Mobility control in carbon dioxide-enhanced oil recovery process using nanoparticle-stabilized foam for carbonate reservoirs

Accepted Manuscript Title: Mobility control in carbon dioxide-enhanced oil recovery process using nanoparticle-stabilized foam for carbonate reservoirs Author: Omeid Rahmani PII: DOI: Reference:

S0927-7757(18)30326-1 https://doi.org/10.1016/j.colsurfa.2018.04.050 COLSUA 22448

To appear in:

Colloids and Surfaces A: Physicochem. Eng. Aspects

Received date: Revised date: Accepted date:

5-2-2018 21-4-2018 23-4-2018

Please cite this article as: Rahmani O, Mobility control in carbon dioxideenhanced oil recovery process using nanoparticle-stabilized foam for carbonate reservoirs, Colloids and Surfaces A: Physicochemical and Engineering Aspects (2010), https://doi.org/10.1016/j.colsurfa.2018.04.050 This is a PDF file of an unedited manuscript that has been accepted for publication. As a service to our customers we are providing this early version of the manuscript. The manuscript will undergo copyediting, typesetting, and review of the resulting proof before it is published in its final form. Please note that during the production process errors may be discovered which could affect the content, and all legal disclaimers that apply to the journal pertain.

Mobility control in carbon dioxide-enhanced oil recovery process using nanoparticle-stabilized foam for carbonate reservoirs Omeid Rahmani a, b, * a

Department of Petroleum Engineering, Mahabad Branch, Islamic Azad University, Mahabad 59135-433, Iran Department of Natural Resources Engineering and Management, School of Science and

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b

Engineering, University of Kurdistan Hewlêr (UKH), Erbil, Kurdistan Region, Iraq

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*Corresponding Author

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E-mail: [email protected] and/or [email protected] .

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Graphical abstract

ABSTRACT Recent developments in the subject of using silica-nanoparticles (SiNPs) for stabilizing carbon dioxide (CO2)-foam have led to a renewed interest in the enhanced

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oil recovery (EOR) in oilfields. This study investigates the mobility control in the process of CO2 EOR through unfractured and fractured limestone cores. Toward this aim, laboratory tests were performed by co-injection of CO2 and 12 nm methyl-coated SiNPs solution to generate stable CO2 foam in the cores. In addition, sodium chloride (NaCl) and decane were used to examine the sensitivity of foam generation to salinity

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and to signify hydrocarbon (HC) phase in the experiments, respectively. The results revealed that SiNPs were able to generate stabilized CO2 foam in both unfractured and

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fractured limestone cores. A critical shear rate was established in the generation of

foam with different conditions in the core-flood experiments. The cores with lower matrix permeability had a lower value of critical shear rate for foam generation.

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Moreover, the magnitude of apparent viscosity was found to be a crucial factor for

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mobility control and to obtain an optimum quality of foam. The results indicated that

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increasing NaCl concentration to 3 wt.% causes a decrease in the value of critical shear

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rate at applied temperatures. Furthermore, the findings revealed that a real mobility

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control in CO2 EOR process can only be reached when the generated foam still

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interacts with HC in the reservoir.

KEYWORDS: Mobility control; Carbon dioxide; Nanoparticle; Enhanced oil

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recovery.

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1. INTRODUCTION

In recent years, both field applications and laboratory tests of foam flooding have shown a well-established mobility control notion in the enhanced oil recovery (EOR) process with positive prospects and effects [1], predominantly for the injection of carbon dioxide (CO2) into the reservoir [2-5]. Further, CO2 flooding has been widely

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used as an EOR technique [5-7], CO2 EOR has become even more attractive recently due to a way of utilizing the CO2 available through advance in CO2 sequestration process, a very substantial fraction of residual oil in reservoirs [8], and likely increasing crude oil price in the upcoming years. Miscible CO2 EOR can be very effective in the reservoir zones where CO2 is able to contact the residual oil. However,

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the actual recovery of oil from CO2 flooding is usually lower than expected due to poor

sweep efficiency [9,10] and the CO2 channeling problem (CCP). Although CO2

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flooding is proven to be domestically successful, improving its recovery efficiency

remains a challenge. The poor sweep efficiency is related to a high mobility ratio between CO2 and water. The problem is even more serious with the presence of natural

