Matrix Imbibition Research Articles

Partially Saturated Fracture‐Matrix Infiltration in Experiments and Theory

AbstractFractures provide pathways for preferential flow, whereas porous rock acts as storage that delays fluid propagation through matrix imbibition. These dual‐porosity mechanisms are investigated in laboratory experiments of partially saturated fracture infiltration. We analyze flow dynamics in terms of the fluid penetration depth in the fracture and delineate fracture‐ and matrix‐dominated flow regimes at different flow rates. We compare wetting front propagation in fracture and matrix and examine the interference of matrix‐wetting fronts with the lateral system boundary. The experimental data are interpreted using the analytical model of Nitao (1991), which accounts for the impact of fracture‐matrix interactions on fluid propagation in the fracture. We find that matrix imbibition affects the observed discontinuous, partially saturated fracture flow to behave, on average, like plug flow. Consequently, and within the range of applied flow rates above a critical threshold, the model’s plug flow assumption is not a relevant precondition for its applicability. Fluid propagation in the fracture exhibits three characteristic scaling regimes (FP1‐3) corresponding to the matrix imbibition state. Only two scaling regimes are established for flow rates below a critical threshold, hence required to recover bulk infiltration for the chosen geometry. Furthermore, wetting fronts switch from fracture‐to matrix‐dominated at moderate to high flow rates, indicating a flow‐rate‐dependent limitation of fracture‐dominated infiltration depth. While the scaling regimes agree with experiments for applied flow rates above the critical threshold, the model underestimates the initial penetration depth below. Here, we observe the direct onset of flow regime FP2 and the delayed transition into FP3.

Study on the Flow Behavior of Gas and Water in Fractured Tight Gas Reservoirs Considering Matrix Imbibition Using the Digital Core Method

Tight gas reservoirs possess unique pore structures and fluid flow mechanisms. Delving into the flow and imbibition mechanisms of water in fractured tight gas reservoirs is crucial for understanding and enhancing the development efficiency of such reservoirs. The flow of water in fractured tight gas reservoirs encompasses the flow within fractures and the imbibition flow within the matrix. However, conventional methods typically separate these two types of flow for study, failing to accurately reflect the true flow characteristics of water. In this study, micro-CT imaging techniques were utilized to evaluate the impact of matrix absorption and to examine water movement in fractured tight gas deposits. Water flooding experiments were conducted on tight sandstone cores with different fracture morphologies. Micro-CT scanning was performed on the cores after water injection and subsequent static conditions, simulating the process of water displacement gas in fractures and the displacement of gas in matrix pores by water through imbibition under reservoir conditions. Changes in gas–water distribution within fractures were observed, and the impact of fracture morphology on water displacement recovery was analyzed. Additionally, the recovery rates of fractures and matrix imbibition at different displacement stages were studied, along with the depth of water infiltration into the matrix along fracture walls. The insights gained from this investigation enhance our comprehension of the dynamics of fluid movement within tight gas deposits, laying a scientific foundation for crafting targeted development plans and boosting operational efficiency in such environments.

Immiscible imbibition in fractured media: A dual-porosity microfluidics study

We use dual porosity microfluidics and fluorescence microscopy to investigate immiscible imbibition in the pore networks formed in fractured rocks, and to identify emergent pore-scale events that arise as a result of the interplay between advection-dominant flow in fractures (F) and capillary-driven matrix imbibition (M). The dimensionless ratio between the two time scales T = tF/tM defines the various displacement patterns: fracture-dominant advective invasion at low Τ-values leaves a higher residual non-wetting phase saturation; compact invasion is observed at intermediate T-values, and fractures act as capillary barriers during matrix-dominant capillary imbibition at high Τ-values. Experiments and analyses show effective capillary-driven corner flow during immiscible imbibition; in particular, corner flow imbibition displaces non-wetting fluids that were initially trapped in the matrix during fast advective invasion. In contrast to wetting fluid invasion and imbibition, injected non-wetting fluids invade and flow along fractures as soon as the capillary pressure reaches the fracture entry pressure, and there is no matrix invasion and drainage. The capillary pressure versus saturation curve for the fractured rock mass assumes that fractures and matrix blocks share the same capillary pressure at equilibrium; then, the combined pressure-saturation response is a function of their relative contributions to the total porosity. In the absence of gouge or precipitates, fractures determine the entry pressure while the matrix controls storativity.

