Hydraulic Fracturing Fluid Research Articles

Study of the Interaction of a Hydraulic Fracture with a Natural Fracture in a Laboratory Experiment Based on Ultrasonic Transmission Monitoring

This paper presents the results of experiments on the study of a hydraulic fracture’s interaction with a preexisting fracture. A distinctive feature of the conducted experiments is the ability to use ultrasonic transmitting monitoring to measure the fracture propagation and opening simultaneously with the pore pressure measurements at several points of the porous saturated sample. It allows us to obtain the pressure distributions at various experiment stages and to establish a relation between the pore pressure distribution and hydraulic fracture propagation and its interaction with macroscopic natural fractures. The possibilities of active ultrasonic monitoring have been expanded due to preliminary calibration experiments, which make it possible to estimate the fracture opening via attenuation of ultrasonic pulses. The experiment demonstrated the most complex scenario of fracture interactions when a hydraulic fracture intersected with a natural fracture and the natural fracture in the vicinity of the intersection was also opened. The additional complications arise from fracture arrangement: the hydrofracture was normal with respect to the base plane, while the natural fracture was slanted. This led to gradual growth of the intersection zone as the hydrofracture propagated. The experiments show that the natural fracture limited the fracture’s propagation. This was caused by the hydraulic fracturing fluid leaking into the natural fracture; thus, both the hydraulic fracture and natural fracture compose a united hydraulic system.

Intensification of oil production through the use of hydraulic fracturing fluid based on polyacrylamide

The article considers the technology of Hydraulic Fracturing (HF) based on polyacrylamide (Co-PAM), identifies parameters for evaluating the quality of the fluid both on a guar and polyacrylamide base. Fluid viscosity is a main criteria of success of HF operations. Thus, fluid thermal stability, determine the pumping time. The composition of the Co-PAM-based HF fluid differs from the guar-based one, consisting of two main chemical reagents - a gelling agent and a crosslinker(x-linker), in that only a synthetic gelling agent is used. Recommended concentration starts from 4 l/m3. At this concentration the synthetic gel starts to exhibit properties of a sand-carrying fluid, suitable for standard pump rate (4.0-5.0 m3/min) HF. A significant advantage is compliance with the requirements for HF fluids which not only improves the filtration properties of the formation but also considers the economic feasibility of using such a chemical reagent. Co-PAM gel using provides reduction of logistics costs, water heating. Also it allows to exclude hydration unit, reduced crew, decreased wear on pumping units, including reduced consumption of lubricants during the HF operation.

Iron Stress Testing of Oilfield Produced Waters and Hydraulic Fracturing Fluids in the Bakken

Iron Stress Testing of Oilfield Produced Waters and Hydraulic Fracturing Fluids in the Bakken

In vivo exposure to electronic waste (e-waste) leachate and hydraulic fracturing fluid adversely impacts the male reproductive system

Human health effects can arise from unregulated manual disassembly of electronic waste (e-waste) and/or hydraulic fracturing fluid spills. There is limited literature on the effects of e-waste and hydraulic fracturing wastewater exposure on the male reproductive system. Thus, this proof-of-concept study begins to address the question of how wastewater from two potentially hazardous environmental processes could affect sperm quality. Therefore, three groups of eight-week-old adult mice were exposed (5 d/wk for 6 wks) via a mealworm (Tenebrio molitor and Zophabas morio) feeding route to either: (1) e-waste leachate (50% dilution) from the Alaba Market (Lagos, Nigeria); (2) West Virginia hydraulic fracturing flowback (HFF) fluid (50% dilution); or, (3) deionized water (control). At 24-hours (hr), 3 weeks (wk), or 9-wk following the 6-wk exposure period, cohorts of mice were necropsied and adverse effects/persistence on the male reproductive system were examined. Ingestion of e-waste leachate or HFF fluid decreased number and concentration of sperm and increased both chromatin damage and numbers of morphological abnormalities in the sperm when compared to control mice. Levels of serum testosterone were reduced post-exposure (3- and 9-wk) in mice exposed to e-waste leachate and HFF when compared to time-matched controls, indicating the long-term persistence of adverse effects, well after the end of exposure. These data suggest that men living around or working in vicinity of either e-waste or hydraulic fracturing could face harmful effects to their reproductive health. From both a human health and economic standpoint, development of prevention and intervention strategies that are culturally relevant and economically sensitive are critically needed to reduce exposure to e-waste and HFF-associated toxic contaminants.