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fractures in the reservoir, which creates high permeability conduits for CO2 to bypass

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low permeability oil-bearing zones. The mobility ratio, which is the ratio between

𝑀𝑜𝑏𝑖𝑙𝑖𝑡𝑦 𝑜𝑓 𝑑𝑖𝑠𝑝𝑙𝑎𝑐𝑖𝑛𝑔 𝑓𝑙𝑢𝑖𝑑 (𝐶𝑂2 ) 𝑀𝑜𝑏𝑖𝑙𝑖𝑡𝑦 𝑜𝑓 𝑑𝑖𝑠𝑝𝑙𝑎𝑐𝑒𝑑 𝑓𝑙𝑢𝑖𝑑 (𝑜𝑖𝑙)

=

𝐾𝑟 𝐶𝑂2 /𝜇 𝐶𝑂2 𝐾𝑟 𝑜𝑖𝑙 /𝜇 𝑜𝑖𝑙

(1)

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𝑀𝑜𝑏𝑖𝑙𝑖𝑡𝑦 𝑟𝑎𝑡𝑖𝑜 =

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mobility of displacing fluid (i.e. CO2) and the displaced fluid (i.e. oil), is defined as:

where kr and µ are the relative matrix permeability (mD) and the viscosity (cP),

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respectively. At the reservoir condition, the 𝜇 𝐶𝑂2 ranges from ~0.05 to 0.1 cP, which is considerably lower than the 𝜇 𝑜𝑖𝑙 , resulting in an unfavorable mobility ratio much

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greater than 1. Reducing the mobility of CO2 would lower the mobility ratio and improve sweep efficiency [9,11]. On the other hand, the CCP stands as an operational

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problem in which the amount of CO2 recycling significantly increases after early CO2 breakthrough. The presence of foam in the reservoir decreases the mobility of CO2 phase [12,13] by increasing the resistance of gas to flow and mitigating the CCP [14]. Conventional foam, extensively used in the oil industry, is defined as a dispersion of gas in a continuous liquid phase where thin liquid films (called lamellae) separate the 3

gas flow paths [10,15]. The foam is produced and stabilized with surfactants, the amphiphilic molecules that have an affinity both to CO2 and water [16]. These surfactants lack the capability to provide enduring foam stability when the reservoir temperature or salinity is high. Recent studies have demonstrated the ability of nanoparticles (NPs) in stabilizing CO2 foam and improving the mobility ratio of CO2

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and oil as displacing and displaced fluids, respectively [10,17,18]. Nguyen et al. [4] demonstrated that NPs adsorb more energy at the interface between liquid and gas than

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the surfactants; therefore, they are a more stable agent for foam formation.

Furthermore, this process is most effective when the surface of NPs is modified to

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minimize their aggregation [19,20].

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So far, there has been little discussion about the behavior of nanoparticle-stabilized

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(NP-St) CO2 foam in the presence of oil [16,17,21]. While extensive studies have been

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carried out on the generation of foam with NPs in unconsolidated porous media [2225], no research has been conducted to test the ability of surface-modified SiNP to

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stabilize CO2 foam in consolidated rock such as limestone. To date, Aroonsri et al.’s study is one of the rare investigations that examined the conditions for forming the

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NP-St CO2 foam in unfractured and fractured sandstone cores. However, they do not

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take account of the experimental evidence to prove the CO2 foam stability while it could be determined through a half-life time as a crucial procedure [4,17]. Additionally, in their study, the core samples were considered vertically rather than

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horizontally in which the core-flood experiment will be more relevant to a real reservoir that is usually developed horizontally. Therefore, the main objectives of this study are to investigate the transmission and stability of SiNP-St CO2 foam in unfractured and fractured limestone cores to improve the mobility control and attain

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insight into the behavior of foam in the presence of hydrocarbon (HC) in the CO2 EOR process. 2. MATERIALS AND METHODS 2.1. Materials In order to investigate the ability of NPs to stabilize CO2 foam, two types of surface-

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modified silica nanoparticle (SiNP) coated by poly ethylene glycol (PEG) and methyl

were considered. In comparison, methyl-coated SiNP has an excessive stability for

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enduring of mobility control in CO2 EOR process [4,21]. Therefore, a 12 nm spherical methyl-coated SiNP received from Wacker Chemicals Korea Inc., with 0%, 50%, and