Numerical Simulation Study on Optimal Shut-In Time in Jimsar Shale Oil Reservoir

The volume fracturing technology along with horizontal well is the main technology to obtain commercial oil flow in shale reservoirs because of the low porosity and low permeability. Whether the fracturing fluid has the potential of shale matrix imbibition oil recovery after a large amount of slickwater injected into the reservoir is a research hotspot at present. Therefore, it is of great significance to study the law of imbibition and replacement during the shut-in time. Aiming at the Jimsar area, there are several steps in this study in order to explore the new law of fracturing fluid imbibition and oil recovery in shale reservoirs. Primarily, the distribution of pressure and saturation during fracturing time and shut-in time is accurately described by the numerical simulation method. Furthermore, the sensitivity analysis is carried out from two aspects of geological and fracture factors. Eventually, the evaluation of optimal shut-in time is taken by imbibition replacement balance. According to the numerical simulation results, the pressure diffuses rapidly among the matrix during the shut-in time in the hydrophilic reservoir. After 65 days of well shut-in, the whole reservoir tends to be at the same pressure and reaches the equilibrium of imbibition replacement. Contrarily, the pressure of the lipophilic reservoir diffuses slowly and only propagates in the secondary fracture or the matrix near the fractures. The fracture system remains a “high-pressure area” for a long time during shut-in. Additionally, the optimal shut-in time chart of different geological parameters and fracture parameters is drawn to optimize the shut-in time. This research work has a certain reference value for the optimization of shut-in time after fracturing in Jimsar and similar shale oil wells.

Enhanced mass transfer between matrix and filled fracture in dual-porosity media during spontaneous imbibition based on low-field nuclear magnetic resonance

Spontaneous imbibition (SI) of wetting fluids is an important process for many hydrological and geological applications. In this study, we investigated experimentally and theoretically the SI process in a dual-porosity medium consisting of the matrix and the filled fracture. Low-field nuclear magnetic resonance (LF NMR) technology was used to dynamically monitor the distribution of the imbibed water in the dual-porosity media during the SI experiments. Based on the LF NMR theory, a cut-off method was proposed to quantitatively distinguish the imbibed water from the matrix and the filled fracture. The results showed that the rate of matrix imbibition was greater in the dual-porosity media than in single-porosity media. This inconsistent rate of matrix imbibition between the single-porosity media and the dual-porosity media was caused by the enhanced mass transfer between the matrix and the filled fracture. An analytical model was then proposed to characterize this enhanced mass transfer between the matrix and the filled fracture. It was found that the rate of matrix imbibition was not only affected by the presence of the filled fractures but also depended on the size of the particles filled in the fracture. A clear non-monotonic relationship was found between the rate of matrix imbibition and the size of the particles filled in the fracture. The rate of matrix imbibition initially increased and then decreased as the size of the particles filled in the fracture increased. The proposed analytical model not only highlighted the mechanism of enhanced mass transfer between the matrix and the filled fracture, but was also able to determine the optimum equivalent capillary diameter of the filled particles in the fracture for enhanced rate of matrix imbibition in dual-porosity media.

Three-dimensional physical simulation of water huff-n-puff in a tight oil reservoir with stimulated reservoir volume

