Fluid Loss Control Research Articles

Technology Focus: Drilling and Completion Fluids (November 2022)

As the oil and gas drilling industry moves into more technically challenging environments [e.g., drilling ultradeep onshore/offshore wells under extremely high temperature (above 300°F) and pressure (mud specific gravity above 2.0)], companies increasingly come under pressure to stretch technology and improve drilling performance while continuously striving to reduce costs and meet the requirements of stricter environmental regulations. Significant reserves additions may be realized if the risks associated with drilling in such harsh conditions (e.g., pressure control, wellbore instability, lost-circulation, sour gas) can be managed effectively. Design and development of a new generation of drilling fluids able to fulfill all of the attributed functions (e.g., stabilize the wellbore, control formation pressure, transport the drilled cuttings, minimize the fluid loss, and not reduce formation productivity) under such extreme pressure and temperature conditions is one of the key requirements for unlocking these resources. Drilling fluids used under ultrahigh pressures and temperatures need to be thermally stable and able to retain their rheological properties. Traditionally, nonaqueous drilling fluids (NADFs) have been used under these extreme conditions. NADFs, however, have significantly high operational costs with an associated health, safety, and environmental risk. As a result, there has been an increasing demand from operators to use aqueous drilling fluids [water-based muds (WBMs)], which are known to be environmentally benign and relatively less expensive. The use of WBMs under extreme temperatures and pressures, however, faces several challenges, including the breakdown of polymers and other additives used as fluid-loss preventers and rheological stabilizers. Therefore, recent research has focused on design and development of WBM systems meeting the following specifications: - Use of sodium chloride (for barite-laden formulation) and sodium bromide (for barite-free formulation) as base brines to reduce the total solids content for optimal fluid properties and to maximize the quality of wireline logs - Ensure inhibition of reactive shale formations to maintain wellbore stability while drilling intermediate sections - Provide optimal and stable rheological properties for excellent hole cleaning and drilling performance The newly developed ultrahigh-temperature water-based systems used custom-made branched synthetic polymers that exhibit superior rheological properties and fluid-loss control as well as long-term stability above 400°F. These branched synthetic polymers are compatible with most oilfield brines and maintain excellent low-end rheology. Other formulations proposed the use of β-cyclodextrin polymer microspheres (β-CPMs) as an environmentally friendly ultrahigh-temperature filtration reducer. When the temperature rose above 160°C, a hydrothermal reaction occurred for β-CPMs, and, as a result, numerous micro- and nanosized carbon spheres formed, which bridged across micro- and nanopores within the filter cake and reduced the filter cake permeability effectively. Bentonite-hydrothermal carbon nanocomposites also are proposed as nonpolymer additives to solve the ultrahigh-temperature/-pressure challenge in water-based drilling fluid. The nanocomposites are synthesized by a simple hydrothermal reaction in which biomass starch and sodium bentonite are used as the precursor and template, respectively. Such formulations have shown favorable rheology and filtration properties after hot rolling at temperatures as high as 460°F. This section presents selected papers showing examples of design, development, and field applications of the new generation of WBM fluid technologies. Recommended additional reading at OnePetro: www.onepetro.org SPE 206444 - Successful Application of a New Generation of Clay-Inhibitor Polymers While Drilling a Deep Exploration Well in the Astrakhan Region by Petr Leonidovich Ryabtsev, Akros, et al. SPE 205539 - Improvement of Rheological and Filtration Properties of Water-Based Drilling Fluids Using Bentonite-Hydrothermal Carbon Nanocomposites Under Ultrahigh-Temperature and High-Pressure Conditions by Hanyi Zhong, China University of Petroleum East China, et al. SPE 209805 - The Utilization of Self-Crosslinkable Nanoparticles as a High-Temperature Plugging Agent in Water-Based Drilling Fluid by Ming Lei, University of Alberta, et al.

