filtration control) were used in the formulation of fluids, Brasgel PA and Cloisite 20 A, in the presence of a viscosifier (xanthan gum), a weighting agent (baritine), a sealant (calcite), and dispersant (water). Properties such as mass loss, filtrate volume, and rheological characteristics of the formulated fluids were analyzed since these are considered essential characteristics for a successful drilling operation. Shear stress (τ) versus shear rate (s−1) data of fluids was best fitted to the Herschel-Bulkley rheological model with R2 of 0.99. The fluids formulated with Brasgel PA obtained the lowest consistency index (k), ranging from 0.37 to 0.61, and, therefore, the force required to start the flow (τy). The thermogravimetric analysis verified that the microemulsified drilling fluids obtained can operate at temperatures up to 100 °C, making it possible to apply them in oil wells with these thermal characteristics. The fluids' filtrate loss volume varied from 2.4 mL to 4.0 mL; the maximum filtercake thickness measured 0.80 mm, and low permeability (0.0173 mD). The analyzed drilling fluids showed a significant swelling reduction when formulated with the microemulsion systems and improved lubricity. In general, it was observed that ecofriendly microemulsion-based drilling fluids were efficient in reducing swelling, showing good rheological and reduced API filtrate loss, being viable alternatives for use in drilling operations of oil wells.

Synthesis and Weak Hydrogelling Properties of a Salt Resistance Copolymer Based on Fumaric Acid Sludge and Its Application in Oil Well Drilling Fluids

Fumaric acid sludge (FAS) by-produced from phthalic anhydride production wastewater treatment contains a large amount of refractory organic compounds with a complex composition, which will cause environmental pollution unless it is treated in a deep, harmless manner. FAS included saturated carboxylic acid, more than 60%, and unsaturated carboxylic acid, close to 30%, which accounted for the total mass of dry sludge. A new oil well drilling fluid filtrate loss reducer, poly(AM-AMPS-FAS) (PAAF), was synthesized by copolymerizing FAS with acrylamide (AM) and 2-acrylamide-2-methyl propane sulfonic acid (AMPS). Without a refining requirement for FAS, it can be used as a polymerizable free radical monomer for the synthesis of PAAF after a simple drying process. The copolymer PAAF synthesis process was studied, and the optimal monomer mass ratio was determined to be AM:AMPS:FAS = 1:1:1. The temperature resistance of the synthesized PAAF was significantly improved when 5% sodium silicate was added as a cross-linking agent. The structural characterization and evaluation of temperature and complex saline resistance performance of PAAF were carried out. The FT-IR results show that the structure of PAAF contained amide groups and sulfonic acid groups. The TGA results show that PAAF has good temperature resistance. As an oilfield filtrate loss reducer, the cost-effective copolymer PAAF not only has excellent temperature and complex saline resistance, the API filtration loss (FL) was only 13.2 mL/30 min after 16 h of hot rolling and aging at 150 °C in the complex saline-based mud, which is smaller compared with other filtrate loss reducer copolymers, but it also has little effect on the rheological properties of drilling fluid.

Improving the rheological properties of water-based calcium bentonite drilling fluids using water-soluble polymers in high temperature applications

Abstract Most of bentonite used in modern drilling engineering is physically and chemically modified calcium bentonite. However, with the increase of drilling depth, the bottom hole temperature may reach 180 °C, thus a large amount of calcium bentonite used in the drilling fluid will be unstable. This paper covers three kinds of calcium bentonite with poor rheological properties at high temperature, such as apparent viscosity is greater than 45 mPa·s or less than 10 mPa·s, API filtration loss is greater than 25 mL/30 min, which are diluted type, shear thickening type and low-shear type, these defects will make the rheological properties of drilling fluid worse. The difference is attributed to bentonite mineral composition, such as montmorillonite with good hydration expansion performance. By adding three kinds of heat-resistant water-soluble copolymers Na-HPAN (hydrolyzed polyacrylonitrile sodium), PAS (polycarboxylate salt) and SMP (sulfomethyl phenolic resin), the rheological properties of calcium bentonite drilling fluids can be significantly improved. For example, the addition of 0.1 wt% Na-HPAN and 0.1 wt% PAS increased the apparent viscosity of the XZJ calcium bentonite suspension from 4.5 to 19.5 mPa·s at 180 °C, and the filtration loss also decreased from 20.2 to 17.8 mL.