Water huff-n-puff has been considered as a cost-effective method to enhance oil recovery in tight reservoirs. However, the physical simulation method for water huff-n-puff is still lacking up to now, so that the production behaviors of actual tight reservoirs cannot be reproduced and the EOR potentials cannot be evaluated directly by scaled models in the laboratory. In this study, mathematical models for water huff-n-puff processes in tight oil reservoirs with stimulated reservoir volume (SRV) were established, then the corresponding scaling criteria were proposed and verified. Taking the tight reservoir ZMY in the Ordos Basin as a prototype, three groups of three-dimensional physical simulations of water huff-n-puff under different conditions (PSM-1, PSM-2 and PSM-3) were designed based on the scaled parameters respectively, then performed favorably and compared comprehensively. The experimental results show that oil recovery of PSM-1 can be increased by 20.16% within 8 cycles, which shows great EOR potentials for the tight reservoir ZMY. Compared with PSM-1, oil recovery of PSM-2 reduces by 8.23%, which indicates that forced imbibition is quite a helpful and promoting mechanism, and oil recovery enhancement will be greatly limited if no imbibition effect is given play between the matrix and fractures. Comparatively, oil recovery reduces by 3.39% for PSM-3, which can be inferred that if fracture density relatively increases and all fractures are well connected, the matrix imbibition effect can be further strengthened, the high pressure can propagate faster, the elastic energy can supplement into the matrix deeper, and the effect of gravitational differentiation can be better utilized as well. It is found that cumulative oil production of the three physical simulations in the first several cycles is always relatively high, which implies that sufficient oil supply in physical models can be maintained. As oil-water interface rises, less oil and more water will be produced and different dynamic characteristics of cumulative oil and water production are shown. It is also found that all three groups of water cut curves have the same upward trend and the Sigmoidal-Logistic model can be employed to accurately depict the dynamic characteristics of water cut at different cycles. This study aims to establish a physical simulation method for water huff-n-puff in tight oil reservoirs with SRV based on the three-dimensional scaled model, which will be greatly helpful to understand the EOR mechanisms and production characteristics of water huff-n-puff. • Scaling criteria of water huff-n-puff in tight oil reservoirs with SRV were proposed and verified. • Three-dimensional physical simulation method for water huff-n-puff was established. • Oil recovery of physical simulation model can be increased by 20.16% within 8 cycles for a case study. • Forced imbibition and large-scale fracture network can greatly enhance oil recovery during water huff-n-puff. • The Sigmoidal-Logistic model can depict the dynamic characteristics of water cut at different cycles.

A pressure drop model of post-fracturing shut-in considering the effect of fracturing-fluid imbibition and oil replacement

Since the production regime of shut-in after fracturing is generally adopted for wells in shale oil reservoir, a shut-in pressure drop model coupling wellbore-fracture network-reservoir oil-water two-phase flow has been proposed. The model takes into account the effects of wellbore afterflow, fracture network channeling, and matrix imbibition and oil exchange after stop of pumping. The simulated log-log curve of pressure-drop derivative by the model presents W-shape, reflecting the oil-water displacement law between wellbore, fracture network and matrix, and is divided into eight main control flow stages according to the soaking time. In the initial stage of pressure drop, the afterflow dominates; in the early stage, the pressure drop is controlled by the cross-flow and leakoff of the fracture system, and the fractures close gradually; in the middle stage of pressure drop, matrix imbibition and oil exchange take dominance, and the fracturing fluid loss basically balances with oil replaced from matrix; the late stage of pressure drop is the reservoir boundary control stage, and the leakoff rate of fracturing-fluid and oil exchange rate decrease synchronously till zero. Finally, the fracture network parameters such as half-length of main fracture, main fracture conductivity and secondary fracture density were inversed by fitting the pressure drop data of five wells in Jimsar shale oil reservoir, and the water imbibition volume of matrix and the oil replacement volume in fracture were calculated by this model. The study results provide a theoretical basis for comprehensively evaluating the fracturing effect of shale oil horizontal wells and understanding the oil-water exchange law of shale reservoir after fracturing.

Multiscale Smoothed Particle Hydrodynamics Model Development for Simulating Preferential Flow Dynamics in Fractured Porous Media

