Shale Surface Research Articles

Reduced adsorption of polyacrylamide‐based fracturing fluid on shale rock using urea

AbstractHydraulic fracturing is generally necessary to achieve economically viable production rates during exploitation of shale reservoirs. Polyacrylamide‐based fracturing fluid is commonly used in shale fracturing. Polyacrylamide (PAM) becomes adsorbed in the shale micro‐fractures, decreasing the permeability of the reservoir. For improving the production of shale after being stimulated, the adsorption behavior and adsorption mechanism between thePAMand shale are studied. An ultraviolet spectrophotometer is used to obtain the amount of adsorption. To observe the adsorption morphology, a scanning electron microscope is employed. The action force between thePAMand shale rock is analyzed through Fourier transform infrared spectroscopy, zeta potential instrument, and X‐ray photoelectron spectroscopy. The results indicate that hydrogen bonding is the key force between thePAMand shale. A kind of shale micro‐fractures model is designed to determine the recovery of permeability. Urea breaks the hydrogen bonding and keeps the molecular ofHPGstretch which can decrease the amount of adsorption on the shale surface and effectively recover the permeability of shale micro‐fractures up to 72.46% after being damaged. In conclusion, it is believed that the competitive adsorption is a new approach for remediation of the permeability damage by PAM‐based fracturing fluid and has great potential in oil field application.

Drill-in fluid loss mechanisms in brittle gas shale: A case study in the Longmaxi Formation, Sichuan Basin, China

Brittle gas shale consists of a high content of brittle mineral and developed natural fractures and has become the focus of petroleum industry in recent years. Lost circulation may easily occur due to the long soaking time and an overbalanced pressure difference during the drill-in process of the horizontal long section. The dynamic fracture width simulation induced by drill-in fluid invasion, plugging zone pressure containment test, friction coefficient test between lost circulation materials and shale surface, oil based drill-in fluid filtrate immersion test were conducted to investigate the drill-in fluid loss mechanisms in the brittle Longmaxi Shale in the Sichuan Basin of China. Results show that the fracture width at the fracture mouth increased from 2 μm to 239 μm for the two mutually perpendicular fractures connecting to the wellbore due to drill-in fluid invasion. Effective plugging for dynamic fractures was failed to be achieved for the original drill-in fluid. Fracture width increase induced by drill-in fluid invasion is the major cause of plugging failure of brittle gas shale. Instability of the brittle shale induced by oil phase lubrication and high pH drill-in fluid erosion further exacerbates lost circulation problems. Optimized LCMs considering the dynamic apertures of fractures should be selected and added into drill-in fluid to rapidly seal pre-exiting fractures and induced fractures for lost circulation control in brittle shale. The results serve as a guide for the drill-in fluid design of shale gas in brittle gas shale formation.

Coupling of Wellbore and Surface-Facilities Models With Reservoir Simulation To Optimize Recovery of Liquids From Shale Reservoirs

Summary The objective of this paper is to couple wellbore and surface-production-facilities models with reservoir simulation for a shale reservoir that contains dry gas, condensate, and oil in separate geologic containers within the same structure. The goal of this integration is to improve liquid recoveries by dry-gas injection and gas recycling. Methods previously published investigate possible means of improving recovery from shales and have concentrated on laboratory work and the reservoir itself, but have ignored the wellbore and surface-production facilities. The coupling of these facilities in the simulation work is critical, particularly in cases involving condensate and oil reservoirs, gas injection, and recycling operations. This is so, because a change in pressure in the reservoir is reflected almost immediately in a change in pressure in the wellbore and in the surface installations. The development presented in this paper considers multistage hydraulically fractured horizontal wells. Dry gas is injected into zones that contain condensate and oil. Gas stripped from the condensate production is reinjected in the condensate zone in a recycling operation. The study focuses on the Eagle Ford Shale, which has separate containers for each fluid within the same structure. The study leads to the conclusion that, for the studied system, liquid recoveries can be maximized with continuous and huff ’n’ puff gas-injection schemes. In general, huff ’n’ puff injection provides better results in terms of production and economics. Molecular diffusion is found to play a crucial role in continuous gas-injection operations. Conversely, the effect of this phenomenon is negligible in huff ’n’ puff gas injection. This research demonstrates that proper design of wellbore and surface installations, including, for example, downhole pumps and compressors, is important because it plays a critical role in the performance of production and injection operations and in maximizing recovery of liquids from shale reservoirs. The novelty of the methodology developed in this paper is the coupling of models that handle surface facilities; wellbores; numerical simulation including oil, condensate, and dry-gas reservoirs; gas injection; and gas/condensate-recycling operations. Essentially, the shale containers, wellbore, and surface facilities are continuously “talking” to each other. To the best of our knowledge, this integration for shales has not been published previously in the literature.

