Enhancing Hydrocarbon Permeability After Hydraulic Fracturing: Laboratory Evaluations of Shut-Ins and Surfactant Additives

SPE Journal ◽  
2017 ◽  
Vol 22 (04) ◽  
pp. 1011-1023 ◽  
Author(s):  
Tianbo Liang ◽  
Rafael A. Longoria ◽  
Jun Lu ◽  
Quoc P. Nguyen ◽  
David A. DiCarlo
Keyword(s):  
Experimental Investigation ◽  
Oil Recovery ◽  
Fractured Reservoirs ◽  
Fluid Loss ◽  
Permeability Reduction ◽  
Fracturing Fluid ◽  
Hydrocarbon Production ◽  
The Matrix ◽  
Reservoir Conditions ◽  
Tight Reservoirs

Summary Fracturing-fluid loss into the formation can potentially damage hydrocarbon production in shale or other tight reservoirs. Well shut-ins are commonly used in the field to dissipate the lost water into the matrix near fracture faces. Borrowing from ideas in chemical enhanced oil recovery (CEOR), surfactants have potential to reduce the effect of fracturing-fluid loss on hydrocarbon permeability in the matrix. Unconventional tight reservoirs can differ significantly from one another, which could make the use of these techniques effective in some cases but not in others. We present an experimental investigation dependent on a coreflood sequence that simulates fluid invasion, flowback, and hydrocarbon production from hydraulically fractured reservoirs. We compare the benefits of shut-ins and reduction in interfacial tension (IFT) by surfactants for hydrocarbon permeability for different initial reservoir conditions (IRCs). From this work, we identify the mechanism responsible for the permeability reduction in the matrix, and we suggest criteria that can be used to optimize fracturing-fluid additives and/or manage flowback operations to enhance hydrocarbon production from unconventional tight reservoirs.

Water Blocks in Tight Formations: The Role of Matrix/Fracture Interaction in Hydrocarbon-Permeability Reduction and Its Implications in the Use of Enhanced Oil Recovery Techniques

SPE Journal ◽  
2017 ◽  
Vol 22 (05) ◽  
pp. 1393-1401 ◽  
Author(s):  
Rafael A. Longoria ◽  
Tianbo Liang ◽  
Uyen T. Huynh ◽  
Quoc P. Nguyen ◽  
David A. DiCarlo
Keyword(s):  
Oil Recovery ◽  
Effective Permeability ◽  
Permeability Reduction ◽  
Fracturing Fluid ◽  
Experimental Artifact ◽  
Recovery Techniques ◽  
The Matrix ◽  
Tight Formations ◽  
Fracture Interaction

Summary Hydraulic fracturing is used to obtain economical rates from tight and unconventional formations by increasing the surface area of the reservoir within the flowing distance to a high-conductivity pathway. However, a significant fraction of the fracturing fluid is never recovered, and thus may reduce the hydrocarbon permeability near the fracture. Here, we experimentally mimic the water-invasion process during fracturing, and measure the effective permeability changes in a low-permeability core. Measurements of water flowback and effective permeability as a function of interfacial tension (IFT), flow rate, and shut-in time suggest that water is being held at the fracture face because of the capillary discontinuity (i.e., when the water leaves the matrix and enters a space with minimal capillary pressure). This effect arises from the capillary interaction between the matrix and the fracture, and is akin to the capillary end effect in coreflood experiments. The results show that this effect, although only a laboratory experimental artifact for conventional reservoirs, can be a significant source of effective hydrocarbon-permeability reduction by fracturing-fluid invasion into the formation in unconventional and tight reservoirs.

Low-IFT Foaming System for Enhanced Oil Recovery in Highly Heterogeneous/Fractured Oil-Wet Carbonate Reservoirs

SPE Journal ◽  
2018 ◽  
Vol 23 (06) ◽  
pp. 2243-2259 ◽  
Author(s):  
Pengfei Dong ◽  
Maura Puerto ◽  
Guoqing Jian ◽  
Kun Ma ◽  
Khalid Mateen ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Fractured Reservoirs ◽  
Surfactant Solution ◽  
Capillary Forces ◽  
Mobility Control ◽  
Carbonate Reservoirs ◽  
Residual Oil ◽  
High Permeability ◽  
The Matrix ◽  
Foam Flooding