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75% coverage of dichlorodimethylsilane (C2H6SiCl2) in purity of 99.5% and specific

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surface area of 129 m2/g, was used in unfractured and fractured limestone core-flood

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experiments. The limestone samples were taken from an oilfield in the Zagros Basin,

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Iran. To prepare the NPs solution, they were dispersed in ethanol (C2H6O) to wet their surface during one day. The solution was then centrifuged to remove the ethanol

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[4,21]. Deionized (DI) water was also applied to dilute NPs dispersion to preferred concentration. Pressurized CO2, with a purity of 99.99% in cylinders equipped with a

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valve for gas and liquid withdrawals, was obtained from ATDM Gas. Sodium chloride

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(NaCl, Thermo Fisher Scientific) was added to the aqueous phase to maintain core permeability and to examine the sensitivity of foam generation to salinity. Decane (C10H22), with more than 99% purity from Thermo Fisher Scientific, was utilized to

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signify HC phase in oil recovery experiments with CO2 foam. 2.2. Experimental Apparatus A schematic of the apparatus used for the generation of foam is shown in Figure 1. A core holder, manufactured by Core Lab’s Reservoir Optimization, was used in the core-flood experiments to handle a 3-cm diameter core sample, with a length up to 30 5

cm. The core was sealed by a silicone rubber sleeve to prevent flow along its outer surface. To establish a seal around the core, a hydraulic lightweight hand pump (Enerpac P-141, 327 cm3, 2.4 kg) was applied to inject hydraulic oil into the annulus between the core holder and the rubber sleeves, providing a confining pressure that could be read off the installed pressure gauge. Teledyne ISCO 500D syringe pump,

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with maximum capacity of 500 ml and working pressure of 3750 psi, was used to inject

brine (with different concentration from 1 to 3 wt.% NaCl) or aqueous dispersion of

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NPs. A floating piston accumulator (FPA1000-10 1/8" FLP) provided by Nano-lab at

IAU-Mahabad Branch was applied to store the liquid phase of CO2. The fluid flow was isolated from the driving water and liquid CO2 via the FPA that by virtue of its

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design minimizes friction and reduces pressure load. To keep the decane and assemble

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the effluent during CO2 EOR process, two FPA, each with a capacity of 500 ml, were

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also supplied by the Nano-lab at IAU-Mahabad Branch. Moreover, an Autoclave

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Engineers O-ring self-sealing closure was designed specifically for low pressure and

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moderate temperature applications, where O-ring seals are permissible. Furthermore, a CO2 flow-meter regulator (HPT-GAR-398CR Hero) was installed to the CO2 gas

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cylinder to control the flow rate of injected CO2 and calculate the net volume (%) of inlet gas. The desired pressure at the experiments was maintained with the CO2 flow-

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meter regulator. In addition, a hose (W.P. 400 bar, 6-SAE 100 at ¼˝) of 6.4 mm diameter and 2 m length was connected to both the CO2 cylinder and the flow-meter

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regulator. A capillary tubing of 1 mm internal diameter and 24 cm length was also utilized to measure the apparent viscosity of fluids flowing. Finally, an oven embedded to a digital set controller with a Hall sensor feedback (input power supply: 220 V; 50Hz) was utilized to provide and control the desired temperatures. Before carrying out the core-flood experiments, the fluids (i.e. CO2 and water) were pre-heated in the

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water bath for 45 min. By carrying out this function, the set-up inside the oven allows for achieving the desired temperatures in the core-flood experiments. 16 19

2 6

10

14

15

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1 Top

4

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Central Bottom

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8

9

7 5 3

1. Ball valve 2. 3-way plug valve 3. Powered valve 4. Needle valve 5. CO2 cylinder 6. CO2 compressor 7. Air source 8. Pressure gauge 9. CO2 accumulator 10. Core holder & Sample 11. Pressure drop 12. ISCO pump (1) 13. ISCO pump (2) 14. Waste accumulator 15. Monitoring 16. Oven 17. Container 18. Hydraulic pump 19. Capillary tubing

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Fig. 1. A schematic of the set-up used for the generation of foam.