AbstractWe present our new multiscale pairwise‐force smoothed particle hydrodynamics (PF‐SPH) model for the characterization of flow in fractured porous media. The fully coupled multiscale PF‐SPH model is able to simulate flow dynamics in a porous and permeable matrix and in adjacent fractures. Porous medium flow is governed by the volume‐effective Richards equation, while the flow in fractures is governed by the Navier‐Stokes equation. Flow from a fracture to the porous matrix is modeled by an efficient particle removal algorithm and a virtual water redistribution formulation to enforce mass and momentum conservation. The model is validated by (1) comparison to a finite‐element model (FEM) COMSOL for Richards‐based flow dynamics in a partially saturated medium and (2) laboratory experiments to cover more complex cases of free‐surface flow dynamics and imbibition into the porous matrix. For the laboratory experiments, Seeberger sandstone is used because of its well‐known homogeneous pore space properties. The saturated hydraulic conductivity of the permeable matrix is estimated from a pore size and grain size distribution analysis. The developed PF‐SPH model shows good correlation with the COMSOL model and all types of laboratory experiments. We employ the proposed model to study preferential flow dynamics for different infiltration rates. Here, flow in the fracture is associated with the term “preferential flow,” providing rapid water transmission, while flow within the adjacent porous matrix enables only slow and diffuse water transmission. Depending on the infiltration rate and water inlet location, two cases can be distinguished: (1) immediate preferential/fracture flow or (2) delayed preferential flow. In the latter case, water accumulates at the surface first (ponding), then the fracture rapidly transmits water to the bottom system outlet. For the immediate fracture flow response, ponding only occurs once the fracture is fully saturated with water. In all cases, preferential flow is much more rapid than diffuse flow even under saturated porous medium conditions. Furthermore, infiltration dynamics in rough fractures adjacent to an impermeable or permeable matrix for different infiltration rates are studied as well. The simulation results show a significant lag in arrival times for small infiltration rates when a permeable porous matrix is employed, rather than an impermeable one. For higher infiltration rates, water rapidly flows through the fracture to the system outlet without any significant delay in arrival times even in the presence of the permeable matrix. The analysis of the amount of water stored in permeable fracture walls and in a fracture void space shows that for small infiltration rates, most of the injected water is retarded within the porous matrix. Flow velocity is higher for large infiltration rates, such that most of the water flows rapidly to the bottom of the fracture with very little influence of matrix imbibition processes.

The retention and flowback of fracturing fluid of branch fractures in tight reservoirs

A small percentage of the fracturing fluid pumped can be recovered after multi-stage fracturing stimulation in tight reservoirs. One cause for this can be the numerous branch fractures formed at different scales during large volume fracturing. Understanding the retention mechanism and flowback law of fracturing fluid in branch fractures is a key to solving this problem. In this study, we used a leaser macroscope, a low-field nuclear magnetic resonance (NMR) instrument, and a permeability device to scan fracture surface morphology and conduct fracturing fluid retention and permeability regain experiments. Meanwhile, retention mechanisms and the flowback process of fracturing fluid in branch fractures during flowback is considered. The experimental results show that the fracturing fluid present in branch fractures can be divided into free movable water (FMW), restricted movable water (RMW) and retained water (RW). The average proportion of FMW, RMW, and RW in Lucaogou and Longmaxi shale reservoirs in our work are about 0.16: 0.14: 0.7 and 0.1: 0.1: 0.8, respectively. The rougher the surface and the greater the tortuosity of the fracture are, the higher the retention percentage of fracturing fluid in branch fractures is. The main mechanisms of fracturing fluid retention in branch fractures include water film, capillary retention on the fracture surface, and matrix imbibition. The critical T2 of FMW and RMW in branch fractures in the Lucaogou shale reservoir are 25.3 ms and 10.2 ms, respectively. However, they are 64 ms and 3.7 ms in the Longmaxi shale reservoir. During the flowback, FMW and partial RMW gradually flowback to the surface. After this, the permeability regains with the decrease of water retention in branch fractures. This study contributes to understanding fracturing fluid retention mechanism in tight reservoirs and provides guidance for the optimization of fracturing flowback.

