Computed-Tomography-Scan Monitoring of Foam-Based Chemical-Enhanced-Oil-Recovery Processes in Fractured Carbonate Cores

SPE Journal ◽  
2017 ◽  
Vol 22 (03) ◽  
pp. 912-923 ◽  
Author(s):  
B.. Bourbiaux ◽  
E.. Rosenberg ◽  
M.. Robin ◽  
M.. Chabert ◽  
E.. Chevallier ◽  
...  
Keyword(s):  
Computed Tomography ◽  
Pressure Gradient ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Carbonate Reservoirs ◽  
Ct Scanner ◽  
Chemical Additives ◽  
Foaming Agents ◽  
Fractured Carbonate ◽  
The Matrix

Summary Waterflooding is often inefficient in carbonate reservoirs because of the presence of fractures and unfavorable wettability. Oil recovery can be improved by enhancing the following drive mechanisms: Capillary imbibition with wettability modifiers Viscous drive by increasing the pressure gradient in the fracture network Water/oil gravity drainage with low-interfacial-tension (IFT) surfactant formulations that also reduce oil trapping This paper presents an experimental approach that evaluates different chemical-enhanced-oil-recovery (EOR) alternatives on the basis of one or several of the three aforementioned recovery mechanisms. The experiments consist of injecting an aqueous chemical solution or a foam containing chemical additives into an artificially fractured carbonate core. The imbibition is monitored with a recent computed-tomography (CT) scanner allowing the local quantitative monitoring of three phases, including accurate quantification of matrix oil recovery. This paper is mainly focused on the impacts of foaming agents and wettability modifiers (WMs), implemented separately or jointly. The experiments have been conducted on several cores of different permeability, resulting in various permeability contrasts between matrix and fracture. A major result concerns the kinetics of oil recovery by chemical additives that is greatly increased when a viscous drive is applied across the matrix medium by means of the circulation of foam in the fracture. Experiments in fractured cores of different permeabilities indicate that foam does not penetrate the matrix, but drives the chemical aqueous phase into the matrix because of the generated pressure gradient. Detailed analysis of oil-mobilization dynamics is provided. These foam-flow experiments are compared with a former chemical imbibition test on a nonfractured core for further insight into the role played by viscous forces. The comparison of tested recovery scenarios leads to conclusions regarding optimal chemical-EOR strategies for naturally fractured carbonate reservoirs with poor secondary-recovery prognosis.

Flow Physics of Polymer Nanospheres and Diluted Microemulsion in Fractured Carbonate Reservoirs: An Investigation into Enhanced Oil Recovery Mechanisms

SPE Journal ◽  
2021 ◽  
pp. 1-14
Author(s):  
Hang Su ◽  
Fujian Zhou ◽  
Qing Wang ◽  
Fuwei Yu ◽  
Rencheng Dong ◽  
...  
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Recovery Rate ◽  
Carbonate Reservoirs ◽  
Wettability Alteration ◽  
Naturally Fractured ◽  
Fractured Carbonate ◽  
Recovery Mechanisms ◽  
Polymer Nanospheres ◽  
Depth Propagation

Summary Enhanced oil recovery (EOR) in fractured carbonate reservoirs is challenging because of the heterogeneous and oil-wet nature. In this work, a new application of using polymer nanospheres (PNSs) and diluted microemulsion (DME) is presented to plug fractures and enhance water imbibition to recover oil from the tight, naturally fractured carbonate reservoirs. DME with different electric charges is compared through contact-angle and core-imbibition tests to evaluate their performances on EOR. The cationic DME is chosen because it has the fastest wettability-alteration rate and thus the highest oil recovery rate. Migration and plugging efficiency tests are conducted to identify the screened particle sizes of PNSs for the target reservoir cores. PNSs with a particle size of 300 nm are demonstrated to have the best performance of in-depth propagation before swelling and plugging after swelling within the naturally fractured cores are used in this study. Then coreflooding experiments are conducted to evaluate the EOR performance when PNSs and DME are used together, and results indicate that the oil recovery rate is increased by 24.3 and 44.1% compared to using PNSs or DME alone. In the end, a microfluidic experiment is carried out to reveal how DME works with PNSs.

An Experimental Study of Wetting Behavior and Surfactant EOR in Carbonates With Model Compounds

SPE Journal ◽  
2008 ◽  
Vol 13 (01) ◽  
pp. 26-34 ◽  
Author(s):  
Yongfu Wu ◽  
Patrick J. Shuler ◽  
Mario Blanco ◽  
Yongchun Tang ◽  
William A. Goddard
Keyword(s):  
Oil Recovery ◽  
Anionic Surfactants ◽  
Fractured Reservoirs ◽  
Naphthenic Acids ◽  
Carbonate Reservoirs ◽  
Reservoir Rock ◽  
Intermediate Water ◽  
Wetting Behavior ◽  
Fractured Carbonate ◽  
The Matrix

