Unconventional Shale Resources Research Articles

Unconventional Fracture Networks Simulation and Shale Gas Production Prediction by Integration of Petrophysics, Geomechanics and Fracture Characterization

The proficient application of multistage fracturing methods enhances the status of the Duvernay shale formation as a highly esteemed shale reservoir on a global scale. Nevertheless, the challenge is in accurately characterizing unconventional fracture behavior and predicting shale productivity due to the complex distributions of natural fractures, pre-existing faults, and reservoir heterogeneity. The present study puts forth a Geo-Engineering approach to comprehensively investigate the Duvernay shale reservoir in the vicinity of Crooked Lake. To begin with, on the basis of the experimental results and well-logging interpretations, a high-quality petrophysical and geomechanical model is constructed. Subsequently, the establishment of an unconventional fracture model (UFM) takes into account the heterogeneity of the reservoir and the interactions between hydraulic fractures and pre-existing natural fractures/faults and is further validated by 18,040 microseismic events. Finally, the analysis of well productivity is conducted by numerical simulations, revealing that the agreement between the simulated and observed production magnitudes exceeds 89%. This paper will guide the efficient development of increasingly important unconventional shale resources.

Grand Challenges for the Oil and Gas Industry for the Next Decade and Beyond

_ The oil and gas industry faces a rapidly changing world of multiple challenges and opportunities, especially with growing climate and sustainability concerns. About a decade ago, SPE conducted a series of workshops to define the grand challenges in technology and R&D for the upstream oil and gas industry for the following decade. It identified 5 + 1 grand challenges (Table 1). To define the set of grand challenges for the next decade, in a much more unpredictable environment, we held an SPE workshop in Austin, Texas, in January 2023. Panelists from IOCs, NOCs, and service companies, as well as environmental and financial stakeholders in the emerging energy system, surveyed the rapidly changing energy landscape. The workshop then facilitated sessions of the more than 120 thought leader participants to define grand challenges that are impactful for society and our industry and have a significant R&D/technology component that is aligned with the capabilities of the SPE membership. We arrived at a list of five technical grand challenges: improved recovery from tight/shale resources, net-zero operations, carbon capture, utilization, and storage (CCUS), geothermal energy, and digital transformation. Additionally, we identified a sixth “bonus” nontechnical challenge—education and advocacy, since we believe that more effective engagement with thought leaders outside our industry will be required to advance and deploy new technologies in all five of these areas. Table 2 summarizes the technical challenges and their impacts. We believe that this work will help the industry focus its R&D and technology efforts on the highest-value activities for both industry and society. We now summarize each of these new grand challenges. Improved Recovery From Tight/Shale Resources Notwithstanding the rapid growth of non-hydrocarbon energy sources and carriers, oil and natural gas demand are projected to continue rising through 2050 (EIA 2023). In the past 20 years, horizontal drilling and hydraulic fracturing were combined to extract hydrocarbons from unconventional shale resources, which helped us meet rising global oil demand. However, production from existing shale oil wells declines quickly, and ultimate recoveries are often less than 10%. To meet global demand, we must improve recovery with minimal environmental impact. Tight and shale oil reservoirs have unique challenges. For example, shale reservoirs are subject to clay swelling and formation damage. Permeabilities are ultra-low, often on the order of nano-Darcys, which leads to extremely low flow rates and to transport dominated by diffusion. Thus, hydraulic and natural fractures are necessary, and geomechanics/rock compaction plays an important role. Many traditional improved oil recovery (IOR) strategies are challenging in tight and shale reservoirs. The small pores make waterflooding techniques difficult, and the low permeability hampers well-to-well methods. Thus, single-well, huff-and-puff strategies are the most common IOR methods. Injectants include miscible and immiscible gases (CO2, CH4, and N2) and chemicals (surfactants, solvents, and nanoparticles). In addition, thermal methods may allow control of oil viscosity and pressurization of the reservoir.