High-Temperature Water-Based Drilling Fluid Accesses Depleted Deepwater Reserves

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 207825, “First Use of Novel High-Temperature Water-Based Reservoir Drilling Fluid To Access Depleted Deepwater Reserves,” by Alexandra C. Morrison, Conan King, SPE, and Kevin Rodrigue, Halliburton. The paper has not been peer reviewed. _ A combination of divalent base brine and high wellbore temperature presents significant challenges for high-density aqueous reservoir drilling fluids. Such systems traditionally use biopolymers as viscosifiers; however, they are subject to degradation at elevated temperatures. Nonaqueous drilling fluids are thermally stable, but complete removal of the filter cake is challenging, which can lead to formation damage. The complete paper describes the qualification and first deepwater drilling application of an aqueous reservoir drilling fluid at temperatures greater than 320°F. Introduction The laboratory development and scale-up yard trials of the high-temperature divalent brine-based reservoir drilling fluid (HT-RDF) and solids-free screen running fluid (SF-SRF) systems used for this well took several years. Specific rheology and fluid-loss targets were set and met during the design phase, and, in conjunction with hydraulic modeling, software simulations demonstrated that equivalent circulating densities (ECDs) would be acceptable based on well-construction plans. The HT-RDF showed excellent thermal stability in static age tests, which was crucial because of the plans for openhole logging of the production zone once total depth was reached. Screen plugging was identified early in the project as a key risk; the most-suitable mitigation for this was to engineer a completely solids-free fluid in which to install the sand screens. The resulting SF-SRF was designed to provide fluid-loss control and wellbore stability in case filter cake was stripped from the formation face during the screen run. Finally, given the focus on production maximization, the fluids underwent rigorous formation-damage tests, ultimately showing that a return permeability of greater than 60% was possible with the inclusion of an acid breaker to assist filter-cake dissolution.

Smart Fluids and Their Applications in Drilling Fluids to Meet Drilling Technical Challenges

This article presents extensive analysis and review on recent developments in smart fluids as well as future opportunities of smart drilling fluids utilization in oil and gas well drilling while focusing on the following smart fluids: smart nanoparticles, electrorheological, magnetorheological, and viscoelastic surfactant (VES) fluids. The distinctive properties of nanoparticles such as tiny particle sizes, high specific surface area, mechanical strength, and thermal stability make them suitable for utilization in drilling fluids. In bentonite water-based drilling fluid systems, this review suggests that charged nanoparticles are capable of displacing exchangeable ions in between bentonite clay platelets, thereby forming intercalates which can interact with clay surfaces through electrostatic attraction or repulsion. In improving wellbore stability, it is presented in this review that nanoparticles are able to invade and plug ultratiny pore spaces in shale formations, thereby further enhancing shale formations’ mechanical strength and wellbore stability. According to this review, the magnitude of changes in properties of smart electrorheological and magnetorheological fluids largely depends on the intensity of applied electric and magnetic fields. The intensity of smart fluids properties alteration due to applied field would equally depend on wt.% concentration and chemical compositions of particles susceptible to electric and magnetic fields. Based on review carried out on VES smart fluids, attractive and repulsive forces in the smart VES fluids solution result in the formation of micelles which can cause changes in viscoelastic property of the formulated smart viscoelastic fluids. The more the concentration of charged ions in the base fluid which VES fluids come in contact with, the higher the viscoelasticity of the smart VES fluids. According to this review, utilization of smart materials in drilling fluids can result in meeting oil and gas well drilling technical challenges including enhancing wellbore stability, improving hole cleaning performance, lost circulation control, fluid loss control, enhancing rate of penetration, pressure drop control, and easing cutting carrying efficiency of drilling fluids. This review equally suggests that the utilization of smart fluids such as smart magnetorheological and electrorheological fluids would facilitate drilling automation and real-time data acquisition processes, which is the future technology in oil and gas drilling.

Effect of micro-magnesium oxide admixture on rheological and compressive strength properties of class G well cement

Rheological property tuning is one key aspect of oil-well cement, not only affecting the cement slurry placement but also indirectly impacting other cementing properties such as the bonding strength and compressive strength. However, the research is scant on the rheological properties of blending magnesium oxide with class G oil-well cement, despite some studies having been conducted on its impacts on shrinkage compensation, compressive strength, bonding strength, and permeability properties of oil-well cement. This work studies the effects of micro-sized magnesium oxide on the rheological properties and compressive strength of the formulated API Class G oil-well cement slurries. Two types of micro-sized magnesium oxide (50 μm and 100 μm) were used as the mineral admixture at different dosages (3%, 9%). The base formulated slurry sample was incorporated with the silica flour and several commercialized additives such as retarder, fluid loss control agent, and defoamer. A batch of flow tests have been conducted by the use of a digital viscometer at two different temperatures, 25 and 88°C. The compressive strength has also been measured after curing the samples with the same formulation and conditions for 7 days. The variations of the rheological properties (plastic viscosity, yield stress, and gel strength), shear stress–shear rate correlations, and shear-thinning/thickening behavior are impacted by the temperature, the type, and dosage of magnesium oxide. The plastic viscosity of the tested slurries decreased by 27.0% (type II, 9%, 25°C) and 15.1% (type II, 3%, 88°C), respectively, and the yield stress increased by 258.5% (type II, 3%, 88°C) and 53.9% (type II, 9%, 25°C). The gel strength generally increases as the magnesium oxide dosage increases. However, all tested slurry samples show shear-thinning behavior and non-Newtonian characteristics. Among the tested slurry samples, it is found that better rheological performance is achieved when incorporating magnesium oxide with a smaller particle size. On the other side, the specimens of mixed magnesium oxide with a bigger particle size and medium dosage outperform their rival with a smaller particle size in compressive strength.

