Tight Shale Formations Research Articles

Predictive scale-bridging simulations through active learning

Throughout computational science, there is a growing need to utilize the continual improvements in raw computational horsepower to achieve greater physical fidelity through scale-bridging over brute-force increases in the number of mesh elements. For instance, quantitative predictions of transport in nanoporous media, critical to hydrocarbon extraction from tight shale formations, are impossible without accounting for molecular-level interactions. Similarly, inertial confinement fusion simulations rely on numerical diffusion to simulate molecular effects such as non-local transport and mixing without truly accounting for molecular interactions. With these two disparate applications in mind, we develop a novel capability which uses an active learning approach to optimize the use of local fine-scale simulations for informing coarse-scale hydrodynamics. Our approach addresses three challenges: forecasting continuum coarse-scale trajectory to speculatively execute new fine-scale molecular dynamics calculations, dynamically updating coarse-scale from fine-scale calculations, and quantifying uncertainty in neural network models.

Multiple upscaling procedures for gas transfer in tight shale matrix-fracture systems

Multiple upscaling schemes for gas transfer in nanoporous media, microporous matrix, core-scale matrix, and centimeter-scale matrix-fracture systems are investigated. An Open Multi-Processing (OpenMP)-based parallelized multi-scale numerical solver for micro-gaseous flow in composite microporous media is developed by coupling the pore-scale multiple-relaxation-time lattice Boltzmann method (MRT-LBM) and representative elementary volume (REV)-scale LBM model. The permeability of the microporous matrix is calculated through hundreds of pore-scale simulations for gas transfer in nanoporous media, before being imported into the REV-scale LBM to predict the core-scale matrix permeability. It is followed by the investigations of the variations of core-scale permeability with the heterogeneous spatial distribution of organic matter aggregates, mineral aggregates, interparticle pores, and microfractures. The parallel and sequential gas transfer processes in a larger shale system containing the tight matrix and hydraulic fractures are studied and analyzed. The results reveal several new insights: 1) the microscale spatial distribution of multiple constituents has relatively little effect on the core-scale permeability; 2) an ultra-large local pressure gradient occurs in a thin boundary layer of tight shale matrix, which is shown to be proportional to the square root of the permeability ratio, resulting in considerable flow characteristic velocity in the matrix; 3) the in-situ matrix-fracture transfer satisfies a sequential transport process due to a long equilibration time delay between the tight matrix and fractures; 4) the observed high production rate for tight shale may be caused by the ultra-large local pressure gradient in the matrix (and not by a large apparent permeability as commonly assumed). The results also reveal some anomalous phenomena for multiscale gas transfer in tight shale formations.

Novel Nanocomposite Coated Proppants for Enhanced Scale Inhibition Lifetime in Tight Shale Formations

Controlling scale deposition in tight formations such as shale is commonly achieved by combining fracturing stimulation with squeeze treatment. The squeeze treatment process’s success relies on the targeted formation’s ability to adsorb the right amount of scale inhibitor and slowly release it during hydrocarbon production. The inhibition lifetime of a standard squeeze treatment lasts from 3 to 6 months depending on the compatibility between the formation and scale inhibitor–operators desire a prolonged inhibition lifetime. Herein, a novel approach of resin-based nanocomposite coated proppants is developed to act as a propping agent and high active surface platform for scale inhibitors to be adsorbed and subsequently slowly released during oil production. In this study, proppants were coated with a thin layer of polyurethane, followed by a layer of carbon-based nanomaterials (Multi-Wall Carbon Nanotubes (MWCNTs) and Graphene Nanoplatelets (GNPs)), and characterized using Field Emission Scanning Electron Microscopy (FESEM) and Energy Dispersive X-ray Analysis (EDX). Due to the concerns of climate change, polyurethane was selected due to its quick curing at lower temperatures and minimal environmental impacts. The potential of the proposed proppant to enhance the adsorption and slow the desorption of a Diethylenetriamine Penta (DTPMP) scale inhibitor, the necessary strength to withstand closure stress, and its thermal stability were evaluated. FESEM and EDX results revealed that an ultrathin uniformed coating layer was established. The stress resistance data showed that the proposed proppants (MWCNTs-RCP and GNPs-RCP) could withstand closure stress as high as 68.9 MPa with less than 10 wt % fines production. In addition, the thermal stability of MWCNTs-RCP and GNPs-RCP reached 347 °C. Scale inhibitor adsorption experiments showed that MWCNTs-RCP and GNPs-RCP adsorbed 583.5 mg/kg and 832.0 mg/kg of DTPMP, respectively. Desorption results indicated that MWCNTs-RCP and GNPs-RCP extended the inhibition lifetime of DTPMP by 400% PV compared to a conventional proppant. Intraparticle diffusion was found to dominate the desorption of DTPMP from MWCNTs-RCP and GNPs-RCP, which explains the slow desorption rate they exhibited. Therefore, the developed proppants could be a promising multifunctional proppant in the oil and gas industry.