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2.3. Experimental Procedure

A core-flood experiment was carried out to study the foaming ability of SiNP by direct

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co-injection of CO2 and NP dispersion through the unfractured and fractured limestone cores. To prepare for the examination of unfractured core-flood, the limestone sample

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was first cut into a cylindrical core of 3-cm in diameter and 30-cm in length. The core

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sample was then wrapped with a polytetrafluoroethylene (PTFE) tape and heat-shrink tubing (UL224-2010 ASTM D 2671) to avoid flow along the core wall and reduce the

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amount of CO2 contacting rubber sleeve. Next, the limestone core was vacuumed twice to ensure that most of the trapped air was removed. Afterwards, the core sample was saturated with brine as an initial condition before carrying out the core-flood experiment. The sample was then put into the oven at 200 ˚C so that the shrink wrap tubing to activate. Once the wrapping process completed, the weight of the wrapped core was measured. The core sample was placed in a sealed chamber and vacuumed 7

for 24 h. In the following step, the 3-way valve at the top of the chamber was opened to introduce the brine into the vacuumed chamber. After submerging the limestone core into the brine, any remaining trapped air that in the sample was vacuumed out. The wet weight (Ww) of the saturated core was also measured and compared with dry weight (Wd) to determine pore volume (PV) and porosity (Φ) of the core using the

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equations 2 and 3. In addition, the permeability (k) was measured through an injection of brine to the core sample at different flow rates (Q in cm3/s), from the low to the

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high, and calculated using Darcy’s law (eq. 4). 𝑊 −𝑊

𝑤 𝑑 𝑃𝑉 = 𝐷𝑒𝑛𝑠𝑖𝑡𝑦 𝑜𝑓 𝑠𝑎𝑡𝑢𝑟𝑎𝑡𝑒𝑑 𝑏𝑟𝑖𝑛𝑒

Φ=𝐴

𝑃𝑉

𝑄.𝜇𝑎𝑝𝑝. .𝐿 𝐴𝑐𝑜𝑟𝑒 .∆𝑃

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𝑘=

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𝑐𝑜𝑟𝑒 .𝐿

(2) (3) (4)

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where Acore, ΔL, and ΔP are the core cross-sectional area to flow (cm2), core length

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(cm), and pressure drop (Pa.), respectively. µapp stands for apparent viscosity (Pa.s) of

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aqueous phase.

For the experiment of fractured core-flood, the limestone core was loaded to crack its

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frame. Similar to the experiment of unfractured limestone core-flood, the limestone sample was first cut into a cylindrical core 30-cm in length and then wrapped

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thoroughly with the PTFE tape to prevent it from breaking down while loaded. Towards this aim, a regular load frame provided by an axial force was applied to

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fracture the core. Based on compressive strength of the limestone core (i.e. 85 MPa), the load frame was set to run at a loading rate of 1000 psi/min. The load frame was then run from the bottom plate to the top one. After contacting the core with the top plate, the run of load frame was continued until the core was failed in its compression. Under tensile loading, the limestone core was fractured into two pieces and then

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removed immediately to avoid more squeezing. The fractured limestone core was next thoroughly wrapped by the shrink tube and PTFE tape, respectively. The heat shrink tubing prevents the crushing of the core by providing confining pressure while it is fractured. The two pieces of fractured core were put back together with some offset to keep the fracture open and, therefore, to extract the fractured core. In doing so, the

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same process used in the unfractured limestone core was applied to prepare the sample for further experiment.

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In addition, Figure 2 shows a schematic of fractured core indicating the width (W) and

height (H) of fracture along the length (L) of the core. The fracture in the core-flood

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experiment was considered as a narrow fissure that the W is extremely larger than the

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H. In view of all that has been mentioned so far, one may suppose that a single phase

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Newtonian fluid flows through the narrow fissure and, therefore, the fracture aperture

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size (H in cm) is calculated from the Equation 5. The H was calculated in the basis of the matrix permeability (km) and the average permeability of the core (kave.) and used

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to determine the fracture permeability (kfr) [16,26]. By knowing the kfr, a model of parallel flow permeability (MPFP), adopted from Odling et al. [27], was applied to

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determine the fractions of flow in both fracture (Ffr) and matrix (Fm). 1

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𝐻 = (12 × 𝑘𝑓𝑟 )2

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𝑘𝑎𝑣𝑒. =

𝐹𝑓𝑟 = 𝑘

(5)

[𝑘𝑚 ×(𝐴𝑐𝑜𝑟𝑒 −𝐻𝑊)]+(𝑘𝑓𝑟 ×𝐻𝑊)

(6)

𝐴𝑐𝑜𝑟𝑒

𝑘𝑓𝑟 ×𝐻𝑊

(7)

𝑎𝑣𝑒. ×𝐴𝑐𝑜𝑟𝑒

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Width

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Fig. 2. A 3D schematic of fractured core indicating the width (W) and height (H) of fracture alongside the core.