Hydrodynamic Equilibrium Simulation and Shut-in Time Optimization for Hydraulically Fractured Shale Gas Wells

Post-fracturing well shut-in is traditionally due to the elastic closure of hydraulic fractures and proppant compaction. However, for shale gas wells, the extension of shut-in time may improve the post-fracturing gas production due to formation energy supplements by fracturing-fluid imbibition. This paper presents a methodology using numerical simulation to simulate the hydrodynamic equilibrium phenomenon of a hydraulically fractured shale gas reservoir, including matrix imbibition and fracture network crossflow, and further optimize the post-fracturing shut-in time. A mathematical model, which can describe the fracturing-fluid hydrodynamic transport during the shut-in process, and consider the distinguishing imbibition characteristics of a hydraulically fractured shale reservoir, i.e., hydraulic pressure, capillarity and chemical osmosis, is developed. The key concept, i.e., hydrodynamic equilibrium time, for optimizing the post-fracturing shut-in schedule, is proposed. The fracturing-fluid crossflow and imbibition profiles are simulated, which indicate the water discharging and sucking equilibrium process in the coupled fracture–matrix system. Based on the simulation, the hydrodynamic equilibrium time is calculated. The influences of hydraulic pressure difference, capillarity and chemical osmosis on imbibition volume, and hydrodynamic equilibrium time are also investigated. Finally, the optimal shut-in time is determined if the gas production rate is pursued and the fracturing-fluid loss is allowable. The proposed simulation method for determining the optimal shut-in time is meaningful to the post-fracturing shut-in schedule.

Experimental Study of Fracturing Fluid Retention in Rough Fractures

Multistage hydraulic fracturing is a key technology for developing tight reservoirs. Field data indicate that a small fraction of the injected water can be recovered during flowback. Fractures play an important role in the retention of fracturing fluid, but the mechanisms and rules remain uncertain. Therefore, an experimental facility was established for studying the fluid retention in fractures using an improved conductivity apparatus. The fluid trapped in rough fractures was measured, and the dynamic changes of the drainage volume and rate under various apertures were analyzed. The effects of different factors, such as the fracture aperture, surface roughness, tortuosity, and matrix imbibition, on the fluid retention were studied. An empirical formula between the retention rate and fracture aperture was derived on the basis of mass conservation. Results showed that the fluid retention rate slowly decreased with an aperture increase in the fracture, and it would increase with considerable roughness, high tortuosity, and significant matrix imbibition. Meanwhile, drainage volume and rate change dramatically resulted from the gas drive. Secondary fractures and microcracks played an important role in the retention of fracturing fluid. Furthermore, the mechanisms of fracturing fluid retained in the tight reservoir, including viscous trapping and “locking” in fractures, the effect of gravity, surface-bound water film, capillary force retention, and matrix imbibition, were discussed. This study is significant for understanding the flowback rules of fracturing fluid, diagnosing fracture development, and identifying reservoir properties.

Modelling shale spontaneous water intake using semi‐analytical and numerical approaches

AbstractShale matrix water intake during hydraulic fracturing is considered undesirable due to the high volume of unrestrained water loss; however, it is also rewarding because it can reduce the possibility of groundwater contamination. The water intake also plays a dual role in changing the shale production performance; water imbibition into matrix pores can dramatically reduce the effective permeability and, at the same time, might enhance hydrocarbon production by creating adsorption‐induced micro‐fractures. Quantifying the formation intake capacity and its breadth is the key to optimizing fracturing operation, flowback, and production strategy. This work entails complementary semi‐analytical and numerical analyses and investigates the effects of basic rock and fluid properties, wettability heterogeneity, and pore space connectivity on the shale imbibition characteristics. We consider a semi‐analytical formulation of the spontaneous water imbibition, together with model results and validations, and try to provide a framework to link the capillary imbibition capacity/rate to lab‐scale observations. The core‐scale measurements provide input for a sensitivity study on the matrix imbibition capacity in six shale plays in North America. The results suggest that rock permeability, hydraulic tortuosity, and initial and residual hydrocarbon saturations are among the most influential factors on the spontaneous water intake during shut‐in periods. Direct quasi‐static simulations are then conducted through a submicron tomography image of the Eagle Ford shale, and two‐phase pore‐level fluid occupancies are reconstructed during spontaneous and forced imbibition processes. According to the numerical results, the presence of continuous organic matter laminae can lower the destructive effects of water imbibition on the hydrocarbon permeability.

