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.

A Novel Coreflood Test to Evaluate EOR Potential of Wettability-Altering Surfactants in Oil-Wet Heterogeneous Carbonate Reservoirs

2021 ◽  
Author(s):  
Yue Shi ◽  
Kishore Mohanty ◽  
Manmath Panda
Keyword(s):  
Oil Recovery ◽  
Carbonate Reservoirs ◽  
Wettability Alteration ◽  
Low Permeability ◽  
High Permeability ◽  
Matrix Permeability ◽  
Rock Heterogeneity ◽  
The Matrix ◽  
Flow Through ◽  
Main Factors

Abstract Oil-wetness and heterogeneity (i.e., existence of low and high permeability regions) are two main factors that result in low oil recovery by waterflood in carbonate reservoirs. The injected water is likely to flow through high permeability regions and bypass the oil in low permeability matrix. In this study, systematic coreflood tests were carried out in both "homogeneous" cores and "heterogeneous" cores. The heterogeneous coreflood test was proposed to model the heterogeneity of carbonate reservoirs, bypassing in low-permeability matrix during waterfloods, and dynamic imbibition of surfactant into the low-permeability matrix. The results of homogeneous coreflood tests showed that both secondary-waterflood and secondary-surfactant flood can achieve high oil recovery (>50%) from relatively homogenous cores. A shut-in phase after the surfactant injection resulted in an additional oil recovery, which suggests enough time should be allowed while using surfactants for wettability alteration. The core with a higher extent of heterogeneity produced lower oil recovery to waterflood in the coreflood tests. Final oil recovery from the matrix depends on matrix permeability as well as the rock heterogeneity. The results of heterogeneous coreflood tests showed that a slow surfactant injection (dynamic imbibition) can significantly improve the oil recovery if the oil-wet reservoir is not well-swept.

Exploring Low-IFT Foam EOR in Fractured Carbonates: Success and Particular Challenges of Sub-10-md Limestone

SPE Journal ◽  
1900 ◽  
Vol 25 (02) ◽  
pp. 867-882
Author(s):  
Pengfei Dong ◽  
Maura Puerto ◽  
Guoqing Jian ◽  
Kun Ma ◽  
Khalid Mateen ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Surfactant Solution ◽  
Mineral Dissolution ◽  
Mobility Control ◽  
Matrix Permeability ◽  
Geochemical Properties ◽  
Remaining Oil ◽  
The Matrix ◽  
Incremental Oil Recovery ◽  
Foam Flooding

Summary The high formation heterogeneity in naturally fractured limestone reservoirs requires mobility control agents to improve sweep efficiency and boost oil recovery. However, typical mobility control agents, such as polymers and gels, are impractical in tight sub-10-md formations due to potential plugging issues. The objective of this study is to demonstrate the feasibility of a low-interfacial-tension (low-IFT) foam process in fractured low-permeability limestone reservoirs and to investigate relevant geochemical interactions. The low-IFT foam process was investigated through coreflood experiments in homogeneous and fractured oil-wet cores with sub-10-md matrix permeability. The performance of a low-IFT foaming formulation and a well-known standard foamer [alpha olefin sulfonate (AOS) C14-16] were compared in terms of the efficiency of oil recovery. The effluent ionic concentrations were measured to understand how the geochemical properties of limestone influenced the low-IFT foam process. Aqueous stability and phase behavior tests with crushed core materials and brines containing various divalent ion concentrations were conducted to interpret the observations in the coreflood experiments. Low-IFT foam process can achieve significant incremental oil recovery in fractured oil-wet limestone reservoirs with sub-10-md matrix permeability. Low-IFT foam flooding in a fractured oil-wet limestone core with 5-md matrix permeability achieved 64% incremental oil recovery compared to waterflooding. In this process, because of the significantly lower capillary entry pressure for surfactant solution compared to gas, the foam primarily diverted surfactant solution from the fracture into the matrix. This selective diversion effect resulted in surfactant or weak foam flooding in the tight matrix and hence improved the invading fluid flow in the matrix. Meanwhile, the low-IFT property of the foaming formulation mobilized the remaining oil in the matrix. This oil mobilization effect of the low-IFT formulation achieved lower remaining oil saturation in the swept zones compared with the formulation lacking low-IFT property with oil. The limestone geochemical instability caused additional challenges for the low-IFT foam process in limestone reservoirs compared to dolomite reservoirs. The reactions of calcite with injected fluids—such as mineral dissolution and the exchange of calcium and magnesium—were found to increase the Ca2+ concentration in the produced fluids. Because the low-IFT foam process is sensitive to brine salinity, the additional Ca2+ may cause potential surfactant precipitation and unfavorable over-optimum conditions. It, therefore, may cause injectivity and phase-trapping issues especially in the homogeneous limestone. Results in this work demonstrated that despite the challenges associated with limestone dissolution, the low-IFT foam process can remarkably extend chemical enhanced oil recovery (EOR) in fractured oil-wet tight reservoirs with matrix permeability as low as 5 md.