Experimental Investigation of Hydraulic Fracturing Fluid Based on Pseudo Gemini Surfactant with Polysaccharide Addition.

In the last decade, hydrogels for hydraulic fracturing based on viscoelastic surfactants have been actively studied. Interest in these systems is justified by their unique qualities: good viscoelasticity and the ability to form stable suspensions of proppant or sand, destruction without the formation of bridging agents, hydrophobization of the rock surface and metal of technological equipment, as well as oil-cleaning properties. These qualities are most often provided by a minimum set of components-a surfactant and an electrolyte. However, the absence of a polymer limits the use of these gels in formations where fluid leakoff is possible. In this article, a liquid was studied, based on a pseudo gemini surfactant (PGVES) with the addition of a water-soluble polysaccharide. The objects of study were selected based on the assumption of interactions between PGVES and the polymer; interactions which favorably influence the technological characteristics of the fracturing fluid. To confirm the hypothesis, rheological studies were carried out. These included rotational viscometry and oscillatory studies at various temperatures. The settling velocity of particles of various proppant fractions was studied and tests were carried out to assess fluid leakoff. The performed experiments show an improvement in the characteristics of the PGVES-based gel under the influence of the polysaccharide. In particular, the rheological properties increase significantly, the stability of proppant suspensions improves, and the fluid leakoff of systems decreases, all of which expands the possibility of using these fracturing fluids and makes this area of experimentation promising.

Artificial fractures conductivity impairment in gas shale when fracturing with surface water

The shale gas fields are mainly in mountainous areas in China. Surface water is the major source of hydraulic fracturing fluid to develop shale gas. The clay mineral is generally rich in the shale gas reservoir. When encountered with low salinity surface water, the clay minerals are easy to hydrate in the process of fracturing and well shut-in. The hydration of clay minerals would result in the expansion, dispersion, and migration of mineral particles from the fracture surface, changing the structure and space of fractures, thereby affecting fracture conductivity. In this paper, shale artificial fracture core models were developed with rough fracture surfaces. With proppant-supported and self-supported fracture core models, the impact of hydration time, net pressure, and dislocation distance of fracture surfaces on the artificial conductivity were evaluated systematically. The results show that the conductivity of proppant-supported and self-supported fractures decreases by 85.3–95.1% under hydration. The turning point of conductivity is 8.0 hrs. and 4.3 hrs., respectively. At the initial stage of production, the artificial fracture could be protected better if the net pressure on the fracture is maintained from small to large. At the same time, the initial net pressure on fracture should be less than the proppant crushing pressure. Certain dislocation distances of self-supported fractures would augment the conductivity by 6.4–12.8 times. After hydration, illite and montmorillonite in the rock surface expanded and dispersed when encountered with water. The fracture surface strength decreases by 29.8%, while the surface roughness decreases by 46.1–51.6%, and some proppants were crushed. Then the fracture conductivity space was reduced. By adding KCl into the fracturing fluid, hydration can be effectively inhibited, which can increase the proppant-supported and self-supported fracture conductivity by 2.5–3.4 times, compared with fracturing fluid prepared with surface water. This study provides a theoretical basis for the optimization of shale gas reservoir fracturing technology and production strategy.