Furthermore, to evaluate the effect of injected pressure on the change in fracture

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aperture, the fractured limestone core was placed under a compression cycle and

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significantly the provided confining pressure did not affect the fracture aperture size.

2.4. Mobility Reduction Factor (MRF)

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MRF is the ratio of the measured ΔP across the core for the foam experiment with NPs to the aqueous phase that does not contain the NPs. During co-injection of CO2 and

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NP dispersion to the both unfractured and fractured limestone cores, the ΔP depends

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on (and also converted to) the µapp of aqueous phase with and without NPs. Therefore, the MRF is the ratio of the µapp of generated foam (with NPs) to the µapp of the CO2-

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water mixture (without NPs) at the same flow rate [16]. 𝑀𝑅𝐹 = 𝜇

𝜇𝑎𝑝𝑝. 𝑔𝑒𝑛𝑒𝑟𝑎𝑡𝑒𝑑 𝑓𝑜𝑎𝑚 𝑎𝑝𝑝. 𝑎𝑞𝑢𝑒𝑜𝑢𝑠 𝑝ℎ𝑎𝑠𝑒 𝑤𝑖𝑡ℎ𝑜𝑢𝑡 𝑁𝑃𝑠

(8)

2.5. Determination of the Quality of CO2 Foam (Fg) Fg, which determines the volume fraction of CO2 in the generation of foam, is defined as the volumetric ratio of carbon dioxide (VCO2 in cm3) to the aqueous phase (VL, liquid 10

volume in cm3) at the core-flood conditions (eq. 9). CO2 and DI water were co-injected at the same volumetric flow rate at core-flood conditions. 𝐹𝑔 = 𝑉

𝑉𝐶𝑂2

(9)

𝑤 + 𝑉𝐶𝑂2

2.6. Estimation of Oil Saturation (So)

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As pointed out in subsection 2.1, decane was utilized as the representative of HC phase

in the experiment due to its miscibility with CO2. With the aim to estimate the

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saturation of oil residing in the core, the So was measured through the difference

between wet weight of the limestone core (𝑊𝑚 ) containing the oil (𝑊𝑠𝑜 ) and when it

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was saturated with brine (𝑊𝑠𝑤 ). This discrepancy was a result of the difference between

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the density of decane (𝜌𝑑 ) and brine (𝜌𝑏 ) in the aqueous phase.

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𝑊𝑠𝑤 = 𝑊𝑚 + 𝑃𝑉. 𝜌𝑏

(10) (11)

𝑊𝑠𝑤 − 𝑊𝑠𝑜 = 𝑃𝑉. 𝑆𝑜 . (𝜌𝑏 − 𝜌𝑑 )

(12)

𝑊𝑠 −𝑊𝑠𝑜 𝑏 −𝜌𝑑 )

(13)

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𝑤 𝑆𝑜 = 𝑃𝑉.(𝜌

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𝑊𝑠𝑜 = 𝑊𝑚 + 𝑃𝑉. [𝜌𝑏 . (1 − 𝑆𝑜 ) + 𝜌𝑑 . 𝑆𝑜 ]

3. RESULTS AND DISCUSSION

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3.1. Foam Generation in Unfractured Limestone Core

To test the ability of NPs for stabilizing CO2 bubbles, CO2 and NP dispersion were coinjected directly into the unfractured limestone cores with average petrophysical properties of ~17.75% porosity and 10 to 60 mD permeability. To infer the MRF, the ΔP drop measured across the core was converted into the µapp (see eq. 4) and compared with the aqueous phase without NPs. 11

Initially, CO2 and DI water at a volumetric ratio of 1:1 were co-injected into the unfractured limestone core to establish the µapp of baseline experiment (without NPs). The measured ΔP converted to the µapp at different PV and Q is shown in Figure 3. The results of this baseline experiment show that the µapp first approaches to a certain amount (1.45 cP) and then reaches the steady state while the flow rate changes. The