Groundwater stress induced by shale resources development in the US: Evolution, response, and mitigation

Unconventional shale resources development consumes a huge amount of groundwater, yet it is short of systematic research on evolution, response, and mitigation of shale-induced groundwater stress (SGS). To fill this gap, we here propose a new SGS evaluation model based on an improved concept of groundwater footprint. We find that the SGS remains heavy within the shale regions of the US in 2017–2019. The projected SGS would keep growing in 2025–2050 within the regions except Permian, owing to comprehensive stochastic response to future intensified shale development and varied precipitation and temperature. Notwithstanding, comparison of the rate of risked returns indicates that shale development could be more economically and environmentally competitive than agricultural planting, demonstrating high suitability of shale development in part of regions such as Niobrara, Anadarko, Permian, and Eagle Ford. Joint policies regulating shale production, water intensity, and groundwater supply coefficient would be effective for mitigating future intensified SGS.

Integrated evaluations of high-quality shale play using core experiments and logging interpretations

The integration of multi-technology and multi-scale evaluation techniques is quite important in the development of shale resources. To assess the high-quality shale in the West Duvernay Shale Basin, an integrated experiment-logging-based strategy is proposed. The investigation of core measurements and logging interpretations is first carried out to ascertain a geographic distribution of high-quality shales. The relationships between shale productivity and reservoir characteristics are then quantified, and the distribution of high-quality shales in space is predicted using machine learning techniques. The Duvernay shale is discovered to be separated into four sublayers, with the D2 and D3 sublayers being considered high-quality shales based on a comprehensive analysis. Shale thickness, effective porosity, a brittleness index, and formation pressure are found to be crucial factors that greatly influence the production of high-quality shale. This strategy can be used to evaluate high-quality shale comprehensively in other shale resources and achieve the effective development of unconventional shale resources.

An Integrated Approach to Reservoir Characterization for Evaluating Shale Productivity of Duvernary Shale: Insights from Multiple Linear Regression

In the development of unconventional shale resources, production forecasts are fraught with uncertainty, especially in the absence of a full, multi-data study of reservoir characterization. To forecast Duvernay shale gas production in the vicinity of Fox Creek, Alberta, the multi-scale experimental findings are thoroughly evaluated. The relationship between shale gas production and reservoir parameters is assessed using multiple linear regression (MLR). Three hundred and five core samples from fifteen wells were later examined using the MLR technique to discover the fundamental controlling characteristics of shale potential. Quartz, clay, and calcite were found to comprise the bulk of the Duvernay shale. The average values for the effective porosity and permeability were 3.96% and 137.2 nD, respectively, whereas the average amount of total organic carbon (TOC) was 3.86%. The examined Duvernay shale was predominantly deposited in a gas-generating timeframe. As input parameters, the MLR method calculated the components governing shale productivity, including the production index (PI), gas saturation (Sg), clay content (Vcl), effective porosity (F), total organic carbon (TOC), brittleness index (BI), and brittle mineral content (BMC) (BMC). Shale gas output was accurately predicted using the MLR-based prediction model. This research may be extended to other shale reservoirs to aid in the selection of optimal well sites, resulting in the effective development of shale resources.

Comparison of water stress regarding potential shale energy development in China and the US

Unconventional shale resources are important options in mitigating intensified energy challenges. Little is known regarding the national-scale water stress induced by the demand-and-supply contradiction during shale development. We here propose a new life-cycle-based model for estimating water intensities of single shale wells and use them as proxies to calculate the water stress facing China and the US. In China, most shale provinces have low water stress (< 1); Xinjiang has the highest one (∼10) so that either long-distance water diversion or groundwater extraction from deep aquifers would be required. The water stress facing the US is not as optimistic as China due to generally lower water availability; Louisiana, Texas, Arkansas, Colorado, and Pennsylvania have the highest water stress (between 10 and 25 under high intensity). We also find that policy combinations can effectively mitigate the water stress and suggest that deep cooperation be desired among those shale -rich countries.