Foam based fracking in unconventional shale reservoir

As the energy demand increases globally, oil and gas industry has started to explore the unconventional shale resources. Shale gas production has become feasible by the application of hydraulic fracking technology which involves the process of injecting water, chemicals and sands at high pressure to create small fractures within tight shale formations to stimulate the production. But the major problem using hydraulic fracturing involves excessive water consumption, formation damage etc. but, fracking methods with low water consumption viz., foam based fracking and nanoparticles based foam fracking are novel and much effective techniques for unconventional shale resources are discussed in detail in the present paper. When nanoparticles are added in the foam, it acts as proppants and enhances the quality of fracturing fluid rheology. The present paper discusses the foam characteristics and its proppants carrying capacity, reviews recent studies on different types of foam based fracking, and nanoparticles stabilized foam fracking. Experimental studies, field applications, its major advantages and disadvantages are also discussed.

Effect of supercritical CO2 on limestone's pore structure based on NMR and SEM

Supercritical CO2 (SC-CO2), as a new type of energizing fluid, has been widely applied in fracturing and acidizing treatment on tight sandstone, shale and carbonate formation. However, the effect of SC-CO2 on limestone's pore structure is unclear. To explore the effect, SC-CO2 reactor featuring high-temperature and high-pressure was used to carry out soaking experiments of SC-CO2-brine-limestone and SC-CO2-limestone respectively. With the help of NMR and SEM, this paper studies the effect of SC-CO2 on limestone's pore structure when the soaking time is different. It is found that in the experiment of SC-CO2-brine-limestone, SC-CO2 will react with brine to produce carbonic acid, which would react with calcite to augment limestone's porosity and permeability. Yet at the same time, Ca2+ and Mg2+ in the brine deposit continuously, which would lessen limestone's porosity and permeability. Besides, it is the generation of large pores that leads to augmentation of porosity, and more large pores are produced as time increases. While in the experiment of SC-CO2-limestone, volume expansion caused by transforming SC-CO2 into gaseous CO2 also augments limestone's porosity, and the augmentation is due to small pores. However, the increase of porosity in experiments without brine is much lower than that with brine.

Effects of Carbonate Minerals on Shale-Hydraulic Fracturing Fluid Interactions in the Marcellus Shale

Natural gas extracted from tight shale formations, such as the Marcellus Shale, represents a significant and developing front in energy exploration. By fracturing these formations using pressurized fracturing fluid, previously unobtainable hydrocarbon reserves may be tapped. While pursuing this resource, hydraulic fracturing operations leave chemically complex fluids in the shale formation for at least two weeks. This provides a substantial opportunity for the hydraulic fracturing fluid (HFF) to react with the shale formation at reservoir temperature and pressure. In this study, we investigated the effects of the carbonates on shale-HFF reactions with a focus on the Marcellus Shale. We performed autoclave experiments at high temperature and pressure reservoir conditions using a carbonate-rich and a decarbonated or carbonate-free version of the same shale sample. We observed that carbonate minerals buffer the pH of the solution, which in turn prevents clay dissolution. Carbonate and bicarbonate ions also scavenge reactive oxidizing species (ROS), which prevents oxidation of shale organic matter and volatile organic compounds (VOCs). Carbonate-free samples also show higher pyrite dissolution compared to the carbonate-rich sample due to chelation reactions. This study demonstrates how carbonate minerals (keeping all other variables constant) affect shale-HFF reactions that can potentially impact porosity, microfracture integrity, and the release of heavy metals and volatile organic contaminants in the produced water.