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highest amount of µapp is 1.92 cP at the Q of more than 8 ml/min. It can be noted that the amount of µapp in the baseline experiment is essentially unaffected by the injection

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rates and is about 1.8 cP in average. Equation 14 [28] was applied to calculate the

amount of shear rate (𝛾̇, measured in s-1) on the fluid flowing through unfractured

4𝑄 1

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4 3.5

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3 2.5

Q=1 ml/min

2

Q=3 ml/min

Q=6 ml/min

Q=8 ml/min

Q=10 ml/min

Q=12 ml/min

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Apparent viscosity (cP)

(14)

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𝐴(8𝑘∅)2

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γ̇ (𝑠 −1 ) =

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limestone cores.

1.5

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1

0.5

0

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0

2

4

6

8

10

Pore volume

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16

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Fig. 3. The plotted measured baseline µapp (81.6 < 𝛾̇ < 980 s-1) vs. injected PV in the unfractured limestone core (without NPs) at an equal ratio (1:1) of CO2 and DI water and an operating pressure of 1000 psi.

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In doing so, NPs (with different dispersion from 0.1 to 1 wt.%) were dispersed into the NaCl (with different concentration from 1 to 3 wt.%) brine to investigate the feasibility of foam generation of high quality in unfractured limestone core (Table 1). According to Worthen et al. [21], foam stabilization is promoted by increasing the salinity of aqueous phase through increasing the affinity of NPs between the CO2 and aqueous

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phase. A gradual increase in the MRF between the Q of 3 and 8 ml/min increases the quality of generated foam. This result can also be approved through the view cell

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observation where the small texture of generated foam was detected at the 𝛾̇ of above

100 s-1. With respect to high quality of foam (i.e. 0.8), CO2 bubbles were distributed in larger size. These bubbles are formed by the coalescence of unstable foam. Because

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the unstable foam has lower µapp, it is necessary to increase the value of 𝛾̇ to improve

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the texture of foam.

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Additionally, the measurement of internal pressure taps provides a perceptive information about the foam generation at different sections of the core. For example,

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after converting the sectional ΔP drops to the µapp, the value of µapp at the top part of the core remains consistent with the baseline level, while it increases at the bottom part

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(e.g. at the Q of 3 ml/min). Although the µapp of the baseline experiment is about 1.8 cP at the top and bottom parts of the unfractured limestone core at every injection rate,

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this value is not considered for the generation of foam. Therefore, the low value of 𝛾̇ at the Q of 3 ml/min causes to move the NPs to the interface of the fluids at the top

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part of the core (see #10 in Fig. 1). As a result, a lower surface of NPs was covered. Accordingly, a small portion of lamellae remains at the top part of the unfractured limestone core. By following these lamellae, they were accumulated to the central part of the core and more surfaces of NPs were covered. At the central part, the µapp became

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greater than the top part. As a result, it can be extended to the bottom part of the core, having the most amount of the µapp among other parts of the core. Table 1. The experiment of foam generation in unfractured limestone cores with NPs dispersion from 0.1 to 1 wt.%.

CNP-3 NPs=1wt.% NaCl=1wt.% Φ=17.75% T=25°C P=1000psi

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CNP-4 NPs=1wt.% NaCl=3wt.% Φ=17.75% T=25°C P=1000psi

60

CNP-5 NPs=0.1wt.% NaCl=1wt.% Φ=17.75% T=50°C P=1500psi

10

CNP-6 NPs=0.1wt.% NaCl=3wt.% Φ=17.75% T=50°C P=1500psi

25

CNP-7 NPs=1wt.% NaCl=1wt.% Φ=17.75% T=50°C P=1500psi

45

CNP-8 NPs=1wt.% NaCl=3wt.% Φ=17.75% T=50°C P=1500psi

60

CNP-9 NPs=0.1wt.% NaCl=1wt.% Φ=17.75% T=75°C P=2000psi

10

CNP-10 NPs=0.1wt.% NaCl=3wt.% Φ=17.75% T=75°C P=2000psi

25

CNP-11 NPs=1wt.% NaCl=1wt.% Φ=17.75% T=75°C P=2000psi

45

CNP-12 NPs=1wt.% NaCl=3wt.% Φ=17.75%

60

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1.017 1.039 1.049 1.066 1.075 1.078 1.082 1.154 1.334 1.366 1.285 1.278 1.190 1.378 1.424 1.477 1.393 1.372 1.493 1.536 1.662 1.763 1.571 1.538 1.060 1.111 1.122 1.185 1.203 1.19 1.103 1.298 1.500 1.712 1.564 1.500 1.623 1.832 2.023 2.261 1.969 1.803 1.947 2.135 2.456 2.664 2.425 2.346 1.147 1.515 1.839 2.034 1.949 1.922 1.212 1.551 2.275 2.477 2.406 2.349 1.947 2.885 2.921 2.962 2.826 2.696 2.488 3.577 3.765 3.865