Characteristics of oil distributions in forced and spontaneous imbibition of tight oil reservoir

Matrix imbibition, which includes spontaneous imbibition (SI) and forced imbibition (FI), is the main mechanism of water-based methods, and can play a significant role in unlocking tight oil potentials as a tremendous amount of oil remains in the matrix following primary production. Previously, SI and FI have been investigated separately in pore-scale studies for several years. However, it is difficult for the results to provide guidance for selecting water-based methods owing to the different core samples and pore classification criteria adopted. Therefore, an integrated study of SI and FI is conducted on tight cores in order to understand the characteristics of oil contributions from different pores. In this work, 68 tight cores from the Chang 8 formation, Ordos Basin (China) are investigated. Nine cores are used to test native wettabilities; then, rate-controlled porosimetry is conducted on a typical tight core. Finally, nuclear magnetic resonance is implemented to determine the oil distributions before and after SI and FI for six cores. Based on the petrophysical properties, the cores are classified into three permeability levels (0.06 mD, 0.1 mD, and 0.22 mD). The SI and FI results demonstrate that FI can always provide more than twice the oil recovery factor of SI in each permeability level. For FI, more than 40% of the produced oil is contributed by mesopores. With increasing permeability, macropores contribute more oil than micropores. For SI, the oil contribution from micropores can reach 53.34%. The permeability of 0.1 mD is a critical point at which the oil contribution of mesopores surpasses that of micropores.

The Global Kondaurov Double Porosity Model

In this paper we derive a non-equilibrium matrix imbibition equation for the homogenized Kondaurov double porosity model which is valid for arbitrary relaxation times. This equation involves the real saturation and Kondaurov's non-equilibrium parameter, i.e., the principal unknowns of the model. The numerical simulation of the obtained result is also presented.

Experimental study of the osmotic effect on shale matrix imbibition process in gas reservoirs

Speaking of imbibition, it usually refers to the displacement of the non-wetting phase by the wetting phase in a porous medium by capillary action. Most of the focuses in the technical literature of this area have been given to the factors related to capillarity and viscous forces with or without gravity effect. However, solute (ions/salt)-rock interaction has been overlooked for long, which is also a critical imbibition mechanism as solvent (water)-rock interaction. Moreover, different from conventional sandstone and limestone, shale gas formations exhibited semi-permeable properties due to high clay content and unique pore structure, which result in the osmotic effect. This may explain the low amount of fracturing fluid flowback and the osmosis diffusion-enhanced imbibition could be a critical recovery mechanism from the low permeability rock.Hence, it is important to investigate the imbibition behavior in the fracture network of stimulated reservoir volume which created by hydraulic fracturing. In this study, shale samples from Horn River shale gas formation were used to conduct spontaneous imbibition tests to study the effect of capillarity and osmosis diffusion. To simulate the process during hydraulic fracturing, the fluids with different salinities were used in the experiment.The experimental results showed that the clay content in shale samples determined how capillarity and osmosis diffusion influenced the imbibition process. The linear relationship between imbibition mass and square root of time was observed only in the lower clay content shale samples. The imbibition process in these samples was dominated only by capillarity. That relationship was used to predict the imbibition mass during the water flooding work. On the other hand, in the higher clay content shale samples, due to osmotic effect, the relationship between imbibition mass and square root of time was non-linear.The results of this study can help people understand the imbibition process of the fracturing fluid when fluid contacts with the shale rock during hydraulic fracturing. Adjusting the salinity of the fracturing fluid to change osmotic effect in the shale formation can be used to control fracturing fluid imbibition.

Numerical investigation of fracture-rock matrix ensemble saturation functions and their dependence on wettability