State-of-the-art drilling fluid made of produced formation water for prevention of clay swelling: Experimental Investigation

This study focuses on the feasibility of reusing formation water as inhibitive base water for water-based drilling fluids (WBDFs) to reduce the need for freshwater and commercial salts. A real produced formation water (PFB) with known composition and a synthetic produced formation brine (SPFB) were compared to commercially available clay inhibitors, i.e., KCl and NaCl salts. Experiments show that the PFB and SPFB have acceptable free swelling indexes and sedimentation rates. According to the zeta potential measurements, they similarly decrease the charge of clay surfaces and reduce swelling of Na-bentonite. Besides, the cutting dispersion test illustrates that PFB and SPFB can reduce the interaction between the Pabdeh and Gurpi shales (Iranian formations) with drilling fluid. Drilling fluids made of the PFB and SPFB have rheological properties, including apparent viscosity, plastic viscosity, yield point, and gel strength less than a typical inhibitive WBDF made of NaCl. API filtration loss of both PFB- and SPFB-based drilling fluids at high bentonite concentrations (more than 12.5wt.%) is similar to the same as the KCl-based drilling fluid, indicating their close inhibition power to the KCl solution. Finally, SEM analysis confirms that the texture/morphology of sodium bentonite exposed to the PFB and SPFB is close to that of the KCl solution and formation water inhibition power is more than NaCl and near to KCl. Eventually, formation water as a potential inhibitive water for water-based drilling fluids, is preferred to the commercial salts from both environmental and economic aspects.

The swelling effect of sodium-bentonite as an additive in water-based drilling sludge with different concentration of polyamine inhibition

A highly reactive sludge on drilling progress has become a common problem. The problem will cause swelling clay or high filtration loss. With a risk of swelling appearance and too much filtration loss that may cause, sodium-bentonite is widely used in drilling sludge to give more viscosity and optimal ability to hold and lift the cutting inside the borehole. It contains mostly montmorillonite like particles of sodium that overpower the iolite content inside it. Polyamine as an inhibitor to the clay can infiltrate into the bentonite c-spacing, which is a gap between two layers of bentonite structure. A test has been conducted to measure the effect of polyamine inhibition inside a water-base sludge formulation x that is previously inhibited with sodium-bentonite. These tests were conducted using a number of instruments such as API Filtrate loss, swell meter test, retort oven, and Vann vg meter with API Standard procedure. The result provides a distinctive conclusion about how the rheological elements react toward the polyamine existence with different concentrations (4gr-10,5gr) inside the sludge. This research also reveals that the sludge durability is different between room temperature and high temperature (300°F).

Synthesis and assessment of a hydrophobically associating heteropolymer in water-based mud

Water-soluble polymers can be used as key ingredients of both drilling fluids for virgin fields and polymer-enhanced oil recovery in underperforming reservoirs. The efficacy of hydrophobically associating heteropolymer (HAH-Polymer) as an agent for petroleum resource recovery was examined in this study. The hydrophobically associating heteropolymer (HAH-Polymer) comprising acrylamide, sodium 2-acrylamido-2-methylpropanesulfonate, hydroxyethyl methacrylate and lauryl methacrylate was synthesized in micellar medium by free-radical polymerization. The hydrophobically associating heteropolymer (HAH-Polymer) was characterised by FTIR and 1H NMR spectral analyses. The effects of temperature, pH and shear on the solution behavior of the HAH-Polymer were also examined. Rheological and fluid loss properties of HAH-Polymer-incorporated water-based drilling fluids were assessed. The HAH-Polymer improved the thermal stability between 25 and 160 °C of the drilling mud and maintained mud fluid loss of 8.4–8.6 cm3 compared with the polymer-free blank of 43.5–107.0cm3. In a salt-contaminated mud, the heteropolymer enhanced rheological properties and significantly reduced API filtration loss to 7.6–8.8 cm3 after hot aging between 25 and 150 °C. Under high temperature–high pressure filtration testing of muds, the HAH-Polymer demonstrated excellent fluid loss reduction by providing about eightfold fluid loss control (14.7 cm3) compared to the polymer-free blank (113.2 cm3) at 150 °C.