Machine-learning-based well production prediction under geological and hydraulic fracture parameters uncertainty for unconventional shale gas reservoirs

Shale gas production prediction under history-matching-based geomodel is crucial to achieve reliable assessment and economic management of unconventional shale resources, however, conventional history matching is generally performed through repeatedly running high-fidelity reservoir simulations and therefore presents intensive computation-cost in practical applications. Without the need of history matching step, this work presents an efficient and robust post-history production forecasting framework using a latent-space learning-based direct forecast approach, e.g., referred to as LS-LDFA. A novel dimensionality reduction method, e.g., convolutional autoencoder, is employed to regularize the multi-well time-series data by low-order representation within a latent space. Once the machine-learning proxy is trained offline, the online post-history production forecast can be efficiently achieved by input history data. This paper presents some comparative studies between LS-LDFA and model-based history matching. This approach is tested on two examples with an increasing complexity, e.g., a multi-fractured horizontal well and a naturally fractured reservoir model with multi-well-pad-production based on synthetic shale formation. The results confirm that the method achieves high robustness and computational efficiency simultaneously in comparison with the conventional history matching. The application of learning-based direct forecast approach can effectively fuse information from history data and thus support reliable decision-making and risk assessment.

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.

Concurrent 17. Presentation for: Resource potential of the Carrara Sub-basin from the deep stratigraphic well NDI Carrara 1

Presented on Wednesday 18 May: Session 17 NDI Carrara 1 is a deep stratigraphic well completed in 2020 as part of the MinEx CRC National Drilling Initiative (NDI), in collaboration with Geoscience Australia and the Northern Territory Geological Survey. It is the first stratigraphic test of the Carrara Sub-basin, a newly discovered depocentre in the South Nicholson Region. The well intersected Proterozoic sediments with numerous hydrocarbon shows, likely to be of particular interest due to affinities with the known Proterozoic plays of the Beetaloo Sub-basin and the Lawn Hill Platform, including two organic-rich black shales and a thick sequence of interbedded black shales and silty-sandstones. Alongside an extensive suite of wireline logs, continuous core was recovered from 283.9 m to total depth at 1750.8 m, providing high-quality data to support comprehensive analysis. Presently, this includes geochronology, geochemistry, geomechanics and petrophysics. Rock-Eval pyrolysis data demonstrate the potential for several thick black shales to be a source of hydrocarbons for conventional and unconventional plays. Integration of these data with geomechanical properties highlights potential brittle zones within the fine-grained intervals where hydraulic stimulation is likely to enhance permeability, identifying prospective Carrara Sub-basin shale gas intervals. Detailed wireline log analysis further supports a high potential for unconventional shale resources. Interpretation of the L210 and L212 seismic surveys suggests that the intersected sequences are laterally extensive and continuous throughout the Carrara Sub-basin, potentially forming a significant new hydrocarbon province and continuing the Proterozoic shale play fairway across the Northern Territory and northwest Queensland. To access the presentation click the link on the right. To read the full paper click here

Resource potential of the Carrara Sub-basin from the deep stratigraphic well NDI Carrara 1

NDI Carrara 1 is a deep stratigraphic well completed in 2020 as part of the MinEx CRC National Drilling Initiative (NDI), in collaboration with Geoscience Australia and the Northern Territory Geological Survey. It is the first stratigraphic test of the Carrara Sub-basin, a newly discovered depocentre in the South Nicholson Region. The well intersected Proterozoic sediments with numerous hydrocarbon shows, likely to be of particular interest due to affinities with the known Proterozoic plays of the Beetaloo Sub-basin and the Lawn Hill Platform, including two organic-rich black shales and a thick sequence of interbedded black shales and silty-sandstones. Alongside an extensive suite of wireline logs, continuous core was recovered from 283.9 m to total depth at 1750.8 m, providing high-quality data to support comprehensive analysis. Presently, this includes geochronology, geochemistry, geomechanics and petrophysics. Rock-Eval pyrolysis data demonstrate the potential for several thick black shales to be a source of hydrocarbons for conventional and unconventional plays. Integration of these data with geomechanical properties highlights potential brittle zones within the fine-grained intervals where hydraulic stimulation is likely to enhance permeability, identifying prospective Carrara Sub-basin shale gas intervals. Detailed wireline log analysis further supports a high potential for unconventional shale resources. Interpretation of the L210 and L212 seismic surveys suggests that the intersected sequences are laterally extensive and continuous throughout the Carrara Sub-basin, potentially forming a significant new hydrocarbon province and continuing the Proterozoic shale play fairway across the Northern Territory and northwest Queensland.