Integrated Ultra Low Invasion–Nanoparticles Drilling Fluid (ULIN): Drilling Additives with Low Environmental Impact as Innovation to Solve Common Drilling Issues

Drilling issues is extremely costly and a smart additives selection could be one of the ways to cope with these issues. Integrated Ultra Low Invasion–Nanoparticles Drilling Fluid (ULIN) purpose to overcome common drilling problems such as formation instability, differential sticking, lost circulation, and clay swelling by minimizing the invasion through environmentally safe drilling fluid additives. Ultra Low-Invasion produces a thin, deformable, yet robust shield that serves as the foundation for a low-permeability barrier at the formation's face, temporarily sealing pore throats. This seal forms after only a few seconds of invasion and has been demonstrated in laboratory experiments to be exceedingly effective at essentially inhibiting future fluid invasion or pressure transmission. On the other hand, nanoparticles drilling fluid inhibiting shales by either plugging pore in shales, viscosifying water in drilling fluids, and or osmotically dehydrating shales. It has a very high surface area to volume ratio resulting in improved physical and chemical sensitivity, boosting their performance efficiency. ULIN has exceeded the original oil production with an additional 1,800 BOPD produced by 11 wells. It also reduces the formation damage up to 93% from 64.3% to 4.5% in Naricual Formation. ULIN is safe for the environment while it can inhibit the reactive montmorillonite shales, declining rheology dropping back, controlling fluid loss amount and lubricity enhancement. Parameter of the feasibility of establishing a factory using economic analysis with an annual sales of 37,449,000 USD, and ULIN get a profit before tax of 23,108,266.89 USD and a profit after tax of 14,340,733.11 USD with a parameter calculation is a positive NPV, IRR of 40.01% including the cash flow and present value start to be positive in the 3rd year when the system starts operating. ULIN has a payback period of 4.3 years. From the result of the analysis, it can be concluded that ULIN has good prospects and deserves to be implemented.

Effect of excess viscosifier and fluid loss control additive on the rheological characteristics of water-based drilling fluid

Water-soluble polymers are used to improve drilling operations to ensure that oil and gas wells are drilled in less time and completed with minimized formation damage. However, excessive utilization of these polymers additives may have implication on the drilling outcomes. In this work, drilling fluids comprising of different compositions of polyanionic cellulose (PAC), and starch; and a constant amount of bentonite were formulated to examine the effects of excessive use of each additive or their combinations in a water-based drilling fluid (WBDF). The fluid properties were further investigated at low pressure and low temperature (LPLT) as well as high pressure and high temperature (HPHT). The results suggest that the viscosities of the fluid are not only dependent on the shear rate, shear stress, and composition but also on the temperature and pressure. Model plots of shear stress (Pa) against shear rate (s−1) using the Power law, Bingham plastic and Herschel-Bulley shows that all composition have low viscosity and low yield point. Increasing the amount of additive increases, the equivalent circulating density (ECD) which may increase differential sticking and consequent formation damage.

Experimental Investigation of Shale Tensile Failure under Thermally Conditioned Linear Fracturing Fluid (LFF) System and Reservoir Temperature Controlled Conditions.