Experimental study on the performance of drilling fluid for coal seam methane drainage boreholes

Adopting in-seam boreholes for gas pre-drainage is an important method for ensuring safety coal mine operation. However, borehole collapse often occurs during the process of construction in soft coal seams, especially in downward boreholes. The main purpose of this study is to develop an efficient drilling fluid for coal seam methane drainage boreholes. First, a drilling fluid with a formula of 1 wt.% xanthan gum, and 1.2 wt.% Na-CMC, 0.6 wt.% cellulase and 4 wt.% bentonite, which is simply referred to as the drilling fluid, was developed based on the actual requirements of the construction site. Then, five property tests (viscosity, fluid loss resistance, cuttings carrying capacity, anti-collapse performance and degradability) of the drilling fluid were conducted in the laboratory. Finally, engineering application performances were carried out in Tangshan Mine, China. The results indicate the following: (1) When the xanthan gum concentration is fixed, the viscosity of the drilling fluid improves with increasing Na-CMC concentration. The API filtrate loss of the drilling fluid decreases with increasing bentonite concentration, while the filter cake thickness increases and then stabilizes. (2) The drilling fluid has an efficient performance in the carrying capacity of drill cuttings and the anti-collapse performance of a coal mass. Thorough degradation is completed 300 min after adding cellulase. (3) Compared with traditional clear water, the effective drilling distance of downward core drilling using the drilling fluid increases by two times, and the anti-collapse performance for coal seam methane drainage boreholes is remarkable.

Influence of carboxyl group on filtration property of oil well cement paste at different temperatures investigated using molecular dynamics simulation

Abstract As a porous material, the microstructure of cement-based material is complex and variable. The pores and cracks are randomly distributed in the cement paste and interconnected to form a fluid channel. To ensure the safety of cementing engineering, filtrate reducers (FR) usually are added to decrease the filtration loss. It was found that two filtrate reducers with different amounts of –COOH caused different filtration loss of oil well cement paste. The API filtration loss of cement paste containing 3% bwoc FR-I with less –COOH increased rapidly from 42.0 mL to 98.0 mL with the curing temperature rising from 30 °C to 90 °C. However, the increment of filtration loss of FR-II with more –COOH is less than 5 mL (from 56.0 mL to 58.0 mL) under the same experimental condition. The microstructure and component of filter cakes which were obtained from static filtration loss experiments were measured to compare the difference between two FRs. The experimental data show that the porosity and chemical composition of the cement phase directly affects the amount of filtration loss of cement paste, but it is not the main reason for the early filtration loss. Furthermore, the components of filtrates were measured and all-atom molecular-scale model was built to perform molecular dynamics simulation. The results show that, compared with FR-I, the advantage of FR-II is that the strong chelating of the “adjacent” carboxyl to Ca2+ ion, causing the local rigidity of the molecular segment, which in turn promotes the uniform distribution of the molecular chain throughout the cement paste. Thus, it shows a stronger binding capacity with water and controls the amount of filtration loss, regardless of the temperature.

The Research of Polymer Film-Forming Plugging Agent for Drilling Fluid

In order to improve the plugging and anti-collapse performance of water-based drilling fluid, a polymer film-forming plugging agent LWFD is synthesized by emulsion polymerization. The effect of the agent on rheology, API filtration loss, lubricity and film plugging of polymer drilling fluid and cationic drilling fluid is evaluated in laboratory. The experimental results show that the agent has little effect on the rheology and filtration loss of polymer drilling fluid and cationic drilling fluid, and can improve the lubricity of drilling fluid. The synthesized polymer film-forming plugging agent LWFD has good plugging properties for sand discs with different permeabilities, and the agent can effectively improve the film-forming plugging and temperature resistance of drilling fluid when combined with the inorganic nano-plugging agent NMFD. The high performance polymer drilling fluid formed by introducing polymer film-forming plugging agent LWFD and inorganic nano-plugging agent NMFD into polymer drilling fluid has comparable performance as Halliburton’s SHALEDRIL high performance drilling fluid, which can meet the requirements of on-site drilling and has application value.