Data-driven workflow for the preemptive detection of excess water producing wells drilled in unconventional shales

The continuous rise in global energy demand requires the production of oil and gas from unconventional shale resources. One major concern for oil and gas producers has been the large volumes of produced water associated with the production of hydrocarbon from the shale resources. Yet, to the level of our knowledge, the source/s of the excess water produced in unconventional shale reservoirs has not been presented in a scientific publication. In this work, we developed a data-driven workflow for identifying potentially high water-producing wells drilled in unconventional shale formation and we identified geophysical signatures that explain the source of excess water production from the wells drilled in unconventional shale reservoirs. To that end, we applied unsupervised learning followed by supervised learning to process five conventional well logs, namely shallow and deep resistivity logs, density porosity logs, neutron porosity logs, and gamma ray logs, from wells drilled in two unconventional shale formations – Gulf Coast and Fort Worth. A novelty of our study is the use of clustering methods to generate pseudo-lithology prior to applying classification techniques for determining excess water producing wells. The data-driven workflow built using 23 wells in Gulf coast basin and 29 wells in Fort Worth basin. Fort Worth (FW) and Gulf Coast (GC) basins in the U.S. are highly productive shale basins that produce 380 million cubic feet of gas and 1.74 million barrels of crude oil every day. Additionally, based on permutation feature ranking and Kendall Tau's associated test, we identified the sources of excess water – highly water-wet and low thermally matured shale present at deep depths in Fort Worth basin, and absence of bituminous, pyrite-bearing shales at deep depths in Gulf Coast basin.

Integrated source rock evaluation along the maturation gradient. Application to the Vaca Muerta Formation, Neuquén Basin of Argentina

AbstractThe Vaca Muerta Formation (Tithonian–early Valanginian) is the main source rock in the Neuquén Basin and the most important unconventional shale resource in South America. In the present study, organic geochemistry, electron microscopy and basin and petroleum system modelling (BPSM) were combined to evaluate source rock properties and related processes along a transect from the early oil (east) to the dry gas (west) window. The unit is characterized by high present‐day (1%–8% average) and original (2%–16% average) total organic carbon contents, which increase towards the base of the unit and basinal (west) settings. Scanning electron microscopy shows that organic pores derived from the transformation of type II kerogen. Isolated bubble pores are typical of the oil window, whereas bubble and densely distributed spongy pores occur in the gas stage, indicating that the maturity gradient exerts strong control on organic porosity. Organic geochemistry, pressure and porosity data were incorporated into a 2D basin petroleum system model that includes the sequential restoration of tectonic events and calculation of compaction trends, kerogen transformation, hydrocarbon generation and estimation of pore pressure through geologic time. The W–E regional model extends from the Agrio Fold and Thrust Belts to the basin border and allows us to evaluate the relationship between thermal maturity and timing of hydrocarbon generation from highly deformed (west) to undeformed (east) regions. Modelling results show a clear decrease in maturity and organic matter (OM) transformation towards the eastern basin margin. Maximum hydrocarbon generation occurred in the inner sectors of the belt, at ca. 120 Ma; long before the first Andean compression phase, which started during the Late Cretaceous (ca. 70 Ma). Miocene compression (15–7 Ma) promoted tectonic uplift of the inner and outer sectors of the belt associated with a reduction in thermal stress and kerogen cracking, as well as massive loss of retained fluids and a decrease in pore pressure. The OM transformation impacted (a) the magnitude of effective porosity associated with organic porosity development, and (b) the magnitude and distribution of pore pressure within the unit controlled by hydrocarbon generation and compaction disequilibrium. BPSM shows a progressive increase in effective porosity from the top to the base and towards the west region related to the original organic carbon content and maturity increasing along the same trend. Overpressure intervals with high organic carbon contents are the most prone to develop organic pores. The latter represent favourable sites for the storage of hydrocarbons in the Vaca Muerta Formation.