Linear fracturing fluid (LFF) provides viscosity driven benefits of proppant suspensibility and fluid loss control, and with the use of a breaker agent, flowback recovery can be greatly enhanced. Shale tensile strength is critical in the prediction of fracture initiation and propagation, but its behavior under the interaction with LFF at reservoir temperature conditions remains poorly understood. This necessitated an in-depth investigation into the tensile strengths of Eagle Ford and Wolfcamp shales under thermally conditioned LFF and reservoir temperature controlled conditions. Brazilian Indirect Tensile Strength (BITS) testing was carried out for the quantitative evaluation of shale tensile strength, followed by extensive failure pattern classifications and surface crack length analysis. The thermally conditioned LFF saturation of shale samples led to average tensile strength (ATS) increases ranging from 26.33–51.33% for Wolfcamp. Then, for the Eagle Ford samples, ATS increases of 3.94 and 6.79% and decreases of 3.13 and 15.35% were recorded. The exposure of the samples to the temperature condition of 90 °C resulted in ATS increases of 24.46 and 33.78% for Eagle Ford and Wolfcamp shales, respectively. Then, for samples exposed to 220 °C, ATS decreases of 6.11 and 5.32% were respectively recorded for Eagle Ford and Wolfcamp shales. The experimental results of this research will facilitate models’ development towards tensile strength predictions and failure pattern analysis and quantifications in the LFF driven hydraulic fracturing of shale gas reservoirs.

Selection of the particle size distribution of granular lost circulation materials for use in naturally fractured thief zones

Granular lost circulation materials (LCMs) are used to control fluid loss in naturally fractured thief zones. Rapid and automated identification of their optimal particle size distribution (PSD) is highly desirable. This paper proposes a PSD selection method for LCMs based on a PSD representation algorithm and the Monte Carlo method. The PSD representation algorithm describes the cumulative and compositional PSD curves of LCMs according to a piecewise cubic Hermite interpolation algorithm. Comparison with measured PSD data shows that the representation algorithm is more accurate than other commonly used PSD models in describing both homogeneous and mixed LCMs, and the relative errors are all within 10%. The Monte Carlo method is adopted to simulate LCMs with various compositions and select ones with PSDs that meet a proposed selection criterion. Experiments show that the PSD curves of the LCMs were all within the upper and lower bounds specified by the selection criterion. Plugging experiments show that LCMs with the recommended compositions can effectively enter fractures, and the fluid loss is less than 200 mL for half an hour under the pressure difference of 7 MPa. The proposed selection method can be used for the rapid and automatic design of granular LCMs used in fractured thief zones.

New HTHP fluid loss control agent for oil-based drilling fluid from pharmaceutical waste

In Oil-Based drilling fluid systems (OBM, for Oil-Based Mud) the oil phase is the major source of contamination and hydrocarbon pollution is, by far, the main concern. However, the release and accumulation of mud additives in the environment may be deleterious on grounds of volume and/or concentration. This paper describes a waste valorisation study from an antibiotic large-scale manufacturing for the preparation of a new drilling fluid additive (Fluid-Loss-Control agent: FLC) for OBM. This additive is environment-friendly, biomaterial in nature, and totally biodegradable and thus expected to have no detrimental effects on the surrounding environment and ecosystems. After product washing, heating, grinding, and screening, a cationic surfactant was used to improve fluid stability and filtration properties. Our results show that: According to drilling fluid requirements, the treatment of this pharmaceutical reject yields a product with good properties, i.e. satisfactory as far as thermal stability, filtration characteristics, and rheology property are concerned, - The pre-treatment of those products (according to their original state and particle size, as well as the type and concentration of added surfactant) enhances additive quality and shows good compatibility in drilling fluid systems, - The substitution of this new product for conventional additives affords good drilling fluid stability and performance under high temperature and high pressure (HTHP) conditions, economic, and environmental solutions to improve the environmental standing of OBMs further. • Providing effective environmentally acceptable fluid loss control. • New additive without damaging formation permeability. • Presentation of new fluid-loss-control agent from the pharmaceutical industry. • It is a by-product of an industrial antibiotic fermentation process.