Increases in trade secret designations in hydraulic fracturing fluids and their potential implications for environmental health and water quality

Hydraulic fracturing is an increasingly common method of oil and gas extraction across the United States. Many of the chemicals used in hydraulic fracturing processes have been proven detrimental to human and environmental health. While disclosure frameworks have advanced significantly in the last 20 years, the practice of withholding chemical identities as “trade secrets” or “proprietary claims” continues to represent a major absence in the data available on hydraulic fracturing. Here, we analyze rates of trade secret claims using FracFocus, a nationwide database of hydraulic fracturing data, from January 1, 2014 to December 31, 2022. We use the open-source tool Open-FF, which collates FracFocus data, makes it accessible for systematic analysis, and performs several quality-control measures. We found that the use by mass of chemicals designated as trade secrets has increased over the study time period, from 728 million pounds in 2014 to 2.96 billion pounds in 2022 (or a 43.7% average yearly increase). A total of 10.4 billion pounds of chemicals were withheld as trade secrets in this time period. The water volume used (and therefore total mass of fracturing fluid) per fracturing job has shown a large increase from 2014 to 2022, which partly explains the increase in mass of chemicals withheld as trade secrets over this time period, even as total fracturing jobs and individual counts of proprietary records have decreased. Our analysis also shows increasing rates of claiming proppants (which can include small grains of sand, ceramic, or other mineral substances used to prop open fractures) as proprietary. However, the mean and median masses of non-proppant constituents designated as trade secrets have also increased over the study period. We also find that the total proportion of all disclosures including proprietary designations has increased by 1.1% per year, from 79.3% in 2014 to 87.5% in 2022. In addition, most disclosures designate more than one chemical record as proprietary: trade secret withholding is most likely to apply to 10–25% of all records in an individual disclosure. We also show the top ten reported purposes that most commonly include proprietary designations, after removing vague or multiple entries, the first three of which are corrosion inhibitors, friction reducers, and surfactants. Finally, we report the top ten operators and suppliers using and supplying proprietary chemicals, ranked by mass used or supplied, over our study period. These results suggest the importance of revisiting the role of proprietary designations within state and federal disclosure mechanisms.

Hybrid Polymer-Surfactant Wormlike Micelles for Concurrent Use for Oil Recovery and Drag Reduction.

We report on the effect of a hydrocarbon (n-dodecane) on the rheological properties and shapes of the hybrid wormlike micelles (WLMs) of a surfactant potassium oleate with an embedded polymer poly(4-vinylpyridine). With and without hydrocarbon solutions, the hybrid micelles exhibit the same values of viscosity at shear rates typical for hydraulic fracturing (HF) tests, as solutions of polymer-free WLMs. Therefore, similar to WLMs of surfactants, they could be applied as thickeners in HF fluids without breakers. At the same time, in the presence of n-dodecane, the hybrid micelles have much higher drag-reducing efficiency compared to microemulsions formed in polymer-free systems since they form "beads-on-string" structures according to results obtained using cryo-transmission electron microscopy (cryo-TEM), dynamic-light scattering (DLS), and small-angle X-ray scattering (SAXS). Consequently, they could also act as drag-reducing agents in the pipeline transport of recovered oil. Such a unique multi-functional additive to a fracturing fluid, which permits its concurrent use in oil production and oil transportation, has not been proposed before.

Fracturing Fluid Optimization in Limestone Formation Using Guar Gum Crosslinked Fluid

The design of the fracturing fluid is a very important aspect of the success of hydraulic fracturing. The most common fracturing fluid used in hydraulic fracturing is the cross-linked guar gum fracturing fluid. To determine the optimal fracturing fluid concentration, it is necessary to analyze the fracturing fluid optimization to obtain the best fracturing results in terms of fracturing fluid rheology, regain permeability, hydraulics, cost, fracture geometry, and FOI. From this analysis, it is expected to obtain the most optimal fracturing fluid to be applied to the JARWO Well. This research was conducted by conducting a sensitivity test method for selecting the concentration of the fracturing fluid system that affects the fracture fluid rheology, regain permeability, fracturing fluid hydraulics during injection, total material cost, fracture geometry, and the resulting FOI. The sensitivity of the fracturing fluid concentration that was tested was the system concentration of 35 pptg, 40 pptg, and 45 pptg. Each fracturing fluid is tested in the laboratory to obtain rheology which will then be simulated using MFrac software to obtain the fracture geometry formed. The results of the analysis of the concentration of each fracturing fluid showed that the fracturing fluid with a system concentration of 40 pptg was the most stable in viscosity at pumping time to produce the highest FOI. The hydraulic fracturing fluid with a concentration of 40 pptg is better than that of a concentration of 45 pptg. From the performance of regaining permeability and residue, it is quite good when compared to fracturing fluid with concentration of 45 pptg, and the cost is lower when compared to a fracturing fluid with concentration of 45 pptg. So that the fracturing fluid with a system concentration of 40 pptg is the most optimal fluid for use in hydraulic fracturing activities at the JARWO Well.