14

𝛾̇ (s-1) 81.648 244.945 489.890 653.186 816.483 979.779 51.639 154.917 309.833 413.111 516.389 619.667 38.489 115.468 230.936 307.915 384.894 461.872 33.333 99.998 199.997 266.662 333.328 399.993 81.648 244.945 489.890 653.186 816.483 979.779 51.639 154.917 309.833 413.111 516.389 619.667 38.489 115.468 230.936 307.915 384.894 461.872 33.333 99.998 199.997 266.662 333.328 399.993 81.648 244.945 489.890 653.186 816.483 979.779 51.639 154.917 309.833 413.111 516.389 619.667 38.489 115.468 230.936 307.915 384.894 461.872 33.333 99.998 199.997 266.662

IP T

25

MRF

1.830 1.869 1.889 1.918 1.936 1.941 1.947 2.077 2.402 2.458 2.313 2.301 2.142 2.480 2.564 2.658 2.508 2.470 2.687 2.765 2.992 3.174 2.827 2.768 1.908 1.999 2.019 2.132 2.165 2.145 1.986 2.337 2.700 3.082 2.816 2.700 2.921 3.297 3.641 4.070 3.544 3.246 3.505 3.843 4.420 4.795 4.366 4.222 2.064 2.726 3.310 3.661 3.509 3.460 2.181 2.791 4.096 4.459 4.331 4.229 3.505 5.193 5.258 5.331 5.086 4.852 4.479 6.439 6.777 6.957

SC R

CNP-2 NPs=0.1wt.% NaCl=3wt.% Φ=17.75% T=25°C P=1000psi

µapp (cP)

U

10

ΔP (psi) 0.47 1.44 2.91 3.94 4.97 5.98 0.5 1.6 3.7 5.05 5.94 7.09 0.55 1.91 3.95 5.46 6.44 7.61 0.69 2.13 4.61 6.52 7.26 8.53 0.49 1.54 3.11 4.38 5.56 6.61 0.51 1.8 4.16 6.33 7.23 8.32 0.75 2.54 5.61 8.36 9.1 10 0.9 2.96 6.81 9.85 11.21 13.01 0.53 2.1 5.1 7.52 9.01 10.66 0.56 2.15 6.31 9.16 11.12 13.03 0.9 4 8.1 10.95 13.06 14.95 1.15 4.96 10.44 14.29

M

CNP-1 NPs=0.1wt.% NaCl=1wt.% Φ=17.75% T=25°C P=1000psi

Q (ml/ min) 1 3 6 8 10 12 1 3 6 8 10 12 1 3 6 8 10 12 1 3 6 8 10 12 1 3 6 8 10 12 1 3 6 8 10 12 1 3 6 8 10 12 1 3 6 8 10 12 1 3 6 8 10 12 1 3 6 8 10 12 1 3 6 8 10 12 1 3 6 8

N

k (mD)

A

Experiment

10 12

15.37 18.22

5.986 5.913

3.326 3.285

333.328 399.993

M

A

N

U

SC R

IP T

T=75°C P=2000psi

The results obtained from the unfractured limestone cores show that the presence of

ED

NPs below than the value of the critical shear rate (𝛾̇crit) and does not affect the

PT

measured ΔP across the core [16]. As shown in Figure 4, the MRF values are about 1 in the unfractured limestone cores with NPs dispersion of 0.1 wt.%, which means that

CC E

the measured ΔP at these conditions is the same as that of without NPs. In addition, the MRF value increases by increasing the 𝛾̇ across the unfractured limestone core.

A

Therefore, the increase in the value of MRF cause to increase the µapp of generated foam as the fluids flow across the core.