Estimating the Total Organic Carbon for Unconventional Shale Resources During the Drilling Process: A Machine Learning Approach

Abstract Total organic carbon (TOC) is an essential parameter that indicates the quality of unconventional reservoirs. In this study, four machine learning (ML) algorithms of the adaptive neuro-fuzzy inference system (ANFIS), support vector regression (SVR), functional neural networks (FNN), and random forests (RFs) were optimized to evaluate the TOC. The novelty of this work is that the optimized models predict the TOC from the bulk gamma-ray (GR) and spectral GR logs of uranium, thorium, and potassium only. The ML algorithms were trained on 749 datasets from Well-1, tested on 226 datasets from Well-2, and validated on 73 data points from Well-3. The predictability of the optimized algorithms was also compared with the available equations. The results of this study indicated that the optimized ANFIS, SVR, and RF models overperformed the available empirical equations in predicting the TOC. For validation data of Well-3, the optimized ANFIS, SVR, and RF algorithms predicted the TOC with AAPEs of 10.6%, 12.0%, and 8.9%, respectively, compared with the AAPE of 21.1% when the FNN model was used. While for the same data, the TOC was assessed with AAPEs of 48.6%, 24.6%, 20.2%, and 17.8% when Schmoker model, ΔlogR method, Zhao et al. correlation, and Mahmoud et al. correlation was used, respectively. The optimized models could be applied to estimate the TOC during the drilling process if the drillstring is provided with GR and spectral GR logging tools.

The effect of clay-swelling induced cracks on imbibition behavior of marine shale reservoirs

Due to the low matrix porosity and permeability of gas shales, the horizontal well drilling and hydraulic fracturing technologies become a necessity to exploit the unconventional shale resources. While a large volume of fracturing fluid is injected into the shale formation to create cracks, some shale reservoirs have a low flowback rate, about which the mechanism is still unclear. In order to clarify the associated fluid retention mechanism, the spontaneous imbibition experiments were conducted, and interpreted with theoretical analyses. Shale imbibition process can be divided into three stages, including initial imbibition, transition and late imbibition stages. Longmaxi Formation shale from Sichuan Basin usually has clay-swelling induced cracks, while Niutitang Formation shale from Guizhou province commonly has no such cracks. Shale samples with induced cracks show both higher initial and late imbibition rates. Induced cracks increase new pathways for liquid entering into samples, which lead to a higher initial imbibition rate. Liquid in induced cracks has a large contact area with matrix and liquid moves quickly from cracks into matrix, which causes a higher late imbibition rate. As a contrast, shale samples without induced cracks have a lower initial imbibition rate and a lower late imbibition rate. In addition, the ultimate normalized imbibed volume is higher than the pore volume in shale samples with induced cracks. Furthermore, models were established to interpret the imbibed water saturation with the density of clay-swelling induced cracks. Theoretical analyses indicate normalized imbibed volume increases with the density of induced cracks, and the imbibed water volume can be higher than pore volume with enough density of induced cracks. As a result, clay-swelling induced cracks could account for the retention of a large volume of fracturing fluid in gas shales, and our research contributes to explaining the mechanism of fracturing liquid retention in shale gas reservoirs.