Iron Stress Testing of Oilfield Produced Waters and Hydraulic Fracturing Fluids in the Bakken

Friction reducers are a major additive in almost all water-based hydraulic fracturing fluids. Despite the important role they play in friction reduction during hydraulic fracturing, they pose a veritable threat to the permeability of tight reservoirs upon precipitation. In the industry today, the potential for such precipitation is seldom assessed and as a result, an additional contributor to the formation damage problem has been given little attention. In this work, the sensitivity and affinity of friction reducers to very low concentrations of ferric ions are exploited to provide a qualitative assessment of their propensity to precipitate in hydraulically fractured hydrocarbon reservoirs. Representative samples of produced water and a routinely utilized hydraulic fracturing fluid recipe were spiked with 50ppm Iron (III) trichloride and incubated for 24 hours in a water bath at 200 degrees Fahrenheit. The results showed that precipitation of friction reducers in fracturing fluid is highly likely at low concentrations of ferric ions. This precipitate formed turned from yellow to brown color over time upon heating. The test showed presence of fragmented/unfragmented Partially Hydrolyzed Polyacrylamide (PHPAM) in the produced water, with varying degrees of FR gel precipitation depending on the processing treatment given to the water used for hydraulic fracturing. Evidence for the presence of partially hydrolyzed polyacrylamide was demonstrated in one of the produced waters while the rest did not produce any discernable precipitates. The results indicate that formations with lower iron concentrations may be more vulnerable to Fe3+-PHPAM precipitation than those with higher ferric ion concentration. Therefore, to mitigate formation damage through precipitation of FRs during hydraulic fracturing, a routine iron stress test like the one described herein is required on both hydraulic fracturing fluid and produced water to determine the vulnerability of the reservoir to formation damage by fragmented/unfragmented anionic PHPAMs.

Fabrication and Release Mechanism Study of a Nanocapsule Breaker for Controlling Degradation Rate of Insoluble Residue in Slickwater at Moderate-Temperature Reservoirs

Summary In an ideal hydraulic fracturing project, the viscosity of hydraulic fracturing fluid (HFF) should drop to facilitate an efficient and quick fracture cleanup once proppants have been placed. Ammonium persulfate (APS) is widely used as an oxidizer breaker to degrade the insoluble residue of the HFF. However, a complex network of artificial fractures with sizes ranging from millimeters to micrometers restricts the transportation application and reaction time of standard breakers and current millimeter-sized capsule breakers. In this study, we introduce an APS nanocapsule (APS-NC) breaker, fabricated via a simple miniemulsion technique, that is capable of addressing the degradation of insoluble residue of the HFF in deep fractures. The nanocapsules are produced through precise control of the nanoprecipitation of poly(methyl methacrylate) (PMMA) onto aqueous APS nanodroplets. Stable aqueous nanodroplets are generated by means of an inverse miniemulsion using Pluronic P-123 as a specific surfactant to form a large and stable water-oil internal surface referring to the long chain and amphipathic property of Pluronic P-123 molecule. Pluronic P-123 is included in the process not only to stabilize the miniemulsion and increase the precipitation efficiency of PMMA but also to function as a thermo-responsive switch for the delayed burst release of APS. The size of the resulting nanocapsules can be controlled within the 207 and 821 nm range, yielding APS up to 92%. The release rate of APS can be controlled by the initial amount of PMMA (150–300 mg), environmental temperature (40–80°C), and environmental pH (3.4–7). When the temperature was 80℃, the initial amount of Pluronic P-123 dominated the release dynamic of APS. Compared with the APS breaker in a dynamic degradation experiment, the APS-NC had a more controllable degradation profile that could cause hydrolyzed polyacrylamide (HPAM) to burst degrade after 6 hours of heating at 80°C.