Formation mechanisms of fracture plugging zone and optimization of plugging particles

As formation mechanisms of plugging zone and criteria for fracture plugging remain unclear, plugging experiments and methods testing granular material mechanical properties are used to study the formation process of the plugging zone in fractured formations, analyze composition and ratios of different sizes of particles in the plugging zone, and reveal the essence and driving energy of the formation and damage of the plugging zone. New criteria for selecting lost circulation materials are proposed. The research results show that the formation of the plugging zone has undergone a process from inertial flow, elastic flow, to quasi-static flow. The plugging zone is composed of fracture mouth plugging particles, bridging particles and filling particles, and the proportion of the three types of particles is an important basis for designing drilling fluid loss control formula. The essence of the construction of the plugging zone is non-equilibrium Jamming phase transition. The response of the plugging zone particle system to pressure is driven by entropy force; the greater the entropy, the more stable the plugging zone. Lost circulation control formula optimized according to the new criteria has better plugging effect than the formula made according to conventional plugging rules and effectively improves the pressure-bearing capacity of the plugging zone. The research results provide a theoretical and technical basis for the lost circulation control of fractured formations.

Rapid bentonite-cement-oil hydration: Implications to fluid loss control

Conventional particulate additives fail to control drilling fluid losses into large-aperture fractures. The separate injections of a bentonite-cement-oil suspension and water can cause rapid hydration, swelling and hardening to effectively plug fractures. This experimental study investigates underlying processes and implications in view of optimal fluid flow control in fractures. Results identify several concurrent hydro-chemo-mechanical coupled processes: capillarity-driven water invasion; cement hydration and the release of Ca2+ and OH− ions; bentonite contractive aggregation and increased hydrophilicity; enlarged inter-aggregate pores that facilitate fluid flow; oil pressurization leading to the formation of oil-filled opening mode discontinuities that facilitate oil escape towards free draining boundaries, and calcium silicate hydrate formation and growth resulting in hardening. The hydration of bentonite-cement-oil suspensions proceeds several times faster than in bentonite-oil suspensions. The optimal mixture should balance competing requirements between flowability, water invasion speed, swelling pressure and plug strength.

Technology Focus: Cementing and Zonal Isolation (May 2022)

Over the past year, the number of cementing and zonal-isolation papers was much lower than usual because of the cancellation and postponement of several conferences. The overall impact, however, was mitigated by the transformation of several conferences to online events. I attended one virtual event and was pleasantly surprised with the value of the technical discussions that immediately followed each paper presentation and the willingness of authors to follow up on discussions after the conference. The development of new technology can take a significant amount of time and resources, and full worldwide introduction may take many years, giving rise to a commercial risk for the technology developer. One paper published last year described the first case history of self-healing cement technology in one geographical area more than 10 years after the publication of the first field application of the technology. In the October 2021 issue of JPT, SPE President Kamel Ben-Naceur discussed the importance of collaboration in solving technical problems quickly and efficiently. Three of the papers selected in this section are from collaborations between multiple companies pooling their expertise and resources to develop solutions for complex problems that could not be addressed efficiently by individual companies. Papers SPE 204015 and SPE 208782 issue from consortia whose goals are to improve the efficiency and reliability of plugging-and-abandonment operations. Paper SPE 204103 is a jointly funded collaboration evaluating CO2-resistant cement with a new experimental methodology to accelerate chemical interactions between the cement and CO2, thus shortening the validation time. The commercial risks associated with the incremental developments of existing technology can be acceptable more readily to individual companies, although this does not mean that efficient internal teamwork is not required. The three other papers selected are all supported and authored by individual companies, but each is a collaboration between multiple people with different expertise—experimental and poromechanical modeling expertise in paper SPE 206144, chemical synthesis and microfluidics expertise in paper SPE 207472, and cement chemistry and experimental expertise in paper SPE 208679. Recommended additional reading at OnePetro: www.onepetro.org. SPE 204103 Evaluation of New Innovative Cement Blend for Enhanced CO2 and H2S Resistance by Gunnar Lende, Halliburton, et al. SPE 206144 Advanced Cement Mechanical Integrity for Thermal Wells by Manh-Huyen Vu, Curistec, et al. SPE 207472 Associative Microgels, New Self-Adaptive Systems To Control Fluid Loss in Well Cementing by Arnaud Cadix, Solvay, et al.

An Inverse Emulsion Polymer as a Highly Effective Salt- and Calcium-Resistant Fluid Loss Reducer in Water-Based Drilling Fluids.