Evaluation of the Total Organic Carbon (TOC) Using Different Artificial Intelligence Techniques

Total organic carbon (TOC) is an essential parameter used in unconventional shale resources evaluation. Current methods that are used for TOC estimation are based, either on conducting time-consuming laboratory experiments, or on using empirical correlations developed for specific formations. In this study, four artificial intelligence (AI) models were developed to estimate the TOC using conventional well logs of deep resistivity, gamma-ray, sonic transit time, and bulk density. These models were developed based on the Takagi-Sugeno-Kang fuzzy interference system (TSK-FIS), Mamdani fuzzy interference system (M-FIS), functional neural network (FNN), and support vector machine (SVM). Over 800 data points of the conventional well logs and core data collected from Barnett shale were used to train and test the AI models. The optimized AI models were validated using unseen data from Devonian shale. The developed AI models showed accurate predictability of TOC in both Barnett and Devonian shale. FNN model overperformed others in estimating TOC for the validation data with average absolute percentage error (AAPE) and correlation coefficient (R) of 12.02%, and 0.879, respectively, followed by M-FIS and SVM, while TSK-FIS model showed the lowest predictability of TOC, with AAPE of 15.62% and R of 0.832. All AI models overperformed Wang models, which have recently developed to evaluate the TOC for Devonian formation.

Application of emerging ion exchange resin for boron removal from saline groundwater

Saline groundwater is presently used, when feasible, for hydraulic fracturing operations of unconventional shale resources. In certain geographies, the saline groundwater possesses high boron concentration which is incompatible with the field fracking chemicals; hence, a low boron concentration is desired. The present investigation evaluated a novel chelating ion exchange resin that has potential to remove boron at neutral pH.Bench scale isotherm experiments at various pH revealed negligible difference in removal efficiency between pH 7 and 10. Experiments conducted at 25 °C and 70 °C showed higher sorption of boron removal at lower temperature. Flow through bench column test using deep well saline groundwater (25 mg/L boron and 2.5% TDS) from south Texas showed boron effluent concentration of < 0.1 mg/L and a resin capacity of 5.0 mg/g. Experimental data from pilot study using same saline groundwater showed the resin was very effective in removing boron to low concentrations (<0.5 mg/L). The resin capacity was in the range of 4.4 to 3.1 mg/g operated under different flowrates, which agreed with Thomas model predicted capacity of 3.8 mg/g. The resin was successfully regenerated multiple times by using 7% HCl and 4% NaOH solutions consecutively.Overall the study elucidated that this emerging resin can be applied for large-scale applications for selective boron removal from saline groundwater sources.

Acid demineralization with pyrite removal and critical point drying for kerogen microstructural analysis

Hydrocarbon storage and transport in unconventional shale resources occurs predominantly within pores hosted by kerogen (solid and insoluble organic matter in sedimentary rocks). Kerogen-hosted pores are small, so physiochemical interactions between pore fluids and pore surfaces (e.g., adsorption) are particularly important in shale. The understanding and prediction of hydrocarbon storage and transport in shale is dependent, therefore, upon the correct understanding of both chemical composition and pore geometry of kerogen. Several recent studies have attempted to construct molecular models of kerogen physical and/or chemical structure. Developing these models is challenging, in part because of the lack of laboratory samples of kerogen for experimental characterization that preserve both its chemical and microstructural properties representative of those in the subsurface.This study presents an integrated kerogen-isolation procedure that combines closed-system chemical demineralization with pyrite removal and critical point drying. The method produces a kerogen that is not only high in chemical purity but more representative of kerogen microstructure that occurs in the subsurface. Characterization of kerogen microstructure, which can be performed by direct measurement of the isolate obtained by this procedure, is essential to better understand and predict the storage, transport, and production hydrocarbons from unconventional resources.

Impact of artificially matured organic matter on the dielectric and elastic properties of compacted shales

Unconventional gas shale resources recently became a standard in the American oil and gas industry and are studied throughout the world. However Gas shales are still poorly characterised with respect to other reservoir rock types. The organic matter (OM) in organic shales is rarely taken into account in all its complexity and variability. This study focuses on the influence of OM maturity on the dielectric and elastic response of shale using a hydrous pyrolysis process to increase their maturity. We then incorporated the OM in a shale-like mineral matrix that was artificially compacted under control. Elastic properties and their anisotropy were measured during compaction while dielectric measurements were acquired post-compaction. The results showed that OM affects the onset of the liquid/plastic transition of compacting sediment. The immature OM lessens the development of P-wave anisotropy. On the other end, mature OM strongly decreases the imaginary dielectric permittivity at low frequencies while it increases electrical conductivity.