Summary Oil recovery in heterogeneous carbonate reservoirs is typically inefficient because of the presence of high-permeability fracture networks and unfavorable capillary forces within the oil-wet matrix. Foam, as a mobility-control agent, has been proposed to mitigate the effect of reservoir heterogeneity by diverting injected fluids from the high-permeability fractured zones into the low-permeability unswept rock matrix, hence improving the sweep efficiency. This paper describes the use of a low-interfacial-tension (low-IFT) foaming formulation to improve oil recovery in highly heterogeneous/fractured oil-wet carbonate reservoirs. This formulation provides both mobility control and oil/water IFT reduction to overcome the unfavorable capillary forces preventing invading fluids from entering an oil-filled matrix. Thus, as expected, the combination of mobility control and low-IFT significantly improves oil recovery compared with either foam or surfactant flooding. A three-component surfactant formulation was tailored using phase-behavior tests with seawater and crude oil from a targeted reservoir. The optimized formulation simultaneously can generate IFT of 10−2 mN/m and strong foam in porous media when oil is present. Foam flooding was investigated in a representative fractured core system, in which a well-defined fracture was created by splitting the core lengthwise and precisely controlling the fracture aperture by applying a specific confining pressure. The foam-flooding experiments reveal that, in an oil-wet fractured Edward Brown dolomite, our low-IFT foaming formulation recovers approximately 72% original oil in place (OOIP), whereas waterflooding recovers only less than 2% OOIP; moreover, the residual oil saturation in the matrix was lowered by more than 20% compared with a foaming formulation lacking a low-IFT property. Coreflood results also indicate that the low-IFT foam diverts primarily the aqueous surfactant solution into the matrix because of (1) mobility reduction caused by foam in the fracture, (2) significantly lower capillary entry pressure for surfactant solution compared with gas, and (3) increasing the water relative permeability in the matrix by decreasing the residual oil. The selective diversion effect of this low-IFT foaming system effectively recovers the trapped oil, which cannot be recovered with single surfactant or high-IFT foaming formulations applied to highly heterogeneous or fractured reservoirs.

Nuclear-Magnetic-Resonance Monitoring of Mass Exchange in a Low-Permeability Matrix/Fracture Model During CO2 Cyclic Injection: A Mechanistic Study

SPE Journal ◽  
2019 ◽  
Vol 25 (01) ◽  
pp. 440-450 ◽  
Author(s):  
Bing Wei ◽  
Ke Gao ◽  
Tao Song ◽  
Xiang Zhang ◽  
Wanfen Pu ◽  
...  
Keyword(s):  
Nuclear Magnetic Resonance ◽  
Magnetic Resonance ◽  
Oil Recovery ◽  
Mass Exchange ◽  
Fracture Model ◽  
Co2 Injection ◽  
The Matrix ◽  
Tight Reservoirs ◽  
Cyclic Injection ◽  
Nuclear Magnetic

Summary Recent reports have demonstrated that carbon dioxide (CO2) injection can further raise the oil recovery of fractured tight reservoirs after natural depletion, with major projects in progress worldwide. There is, however, a lack of understanding of the mass-exchange process between the matrix and fracture at pore scale. In this study, a matrix (0.8 md)/fracture model was designed to experimentally simulate a CO2-cyclic-injection process at 80°C and 35 MPa (Lucaogou tight formation). The oil (dead-oil) concentration in the matrix and fracture was continuously monitored online using a low-field nuclear-magnetic-resonance (NMR) technique aiming to quantify the oil recovery in situ and clarify the mass-exchange behaviors. The results showed that CO2 cyclic injection was promising in improving the oil recovery of fractured tight reservoirs. Nevertheless, the oil-recovery rates rapidly declined with the cycle of CO2 injection and the incremental oil was primarily produced by large pores with 100 ms > T2 > 3.0 ms. The NMR T2 profiles of the model evidenced the drainage of the matrix oil by CO2 toward the fracture. Because of the light-hydrocarbon extraction, the produced oils became lighter than the original oil. We noted that the main driving forces of the incremental oil recovery were CO2 displacement, CO2/oil interactions (mainly extraction and solubility), and pressure gradient (depressurization). In the first cycle, the CO2/oil interactions driven by CO2 diffusion during soaking enhanced the mass exchange between the matrix and the fracture. However, from the second cycle, CO2/oil interactions and CO2 displacement became insignificant. The results of this study supplement earlier findings and can provide insights into the CO2-enhanced-oil- recovery (EOR) mechanisms in fractured tight reservoirs. NOTE: Supporting information available.