Analyzing the impact of the interaction between hydraulic fracturing fluid and Kerogen on its wettability alteration

The increasing demand for exploring and developing unconventional reservoirs has sparked active research into hydraulic fracturing. However, the effect of hydraulic fracturing fluid on kerogen wettability alteration resulting from their interaction remains inadequately understood. This study aims to experimentally quantify the impact of hydraulic fracturing fluid on kerogen wettability alterations as a function of thermal maturity level. To achieve this objective, kerogens isolated from various organic-rich shale rocks of different types and maturities were mixed with synthetic hydraulic fracturing fluid at a temperature of 80 °C for 14 days. The resulting kerogen wettability was analyzed with the sessile drop method, Ion Chromatography (IC), and Attenuated Total Reflectance Fourier-Transform Infrared spectroscopy (ATR-FTIR), while Rock-Eval pyrolysis experiments were conducted as well to determine the kerogen geochemistry changes. After experiments, ANSYS-CFD was utilized to conduct numerical simulations of two-phase fluid flow to identify the impact of wettability on gas-water relative permeability.This study experimentally demonstrated that hydraulic fracturing fluid interacting with kerogen results in significant wettability alterations, which depend on the type and maturity of the kerogen. The Drop Shape Analyzer (DSA) results revealed that the air/water-contact angle decreased after the reaction for every type and maturity of kerogen, although the wettability alteration was greater with higher kerogen maturity. The ATR-FTIR findings revealed that mature kerogen isolates experienced a reduction in their hydrophobic functional groups, whereas kerogen isolates with relatively lower maturity demonstrated a potential loss of such groups, possibly resulting from oxidation. This trend toward hydrophilicity is consistent with the DSA results. The numerical modeling results indicated that the relative permeability was strongly influenced by the wettability of the formation. A water-wet formation led to a higher water relative permeability compared to the relative permeability of gas, and vice versa. These results represent a significant step forward in assessing multiphase fluid transport in organic-rich shales and hydrocarbon production.

Micellar aggregation of poly(acrylamide-co-styrene): Towards ‘self-removing’ polymers from solution

Polymer drag reducing agents (DRAs) are used in hydraulic fracturing processes to reduce frictional drag developed in fully turbulent pipe-flows. The drag reduction lowers energy consumption required to pump fluids. Removal and/or recovery of DRAs from the fracking fluids remains challenging causing environmental issues. We used model aqueous hydraulic fracturing fluids containing poly(acrylamide-co-styrene) P(AAm-co-St) as DRA and demonstrate an approach to ‘self-remove’/recover the P(AAm-co-St) copolymers by up to 55%. This approach involves foaming of P(AAm-co-St) solutions by sparging gas into fluid (at application relevant conditions) resulting in copolymer enrichment in a generated foam phase and subsequent removal from solution. Our observations suggest a simple method to remove or recover DRAs after drag reduction applications from fracking fluids. Liquid foams containing the P(AAm-co-St) copolymer were dried and redissolved in water offering the potential to be reused for further drag reduction applications or, in case of waste, explored for other applications as emulsifier or in macroporous materials.

A feasibility study on time-lapse controlled-source electromagnetic method for hydraulic fracturing monitoring of Well Eyangye-2HF in Yichang, Hubei Province, China