Multiscale Fluid-Phase-Behavior Simulation in Shale Reservoirs Using a Pore-Size-Dependent Equation of State

Summary The phase behavior of reservoir fluids plays a fundamental role in predicting well performance and ultimate recovery. The uncertainty in phase behavior is currently one of the greatest challenges in developing unconventional shale resources. The complex phase behavior is attributed to the broad range of pore sizes in shale. In macroscale geometries such as fractures and macropores, the fluid behavior is bulk-like; in nanoscale pores, the fluid behavior is significantly altered by confinement effects. The overall phase behavior of fluids in porous media of mixed pore sizes is yet to be understood. In this paper, we present a study on the effect of pore-size distribution on the phase behavior of shale-reservoir fluids in a multiscale-pore system. The global fluid-phase equilibria among different sizes of pores are simulated. A pore-size-dependent equation of state (EOS) is used to describe the fluid by the confining pore diameter. The EOS confinement parameters for fluid/pore-wall surface interaction are determined by experimental results from differential-scanning calorimetry (DSC) and isothermal adsorption of species C1–14. The multiscale phase equilibria are simulated by directly minimizing the total Helmholtz free energy. A modified Eagle Ford oil is used for the case study. Constant-composition expansions (CCEs) of dual-scale (bulk and 15 nm) and triple-scale (bulk, 15 nm, and 5 nm) systems are simulated. The first bubble emerges from the bulk region at a lightly suppressed “apparent” bubblepoint pressure. Below the bubblepoint, the liquid saturation in the bulk region drops sharply, but the fluids in the nanopores are undersaturated throughout the multistage expansions. In the end, large amounts of intermediate-to-heavy hydrocarbons are retained in nanopores, implying a significant oil-recovery loss in shale. The confinement effect also leads to near-critical phase behavior in small-scale nanopores (&amp;lt;5 nm).

Drivers of Wettability Alteration for Oil/Brine/Kaolinite System: Implications for Hydraulic Fracturing Fluids Uptake in Shale Rocks

Hydraulic fracturing technique is of vital importance to effectively develop unconventional shale resources. However, the low recovery of hydraulic fracturing fluids appears to be the main challenge from both technical and environmental perspectives in the last decade. While capillary forces account for the low recovery of hydraulic fracturing fluids, the controlling factor(s) of contact angle, thus wettability, has yet to be clearly defined. We hypothesized that the interaction of oil/brine and brine/rock interfaces governs the wettability of system, which can be interpreted using Derjaguin–Landau–Verwey–Overbeek (DLVO) and surface complexation modelling. To test our hypothesis, we measured a suit of zeta potential of oil/brines and brine/minerals, and tested the effect of ion type (NaCl, MgCl2 and CaCl2) and concentrations (0.1, 1, and 5 wt %). Moreover, we calculated the disjoining pressure of the oil/brine/mineral systems and compared with geochemical modelling predictions. Our results show that cation type and salinity governed oil/brine/minerals wettability. Divalent cations (Ca2+ and Mg2+) compressed the electrical double layer, and electrostatically linked oil and clays, thus increasing the adhesion between oil and minerals, triggering an oil-wet system. Increasing salinity also compressed the double layer, and increased the site density of oppositely charged surface species which made oil and clay link more strongly. Our results suggest that increasing salinity and divalent cations concentration likely decrease water uptake in shale oil reservoirs, thus de-risking the hydraulic fracturing induced formation damage. Combining DLVO and surface complexation modelling can delineate the interaction of oil/brine/minerals, thus wettability. Therefore, the relative contribution of capillary forces with respect to water uptake into shale reservoirs, and the possible impairment of hydrocarbon production from conventional reservoirs can be quantified.