Flow transportation inside shale rocks at low-temperature combustion condition: A simple scaling law

The gas flow inside the shale undergoes a complicated process from continuum-flow to Knudsen diffusion during combustion. In this study, a shale sample obtained from Shanxi province with burial depth of 643 m was combusted at a constant temperature to study the transient internal pressure variation. In the beginning, a cylinder-shaped shale was combusted above an electric heater at a constant temperature 450 °C. The transient internal pressures and surface temperatures of the shale sample were recorded every 15 s. With the thermal wave propagating from the electric heater to the top of shale, the shale surface temperature gradually increased. The pressure inside the sample was quickly built up because of the thermal cracking of kerogen. It reached a peak value of 12,000 Pa. Afterwards, the pressure gradually declined with the improvement of the permeability of the shale. By the observations during the experiment, a combustion model based on the scaling power law was used to simulate the transient internal pressure changes of a cylinder shaped shale sample during the combustion process. The simulated results showed a good agreement with experimental data. Based on the pressure variation data, it was found that not only the original trapped/storage gas (free state gas, adsorbed state gas, and dissolved state gas) but also the thermal cracking hydrocarbon gases produced from kerogen could be extracted from tight shale formation for gas recovery. Thus, combustion can further improve the production rate of gas from shale reservoirs.

Influence of CO2 on the adsorption of CH4 on shale using low-field nuclear magnetic resonance technique

Due to the higher adsorption capacity, CO2 can efficiently replace the adsorbed CH4 from shale surface. To understand the effect of CO2 on the adsorption of CH4 on shale is significant for comprehending the mechanisms of enhanced shale methane recovery using CO2 method in shale gas reservoirs. In this work, the low-field nuclear magnetic resonance (NMR) technique is employed to quantitatively investigate the influence of CO2 on the CH4 adsorption on typical shale samples. CH4 is first introduced to “saturate” the shale samples at given pressures; based on the measured T2 spectrum for the “CH4-saturated” shale samples, the states that CH4 exists in shale samples are identified. CO2 is then introduced into the “CH4-saturated” shale samples at higher pressures. By comparing the measured T2 spectrum before and after CO2 introduction, the change of CH4 adsorption of due to the presence of CO2 is comprehensively analyzed. According to the measured T2 spectrum, CH4 exists on shale samples in three different states, i.e., the adsorbed CH4 on pore surface, the free-state CH4 in pore center, and the free-state CH4 among shale particles. Compared to the free-state CH4, the “CH4-saturated” shale samples are dominated by the adsorbed CH4. As pressure increases, the adsorbed amount of CH4 first increases and then tends to level off. After introducing CO2 into the “CH4-saturated” shale samples, the adsorbed CH4 is firstly reduced, suggesting the more affinity of CO2 to the organic shale surface, and then tends to level off, achieving the adsorption/desorption equilibrium. CO2 can replace the adsorbed CH4 from pore surface, decreasing the adsorbed molar amount of CH4. However, the replaced CH4 seems to only become free-state CH4 in pore center and hardly escape from the organic pores. Thereby, other stimulating methods, such as secondary hydraulic fracturing, should be supplemented with the CO2 injection for further development of the shale gas reservoirs.