Synthesis and characterisation of a multifunctional oil-based drilling fluid additive

An oil-based drilling fluid additive H-DEA (or humic acid-cocamide diethanolamine) was synthesised using humic acid and cocamide diethanolamine as raw materials. The rheological behaviors of H-DEA showed that the synthesised product has the good properties in both decreasing the filtrate loss and improving rheology property of oil-based drilling fluids compared with other commercially available additives. Under the optimal additive amount of 3%, both API filtrate loss and yield point changed remarkably from 5.40 to 0.41 mL and 9.0 to 25.6 Pa, respectively. Furthermore, differential scanning calorimetry (DSC) showed that H-DEA has good thermal stability in a wide temperature range up to 170 °C. Infrared spectroscopy (IR) and rheological analysis revealed that the possible mechanism of the multifunctional effects may be attributed to the existing of high density of strong polar groups, hydrogen bonds, electrostatic forces, and intermolecular association on H-DEA molecular structure. The results of the study showed that the synthesised H-DEA can be potentially used as a multifunctional oil-based drilling fluid additive in oil-drilling excavation.

Enhancing the properties of water based drilling fluid using bismuth ferrite nanoparticles

Drilling fluids are characterized by rheological and filtration characteristics and control of these properties is critical to the success of drilling operation. Among the popular additives for the control of these properties, nanoparticles are emerging to be one of the best additives for drilling fluids. For water based muds, rheology and filtration loss is generally controlled by polymers and it can also be improved by addition of small amounts of nanoparticles. In this paper, we have synthesized a BiFeO3 (BFO) nanoparticle by non-aqueous wet chemical techniques and used as additive for water based mud along with bentonite and other polymeric additives. BFO nanoparticles showed good compatibility with clay resulting in improved mud properties. Interaction of nanoparticles with clay and polymers resulted in enhanced apparent viscosity (AV), plastic viscosity (PV), yield point (YP), and API fluid loss. It was found that increasing the nanoparticle concentration from zero to 0.30 w/v% resulted in 25% increase in AV, PV and YP whereas a 35% decrease in API filtrate loss was observed at 20 °C before hot rolling. Even after hot rolling at 110 °C, these properties were not degraded significantly as was the case with mud without nanoparticles. Nanoparticles combined with bentonite platelets imparted good thermal stability to the drilling fluid.

Minimizing the HTHP filtration loss of oil-based drilling fluid with swellable polymer microspheres

Filtration control of drilling fluid plays an important role in the process of wellbore construction and ensures the success of drilling operation. A swellable polymer microsphere (SPM) of methylmethacrylate (MMA), butyl acrylate (BA), and lauryl methacrylate (LMA) was synthesized with suspension polymerization. Its swelling property was characterized by oil adsorption capacity measurement. First, the effect of SPM on the filtration and rheological properties of virgin organic clay dispersion was investigated. Then the filtration and rheological properties of mineral oil-based drilling fluid in the presence of SPM were elucidated under the respective conditions of hot aging temperature, oil to water ratio and density. Furthermore, the filtration control properties between SPM and two traditional filtration loss additives including modified lignite and asphaltic additive was compared. Addition of SPM exhibited obvious influence on the viscosity of oil-based drilling fluid especially at high concentration of 3 w/v%, therefore, a concentration of lower than 1.5 w/v% was recommended. After hot aging at 200 °C, the oil-based drilling fluid containing 1 w/v% SPM exhibited an API filtration loss decrease of 85%, and HTHP filtration loss decrease of 79% in comparison with the base fluid. After hot rolling at 180 °C, the API filtration loss decreased by 2%, 24% and 53%, and the HTHP filtration loss decreased by 42%, 54% and 65% respectively when 1 w/v% asphaltic additive, modified lignite and SPM are in the presence of the base fluid. Besides decreasing the filtration loss volume under high temperatures, incorporation of SPM also improves the filter cake quality of oil-based drilling fluid. SPM is capable of adsorbing considerable base oil and become swellable. The swellable polymer microspheres with favorably deformable and compressible properties can effectively fill the voids of filter cake and reduce the permeability, which leads to low filtration loss and minimization of solids invasion.