An Experimental Study on Interactions between Imbibed Fracturing Fluid and Organic-Rich Tight Carbonate Source Rocks

Summary Carbonate reservoirs dominate oil (70%) and gas (90%) reserves in the Middle East, and imbibition is the main mechanism for fracturing-fluid uptake during the hydraulic-fracturing stimulation process. Because of the highly heterogeneous nature of tight carbonate source rocks, it is crucial to understand the effects of imbibed fluid on the mechanical, morphological, and flow properties of carbonate rocks. Although the influence of imbibed fluids on the wettability of carbonate reservoir has been studied extensively, research regarding the effects of imbibed fluids on the texture and mineralogy of carbonate rocks is still very limited. This paper aims to provide a conceptual approach and work flow to characterize and quantify microstructure and mineralogy changes in carbonate rocks caused by imbibed fluids. A thin section of a low-permeability organic-rich carbonate-rock sample [7×7×0.3 mm (length×width×thickness)] was used in the study. The sample was submerged into 2%-KCl (pH = 7.1) fluid from one end to simulate the spontaneous-imbibition process. A scanning electron microscope (SEM) was used to capture the sample's morphological changes before and after spontaneous imbibition. Energy-dispersive-spectroscopy (EDS) maps were measured before and after fluid treatment to investigate changes in various elemental distribution. In addition, inductively coupled plasma (ICP) equipped with an optical-emission-spectrometer (OES) detector was used to quantify dissolved-ion concentration in the treatment fluid. Permeability and porosity were measured using core plugs with dimensions of 1.0×1.5 in. (diameter×length) before and after fluid treatment. During the imbibition process, approximately one-half of the sample was submerged in the treatment fluid. The SEM images for the thin-section sample showed three zones with distinct fluid-uptake characteristics. In Zone I, which was fully submerged in the testing fluid, a significant amount of mineral dissolution was observed. In Zone III, which was above the testing-fluid level, considerable mineral precipitation was detected. While in the transition zone just above the water/air interface (Zone II between the previous two zones), only a minor level of mineral dissolution was observed. Elemental-distribution changes resulting from the fluid treatment were identified by EDS analysis in all three zones. Gypsum and calcite crystals dissolved into imbibed fluids upon reaction. Gypsum was found reprecipitated on the rock surface in the zones above fluid level. The observed gypsum formation likely resulted from the dissolution of the gypsum from the rock matrix, then reprecipitation later from the imbibition experiment caused by water evaporation. Absolute-permeability and porosity measurements for core-plug samples have shown that both were increased after the imbibition process.

Summary Hydraulic fracturing has been widely used for unconventional reservoirs, including organic-rich carbonate formations, for oil and gas production. During hydraulic fracturing, massive amounts of fracturing fluids are pumped to crack open the formation, and only a small percentage of the fluids are recovered during the flowback process. The negative effects of the remaining fluid on the formation, such as clay swelling and reduction of rock mechanical properties, have been reported in the literature. However, the effects of the fluids on source-rock properties—especially on microstructures, porosity, and permeability—are scarcely documented. In this study, microstructure and mineralogy changes induced in tight carbonate rocks by imbibed fluids and the corresponding changes in permeability and porosity are reported. Two sets of tight organic-rich carbonate-source-rock samples were examined. One sample set was sourced from a Middle East field, and the other was an outcrop from Eagle Ford Shale that is considered to be similar to the one from the Middle East field in terms of mineralogy and organic content. Three fracturing fluids—2% potassium chloride (KCl), 0.5 gal/1,000 gal (gpt) slickwater, and synthetic seawater—were used to treat the thin section of the source-rock and core samples. Modern analytical techniques, such as scanning electron microscopy (SEM) and energy-dispersive spectroscopy (EDS), were used to investigate the source-rock morphology and mineralogy changes before and after the fluid treatment, at the micrometer scale. Permeability as a function of effective stress was quantified on core samples to investigate changes in flow properties caused by the fracturing-fluid treatments. The SEM and EDS results before and after fracturing-fluid treatments on the source-rock samples showed the microstructural changes for all three fluids. For 2% KCl and slickwater fluid, reopening of some mineral-filled natural fractures was observed. The enlargement of the aperture for pre-existing microfractures was slightly more noticeable for samples treated with 2% KCl compared with slickwater at the micrometer scale. In one sample, dissolution of organic matter was captured in the slickwater-fluid-treated rock sample. Mineral precipitation of sodium chloride (NaCl) and generation of new microfractures were observed for samples treated with synthetic seawater. The formation of new microfractures and the dissolution of minerals could result in increases in both porosity and permeability, whereas the mineral deposition would result in permeability decrease. The overall increase in absolute gas permeability was quantified by the experimental measurements under different effective stress for the core-plug samples. This effect on absolute-gas-permeability increase might have an important implication for hydrocarbon recovery from unconventional reservoirs. This study provides experimental evidence at different scales that aqueous-based fracturing fluid might potentially have a positive effect on gas production from organic-rich carbonate source rock by increasing absolute gas permeability through mineral dissolution and generation of new fractures or reopening of existing microfractures. This observation will be beneficial to the future use of freshwater- and seawater-based fluids in stimulating gas production from organic-rich carbonate formations.