Hydrothermal deformation of Marcellus shale: Effects of subcritical water temperature and holding time on shale porosity and surface morphology

Low porosity of Marcellus shale often limits the hydrocarbon recovery. To increase shale porosity, hydrothermal deformation (HTD) of Marcellus shale was performed and the effects of subcritical water temperature and reaction time on porosity were evaluated. HTD was performed at 200, 250 and 300 °C for one, three and 6 h of residence time. Low-temperature N2 adsorption was used for porosity measurement. Furthermore, the morphology of raw and HTD shale samples was analyzed with scanning electron microscopy-energy dispersive spectroscopy (SEM-EDS), and X-ray diffraction analyzer (XRD). It was observed that shale porosity was significantly enhanced by HTD conditions. For instance, HTD at 300 °C for 6 h of residence time, shale porosity increased more than four times compared to raw shale. This porosity was attributed to leaching of calcite, clay and quartz, which is confirmed by analyzing HTD process liquids by Induced Coupled Plasma-Optical Emission Spectroscopy (ICP-OES).

Fully coupled heat and water dynamics modelling of a reclamation cover for oil sands shale overburden

Numerical models of soil-water dynamics have been widely used in the design of soil cover systems for mine site reclamation; however, in most cases these models only consider water dynamics without consideration of heat dynamics. For cover systems in northern climates, such as those associated with oil sands mines in northern Alberta, Canada, freezing conditions exist for approximately 6 months of the year and snow melt comprises approximately 25% of annual precipitation. This study attempts to assess whether a fully coupled water and heat flow model (CM) provides additional insights into cover performance as compared with a water flow model (FM). The CM and FM are developed for a monitored reclamation cover constructed over oil sands shale overburden. The validated results indicated that the key limitation of the CM was its inability to simulate frozen ground infiltration. This limitation results in an overestimate of snow melt runoff and does not replicate the development of perched conditions on the shale overburden surface as a result of snow melt infiltration. The FM is also unable to simulate the observed infiltration of snow melt deep into the cover when snow melt is represented simply as surface precipitation in early spring following ground thaw. Both models are improved if snow melt infiltration is represented in the model by the preferential filling of macropores across the full depth of the cover and oxidized shale prior to ground thaw. This methodology is incorporated with the CM to produce a coupled water and heat model with enhanced infiltration (CM-EI), and with the FM to produce a flow model with enhanced infiltration (FM-EI). The CM-EI provided an improved simulation of soil temperature dynamics under frozen and unfrozen conditions, as well as soil water dynamics under unfrozen conditions, including the improved representation of the annual water balance components over each water year. Given the small difference in annual water balance components between the CM-EI and FM-EI modelling approaches (∼5 mm/year), it is concluded that a FM-EI provides the best tool with which to assess the performance of these reclamation covers.

Insight into the pore structure of Wufeng-Longmaxi black shales in the south Sichuan Basin, China

Based on total organic carbon (TOC) testing, X-ray diffraction (XRD) analysis, and low-pressure N2 adsorption experiments, vertical change and controlling factors of pore structure and gas content of Wufeng - Longmaxi over mature shales were investigated. The results show that within the most favorable pay zones of shale gas, surface area and pore volume reveal an upward decreasing trend with maximum value occurred in Wufeng and the bottom of Longmaxi Formations. Vertically constant pore size distribution (PSD) and fractal dimensions indicating the dominant pore type remains the same in the studied samples. Increasing of pore volume with depth is mainly caused by volume change of mesopore, especially that with size >4 nm. Surface area, however shows a good correlation with micropore area and is a function of micropore quantity. Pore structure variation of over mature shales is primarily controlled by TOC content and influence of minerals on pore structure is limited. For shales with similar preservation condition and thermal evolution, gas content is a function of reservoir storage capacity (surface area and pore volume) and gas generation. Organic matter acted both as the source of shale gas and as a storage medium and is the major control of gas content.