Abstract Hydraulic fracturing plays a crucial role in enhancing reserves and production of unconventional oil and gas resources. Injecting fracturing fluids into the ground to improve reservoirs also introduces the risk of inducing earthquakes; thus, monitoring the migration of these fluids is crucial. The microseismic positioning method determines the fracturing fluid by locating microseismic events generated by the fractured rock strata; however, this method is susceptible to errors. Low-resistivity subsurface fluids can directly change electromagnetic field signals, making the electromagnetic method a technically advantageous approach for monitoring the migration of hydraulic fracturing fluids. The monitoring test data of Well Eyangye-2HF show that the time-lapse controlled-source electromagnetic (CSEM) method is suitable for hydraulic fracturing and has good monitoring effects. The results of CSEM method can also compensate for deficiencies in microseismic monitoring. The electric field (Ex) observed using the CSEM method can directly predict the distribution edge of the fracturing fluid, and the anomalous zone of the Exrate of change is consistent with the fracturing-fluid injection parameters and microseismic monitoring results. The analysis of field data and forward simulation, based on electrical logging results, led to the conclusion that hydraulic fracturing operations can cause changes in the resistivity of the target layer and surrounding strata. These changes are attributed to the synergistic effects of formation stress, temperature, and the fracturing fluid. The electric-field changes observed using the CSEM method may be caused by multiple factors; however, use of time-lapse CSEM for monitoring hydraulic fracturing is still feasible.

Combined finite-discrete element modelling of hydraulic fracturing in reservoirs with filled joints

Hydraulic fracturing (HF) is known to be the most effective stimulation to enhance fractured reservoir permeability. The efficiency of an HF fluid injection largely depends on the pre-existing discontinuities or sources of heterogeneities. These features need to be considered in an HF operation design. Amongst these features, rock masses with filled joints are largely ignored despite their presence in deep rocks. This study focuses on HF development in such ground conditions and simulates their hydro-mechanical behavior by using the combined finite-discrete element method (FDEM), which is fully capable of modelling HF propagation in heterogeneous rocks. First, the interaction mechanism between an HF and a closed joint with approaching angles of 30, 60, and 90° is studied. The influences of flow rate, fluid kinematic viscosity, and confining in-situ stresses are evaluated. Then models with a single filled joint with approaching angles of 30, 60, and 90° are studied, interaction types explored, and failure types revealed by varying flow rate, fluid kinematic viscosity, and in-situ stresses. Having explored the interaction mechanism between an HF and a filled joint, three models with complex joint sets are considered; Voronoi filled joint, orthogonal filled joints, and randomly distributed discrete fracture networks (DFNs). The results show a complex interaction mechanism between the HFs and the filled joints. It is revealed that increasing approaching angle, flow rate, or fluid kinematic viscosity causes the development of more shear failure than tensile in models with Voronoi or orthogonal filled joints. However, it is shown that HF's interaction with the DFN is minimal and tensile failure governs considerably.

An Artificial Intelligence Method for Flowback Control of Hydraulic Fracturing Fluid in Oil and Gas Wells

Hydraulic fracturing is one of the main ways to increase oil and gas production. However, with existing methods, the diameter of the nozzle cannot be easily adjusted. This therefore results in ‘sand production’ in flowback fluid, affecting the application of hydraulic fracturing. This is because it is difficult to identify the one-dimensional series signal of fracturing fluid collected on site. In order to avoid ‘sand production’ in the flowback fluid, the nozzle should be properly controlled. Aiming to address this problem, a novel augmented residual deep learning neural network (AU-RES) is proposed that can identify the characteristics of multiple one-dimensional time series signals and effectively predict the diameter of the nozzle. The AU-RES network includes three parts: signal conversion layer, residual and convolutional layer, fully connected layer (including regression layer). Firstly, a spatial conversion algorithm for multiple one-dimensional time series signals is proposed, which can transform the one-dimensional time series signals into images in high dimensional space. Secondly, the features of the images are extracted and identified by the residual network. Thirdly, the network hyperparameters are optimized to improve the prediction accuracy of the network. Simulations and experiments performed on the field data samples show that the RMSE and LOSS when training the AU-RES network are 0.131 and 0.00021, respectively, and the prediction error of the test samples is 0.1689. In the gas field experiments, fracturing fluid sand production could be controlled, thus demonstrating the validity and reliability of the AU-RES network. By using the AU-RES neural network, sand particles will not be present in the flowback of fracturing fluid, thus improving the efficiency of hydraulic fracturing and reducing the cost of hydraulic fracturing. In addition, the AU-RES network can also be used in other similar situations.