Hydraulic fracturing has been widely used for unconventional reservoirs including organic-rich carbonate formations for oil and gas production. During hydraulic fracturing, massive amount of fracturing fluids are pumped to crack-open the formation and only a small percentage of the fluid is recovered during the flowback process. The negative effects of the remaining fluid on the formation such as clays swelling and reduction of rock mechanical properties have been reported in literatures. However, effects of fluids on source rock properties, especially the microstructures, porosity and permeability, are scarcely documented. In this study, microstructure and mineralogy changes induced in tight carbonate rocks by imbibed fluids and corresponding changes in permeability and porosity are reported. Two sets of tight organic-rich carbonate source rock samples were examined. One sample set was sourced from the Middle East field and the other was an outcrop from Eagle Ford Shale that is considered to be analogous to the one from the Middle East field. Three fracturing fluids, namely 2% KCl, 0.5 gpt slickwater and synthetic seawater, were used to treat the thin-section of the source rock and core samples. Modern analytical techniques such as SEM and EDS were used to investigate the source-rock morphology and mineralogy changes prior and after the fluid treatment at micron-scale level. Porosity and permeability as a function of confining pressures were quantified on core samples to investigate changes in flow properties due to the fracturing fluids treatments. The SEM and EDS results prior to and after fracturing fluid treatments on the source rock samples showed the microstructural changes in all three fluids. In 2% KCl and slickwater fluid, reopening of some mineral-filled natural fractures was observed. The enlargement of micro-fractures was slightly more noticeable for samples treated with 2% KCl in comparison to slickwater at the micron-scale level. In one sample, dissolution of organic matters was captured in slickwater fluid treated rock sample. Some mineral precipitation and new micro-fractures generation were observed for samples treated with seawater. The new micro-fractures generation and mineral dissolution through the fluid treatment would result in the increases in both porosity and permeability, while the mineral deposition would result in permeability decrease. The overall increase in absolute gas permeability was quantified by the experimental measurements under different effective stresses for the core plug samples. This effect on absolute gas permeability increase has an important implication for hydrocarbon recovery from unconventional reservoirs. This study provides experimental evidences at different scales that aqueous-based fracturing fluid may potentially have positive effect on gas production from organic-rich carbonate source rock by increasing absolute gas permeability through mineral dissolution and generation of new or re-opening of old micro- fractures. This observation will be beneficial to the future usage of fresh and seawater based fluids in stimulating gas production for organic-rich carbonate formations.