To control the fluid loss of water-based drilling fluids (WBDFs) in salt-gypsum formations, a nano-SiO2 graft copolymer was prepared by inverse emulsion polymerization. The polymer (EAANS) was prepared with acrylamide, 2-acrylamido-2-methyl-1-propane sulfonic acid, N-vinylpyrrolidone, and KH570-modified nano-silica (M-SiO2) as raw materials. The molecular structure and morphology of EAANS were characterized by Fourier transform infrared spectroscopy, nuclear magnetic resonance, thermogravimetric analysis, transmission electron microscopy (TEM), and other methods. In the temperature range of 150 °C, 2 wt % EAANS can reduce the API filtration volume of the base slurry to within 20 mL and the HP-HT filtration volume at 150 °C to 21.8 mL. More importantly, 2 wt % EAANS can maintain the API filtration volume less than 10 mL even when the concentration of NaCl or CaCl2 was as high as 36 or 30 wt %, and as the salt/calcium content increased, the amount of filtration continued to decrease. The results of TEM, X-ray diffraction, particle size distribution, and scanning electron microscopy showed that the fluid loss control mechanism of EAANS was that EAANS can form a crosslinked network structure in the solution and adsorb on the clay surface, so as to reduce the particle size of clay particles, increase the proportion of fine particles in drilling fluids, and finally form a dense filter cake to reduce the filtration volume. Because of the excellent filtration performance of EAANS at high Na+/Ca2+ concentration, EAANS can become a promising WBDF fluid loss reducer in salt-gypsum formations.

Status and Prospect of Drilling Fluid Loss and Lost Circulation Control Technology in Fractured Formation.

Lost circulation in fractured formation is the first major technical problem that restricts improvements in the quality and efficiency of oil and gas drilling engineering. Improving the success rate of one-time lost circulation control is an urgent demand to ensure “safe, efficient and economic” drilling in oilfields all over the world. In view of the current situation, where drilling fluid loss occurs and the plugging mechanism of fractured formation is not perfect, this paper systematically summarizes the drilling fluid loss mechanism and model of fractured formation. The mechanism and the main influencing factors to improve the formation’s pressure-bearing capacity, based on stress cage theory, fracture closure stress theory, fracture extension stress theory and chemical strengthening wellbore theory, are analyzed in detail. The properties and interaction mechanism of various types of lost circulation materials, such as bridging, high water loss, curable, liquid absorption and expansion and flexible gel, are introduced. The characteristics and distribution of drilling fluid loss in fractured formation are also clarified. Furthermore, it is proposed that lost circulation control technology for fractured formation should focus on the development of big data and intelligence, and adaptive and efficient intelligent lost circulation material should be continuously developed, which lays a theoretical foundation for improving the success rate of lost circulation control in fractured formation.

Dynamically Evaluating the Performance of Naturally Occurring Additives to Control Lost Circulation: On the Effect of Lost Circulation Material Type, Particle-Size Distribution, and Fracture Width

Summary Lost circulation is one of the most challenging problems during drilling of oil and gas wells. This issue leads to significant loss of drilling fluid, increase of nonproductive time as well as dictating additional costs to drilling companies. Lost circulation may also lead to other consequences, including stuck pipe, poor hole cleaning, and well control issues. How to efficiently control lost circulation have been traditionally depending on the type of the used lost circulation material (LCM). Injection of commonly available materials (without any further process on their chemical properties) into the thief zone is a common method of lost circulation control. These nonmodified materials are named as conventional LCMs against the unconventional LCMs which are designed/produced just for fluid lost control. The objective of this paper is to comparatively investigate the performance of cane, oak shell, wheat, and mica as LCM of water-based drilling fluid exposed to fractured formations. These materials were chosen because of their low cost, easy access, and compatibility with the environment. The sealing efficiency of these materials was assessed at different particle-size distributions (PSDs) for proper treatment of loss circulation. To do so, an experimental setup containing a cell with adjustable fracture size was designed. Among the LCM formulations made of each of the materials, oak shell formulations are better than the others, followed by mica and cane blends, respectively. The results reveal that combining the materials together is a better treatment than the separate use of them. As it will be seen in detail later, high diversity in particle size (broad PSD) causes more efficient control of fluid loss. Also, to reduce the dependency of sealing ability of LCM formulation on fracture size, mixing of the materials with different particle sizes and shapes is recommended.