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.

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.

Measurements of the Contact Angles for Various Fluids Which Are Widely Used in the Oilfields to Improve Oil Recovery

2018 ◽  
Author(s):  
M. Elsharafi ◽  
K. Vidal ◽  
R. Thomas
Keyword(s):  
Surface Tension ◽  
Contact Angle ◽  
Interfacial Tension ◽  
Oil Recovery ◽  
Dynamic Contact Angle ◽  
Dynamic Contact ◽  
Contact Angles ◽  
Rock Face ◽  
Angle Measurements ◽  
Contact Angle Measurements

Contact angle measurements are important to determine surface and interfacial tension between solids and fluids. A ‘water-wet’ condition on the rock face is necessary in order to extract oil. In this research, the objectives are to determine the wettability (water-wet or oil-wet), analyze how different brine concentrations will affect the wettability, and study the effect of the temperature on the dynamic contact angle measurements. This will be carried out by using the Cahn Dynamic Contact Angle. Analyzer DCA 315 to measure the contact angle between different fluids such as surfactant, alkaline, and mineral oil. This instrument is also used to measure the surface properties such as surface tension, contact angle, and interfacial tension of solid and liquid samples by using the Wilhelmy technique. The work used different surfactant and oil mixed with different alkaline concentrations. Varying alkaline concentrations from 20ml to 1ml were used, whilst keeping the surfactant concentration constant at 50ml.. It was observed that contact angle measurements and surface tension increase with increased alkaline concentrations. Therefore, we can deduce that they are directly proportional. We noticed that changing certain values on the software affected our results. It was found that after calculating the density and inputting it into the CAHN software, more accurate readings for the surface tension were obtained. We anticipate that the surfactant and alkaline can change the surface tension of the solid surface. In our research, surfactant is desirable as it maintains a high surface tension even when alkaline percentage is increased.

Bivariate Log-Normal Distribution of Stimulated Matrix Permeability and Block Size in Fractured Reservoirs: Proposing New Multilinear-Flow Regime for Transient-State Production

SPE Journal ◽  
2018 ◽  
Vol 23 (04) ◽  
pp. 1316-1342 ◽  
Author(s):  
Salam Al-Rbeawi
Keyword(s):  
Normal Distribution ◽  
Flow Regime ◽  
Fractured Reservoirs ◽  
Block Size ◽  
Analytical Models ◽  
Matrix Permeability ◽  
Matrix Block ◽  
The Matrix ◽  
Log Normal ◽  
Log Normal Distribution