Quantification of multiphase flow in fractured permeable rocks is vital for hydrocarbon recovery, gas storage, and water resource management. Where fractures provide the permeability and the rock matrix provides the storage for oil and gas, fracture-matrix transfer has a decisive impact on recovery and capillary-driven transfer. However, while most modelling efforts assume a constant fracture aperture and fracture capillary pressure, in reality, fracture aperture and capillary pressure, pcf vary among fractures. Here we contrast and compare relative permeability curves obtained from constant aperture or constant capillary pressure, discrete fracture and matrix (DFM) models with more realistic ones taking variations into account. These models are constructed from line drawings of pervasively fractured layered rock mapped in meter-to kilometer-scale outcrops. Fracture aperture is obtained by mechanical modelling. Capillary pressure is computed from fracture aperture taking into account the wettability of the rock matrix.An unsteady state approach is applied to the analysis of fracture-matrix ensemble relative permeability and ultimate recovery. Imbibition simulations are performed with the Finite Element-Centered Finite Volume Method (FECFVM). Globally flow-based upscaling is used to establish ensemble relative permeability curves between capillary and viscous limits.The obtained fracture-matrix ensemble relative permeability curves show that ultimate recovery is 2–3 times higher in the water-wet than in the oil-wet case. With increasing wetting angle, counter-current-imbibition (CCI) rate decreases because the capillary pressure difference between small fractures that contribute the most to the fracture-matrix transfer area is very small. As the rock becomes oil wet, ensemble relative permeability curves steepen and matrix imbibition proceeds only over a very narrow saturation range.

Numerical Investigation of Coupling Multiphase Flow and Geomechanical Effects on Water Loss During Hydraulic-Fracturing Flowback Operation

SummaryLess than half the fracturing fluid is typically recovered during the flowback operation. This study models the effects of capillarity and geomechanics on water loss in the fracture/matrix system, and investigates the circumstances under which this phenomenon might be beneficial or detrimental to subsequent tight-oil production. During the shut-in (soaking) and flowback periods, the fracture conductivity decreases as effective stress increases because of imbibition. Previous works have addressed fracture closure during the production phase; however, the coupling of imbibition caused by multiphase flow and stress-dependent fracture properties during shut-in is less understood.A series of mechanistic simulation models is constructed to simulate multiphase flow and fluid distribution during shut-in and flowback. Three systems—matrix, hydraulic fracture, and microfractures—are explicitly represented in the computational domain. Sensitivities to wettability and multiphase-flow functions (relative permeability and capillary pressure relationships) are investigated. As wettability to water increases, matrix imbibition increases. Imbibition helps to displace the hydrocarbons into nearby microfractures and hydraulic fractures, enhancing initial oil rate, but it also hinders water recovery. The results indicate that fracture closure may enhance imbibition and water loss, which, in turn, leads to further reduction in fracture pressure and conductivity. Results also suggest that more-aggressive flowback is beneficial to water cleanup and long-term oil production in stiff rocks, whereas this benefit is less prominent in medium-to-soft formations because of excessive fracture closure. Because no direct correlation between high initial oil-flow rate and improved cumulative oil production is observed, measures for increasing oil relative permeability are recommended for improving long-term oil production.This work presents a quantitative study of the controlling factors of water loss caused by fluid/rock properties and geomechanics. The results highlight the crucial interplay between imbibition and geomechanics in short- and long-term production performances. The results in this study would have considerable impact on understanding and improving current industry practice in fracturing design and assessment of stimulated reservoir volume.

Experimental investigation of shale imbibition capacity and the factors influencing loss of hydraulic fracturing fluids

Spontaneous imbibition of water-based fracturing fluids into the shale matrix is considered to be the main mechanism responsible for the high volume of water loss during the flowback period. Understanding the matrix imbibition capacity and rate helps to determine the fracturing fluid volume, optimize the flowback design, and to analyze the influences on the production of shale gas. Imbibition experiments were conducted on shale samples from the Sichuan Basin, and some tight sandstone samples from the Ordos Basin. Tight volcanic samples from the Songliao Basin were also investigated for comparison. The effects of porosity, clay minerals, surfactants, and KCl solutions on the matrix imbibition capacity and rate were systematically investigated. The results show that the imbibition characteristic of tight rocks can be characterized by the imbibition curve shape, the imbibition capacity, the imbibition rate, and the diffusion rate. The driving forces of water imbibition are the capillary pressure and the clay absorption force. For the tight rocks with low clay contents, the imbibition capacity and rate are positively correlated with the porosity. For tight rocks with high clay content, the type and content of clay minerals are the most important factors affecting the imbibition capacity. The imbibed water volume normalized by the porosity increases with an increasing total clay content. Smectite and illite/smectite tend to greatly enhance the water imbibition capacity. Furthermore, clay-rich tight rocks can imbibe a volume of water greater than their measured pore volume. The average ratio of the imbibed water volume to the pore volume is approximately 1.1 in the Niutitang shale, 1.9 in the Lujiaping shale, 2.8 in the Longmaxi shale, and 4.0 in the Yingcheng volcanic rock, and this ratio can be regarded as a parameter that indicates the influence of clay. In addition, surfactants can change the imbibition capacity due to alteration of the capillary pressure and wettability. A 10 wt% KCl solution can inhibit clay absorption to reduce the imbibition capacity.