The spontaneous imbibition (SI) process within shale reservoirs is influenced by both capillary force and the osmotic pressure differential existing between formation water and fracturing fluid. To delve into this intricate mechanism, a numerical simulation study on shale SI is conducted, utilizing seepage theory, the osmotic pressure equation, and solute transport theory. A notable innovation of this research is the derivation of a control equation governing salt ion transport under oil–water two-phase flow conditions. Subsequently, a comprehensive mathematical model for shale SI, accounting for both capillary force and osmotic pressure, is established and solved through numerical simulation methods. The findings reveal that the osmotic pressure between high-salinity formation water and low-salinity fracturing fluid exerts a substantial influence on the imbibition process. It not only accelerates the advancing speed of the imbibition front but also augments the volume of imbibed fluid, thereby significantly enhancing the imbibition recovery ratio. Consequently, optimizing membrane efficiency and increasing the salinity difference emerge as an effective strategy to boost imbibition recovery. Conversely, the impact of hydrodynamic dispersion on salt concentration distribution and imbibition recovery ratio is found to be relatively modest. Overall, this study systematically elucidates the underlying mechanisms of osmotic pressure in the context of the imbibition process. The insights gleaned from this research are anticipated to provide crucial theoretical guidance for enhancing SI efficiency in shale oil reservoirs.

Summary After hydraulic fracturing, only 10 to 50% of the fracturing fluids is typically recovered. This paper investigates how the remaining fracturing fluids are imbibed by shale as a function of time, and it investigates the influence of various parameters on the imbibition process that include lithology, reservoir characteristics, and fluid properties. In addition, on the basis of experimental results, a numerical model has been developed to estimate the volume and rate of spontaneous imbibition over the entire fracture face. The rock samples are from the Horn River formation onshore Canada. The fracturing fluids used in the experiments included 2% KCl, 0.07% friction reducer, and 2% KCl substitute. In the experimental control group, distilled water was used. Through spontaneous-imbibition experiments, the relationship between imbibed fluid volume and time indicated that clay content was the most important factor that affected the total imbibed amount. Shale matrix with high clay content could imbibe more fracturing fluids than its measured porous space because of the clay's strong ability to expand and hold water. According to contact-angle-test results, the strongly water-wet shale samples had a faster imbibed rate. Total organic carbon (TOC) and porosity had no influence on imbibed volume and rate. These experimental findings can contribute to an improved fracturing-fluid design for different shale-formation conditions to reduce fluid loss. The experiment showed that 2% KCl and 2% KCl substitute fracturing fluids were imbibed from 10 to 40% less than 0.07% friction reducer in the shale formation with high clay content, whereas in the shale formation with low clay content, the opposite occurred. In the low-clay-content shale, 0.07%-friction-reducer test fluid was imbibed from 10 to 30% less than 2% KCl fluid, but had an imbibed amount similar to that of 2% KCl substitute fluid. The numerical-model result was matched with the experimental result to estimate a relative permeability in the model that could represent the rock properties. This model could be used to estimate the total imbibed volume along fracture faces through spontaneous imbibition.

Spontaneous imbibition is a capillary dominated displacement process where a non-wetting fluid is displaced from a porous medium by the inflow of a more-wetting fluid. Spontaneous imbibition strongly impacts waterflood oil recovery in fractured reservoirs and is therefore widely studied, often using core scale experiments for predictions. Decades of core scale experiments have concluded that spontaneous imbibition occurs by a uniformly shaped saturation front and that the rate of imbibition scales with square root of time. We use emerging imaging techniques to study local flow patterns and present new experimental results where spontaneous imbibition deviates from this behavior. The imbibition rate during early stages of spontaneous imbibition (the onset period) was sometimes observed to deviate from the square root of time behavior. The impact of the onset period on the imbibition process is, however, not well understood. In this work, the development of displacement fronts were visualized during the onset period, using twodimensional paperboard models and core plugs imaged using Positron Emission Tomography (PET-CT). The new experimental results provided insight on the dynamics during the initial spontaneous imbibition period. Controlled two-dimensional paperboard experiments demonstrated that restricted wetting phase flow through the surface exposed to water caused irregular saturation fronts and deviation from the square root of time behavior during the onset period. Local restriction of the wetting phase flow was observed during spontaneous imbibition in sandstone core plugs as a result of non-uniform wetting preference. The presence of nonuniform wetting resulted in unpredictable spontaneous imbibition behavior, with induction time (delayed imbibition start) and highly irregular fronts. Without imaging, the development of irregular saturation fronts cannot be observed locally; hence the effect cannot be accounted for, and the development of spontaneous imbibition in the core erroneously interpreted as a corescale wettability effect. This underlines the undeniable need for a homogenous wettability preference through the porous medium when performing laboratory spontaneous imbibition measurements. Our observations of non-uniform wetting preference will affect Darcy-scale wettability measurements, scaling and modeling. We argue that great care must be taken when preparing core plugs for spontaneous imbibition, to avoid experimental artifacts.