A polished and striated pavement formed by a rock avalanche in under 90 s mimics a glacially striated pavement

A polished and striated bedrock surface resembling a classical glacial striated pavement formed in 2009 in substantially <90 s beneath a rock avalanche on Jiweishan Mountain. Opportunities to closely examine such surfaces are rare, allowing researchers to speculate widely on basal rock-avalanche processes. We constrain future speculation by discussing signatures left on a basal sliding surface at a distance of 500 m from the headwall of this 2.2 km long rock avalanche. There are scratches, chatter marks and plucking scars on a surface of dolomitic black shale. They indicate frictional drag of particles in direct contact with the bed, causing relatively mild abrasion. Striations have beginnings and ends, vary in depth along their lengths, and do not always follow straight lines. These patterns suggest that the scratching particles moved about relative to one-another while confined in a deforming basal gouge. We used rotary shear equipment to experimentally shear both dry and saturated landslide gouge against intact shale from the sliding surface to create similarly grooved pavements under a realistic normal stress (1 MPa). Our observations and experiments suggested that the base of the landslide slid rapidly across this site on Jiweishan Mountain as a slightly erosive, initially water-saturated, dense grain flow with a low dynamic friction coefficient of about 0.1. Friction heated the base to about 800 °C, decomposing talc and dolomite to produce high-pressure live steam and carbon dioxide. What was left was a polished and grooved pavement highly reminiscent of a glacially striated pavement.

Investigation on the damage of high-temperature shale subjected to liquid nitrogen cooling

Cryogenic nitrogen fracturing can provide a new insight into the stimulation of deep shale gas reservoirs. In order to investigate the physical and mechanical behaviors of high-temperature shales (298–533 K) subjected to LN2 cooling, we tested the permeability, P-wave velocity and uniaxial compressive strength (UCS) of shale specimens. In the experiment, two cooling ways were used and compared: cooling by LN2 immersion and cooling in air naturally. The scanning electron microscope (SEM) was employed to observe the micro-structural changes after cooling. To determine the effect of cooling rate on the rock damage, we conducted a transient 3D thermo-mechanical simulation using ABAQUS. The experimental results indicate that LN2 cooling induces significant damage in shales. At any given shale temperature, the enhancement of permeability and reductions of UCS and P-wave velocity after LN2 cooling are greater than those after air cooling. Differences in the physical and mechanical properties between two cooling groups become more significant with shale temperature rising. LN2 cooling can create obvious cracks on the surface of shales, and size and number of these cracks increase as temperature rises. According to the SEM observation, most of the cooling induced cracks are inter-granular cracks which are mainly attributed to the mismatch of thermal properties between particles. The simulation results indicate that the cooling rate has a positive impact on the thermal stress. Faster cooling rate generates higher tensile stress in the exterior region of rocks, which helps intensify the deterioration of the rocks.

The effect of N-ethyl-N-hydroxyethyl perfluorooctanoamide on wettability alteration of shale reservoir

The wettability of the formation is critical for the flow back of the fracturing fluid and can further affect the gas production. So it is very necessary to study the wettability of shale reservoir. Here, a novel fluorocarbon surfactant, N-ethyl-N-hydroxyethyl perfluorooctanoamide, was synthesized and characterized by different methods. the contact angles of water and n-decane on the shale increased from 36° and 0° to 121° and 105°, respectively, after treated by N-ethyl-N-hydroxyethyl perfluorooctanoamide (0.5 wt.%). The surface free energy reduced from 72 mN/m to 7.4 mN/m. The results agreed with that of imbibition and capillary tube rise test. Additionally, the analysis of scanning electron microscope (SEM) and energy dispersive spectroscopy (EDS) showed that the roughness of shale surface remarkably increased. These results fully proved that the shale wettability is changed to super gas-wetting. Besides, the thermal analysis revealed that the novel fluorocarbon surfactant has good thermal stability. This indicates that it can be better applied to reservoir modifications at higher temperatures.