Summary This paper investigates the impacts of varied stimulated matrix permeability and matrix-block size on pressure behaviors and flow regimes of hydraulically fractured reservoirs using bivariate log-normal distribution. The main objective is assembling the variance in these two parameters to the analytical models of pressure and pressure derivative considering different porous-media petrophysical properties, reservoir configurations, and hydraulic-fracture (HF) characteristics. The motivation is eliminating the long-run discretization treatment in the porous media required by applying analytical models to describe the variance in the previously discussed parameters with the distance between HFs. Several analytical models for pressure response were generated in this study for hydraulically fractured reservoirs with rectangular-shaped drainage areas. These models take into account the change in stimulated matrix permeability from the maximum value close to the HF face to the minimum value at the so-called no-flow boundary between fractures. They also consider the change in the matrix-block size, corresponding to the change in the induced-fracture density (number of fractures per foot of length), from the minimum value close to the fracture face to the maximum value at the no-flow boundary. Bivariate log-normal distribution was used to describe the change in the stimulated matrix permeability and matrix-block size. The formations of interest are composed of stimulated reservoir volume (SRV), where the matrix is stimulated by the fracturing process, and unstimulated reservoir volume (USRV), where the stimulation process does not affect the matrix. The outcomes of this study can be summarized as Generating new analytical models for pressure and pressure derivative in hydraulically fractured reservoirs that consider the change in stimulated matrix-block size and permeability using bivariate log-normal distribution Understanding the effect of using the probability-density function (PDF) of matrix-block size and permeability in the pressure distribution of different reservoirs Observing the new multilinear-flow regime that develops at intermediate production time and represents several simultaneous linear-flow regimes inside HFs, SRV, and USRV Developing analytical models for the new multilinear-flow regime Studying the effects of petrophysical properties of HFs, induced fractures, and matrix as well as reservoir size and configuration on pressure behavior The most interesting points in this study are The applicability of bivariate log-normal distribution for describing the variance and nonuniform distribution of matrix-block size and permeability. The large variance in the matrix-block size and permeability causes significant decrease in wellbore-pressure drop. Small value of standard deviation of matrix-block size and permeability indicates the possibilities for significant decrease in wellbore pressure drop. The means of matrix-block size and permeability may not have significant effects on reservoir-pressure distribution. The new multilinear-flow regime is characterized by a one-eighth slope on the pressure-derivative curve and is seen always after HF linear flow and before boundary-dominated flow regime. Multilinear-flow regime develops to bilinear-flow regime with a one-quarter slope for uniform distribution of equal matrix-block size and permeability.

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.

Experimental and Numerical Analysis of In-Situ Combustion in a Fractured Core

SPE Journal ◽  
2011 ◽  
Vol 16 (02) ◽  
pp. 358-373 ◽  
Author(s):  
H.. Fadaei ◽  
L.. Castanier ◽  
A.M.. M. Kamp ◽  
G.. Debenest ◽  
M.. Quintard ◽  
...  
Keyword(s):  
Combustion Front ◽  
Fractured Reservoirs ◽  
Experimental Studies ◽  
Steam Injection ◽  
Combustion Tube ◽  
Fractured Reservoir ◽  
In Situ Combustion ◽  
Matrix Permeability ◽  
The Matrix

Summary Approximately one-third of global heavy-oil resources can be found in fractured reservoirs. In spite of its strategic importance, recovery of heavy crudes from fractured reservoirs has found few applications because of the complexity of such reservoirs. In-situ combustion (ISC) is a candidate process for such reservoirs, especially for those where steam injection is not feasible. Experimental studies reported in the literature on this topic mentioned a cone-shaped combustion front, indicating that the process was governed by diffusion of oxygen into the matrix. The main oil-production mechanisms were found to be thermal expansion of oil and evaporation of light components (Schulte and de Vries 1985; Greaves et al. 1991). In order to confirm these results, we carried out reservoir-simulation studies presented in Fadaei et al. (2010). We have shown that the front has the shape of a cone, and we have performed a combustion/extinction analysis representing the results in a diagram of cumulative production vs. diffusion coefficient and matrix permeability. Before obtaining quantitative and qualitative comparisons, we need to characterize the systems we want to study. Therefore, we also carried out laboratory experiments using kinetic cells and combustion tubes. The kinetic-cell studies showed that the presence of carbonates has a significant effect on combustion kinetics. Our combustion-tube studies confirmed the previously observed coneshaped front. Previous studies reported in literature used heating elements along the combustion tube to regulate the temperature, which may have caused some undue heating of the core. To avoid that, we chose to use efficient insulation to minimize heat losses. Combustion advanced faster in nonconsolidated matrix, in which the permeability was higher than in consolidated matrix. The results showed that the presence of severe heterogeneities may prevent the combustion front from propagating. Several runs were performed for different air-injection rates and pressures and for different permeability contrasts between the matrix and the fracture. The next step of our work is the upscaling of ISC in the fractured reservoir at interwell scale on the basis of knowledge provided by simulation and experimental studies.