A novel method for evaluation of the spontaneous imbibition process in tight reservoir rocks: Mathematical model and experimental verification

What type of surfactants should be used to enhance spontaneous imbibition in shale and tight reservoirs?

Visualizing and quantifying fluid distribution during spontaneous imbibition at the nanomicro scale is vital for understanding microfluid flow and dynamic wettability in coalbed methane (CBM) reservoirs, which could serve as a fundamental basis for optimizing the parameters of the hydraulic fracturing process. In this study, fluid distribution and flow behavior can be acquired by combining nuclear magnetic resonance (NMR) and in situ X-ray microcomputed tomography (μ-CT) technologies. Meanwhile, spontaneous imbibition stages were studied to analyze gas-water exchange efficiency. Additionally, dynamic wettability of gas-water was calculated during the process of spontaneous imbibition based on NMR. The results show that imbibition characteristics can be divided into three categories based on NMR. In type I, changes in imbibition fluid within nanopores are not obvious, while significant changes occur in micro pore-fractures, especially during the early stage of imbibition (0-2 h) for type I, which is almost the opposite of type II. Coal samples of type III exhibit low porosity and permeability, making it difficult for water to flow through the pores in coal due to capillary forces. The dynamic process of spontaneous imbibition can be divided into four stages using μ-CT equipment, with the third stage displaying the highest imbibition efficiency. This stage is characterized by frequent imbibition fluid exchange among various-scale fractures, which is related to the wettability and pore-fracture of the coal sample. A negative correlation between contact angle and T 2g was observed, where hydrophobic samples corresponded to a smaller geometric average of T 2g in the sample. In addition, the wettability of coal samples changed dynamically during the process of imbibition, with the contact angle gradually decreasing as imbibition time increased, which may be related to the formation of water film and hydration reactions.

Capillary spontaneous imbibition of solvent (brine bound in gel) from formed polymer gel into an adjacent, oil-saturated porous medium was recently observed in laboratory experiments. Loss of solvent from the gel by spontaneous imbibition may influence the blocking capacity of the gel residing in a fracture, by decreasing the gel volume, and may contribute to gel failure, often observed in water-wet oil fields. Formed gel cannot enter significantly into porous rock, which has important implications for spontaneous imbibition: the gel particle network itself is not imbibed, and remains close to the rock matrix surface, while gel solvent can leave the gel and progress into the matrix due to capillary forces. Polymer gel is an inherently complex fluid and modelling of its behavior is, as such, complicated. Accurate description and quantification of gel properties and behaviour on the laboratory scale is, however, necessary to predict the performance of gel placed in an oil field, particularly in fractured formations. In this work, we present an original modelling approach, to simulate and interpret spontaneous solvent imbibition from Cr(III)-Acetate HPAM gel into oil-saturated chalk core plugs. A theory describing solvent flow within a gel network is detailed, and was implemented into an in-house simulator. Simulations of spontaneous imbibition from gel was performed, and compared to free spontaneous imbibition of water. A good overall match was achieved between experiments and simulations on the core scale, which validates the proposed gel model. All Faces Open (AFO) and Two Ends Open - Free Spontaneous Imbibition (TEOFSI) boundary conditions were used in the experiments, and formed the basis for simulation. Spontaneous imbibition occurs at the core end faces that are open to flow and exposed to gel (different for the two boundary conditions). The gel surrounding the core was discretized and included as a part of the total grid to capture transient behavior. The surrounding gel is treated as a compressible porous medium where the gel's polymer structure constitutes the matrix having constant solid volume while the gel porosity is a function of pore pressure. The gel permeability is modelled as function of gel porosity using a Kozeny-Carman approach. The flow equations for the gel and core domains were solved simultaneously by implementing the proposed description into the core scale simulator IORCoreSim. Two properties were identified to control the transport of water from gel into the adjacent matrix: the permeability and compressibility of the gel. The flow of water from the gel was observed in simulations to occur in a transient manner, driven by the coupled gradients in gel fluid pressure and gel porosity, where the gel porosity initially decreases in a layer close to the core surface due to reduced aqueous pressure. Gel porosity continued to decrease in layers away from the core surface; the propagation rate was controlled by two main gel parameters: (i) Gel compressibility controlled the pressure gradient within the gel network, and the amount of water transported from the outer part of the gel towards the core surface to balance the pore pressure. (ii) Gel permeability limited how fast water could flow within the gel at a given pressure gradient, thus increasing the time scale of the overall imbibition process.