Impact of drilling fluids on friction coefficient of brittle gas shale

The stability of the horizontal long section of a wellbore is the main restriction of efficient development of shale gas. The use of oil-based drilling fluids in the initial stage of Longmaxi shale gas exploration in the Southern Sichuan Basin, China still causes wellbore collapses for reasons not well understood. Based on the geological characteristics and engineering conditions of brittle shale, a significant factor influencing shale wellbore stability-friction coefficient is proposed. Due to the developed facture networks of brittle shale in this region, frictional sliding along the fracture surface is the main source of movement within the Longmaxi Formation. Here, we determined the effects of drilling fluids on the Longmaxi Formation shale in Southern Sichuan Basin. Natural fractures slide due to compression shear slip, and the friction coefficient of the fracture surfaces is a controllable factor of shear and slip in natural fractures in shales. The typical experimental apparatus of rock friction sliding was modified to accommodate for drilling fluids and typical in-situ temperatures. Results show that the friction coefficient decreases, induced by infiltration of drilling fluids filtrate, and the friction coefficient is more sensitive to oil-based drilling fluid filtrate than water-based. The high-pH oil-based drilling fluid filtrate shortens the length of time taken by static friction stage, and smooths the time vs friction coefficient curve, which creates an easier situation for frictional sliding. High viscosity and good wettability lead to the strong lubricity of oil-based drilling fluid. The surface properties of the shale samples changed after the high alkalinity fluid immersion, such as fracture surface planarization, and floc-like particle generation, causing an obvious reduction of friction coefficient between fracture surfaces. As a result of rock strength decreasing after immersion into drilling fluids filtrate, asperities on fracture surface were prone to shear failure in the process of frictional sliding, and their failure products migrated with the fracture surface movement. This not only decreased the roughness shale surface but also acted as a friction reduction agent between the sliding surfaces. This study provides theoretical guidance for drilling fluid selection and optimization during brittle shale well drilling.

The effect of fluorocarbon surfactant on the gas-wetting alteration of reservoir

ABSTRACTReservoir wettability plays a vital role in the production of shale gas. In this work, two fluorocarbon surfactants were synthesized and characterized. The wettability of shale surface was evaluated by different method. The results showed that the contact angles of water and oil increased significantly after treatment. The surface free energy rapidly reduced to 10.3 mN/m and 5.9 mN/m, respectively. The roughness of the shale surface remarkably increased. These results confirmed that the shale wettability is altered from liquid-wetting to gas-wetting. Besides, the thermal analysis exhibited that they have good thermal stability before 173°C and 201°C, respectively.

Adsorption damage and control measures of slick-water fracturing fluid in shale reservoirs

Abstract The slick-water polymer adsorption damage and control measures in shale were examined using a shale pack model of the Ordovician Wufeng Formation–Silurian Longmaxi Formation in the Changning block of the Sichuan Basin. The adsorption law of slick water under different displacement time, concentrations, pH values and temperatures of polymer were tested by traditional displacement experiment and UV-Vis spectrophotometer. The adsorption equilibrium time was 150 min, the amount of adsorption was proportional to the concentration of the polymer, and the maximum adsorption concentration was 1 800 mg/L. With the increase of pH value, the adsorption capacity decreased gradually, the adsorption capacity increased first and then decreased with the increase of temperature, and the adsorption capacity was the largest at 45 °C. The adsorption patterns of polymers on shale were described by scanning electron microscopy and magnetic resonance imaging. It is proved that the adsorption of polymer on shale led to the destruction of the network structure of anionic polyacrylamide molecules, and the shale adsorption conformation was characterized qualitatively. Finally, according to the adsorption law and adsorption mechanism, it is proposed to reduce the adsorption quantity of polymer on shale surface by using hydrogen bond destruction agent. The effects of hydrogen bond destruction on four kinds of strong electronegative small molecules were compared, the hydrogen bond destroyer c was the best, which lowered the adsorption capacity by 5.49 mg/g and recovered permeability to 73.2%. The research results provide a reference for the optimization of construction parameters and the improvement of slickwater liquid system.