scholarly journals Experimental study of microbial enhanced oil recovery in oil-wet fractured porous media

2020 ◽  
Vol 75 ◽  
pp. 73
Author(s):  
Amin Abolhasanzadeh ◽  
Ali Reza Khaz’ali ◽  
Rohallah Hashemi ◽  
Mohammadhadi Jazini
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Low Cost ◽  
Fractured Reservoirs ◽  
Gas Production ◽  
Wettability Alteration ◽  
Oil Viscosity ◽  
Sweep Efficiency ◽  
The Matrix ◽  
Microbial Flooding

Without Enhanced Oil Recovery (EOR) operations, the final recovery factor of most hydrocarbon reservoirs would be limited. However, EOR can be an expensive task, especially for methods involving gas injection. On the other hand, aqueous injection in fractured reservoirs with small oil-wet or mixed-wet matrices will not be beneficial if the rock wettability is not changed effectively. In the current research, an unpracticed fabrication method was implemented to build natively oil-wet, fractured micromodels. Then, the efficiency of microbial flooding in the micromodels, as a low-cost EOR method, is investigated using a new-found bacteria, Bacillus persicus. Bacillus persicus improves the sweep efficiency via reduction of water/oil IFT and oil viscosity, in-situ gas production, and wettability alteration mechanisms. In our experiments, the microbial flooding technique extracted 65% of matrix oil, while no oil was produced from the matrix system by water or surfactant flooding.

Modeling Contact Angle vs. Temperature for the Quartz-Water-Decane System

SPE Journal ◽  
2021 ◽  
pp. 1-13
Author(s):  
Timothy S. Duffy ◽  
Isaac K. Gamwo ◽  
Russell T. Johns ◽  
Serguei N. Lvov
Keyword(s):  
Contact Angle ◽  
Oil Recovery ◽  
Elevated Temperatures ◽  
Van Der Waals ◽  
Water System ◽  
Contact Angles ◽  
Ambient Conditions ◽  
Temperature Dependent ◽  
Acid Base ◽  
Ambient Temperatures

Summary Innovative approaches are needed to improve the efficiency of oil recovery technologies to meet the growing demands of fossil-fuel based energy consumption. Enhanced oil recovery (EOR) methods such as low-salinity waterflooding and chemically tuned waterflooding aim to optimize the reservoir’s wetting properties, detaching oil globules from rock surfaces and allowing easier oil flow through pore throats. This wetting behavior is commonly quantified by contact angle measurements of the rock-oil-brine interface, which have been thoroughly investigated and theorized for many systems at ambient temperatures and pressures. However, few studies exist for extending contact angle theories away from ambient conditions. In this paper, we model the contact angles of a quartz-water-decane system at elevated temperatures using the surface tension component (STC) approach. Temperature-dependent van der Waals [Lifshitz-van der Waals (LW)] interactions and hydrogen-bonding (acid-base) interactions were calculated and are incorporated into the model for the quartz-water-decane interface. The Hough and White procedure was used to create temperature-dependent dielectric functions of quartz, water, and normal decane for calculations of Hamaker coefficients. Hamaker coefficients calculated this way are highly linear with temperature and agree well with Israelachvili’s approximation. The acid-base interactions likely contribute the most to system wettability changes. Resulting contact angles of the quartz-water-decane system shift from water-wet (16°) to slightly water-wet (57.4°) as temperature increases. The model was also successfully verified for the quartz-air-water system. Our results can be used in future studies to determine optimal injected water compositions for specific rock-oil-brine and other systems with consideration of reservoir temperature.

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