A Model for Spontaneous Imbibition as a Mechanism for Oil Recovery in Fractured Reservoirs

The flow of oil and water in naturally fractured reservoirs (NFR) can be highly complex and a simplified model is presented to illustrate some main features of this flow system. NFRs typically consist of low-permeable matrix rock containing a high-permeable fracture network. The effect of this network is that the advective flow bypasses the main portions of the reservoir where the oil is contained. Instead capillary forces and gravity forces are important for recovering the oil from these sections. We consider a linear fracture which is symmetrically surrounded by porous matrix. Advective flow occurs only along the fracture, while capillary driven flow occurs only along the axis of the matrix normal to the fracture. For a given set of relative permeability and capillary pressure curves, the behavior of the system is completely determined by the choice of two dimensionless parameters: (i) the ratio of time scales for advective flow in fracture to capillary flow in matrix $$\alpha =\tau ^f/\tau ^m$$ ; (ii) the ratio of pore volumes in matrix and fracture $$\beta =V^m/V^f$$ . A characteristic property of the flow in the coupled fracture–matrix medium is the linear recovery curve (before water breakthrough) which has been referred to as the “filling fracture” regime Rangel-German and Kovscek (J Pet Sci Eng 36:45–60, 2002), followed by a nonlinear period, referred to as the “instantly filled” regime, where the rate is approximately linear with the square root of time. We derive an analytical solution for the limiting case where the time scale $$\tau ^{m}$$ of the matrix imbibition becomes small relative to the time scale $$\tau ^{f}$$ of the fracture flow (i.e., $$\alpha \rightarrow \infty $$ ), and verify by numerical experiments that the model will converge to this limit as $$\alpha $$ becomes large. The model provides insight into the role played by parameters like saturation functions, injection rate, volume of fractures versus volume of matrix, different viscosity relations, and strength of capillary forces versus injection rate. Especially, a scaling number $$\omega $$ is suggested that seems to incorporate variations in these parameters. An interesting observation is that at $$\omega =1$$ there is little to gain in efficiency by reducing the injection rate. The model can be used as a tool for interpretation of laboratory experiments involving fracture–matrix flow as well as a tool for testing different transfer functions that have been suggested to use in reservoir simulators.

Simulation of multiphase flow in fractured reservoirs using a fracture-only model with transfer functions

We present a fracture-only reservoir simulator for multiphase flow: the fracture geometry is modeled explicitly, while fluid movement between fracture and matrix is accommodated using empirical transfer functions. This is a hybrid between discrete fracture discrete matrix modeling where both the fracture and matrix are gridded and dual-porosity or dual-permeability simulation where both fracture and matrix continua are upscaled. The advantage of this approach is that the complex fracture geometry that controls the main flow paths is retained. The use of transfer functions, however, simplifies meshing and makes the simulation method considerably more efficient than discrete fracture discrete matrix models. The transfer functions accommodate capillary- and gravity-mediated flow between fracture and matrix and have been shown to be accurate for simple fracture geometries, capturing both the early- and late-time average behavior. We verify our simulator by comparing its predictions with simulation results where the fracture and matrix are explicitly modeled. We then show the utility of the approach by simulating multiphase flow in a geologically realistic fracture network. Waterflooding runs reveal the fraction of the fracture–matrix interface area that is infiltrated by water so that matrix imbibition can occur. The evolving fraction of the fracture–matrix interface area turns out to be an important characteristic of any particular fracture system to be used as a scaling parameter for capillary driven fracture–matrix transfer.