Visualization and Analysis of Surfactant Imbibition Into Oil-Wet Fractured Cores

SPE Journal ◽  
2016 ◽  
Vol 21 (01) ◽  
pp. 101-111 ◽  
Author(s):  
Mohammad Mirzaei ◽  
David A. DiCarlo ◽  
Gary A. Pope
Keyword(s):  
Oil Recovery ◽  
Fractured Reservoirs ◽  
Surfactant Solution ◽  
Ct Scanning ◽  
Recovery Curves ◽  
The Core ◽  
The Matrix ◽  
Insight Into ◽  
Scaling Group ◽  
Better Than

Summary Imbibition of surfactant solution into the oil-wet matrix in fractured reservoirs is a complicated process that involves gravity, capillary, viscous, and diffusive forces. The standard experiment for testing imbibition of surfactant solution involves an imbibition cell, in which the core is placed in the surfactant solution and the recovery is measured vs. time. Although these experiments prove the effectiveness of surfactants, little insight into the physics of the problem is achieved. In this study, we performed water and surfactant flooding into oil-wet fractured cores and monitored the imbibition of the surfactant solution by use of computed-tomography (CT) scanning. From the CT images, the surfactant-imbibition dynamics as a function of height along the core was obtained. Although the waterflood only displaced oil from the fracture, the surfactant solution imbibed into the matrix; the imbibition is frontal, with the greatest imbibition rate at the bottom of the core, and the imbibition decreases roughly linearly with height. Experiments with cores of different sizes showed that increase in either the height or the diameter of the core causes decrease in imbibition and fractional oil-recovery rate. We also perform numerical simulations to model the observed imbibition. On the basis of the experimental measurements and numerical-simulation results, we propose a new scaling group that includes both the diameter and the height of the core. We show that the new scaling groups scale the recovery curves better than the traditional scaling group.

Use of Surfactant to Reduce CO2 Mobility in Oil Displacement

1980 ◽  
Vol 20 (04) ◽  
pp. 281-292 ◽  
Author(s):  
George C. Bernard ◽  
L.W. Holm ◽  
Craig P. Harvey
Keyword(s):  
Crude Oil ◽  
Oil Recovery ◽  
Permeability Reduction ◽  
Co2 Flooding ◽  
Emulsifying Properties ◽  
Residual Oil ◽  
Oil Displacement ◽  
Reservoir Conditions ◽  
Carbonate Cores ◽  
Flow Through

Abstract This paper presents results from a study designed to improve effectiveness of CO2 flooding by reducing CO2 mobility. In the course of reaching this objective we (1) screened surfactants for their ability to generate an effective and stable emulsion with CO2 under reservoir conditions, (2) determined the concentration range over which surfactants were effective, (3) examined chemical stability of the surfactants at reservoir conditions, (4) determined the extent to which emulsifying action alters gas and liquid mobilities in carbonate and sandstone cores, (5) determined that surfactant can enhance the production of residual oil from watered-out production of residual oil from watered-out carbonate cores by CO2, and (6) showed that the permeability reduction caused by surfactant can be permeability reduction caused by surfactant can be dissipated.At reservoir conditions required for miscible displacement, carbon dioxide exists in its critical state as a very dense fluid whose viscosity is about oneeighth that of crude oil. Generally, this unfavorable viscosity and mobility ratio produces inefficient oil displacement. This study shows that surfactant reduces CO2 mobility and should improve oil displacement by CO2, presumably by reducing flow through the most permeable zones, thus increasing areal and vertical sweep efficiencies.All three classes of surfactants (anionic, cationic, and nonionic) were found to be stable under conditions encountered during a CO2 flood in limestone formation; however, only a few surfactants had proper adsorption and emulsifying properties. proper adsorption and emulsifying properties. Surfactant generated foams or emulsions with CO2 at reservoir conditions (1,000 to 3,000 psi and 135 degrees F) dramatically reduced CO2 flow through sandstone and carbonate cores. Surfactant reduced the amount of CO2 used to recover a given volume of oil, especially from watered-out cores. The mechanism of tertiary oil production from linear cores appears to be limited to CO2 extraction. Approximately the same oil recovery was obtained either by continuous CO2 injection after a surfactant slug or by alternate slugs of CO2 and surfactant solution. It was found that oil recovery efficiency increased when surfactant was used with CO2 and that efficiency increased with flooding pressure.One anionic surfactant was found to be superior for this purpose. This surfactant emulsified CO2 well, was least adsorbed on carbonate rocks, and greatly reduced CO2 mobility in linear cores at concentrations of 0.1 to 1 %.The study indicates that effectiveness of CO2 miscible flooding can be increased by alternate injection of CO2 and aqueous surfactant slugs into the reservoir. Introduction The basic principles of CO2 flooding have been studied for the past 25 years by many investigators. Numerous laboratory studies have demonstrated that CO2, at elevated pressures, can recover oil unrecoverable by conventional methods and that super-critical CO2 develops multicontact miscibility with many crude oils, with a very efficient oil displacement, approaching 100% of the contacted oil. Generally, oil recoveries with CO2 have been much higher in the laboratory than in the field because field conditions are more severe for all oil recovery processes.A principal problem in CO2 flooding is the low viscosity of CO2 compared with that of crude oil. At reservoir conditions, CO2 viscosity is often 10 to 50 times lower than oil viscosity. At these unfavorable viscosity (mobility) ratios, CO2 has a great potential to channel through the oil. potential to channel through the oil. SPEJ P. 281