A diffusion-based compositionally-extended black oil model to investigate produced gas re-injection EOR in Eagle Ford

In this study, an in-house reduced black oil simulation model is used to investigate cyclic produced gas rejection in Eagle Ford shale formation. Molecular diffusion may play a crucial role in mass transfer in tight shale formations. However, the diffusion has not been incorporated in a black-oil type model in previous studies. In this study, the diffusive term is included into the governing equation and its effect on production performance is examined by using a black oil model. Diffusion coefficients are calculated by using Sigmund correlation, which makes them a function of phase compositions, phase properties, pressure, and temperature. Considering that phase compositions are influenced by large gas-oil capillary pressure nanoconfinement effect, diffusion coefficients are also altered based on this affect. This is the first study that incorporates the large gas-oil capillary pressure effect on diffusion coefficients in nanopores, through using a reduced black oil model. The operation parameters including initial injection time, injection rate, number of cycles are examined. We found that larger injection rates and more number of cycles are efficient in improving the oil recovery. Injection rate is the most crucial parameters in cyclic gas injection approach, followed by cycle numbers. Huff-n-puff results in good efficiency at relatively tight matrix, however, it is not always more efficient for very low permeabilities, as for the very tight formation, the injection gas cannot penetrate to the deeper formation to bring out much more oil from the reservoir in the same “huff” and “soaking” time period. The molecular diffusion plays an important role in gas injection process and cannot be ignored. When nano-confinement effect is included, the diffusion coefficient in gas phase is decreased and the diffusion coefficient in oil phase is increased as pore size decreases, but the effect is not strong especially at relatively high pressures.

Multi-scale modelling of gas transport and production evaluation in shale reservoir considering crisscrossing fractures

Advancements in recent shale gas development technologies like creating hydraulic fracturing have greatly improved the production of unconventional shale gas reservoirs (USGR). However, the production of USGR is still low mainly due to the inefficient gas transport in tight shale formation. Towards this end, the investigations about the mechanism of gas transport through the fractures and the effects of both hydraulic and natural fractures on the overall gas production are urgently needed. In this study, a multi-scale modelling is established to analyze the gas transport and production performance in shale formation with crisscrossing natural fractures using finite element method (FEM). For the base case with fracture-scale model, the gas transport behavior and pressure distribution within the matrix and crisscrossing fractures are revealed, demonstrating that the crisscrossing fractures serve as the fast paths to enhance the gas transport from shale matrix to wells. Then, the field-scale model is developed by considering the complex fracture networks consisting of the hydraulically fractured horizontal wells and crisscrossing natural fractures, which is well verified against field data. On this basis, the comprehensive analysis for the influence of various parameters, including the properties of matrix, hydraulic fractures and natural fractures, on the production performance are conducted to optimize the exploitation strategy of shale gas reservoir. It is believed that the multi-scale simulation framework and the optimized exploitation strategies presented in this study are useful for the enhanced gas recovery (EGR) of shale reservoir.

Nutrient Enrichment of Wastewater Generated During Hydraulic Fracturing with Animal Wastewater to Enhance Microalgae Growth

Hydraulic fracturing technology widely used for recovery of oil and gas from tight shale formations generate millions of gallons of wastewater. This study examined viability of algal remediation of the hydraulic fracturing wastewater (HFWW). Our previous studies have shown that although Oklahoma native algae strains can grow in HFWW, cell growth was constrained by the low nutrient concentrations in HFWW. Hence, the goal of this study was to examine the effect of nutrient supplementation of HFWW with another nutrient rich wastewater on microalgae growth. An Oklahoma, USA, native algae strain, Picochlorum oklahomensis, was selected for the study because of its high biomass productivity in wastewater. This study demonstrated that P. oklahomensis can grow in HFWW. Supplementation of the HFWW with animal wastewater enhanced biomass productivity and lipid content of the biomass. Chemical compositions of the wastewater before and after algae growth were significantly different indicating substantial amount of contaminant removal.