Monitor the process of shale spontaneous imbibition in co-current and counter-current displacing gas by using low field nuclear magnetic resonance method

Spontaneous imbibition in asymmetric branch-like throat structures in unconventional reservoirs

This study integrates one-dimensional and two-dimensional nuclear magnetic resonance (NMR) techniques to conduct spontaneous imbibition experiments on two distinct lithologies (laminated calcareous shale and bulk clay-rich shale) from the Qintong Depression using four different fluid types. Field emission scanning electron microscopy (FE-SEM) and computed tomography (CT) scanning were employed to observe and track the dynamic changes in shale microstructures at specific intervals allowing for a comprehensive analysis of induced microfractures and their propagation patterns. These methods enabled a deeper understanding of the underlying mechanisms, enriching the interpretation of the imbibition results. The study reveals that anionic surfactants demonstrate exceptional performance during the imbibition process, and the combination of surfactants further enhanced oil recovery. The imbibition process can be divided into three stages: the imbibition diffusion stage, the transition stage, and the equilibrium stage, with the diffusion stage serving as the primary contributor, driven predominantly by capillary pressure. The calcareous shale cores exhibited the highest imbibition rates in the early stages, approaching equilibrium in the middle stages. Conversely, the clay-rich shale cores maintained relatively high imbibition rates throughout the second stage, indicating different imbibition dynamics based on lithology. NMR, CT scanning, and SEM analysis highlighted significant lithology-dependent differences in the mechanisms driving induced microfracture development during the imbibition and hydration. In laminated calcareous shale, imbibition and hydration primarily proceeded through the dissolution of calcareous minerals, resulting in pore expansion and induced microfractures along pre-existing fractures. In contrast, clay-rich shale exhibited similar mineral dissolution but also experienced clay swelling due to its high clay content, leading to the formation of bedding-parallel fractures with distinct directional patterns along weak mineral-matrix bonds. The experimental results underscored the pivotal role of lithology in determining final imbibition efficiency, with high-clay-content shales demonstrating superior recovery rates under spontaneous imbibition conditions. This study provides critical experimental data and insights into the microscopic mechanisms governing spontaneous imbibition across varied lithologies and fluid types in the Qintong Depression. The results offer foundational knowledge for optimizing oilfield development strategies.

Spontaneous imbibition (SI) has proven to be an effective method for enhancing oil recovery in water-wet shale reservoirs due to the capillary force. There are few articles that focus on the water imbibition and oil displacement for oil-wet reservoirs. However, we believe that the potential of oil displacement caused by water imbibition should not be neglected, since field observations from dozens of wells show strong positive relevance between initial oil production and post-fracturing well shut-in time in the oil-wet shale oil reservoir of Junggar Basin, China. In this paper, several experiments and numerical simulations are designed to shed light on the mechanism of oil displacement by fracturing fluid imbibition, including the driving force and the oil recovery of different pores. The real field fracturing fluid which is prepared by guar gel, anti-emulsifiers, anti-swelling, cleanup additives and gel breakers is used as the test fluid. Also, the oil-wet shale cores saturated with crude oil are used as the samples. Firstly, contact angle after different contact times and interfacial tension are measured to figure out the petrophysical properties of fracturing fluid and crude oil. Secondly, the SI experiments using the fracturing fluid made up of deuterium oxide as the imbibed fluid are conducted to discover the oil recovery of different sizes of pores with shale samples. The low-field nuclear magnetic resonance(LF-NMR) is used to describe the relative content of crude oil under different pores and different SI times. Finally, an experimental core model is established based on the above experimental results. The results show that wettability alteration appears in the oil-wet the core sample. As the contact time increases, the contact angle decreases continuously. The interfacial tension decreases from 72(water and crude oil) mN/m to 1.2(fracturing fluid and crude oil) mN/m. These two phenomena effectively explain the driving force of imbibition and displacement in oil-wet samples. The imbibition oil recovery is about 18.4% in the oil-wet core samples, which indicates that oil-wet cores have a certain oil displacement effect. The fracturing fluid enters the mesopore first because of the driving force produced by wettability alteration and the low frictional resistance, and the imbibition oil recovery in the mesopore is 35%, which is higher than that in micropore and small mesopore in oil-wet samples. This phenomenon and result show a sharp contrast with that of water-wet rock cores proved by previous studies. Finally, a new capillary force curve accounting for the effect of wettability alteration is fitted to characterize the oil displacement in oil-wet samples by the experimental core model simulation. This study aims to demonstrate the SI characteristics of oil-wet shale and helps to provide crucial theoretical foundations for developing oil-wet shale reservoirs.