scholarly journals Geomechanical Response of Fractured Reservoirs

Fluids ◽  
2018 ◽  
Vol 3 (4) ◽  
pp. 70 ◽  
Author(s):  
Ahmad Zareidarmiyan ◽  
Hossein Salarirad ◽  
Victor Vilarrasa ◽  
Silvia De Simone ◽  
Sebastia Olivella
Keyword(s):  
Oil Recovery ◽  
Shear Failure ◽  
Numerical Models ◽  
Fractured Reservoirs ◽  
Fluid Pressure ◽  
Carbonate Reservoir ◽  
Improved Oil Recovery ◽  
Matrix Blocks ◽  
The Matrix ◽  
Pressure Changes

Geologic carbon storage will most likely be feasible only if carbon dioxide (CO2) is utilized for improved oil recovery (IOR). The majority of carbonate reservoirs that bear hydrocarbons are fractured. Thus, the geomechanical response of the reservoir and caprock to IOR operations is controlled by pre-existing fractures. However, given the complexity of including fractures in numerical models, they are usually neglected and incorporated into an equivalent porous media. In this paper, we perform fully coupled thermo-hydro-mechanical numerical simulations of fluid injection and production into a naturally fractured carbonate reservoir. Simulation results show that fluid pressure propagates through the fractures much faster than the reservoir matrix as a result of their permeability contrast. Nevertheless, pressure diffusion propagates through the matrix blocks within days, reaching equilibrium with the fluid pressure in the fractures. In contrast, the cooling front remains within the fractures because it advances much faster by advection through the fractures than by conduction towards the matrix blocks. Moreover, the total stresses change proportionally to pressure changes and inversely proportional to temperature changes, with the maximum change occurring in the longitudinal direction of the fracture and the minimum in the direction normal to it. We find that shear failure is more likely to occur in the fractures and reservoir matrix that undergo cooling than in the region that is only affected by pressure changes. We also find that stability changes in the caprock are small and its integrity is maintained. We conclude that explicitly including fractures into numerical models permits identifying fracture instability that may be otherwise neglected.

The Influence of Heterogeneity, Wetting, and Viscosity Ratio on Oil Recovery From Vertically Fractured Reservoirs

SPE Journal ◽  
2010 ◽  
Vol 16 (02) ◽  
pp. 411-428 ◽  
Author(s):  
Hamidreza Salimi ◽  
Johannes Bruining
Keyword(s):  
Contact Angle ◽  
Oil Recovery ◽  
Delay Time ◽  
Viscosity Ratio ◽  
Fractured Reservoirs ◽  
Contact Angles ◽  
Effective Length ◽  
Fracture Aperture ◽  
Matrix Permeability ◽  
The Matrix

Summary We use upscaling through homogenization to predict oil recovery from fractured reservoirs consisting of matrix columns, also called vertically fractured reservoirs (VFRs), for a variety of conditions. The upscaled VFR model overcomes limitations of the dual-porosity model, including the use of a shape factor. The purpose of this paper is to investigate three main physical aspects of multiphase flow in fractured reservoirs: reservoir wettability, viscosity ratio, and heterogeneity in rock/fluid properties. The main characteristic that determines reservoir behavior is the Péclet number that expresses the ratio of the average imbibition time divided by the residence time of the fluids in the fractures. The second characteristic dimensionless number is the gravity number. Upscaled VFR simulations, aimed at studying the mentioned features, add new insights. First, we discuss the results at low Péclet numbers. For only small gravity numbers, the effect of contact angle, delay time for the nonequilibrium capillary effect, the heterogeneity of the matrix-column size, and the matrix permeability can be ignored without appreciable loss of accuracy. The ultimate oil recovery for mixed-wet VFRs is approximately equal to the Amott index, and the oil production does not depend on the absolute value of the phase viscosity but on viscosity ratio. However, large gravity numbers enhance underriding, aggravated by large contact angles, longer delay times, and higher viscosity ratios. Layering can lead to an improvement or deterioration, depending on the fracture aperture and permeability distribution. At low Péclet numbers, the fractured reservoir behaves very similarly to a conventional reservoir and depends largely on the viscosity ratio and the gravity number. At high Péclet numbers, after water breakthrough, the oil recovery appears to be proportional to the cosine of the contact angle and inversely proportional to the sum of the oil and water viscosity. In addition, the mixed-wetting effect is more pronounced; there are significant influences of delay time (nonequilibrium effects), matrix permeability, matrix-column size, and the column-size distribution on oil recovery. At low gravity numbers and an effective length/thickness ratio larger than 10, the oil recovery is independent of the vertical-fracture-aperture distribution. For the same amount of injected water, the recovery at low Péclet numbers is larger than the recovery at high Péclet numbers.

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