Synergistic foam stabilization and transport improvement in simulated fractures with polyelectrolyte complex nanoparticles: Microscale observation using laser etched glass micromodels

Inaccessibility to direct pore scale observation in hydrocarbon recovery of tight shale formations poses a great challenge to water-energy nexus initiatives and necessitates the use of high throughput technologies to emulate environmentally friendly processes. Herein, we employ a precise glass micromodel fabrication and visualization method to isolate the supercritical CO2 bubbles surrounded by CO2-water lamella prepared in saline produced water stabilized with molecular complexation of zwitterionic surfactants (ZS) and polyelectrolyte complex nanoparticles (PECNP).The Selective Laser Enhanced Etching (SLE) technique was selected for micromodel simulation of high-pressure flow. Two representative designs, (1) fracture/micro-crack network and (2) fracture/matrix were etched on fused silica glass with a laser printing machine and scCO2 foam was injected to study the foamability, propagation, stability, and fluid loss properties.The highly monodispersed and uniformly distributed array of scCO2 bubbles were detected in flow of scCO2 foam in highly saline brine containing ionic complexes of positively charged PECNPs and ZS, whereas foam flow with the lamella containing ZS in fractures offered a noticeably large and polydisperse array of scCO2 bubbles. scCO2 bubble motion and deformation were traced, and local description of foam flow was visually examined. The confined array of scCO2 bubbles stabilized by ZS in microcracks was affected by bubble growth and coalescence, whereas the super-populated array of monodispersed scCO2 bubbles with lamella containing complexes of PECNP and ZS were able to fill the channels with stable configurations within the timeframe of comparative stability measurements. The ability of complex fluid to prevent the formation damage was evaluated through fluid loss visualization in micromodels. Probing scCO2 foam transport in homogenous porous media revealed smaller volume leak-off for scCO2 foam containing PECNP-ZS ionic complexes.

Growing Picochlorum oklahomensis in Hydraulic Fracturing Wastewater Supplemented with Animal Wastewater

Hydraulic fracturing is used to enhance oil and gas extraction from tight shale formations and generates millions of gallons of wastewater which needs to be cleaned up prior to disposal or reuse. The current technologies used for the management of this wastewater present technical, economic, and environmental challenges. Hence, the main objective of this study was to examine the potential of algal remediation of hydraulic fracturing wastewater (PW) as an alternative method. Considering that PW contains very low concentration of the nutrients needed for algae growth PW supplemented with animal wastewater (AW-PW) was also examined. Biomass production capacity, average biomass productivity, and specific growth rate of the microalgae strain used in the study, Picochlorum oklahomensis, were 1.87 g L−1, 268 mg L−1 day−1, and 0.35 day−1, respectively, when grown in PW. Complete nitrate, ammonia, and phosphate removal could be achieved by growing algae in PW. Supplementation of PW with animal wastewater enhanced biomass production (1.87–2.40 g L−1) and lipid content (15–25% wt) in the produced algal biomass. A mathematical model with a correlation coefficient of greater than 0.94 was developed to describe the growth kinetics of algae grown in AW-PW.

Modeling and scale-bridging using machine learning: nanoconfinement effects in porous media

Fine-scale models that represent first-principles physics are challenging to represent at larger scales of interest in many application areas. In nanoporous media such as tight-shale formations, where the typical pore size is less than 50 nm, confinement effects play a significant role in how fluids behave. At these scales, fluids are under confinement, affecting key properties such as density, viscosity, adsorption, etc. Pore-scale Lattice Boltzmann Methods (LBM) can simulate flow in complex pore structures relevant to predicting hydrocarbon production, but must be corrected to account for confinement effects. Molecular dynamics (MD) can model confinement effects but is computationally expensive in comparison. The hurdle to bridging MD with LBM is the computational expense of MD simulations needed to perform this correction. Here, we build a Machine Learning (ML) surrogate model that captures adsorption effects across a wide range of parameter space and bridges the MD and LBM scales using a relatively small number of MD calculations. The model computes upscaled adsorption parameters across varying density, temperature, and pore width. The ML model is 7 orders of magnitude faster than brute force MD. This workflow is agnostic to the physical system and could be generalized to further scale-bridging applications.