Synthesis and Evaluation of Two Gas-Wetting Alteration Agents for a Shale Reservoir

It is well-known that shale gas production is affected by the wettability of the reservoir. In this work, two gas-wetting alteration agents were synthesized and characterized by 1H NMR and FTIR. To evaluate the effect of the gas-wetting alteration agents on the shale wettability, the contact angle for droplets on the shale surface was detected, and the results showed that the contact angles of water and n-hexadecane increased from 36° and 0° to 119° and 88° after treatment with sodium [N-propyl-N-(perfluorooctanoyl)amino]acetate (SCF-102), while the contact angles increased to 122° and 110°, respectively, after treatment with sodium [N-[[N-(perfluorooctanoyl)amino]ethyl]amino]propionate (SCF-113). The surface free energy rapidly decreased from the primeval 72 to 10.3 and 6.8 mN/m at equal concentration. These values agreed with the results of spontaneous imbibition, the capillary tube rise test, and the fluid flow test. Additionally, the analysis with energy dispersive spectroscopy and scanning electron m...

Synthesis and characterization of shale stabilizer based on polyethylene glycol grafted nano-silica composite in water-based drilling fluids

In order to solve wellbore instability problems in the drilling process, high-performance shale stabilizers in water-based drilling fluids are essential. In this paper, a novel shale stabilizer based on polyethylene glycol grafted nano-silica composite (PEG-NS) was successfully synthesized. Conventional techniques were used to characterize PEG-NS including Flourier transform infrared spectroscopy (FT-IR), scanning electron microscope (SEM), transmission electron microscopy (TEM), particle size distribution (PSD) and thermogravimetric analysis (TGA). The results showed that the structure of PEG-NS was in agreement with the design objective. The particle size of PEG-NS ranged from 110 to 434 nm, and PEG-NS had good thermal stability. Pressure transmission test, pore structure characterization of shale, rolling recovery test were applied to evaluate the comprehensive performance of PEG-NS as a novel shale stabilizer. The experimental data indicated that PEG-NS could effectively retard the pore pressure transmission and reduce the permeability of shale sample. PEG-NS could adsorb onto the shale surface and a dense plugging film could finally coat on it. Moreover, PEG-NS also exhibited better inhibition performance compared with that of potassium chloride (KCl) and polymeric alcohol (JHC) at the same concentration. Hence, PEG-NS could be a good shale stabilizer in water-based drilling fluids for drilling reactive shale formations.

Release of Particulate Iron Sulfide during Shale-Fluid Interaction.

During hydraulic fracturing, a technique often used to extract hydrocarbons from shales, large volumes of water are injected into the subsurface. Although the injected fluid typically contains various reagents, it can become further contaminated by interaction with minerals present in the rocks. Pyrite, which is common in organic-rich shales, is a potential source of toxic elements, including arsenic and lead, and it is generally thought that for these elements to become mobilized, pyrite must first dissolve. Here, we use atomic force microscopy and environmental scanning electron microscopy to show that during fluid-rock interaction, the dissolution of carbonate minerals in Eagle Ford shale leads to the physical detachment, and mobilization, of embedded pyrite grains. In experiments carried out over a range of pH, salinity, and temperature we found that in all cases pyrite particles became detached from the shale surfaces. On average, the amount of pyrite detached was equivalent to 6.5 × 10-11 mol m-2 s-1, which is over an order of magnitude greater than the rate of pyrite oxidation expected under similar conditions. This result suggests that mechanical detachment of pyrite grains could be an important pathway for the mobilization of arsenic in hydraulic fracturing operations and in groundwater systems containing shales.