Field experience along with laboratory evidence of spontaneous imbibition via the addition of surfactants into the completion fluid is widely believed to improve the IP and ultimate oil recovery from unconventional liquid reservoirs (ULR). During fracture treatment with surface active additives, surfactant molecules interact with the rock surface to enhance oil recovery through wettability alteration combined with interfacial tension (IFT) reduction. The change in capillary force as the wettability is altered by the surfactant leads to oil being expelled as water imbibes into the pore space. Several laboratory studies have been conducted to observe the effectiveness of surfactants on various shale plays during the spontaneous imbibition process, but there is an insufficient understanding of the physical mechanisms that allow scaling the lab results to field dimensions. In this manuscript, we review and evaluate dimensionless, analytical scaling groups to correlate laboratory spontaneous imbibition data in order to predict oil recovery at the field scale in ULR. In addition, capillary pressure curves are generated from imbibition rate theory originally developed by Mattax and Kyte (1962). The original scaling analysis was intended for understanding the rate of matrix-fracture transfer for a rising water level in a fracture-matrix system with variable matrix block sizes. Although contact angle and interfacial tension (IFT) are natural terms in scaling theory, virtually no work has been performed investigating these two properties. To that end, we present scaling analysis combined with numerical simulation to derive relative permeability curves, which will be imported into a discrete fracture network (DFN) model. We can then compare analytical scaling methods with conventional dual porosity concepts and then progressed to more sophisticated Discrete Fracture Network concepts. The ultimate goal is to develop more accurate predictive methods of the field-scale impact due to the addition of surfactants in the completion fluid. Correlated experimental workflows were developed to achieve the aforementioned objectives including contact angle (CA) and IFT at reservoir temperature. In addition, oil recovery of spontaneous imbibition experiments was recorded with time to evaluate the performance of different surfactants. Capillary pressure-based scaling is developed by modifying previously available scaling models based on available surfactant-related properties measured in the laboratory. To ensure representability of the scaling method; contact angle, interfacial tension, and ultimately spontaneous imbibition experiments were performed on field-retrieved samples and used as a base for developing a new scaling analysis by considering dimensionless recovery and time. Based on the capillary pressure curves obtained from the scaling model, relative permeability is approximated through a history matching procedure on core-scale numerical models. CT-Scan technology is used to build the numerical core plug model in order to preserve the heterogeneity of the unconventional core plugs and visualize the process of water imbibition in the core plugs. Time-lapse saturation changes are recorded using the CT scanner to visualize penetration of the aqueous phase into oil-saturated core samples. The capillary and relative permeability curves can then be used on DFN realizations to test cases with or without surfactant. The results of spontaneous imbibition showed that surfactant solutions had a higher oil recovery due to wettability alteration combined with IFT reduction. Our upscaling results indicate that all three methods can be used to scale laboratory results to the field. When compared to a well without surfactant additives, the optimum 3-year cumulative oil production of well that is treated with surfactant can increase by more than 20%.