Estimating diffusion coefficients of shale oil, gas, and condensate with nano-confinement effect

Molecular diffusion plays an important role in oil and gas migration in tight shale formations. However, there are insufficient reference data in the literature to specify the diffusion coefficients within porous media. This study aims at calculating diffusion coefficients of shale gas, shale condensate, and shale oil at reservoir conditions with CO2 injection for EOR/EGR. The large nano-confinement effects including large gas-oil capillary pressure and critical property shifts could alter the phase behaviors. This paper estimates the diffusivities of shale fluids in nanometer-scale shale rock from two perspectives: 1) examining the shift of diffusivity caused by nanopore confinement effects from phase change (phase composition and fluid property) perspective, and 2) calculating the effective diffusion coefficient in porous media by incorporating rock intrinsic properties (porosity and tortuosity factor). The tortuosity is obtained by using tortuosity-porosity relations as well as the measured tortuosity of shale from 3D imaging techniques. The results indicated that nano-confinement effects could affect the diffusion coefficient through altering the phase properties, such as phase compositions and densities. Compared to bulk phase diffusivity, the effective diffusion coefficient in porous shale rock is reduced by 102 to 104 times as porosity decreases from 0.1 to 0.03.

Effect of vertical heterogeneity and nano-confinement on the recovery performance of oil-rich shale reservoir

Due to the effect of compaction, stress-dependent properties such as permeability, porosity, and pore size vary in the vertical direction of shale reservoir. The heterogeneity of physical properties influences the fluid flow in shale formation. Meanwhile, the confinement effects, including large oil-gas capillary pressure and critical property shifts, as a function of pore-throat radius could greatly alter phase behaviors in nano-pores. Thus, vertical heterogeneity affects the interpretation of production performance of an oil-rich shale reservoir. In this study, a compositional simulation model incorporated with confinement effects is applied to simulate primary depletion in an intensively fractured oil-rich shale formation. Stress-dependent properties are assigned to different depth of the pay zone. Two nano-confinement effects on phase behavior and recovery performance are examined, respectively. Simulation results show that nano-confinement effects affect the well productivity through altering the fluid properties and phase behaviors. Inclusion of capillary pressure effect increases oil production but suppresses gas production. Considering critical property shift enhances both oil and gas recoveries. In very tight shale formation, confinement effects are more comparable to gravity drainage on improving oil recovery. As pore size is reduced with depth, confinement effects become more apparent on increasing oil recovery. However, it still cannot exceed the benefits from drilling the well at high permeable formation. Drilling the horizontal well in relatively high-permeability layer that has high permeable adjacent layers could achieve the largest oil and gas recoveries.

Evaluation of Multicomponent Adsorption Kinetics for Carbon Dioxide Enhanced Gas Recovery from Tight Shales