Spatial and temporal water chemistry variations of hydraulic fracturing flowback and produced waters from the Duvernay Formation

Chemical characterization of hydraulic fracturing (HF) flowback and produced water (FPW) is important to the environmental sustainability of HF operations. In this research, we analyzed and compared HF FPW samples from different well locations as well as FPW samples from a single well at different stages of FPW production in the Duvernay Formation using a suite of analytical techniques and statistical methods. The results provide vital information to assess the reusability of FPW and support the choice of water handling, treatment, or disposal options. Additionally, this work contributes to a more complete understanding of regional FPW chemical composition and has the potential to provide guidance on best practices for future applications of HF fluid additives. While reuse of FPW is desirable, it is not always feasible. In these scenarios, the transportation of FPW offsite for treatment and/or disposal increases the risk of spills to near-surface environments. This work provides data to aid spill clean-up efforts and to determine the environmental fate of FPW contaminants. Overall, the information presented in this work may be used to provide economic benefits to the oil and gas sector by increasing FPW reuse that will directly decrease wastewater disposal costs and reduce environmental impacts of HF operations by decreasing the volume of used surface water and the risk of FPW surface spills.

Effects of Active Hydraulic Fracturing Fluid on the Fracture Propagation and Structural Damage of Coal: Phenomena and Mechanisms

Effects of Active Hydraulic Fracturing Fluid on the Fracture Propagation and Structural Damage of Coal: Phenomena and Mechanisms

Backstress Influence on the Formation Stress Field in Hydraulic Fracturing Experiments

This work presents an analysis of data obtained through unique laboratory experiments on hydraulic fracturing. In the experiments, sufficiently large artificial samples were used to model a reservoir. Thus, it was possible to simulate several wells simultaneously, given that hydraulic fracture was initiated in one of them. In addition, the setup construction provided a true triaxial stress–strain state. The setup allowed us to investigate parameters that are difficult to access in real conditions. The data processing based on six laboratory experiments on hydraulic fracturing showed discrepancies between the values of the minimum stresses calculated from the fracture closure pressure and the actual values known based on the experimental conditions. There was also a discrepancy between the theoretical values of the fracture breakdown pressure and those obtained through the experiments. This paper examines phenomena such as backstress as the main reasons for this discrepancy. Backstress is stress acting on the walls of a fracture or well and is caused by the filtered hydraulic fracturing fluid. The authors demonstrated that by taking into account this phenomenon, one can significantly reduce the differences between calculated and experimental values. Therefore, the authors call for the careful use of the standard theory when determining the stress state in real fields.

Comparative Laboratory Study of the Geochemical Reactivity of the Marcellus Shale: Rock–Fluid Interaction of Drilled Core Samples vs. Outcrop Specimens

The Marcellus shale is an unconventional reservoir of significant economic potential with Total Organic Carbon (TOC) ranging from 1 to 20%. Hydraulic fracturing is used to extract the shale’s resources, which requires large amounts of water and can result in mineral-rich flowback waters containing hazardous contaminants. This study focuses on a geochemical analysis of the flowback waters and an evaluation of the potential environmental impacts on water and soil quality. Drilled core samples from different depths were treated with lab-prepared hydraulic fracturing fluids. Rock samples were analyzed using Energy Dispersive Spectroscopy (EDS), while effluents’ chemical compositions were obtained using Inductively Coupled Plasma Optical Emission Spectroscopy (ICP-OES). A comparison of results from drilled core samples treated with additives for hydraulic fracturing to those treated with deionized (DI) water confirms that, as expected, the major elements present in the effluent were Ca, Ba, and Cl in concentrations greater than 100 µg/L. The most concerning elements in the effluent samples include As, Ca, Cd, Pb, Se, S, K, Na, B, Mo, and Mn, with Cd and Cr values averaging 380 and 320 µg/L, respectively, which are above safe limits. Se concentrations and high levels of Ca pose major safety and scaling concerns, respectively. We also compared Marcellus shale drilled core samples’ geochemical reactivity to samples collected from an outcrop.