Improving wellbore stability of shale by adjusting its wettability

The possibility of improving wellbore stability of shale by adjusting its wettability was investigated. First, an optimized surfactants combination (0.2 wt% cetyltrimethylammonium bromide (CTAB) plus 0.1 wt% sodium dodecyl benzene sulfonate (SDBS)) was screened out that could effectively reduce the surface tension of the water-based mud (WBM) or fresh water, and increase the contact angle with shale. Then, regular tests on viscosity, filtration, lubrication, water activity, and special tests on linear swelling, rolling recovery rate, temperature tolerance, salts, and active cuttings tolerance, along with pressure transmission test (PTT) of shale were conducted to evaluate the performance of the optimized surfactants combination. Results show that the WBM's surface tension could be decreased from 45.1 to 20.0 mN/m and the contact angle on the shale could be increased from 34.5 to 63.5°. The optimized surfactants combination could also improve the WBM's performance to inhibit shale hydration. The WBM in the presence of the optimized surfactants combination had good tolerance to a pollutants complex (0.8 wt% CaCl2, 0.8 wt% MgCl2, 5 wt% sodium bentonite, and 10 wt% NaCl) and could withstand a high temperature of 130 °C. Foaming phenomenon could be avoided by adding surfactants in the last step. PTT results show that compared with 4 wt% NaCl, the optimized surfactants combination could effectively retard the pore pressure transmission in shale and reduce its permeability by 98.6%. The addition of CTAB to the WBM or fresh water, hydrolyzed CTA+ cation adsorbs on the surface of shale via an ionic bond, forming a hydrophilic base toward shale and a lipophilic base toward the WBM or water, thus, increasing the contact angle with shale and improve wellbore stability in shale. This paper paves a new way to address wellbore stability issues in troublesome shale formations.

Molecular dynamics of methane adsorption in shale

ABSTRACTIn this paper, the supercritical gas molecule adsorption characteristics of methane in shale are quantitatively described by using the lattice theory. The results show that the methane adsorption capacity predicted by this theory is high, with the average absolute error 0.003 3 mmol·g−1. There is a near-linear positive relationship between the adsorption potential between methane and the solid surface (ϵs) and the experimental temperature. The value of the average potential between the adsorbate molecules (ϵa) is distributed in −0.841–1.791 kJ·mol−1, and the absolute value of ϵa is significantly smaller than the absolute value of ϵs, indicats that the potential energy between the adsorbate molecules is significantly smaller than that between the adsorbate molecules and the pore surface of shale. When the temperature is relatively low (T = 308.55 K), the value of ϵs/ϵa is 7.5 times; with the increases of the temperature, the magnification will gradually decrease and keep stabilize (3.37 times).

Microencapsulation of Acids by Nanoparticles for Acid Treatment of Shales

Acid treatment is one of the common well-stimulation techniques to improve the production in tight carbonates or calcite-rich shale reservoirs. Because the reaction rates are often too large at the reservoir temperatures, retarded acid systems such as emulsified acids, foamed acids, and polymer-gelled acids are used. The retarded acids also minimize damage to the wellbore and propagate acids long-distance from the wellbore in fractured shales. In this work, a novel encapsulation method of highly concentrated acid (∼10 wt % HCl) is reported as an alternative retarded acid system. Microencapsulation of these acids is performed using highly hydrophobic silica nanoparticles. The mixing of these particles with acid under high shear rates results in the formation of acid-in-air powders. The release of acid from these powders could be triggered by external stimuli such as mechanical pressure or surfactant addition. The thermal stability, corrosion inhibition efficiency, and shale surface reactivity are compared ...