SummaryOnly 3 to 10% of gas from tight shale is recovered economically through natural depletion, demonstrating a significant potential for enhanced shale-gas recovery (ESGR). Experimental studies have demonstrated that shale kerogen/organic matter has higher affinity for carbon dioxide (CO2) than methane (CH4), which opens possibilities for carbon storage and new production strategies.This paper presents a new multicomponent adsorption isotherm that is coupled with a flow model for the evaluation of injection/production scenarios. The isotherm is dependent on the assumption that different gas species compete to adsorb on a limited specific surface area. Rather than assuming a capacity of a fixed number of sites or moles, this finite surface area is filled with species taking different amounts of space per mole. The final form is a generalized multicomponent Langmuir isotherm. Experimental adsorption data for CO2 and CH4 on Marcellus Shale are matched with the proposed isotherm using relevant fitting parameters. The isotherm is first applied in static examples to calculate gas-in-place reserves, recovery factors (RFs), and enhanced gas-recovery (EGR) potential according to the contributions from free-gas and adsorbed-gas components. The isotherm is further coupled with a dynamic flow model with application to CO2/CH4 substitution for CO2-ESGR, assuming only a gas phase exists in the system. We study the feasibility and effectiveness of CO2 injection in tight shale formations in an injection/production setting representative of laboratory and field implementation and compare that with regular pressure depletion.The production scenario we consider is a 1D shale-core or matrix system first saturated with free and adsorbed CH4 gas with only the left-side (well) boundary open. During primary depletion, gas is produced from the shale to the well by advection and desorption. This process tends to give low recovery and is entirely dependent on the well pressure. Stopping production and then injecting CO2 into the shale leads to an increase in pressure, where CO2 is preferentially adsorbed over CH4. The injected CO2 displaces but also mixes with the in-situ CH4. Restarting production from the well then allows CH4 gas to be produced in the gas mixture. Diffusion allows the CO2 to travel farther into the matrix while keeping CH4 accessible to the well. Surface substitution further reduces the CO2 content and increases the CH4 content in the gas mixture that is produced to the well. A result of the isotherm and its application of Marcellus experimental data is that adsorption of CO2 with resulting desorption of CH4 will lead to a reduction in total pressure if the CO2 content in the gas composition is increased. That is in itself an important drive mechanism because the pressure gradient driving fluid flow is maintained (pressure buildup is avoided). This is because CO2 takes approximately 24 times less space per mole than CH4.

Investigation of asphaltene-derived formation damage and nano-confinement on the performance of CO2 huff-n-puff in shale oil reservoirs

In this study, the behavior of asphaltene formation and nano-confinement during the CO2 huff-n-puff process in liquid-rich shale reservoirs is investigated. Asphaltene precipitation and deposition in the pore volume of shale formation from mixing between oil and CO2 could cause formation damage, which reduces the permeability and/or changes the rock surface condition toward more oil-wet. In addition, the nano-confinement effect changes the phase behavior of the fluid affecting the asphaltene formation in tight shale formations. With the development of a reservoir simulation model that incorporates both asphaltene formation and the nano-confinement effect, this study quantifies the effects of asphaltene deposition and nano-confinement on shale oil production of CO2 huff-n-puff.While ignoring the permeability reduction and wettability alteration due to asphaltene deposition, the nano-confinement effect increases the shale oil production by up to 42% during the CO2 huff-n-puff process. However, the nano-confinement effect increases the asphaltene precipitation and deposition in nano-scaled tight formation. On incorporating the formation damage due to asphaltene deposition, more deposited asphaltene due to nano-confinement effect decreases the oil production by 4%. This study clarifies that the effects of asphaltene formation and nano-confinement should be taken into consideration for an accurate prediction of hydrocarbon production during CO2 huff-n-puff in tight shale formation.

Effect of reservoir characteristics on the productivity and production forecasting of the Montney shale gas in Canada

Shale gas is a typical unconventional gas trapped in a tight shale formation, which is considered as a source as well as reservoir rock. Therefore, the productivity of shale gas is closely related to the reservoir parameters making it very important to understand the characteristics of shale reservoirs. In this study, the production data of Montney shale was analyzed and the impact of the reservoir characteristics on the productivity was quantified. The reservoir characteristics can be divided into the reservoir quality (RQ) and completion quality (CQ) parameters. The productivity of shale gas, which is defined as the production decline variables, such as the peak monthly rate (PMR), the initial decline rate, and the decline exponent, was compared with the RQ and CQ.Among the CQ parameters, the brittleness index (BI) was found to affect the overall decline trend in production and had a qualitative correlation with the initial decline rate and decline exponent. Moreover, among the RQ, the total organic carbon (TOC) is closely related to the PMR and the amount of organic carbon (S1) already generated as hydrocarbon is strongly correlated with the initial decline rate and the decline exponent, especially in the transient linear flow regime. Therefore, it is possible to quantify the effects of the organic carbon contents on the productivity of shale gas and estimate the production in the transient linear flow regime.