Summary This study focuses on the mechanisms responsible for enhanced oil recovery (EOR) from fractured carbonate reservoirs by surfactant solutions, and methods to screen for effective chemical formulations quickly. One key to this EOR process is the surfactant solution reversing the wettability of the carbonate surfaces from less water-wet to more water-wet conditions. This effect allows the aqueous phase to imbibe into the matrix spontaneously and expel oil bypassed by a waterflood. This study used different naphthenic acids (NA) dissolved in decane as a model oil to render calcite surfaces less water-wet. Because pure compounds are used, trends in wetting behavior can be related to NA molecular structure as measured by solid adsorption; contact angle; and a novel, simple flotation test with calcite powder. Experiments with different surfactants and NA-treated calcite powder provide information about mechanisms responsible for sought-after reversal to a more water-wet state. Results indicate this flotation test is a useful rapid screening tool to identify better EOR surfactants for carbonates. The study considers the application of surfactants for EOR from carbonate reservoirs. This technology provides a new opportunity for EOR, especially for fractured carbonate, where waterflood response typically is poor and the matrix is a high oil-saturation target. Introduction Typically only approximately a third of the original oil in place (OOIP) is recovered by primary and secondary recovery processes, leaving two-thirds trapped in reservoirs as residual oil. Approximately half of world's discovered oil reserves are in carbonate reservoirs and many of these reservoirs are naturally fractured (Roehl and Choquette 1985). According to a recent review of 100 fractured reservoirs (Allan and Sun 2003), carbonate fractured reservoirs with high matrix porosity and low matrix permeability especially could use EOR processes. The oil recovery from these reservoirs is typically very low by conventional waterflooding, due in part to fractured carbonate reservoirs (about 80%) being originally less water-wet. Injected water will not penetrate easily into a less water-wetting porous matrix and so cannot displace that oil in place. Wettability of carbonate reservoirs has been widely recognized an important parameter in oil recovery by flooding technology (Tong et al. 2002; Morrow and Mason 2001; Zhou et al. 2000; Hirasaki and Zhang 2004). Because altering the wettability of a rock surface to preferentially more water-wet conditions is critical to oil recovery, alteration of reservoir wettability by surfactants has been intensively studied, and many research papers have been published (Spinler and Baldwin 2000). Vijapurapu and Rao (2004) studied the capability of certain ethoxy alcohol surfactants to alter wettability of the Yates reservoir rock to water-wet conditions. Seethepali et al. (2004) reported that several anionic surfactants in the presence of Na2CO3 can change a calcite surface wetted by a West Texas crude oil to intermediate/water-wet conditions as well as, or even better than, an efficient cationic surfactant. Zhang et al. (2004) investigated also the effect of electrolyte concentration, surfactant concentration, and water/oil ratio on wettability alteration. They reported that wettability of calcite surface can be altered to approximately intermediate water-wet to preferentially water-wet conditions with alkaline/anionic surfactant systems. Adsorption of anionic surfactants on a dolomite surface can be significantly reduced in the presence of sodium carbonate.

Aqueous Solution of Ketone Solvent for Enhanced Water Imbibition in Fractured Carbonate Reservoirs

SPE Journal ◽  
2020 ◽  
Vol 25 (05) ◽  
pp. 2694-2709
Author(s):  
Mingyuan Wang ◽  
Gayan A. Abeykoon ◽  
Francisco J. Argüelles-Vivas ◽  
Ryosuke Okuno
Keyword(s):  
Oil Recovery ◽  
Material Balance ◽  
Wettability Alteration ◽  
Chemical Additives ◽  
Oil Displacement ◽  
Surrounding Matrix ◽  
Relative Contribution ◽  
Fractured Carbonate ◽  
The Matrix ◽  
Fractured Limestone

Summary This paper presents four dynamic imbibition experiments using fractured limestone cores with aqueous solutions of 3-pentanone and a nonionic surfactant. Results of the dynamic imbibition experiments were analyzed by the material balance for components: oil, brine, and chemical (3-pentanone or surfactant). The analysis resulted in a quantitative evaluation of the imbibed fraction of the injected components (brine and chemical additives) and the relative contribution of these components to the oil displacement in the matrix. Results show that 3-pentanone and surfactant both can enhance the imbibition of brine through wettability alteration; however, 3-pentanone is more efficient in transferring from a fracture to the surrounding matrix. The imbibed fraction was more than 57.0% for 3-pentanone, and only 6.0% for surfactant at the end of the chemical-slug stage. During injection of the 3-pentanone solution, brine and 3-pentanone both displaced oil from the matrix pore volume (PV). Results of the material-balance analysis suggest that an optimal process with an aqueous wettability modifier will have a large imbibed fraction to rapidly enhance the oil displacement by brine in the matrix. Such a process will benefit from chase brine and soaking (or shut-in) so that the oil recovery can be maximized for a small amount of chemical injection.

Characterization of Matrix Wettability and Mass Transfer From Matrix to Fractures in Carbonate Reservoirs

2012 ◽  
Author(s):  
Anuj Gupta
Keyword(s):  
Oil Recovery ◽  
History Matching ◽  
Oil And Gas ◽  
Fractured Reservoirs ◽  
Naturally Fractured Reservoirs ◽  
Carbonate Reservoirs ◽  
Shape Factors ◽  
Naturally Fractured ◽  
Fractured Carbonate ◽  
The Matrix

This paper presents results of an experimental investigation, supported by numerical analysis, to characterize oil recovery from fractured carbonate reservoirs. Imbibition recovery of oil is measured as a function of time for samples with varying wettability and shape factors. One of the objectives of this study is to verify the validity of exponential transfer function for matrix-fracture systems with varying wettability and flow-boundary conditions. Another objective is to establish the possibility of quantitatively determining the wettability of a sample based on history-matching of cumulative imbibition recovery and recovery rate data. The productivity of most carbonate oil and gas reservoirs is closely tied to the natural or stimulated fracture system present in the reservoir. Further, the recovery from naturally fractured reservoirs, in presence of aquifer drive or waterflooding is closely tied to the wettability of the matrix. The approach presented in this paper offers means to evaluate how recovery factor in a fractured system can be affected by wettability. A detailed understanding of rock-fluid interactions and wettability alterations at the fracturing face should help design improved strategies for exploiting naturally fractured carbonate reservoirs.

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