Slightly Amphiphilic Polymer Microspheres as an HTHP Fluid Loss Control Additive for Oil-Based Drilling Fluid

Slightly Amphiphilic Polymer Microspheres as an HTHP Fluid Loss Control Additive for Oil-Based Drilling Fluid

An efficient, cost-effective, and green natural extract in water-based drilling muds for clay swelling inhibition

Clay swelling is one of the major challenges of the oil and gas industry during the drilling operation. Water-based muds (WBM) are commonly used in drilling operations due to their low environmental footprint. The rheological properties, fluid loss control, and clay hydration play a crucial role in the selection of WBM. However, WBM can cause clay swelling in contact with clay material. For the first time, the present work reports the effect of Date palm leaves extract (DPLE) as a naturally occurring and environment-friendly green additive as a clay swelling inhibitor for water-based muds (WBM). The extensive evaluation including rheology, fluid loss, capillary suction timer (CST), zeta potential, X-ray diffraction (XRD), scanning electron microscope (SEM), and linear swelling tests were used to assess the clay swelling inhibition features of the DPLE. The outcomes revealed that the swelling control by DPLE was the function of its concentration. The 5% DPLE demonstrates the least linear swelling (62.3%) as compared to 2% DPLE (98.5%) Na2SiO3 (96.5%), and water (124.2%). The DPLE also influences and improves the rheology and deflocculation properties of the WBM. The proposed inhibition mechanism shows that the surface coating of DPLE resulted in the protection of bentonite clay and make it hydrophobic. Consequently, the affordability, environment friendliness, clay swelling control, and ease of access make the pertinency of DPLE in WBM extremely worthy.

The Potential of Ultrahigh Strength Gel through Novel Multistage Reinforcement Method for Sealing Operations in Medium to Ultralow Temperature Reservoirs

Summary Polymer gels are widely used in sealing operations in the oil and gas industry. Gel with high strength is strongly needed to perform such operations as fluid loss control, temporary plugging, casing integrity treatment, and water shutoff, etc. In this paper, a simple method is proposed to obtain ultrahigh strength gel (USGel), which is called multistage reinforcement method (MRM) and implies the philosophy of noncompetitive crosslinking, multistage reinforcement of molecular chains, and increased entanglement. By this method, acrylamide (AM), xanthan (XC), and two crosslinkers [N,N'-Methylenebisacrylamide (MBA), chromium acetate (Cr3+)] are selected to develop an USGel with potential for medium to ultralow temperature reservoir applications. The thermal stability and sealing performance of USGel are evaluated. The effect of component concentration, gelant pH, and temperature on the strength and gelation time of USGel are investigated. Counterintuitively, adding solid materials even reduces USGel strength. The strength of USGel exceeds other gels by comparison with reported stress-strain data from similar literature. After data fitting analysis, without considering the XC concentration, 1% Cr3+ can increase the strength of the gel by 78.32 times, while other gels with 1% reinforcement material (e.g., solid materials) can only increase by 1.09 to 1.35 times. At low concentrations (0.4% XC and 0.2% Cr3+), USGel strength can also reach 84.59–383.21 kPa at 15°C to 105°C when strain = 60%. Environmental scanning electron microscope(ESEM) and gelation data are used to further reveal the multistage reinforcement mechanism of USGel and the reason for strength reduction owing to adding solid materials. USGel is promising to be applied in sealing operations in medium to ultralow temperature reservoirs.

Study on the Preparation and System of Desulfonated Anti-High Temperature Fluid Loss Agent

In this study, a desulfonated hybrid organic/inorganic fluid loss agent resistant to high temperatures is synthesized by using free-radical copolymerization. The fluid loss agent consists of the organic monomer acrylamide (AM), N-vinylpyrrolidone (NVP), dimethyl diallyl ammonium chloride (DMDAAC), and the inorganic monomer KH570 modified by nano-silica (M-SiO2). A field emission transmission electron microscope, an infrared spectrometer, and a thermogravimetric analyzer are used to examine the morphology and structure of the fluid loss agent. The results show that the inorganic nanoparticles and organic polymers are successfully grafted, and the resulting “core-shell” structure is connected by molecular chains. When 2% wt of the synthetic fluid loss additive E(AND-SiO2) is added to the base slurry, the normal-pressure fluid loss (FLAPI) and high-temperature, high-pressure fluid loss (FLHTHP) of the slurry are determined by the aging tests at 150, 160, 170, 180, 190, and 200°C for 16 hours. The results show that when the temperature is 180°C, FLAPI is 6.4 mL, FLHTHP is 28 mL, and temperature resistance is good. The biological toxicity and biodegradability tests show that the fluid loss control agent does not only effectively reduce the fluid loss, but also easily degrades, making it an environmentally-friendly treatment agent.

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

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