H2O2-Enhanced Shale Gas Recovery under Different Thermal Conditions

The permeability of tight shale formations varies from micro-Darcy to nano-Darcy. Recently, hydrogen peroxide (H2O2) was tested as an oxidizer to remove the organic matter in the rock in order to increase shale permeability. In this study, shale particles were reacted with hydrogen peroxide solutions under different temperature and pressure conditions in order to “mimic” underground geology conditions. Then, low-temperature nitrogen adsorption and desorption experiments were conducted to measure the pore diameters and porosity of raw and treated shale samples. Moreover, scanning electron microscopy (SEM) images of the samples were analyzed to observe pore structure changes on the surface of shale samples. From the experiments, it was found that the organic matter, including extractable and solid organic matter, could react with H2O2 under high temperature and pressure conditions. The original blocked pores and pore throats were reopened after removing organic matter. With the increase of reaction temperature and pressure, the mean pore diameters of the shale samples decreased first and then increased afterwards. However, the volume and Brunauer–Emmett–Teller (BET) surface areas of the shale particles kept increasing with increasing reaction temperature and pressure. In addition to the effect of reaction temperature and pressure, the pore diameter increased significantly with the increasing reaction duration. As a result, H2O2 could be used to improve the shale permeability.

Selecting seismically safe formations for salt water disposal in the Delaware basin

An increased level of seismicity in Delaware Basin generally from 2015 (West Texas and New Mexico, USA), and specifically in its southeast part near the city of Pecos from the year 2017 has opened up the question of whether it is induced or natural. Earthquakes can be induced either due to hydraulic fracturing designed to stimulate the production from tight shale formations, or by disposal of wastewater (Ellsworth, 2013). As the production from the Permian basin is rapidly growing, there are many new active injection wells (both hydraulic fracturing as well as salt water disposal wells) within this basin. As the detectability of seismic events increased (the result of the state-wide effort of TexNet network) some increase of reported seismicity can be attributed to the lower detection threshold for natural seismicity, but some increased seismicity can be due to hydraulic fracturing and some due to salt water disposal. The spatial and temporal relationship between injection rates and observed seismicity can be used to associate these earthquakes, origins.

Incorporation of multi-phase solubility and molecular diffusion in a geochemical evaluation of the CO2 huff-n-puff process in liquid-rich shale reservoirs

Despite the development of horizontal well and hydraulic fracturing technologies, natural depletion is limited in low productivity, and thereby considerable hydrocarbon remains in low permeable shale reservoirs. Recent researches proved that the deployment of CO2 huff-puff process could extract the remained hydrocarbon. They quantified various mechanisms behind the process and proposed the potential for CO2 sequestration in the shale formation. However, thorough understanding of fluid transport in the CO2 huff-n-puff process has not been completed due to complexity in tight shale formations. They had a lack to analyze potential factors affecting fluid flow in the system of oil/CO2/brine/shale formation: 1) aqueous solubility; 2) molecular diffusion in aqueous and oleic phases; and 3) geochemistry. Therefore, this study diagnoses the potential factors affecting fluid flow during CO2 huff-n-puff process in the shale oil reservoirs. Then, their effects are quantified by analyzing shale oil recovery and CO2 storage capacity.Since a fraction of injected CO2 dissolves in water and oil during the CO2 huff-n-puff process, transportability is acquired by molecular diffusion in aqueous and oleic phases. In addition, dissolution of CO2 changes the pH of in-situ brine, which is a sensitive factor in geochemistry, and thereby would change physical properties of formation. Implementing these mechanisms, this study simulates the CO2 huff-n-puff process in shale oil reservoirs. It is observed that effects of aqueous solubility and geochemistry decrease oil production by 3.2% and 6%, respectively. Approximately, up to 9.5% of CO2 to be injected is sequestrated in depleted shale formation via solubility mechanism. Molecular diffusion in oleic phase increases the oil production by 2%, but that in aqueous phase is negligible. For the accurate estimation of oil production and CO2 storage capacity in the simulation of CO2 huff-n-puff process for shale oil reservoir, the comprehensive model should consider potential factors such as aqueous solubility, molecular diffusion, and geochemical reactions. Because the potential factors have been neglected in the works of other types of shale reservoirs, the proposed approaches expect to expand our understanding in the CO2 injection to tight and shale gas/oil reservoirs.