15

4

3

2.5

2

IP T

Mobility reduction factor

3.5

SC R

1.5

1 10

100

1000

Shear rate (s-1)

10000

CNP-2

CNP-3

CNP-4

CNP-5

CNP-6

CNP-7

CNP-8

CNP-9

CNP-10

CNP-11

CNP-12

U

CNP-1

Fig. 4. The amount of MRF vs. shear rate for unfractured limestone cores with different dispersion of

N

NPs from 0.1 to 1 wt.% and different concentration of NaCl from 1 to 3 wt.% at temperatures of 25, 50,

A

and 75 °C.

M

By increasing the Q to the rate of 8 ml/min, the µapp increased equally at the whole

ED

parts of the core. Because the amount of 𝛾̇ was sufficient at this rate and caused enough NPs to move to the interface, the foam was generated in the top part of unfractured

PT

limestone core where the highest rank of lamellae was earlier accumulated. For this reason, the µapp of foam remained at the same level in the other parts, while the

CC E

generated foam was transmitted to the central and bottom parts of the core. In the higher quality of generated foam (i.e. 0.9), the amount of µapp significantly differed

A

among the parts of core (Fig. 5). This result is enhanced when the Q of more than 8 ml/min is applied in the experiment of foam generation. This result is also significant at the Q of ≥ 10 ml/min.

16

7

5 4

Q=10 ml/min

Q=6 ml/min Q=8 ml/min

Q=12 ml/min

Q=3 ml/min

3 2 1 Q=1 ml/min

0

2

4

6

8

10

12

Pore volume Top

Central

14

16

18

20

SC R

0

IP T

Apparent viscosity (cP)

6

Bottom

Fig. 5. The measured apparent viscosity at the top, central, and bottom parts (see # 10 in Fig.1) of the

N

U

unfractured limestone cores with flow rates from 1 to 12 ml/min.

A

3.2. Foam Generation in Fractured Limestone Cores

M

Similar to the experiment of foam generation in the unfractured limestone core, the brine containing NPs dispersion with 1 wt.% was first prepared through injection of

ED

CO2 and NaCl (with concentration of 1 wt.%) simultaneously into the fractured core with aperture size (or fracture height) of 85 µm. Then, the experiments were conducted

PT

using higher concentration of NaCl to 3 wt.% into the cores with aperture size of 102

CC E

and 164 µm. The obtained data of baseline apparent viscosity (i.e. 1.8 cP) from the previous experiment were used to deduce the proportion of limestone matrix in the foam generation (Table 2). Despite the previous results, the significant increase of the

A

µapp only occurred at the Q of >8 ml/min in the fractured limestone core (Fig. 6). Therefore, in this section, both limestone matrix and fracture were used to evaluate the generation of foam. Additionally, the MPFP was applied to estimate the amount of Q across the fractured limestone core and hence the value of 𝛾̇ on the fluid flowing was calculated through Equation 15.

17

𝛾̇ (𝑠 −1 ) =

6𝑄

(15)

𝐻2𝑊

Figure 6 shows the measured µapp vs. 𝛾̇ in the fractured limestone core. It can be inferred that the notion of 𝛾̇crit also applies for the fractures in the core. As shown in Figure 6A, by reaching the 𝛾̇ to 𝛾̇crit at 221.1 s-1, the µapp increases to 2.53 cP. This is

IP T

in accordance with forming the fine texture of foam at the limestone matrix. Regarding the generation of foam, the results reveal that the limestone matrix reached the value

SC R

of 𝛾̇crit before the fracture (i.e. 𝛾̇crit 1011.3 s-1, Fig. 6B). This occurred when 52% of

injected fluid was passed through the fracture. It is somewhat surprising that further injected fluid was allocated to the limestone matrix, while the foam was generated in

U

the fracture.

N

Table 2. The experiment of foam generation in fractured limestone cores with different

A

dispersion of NPs from 0.1 to 1 wt.%. The width of fracture equals to the core diameter (i.e.

Experiment

ϕ (%)

21

FNP-2 NPs=0.1wt.% NaCl=1wt.% H= 85 µm T=50°C P=1500psi

21

FNP-3 NPs=0.1wt.% NaCl=1wt.% H=85 µm T=75°C P=2000psi

21

6.02×10-6

kave. (mD)

25

24.91

6.02×10-6

25

24.91

6.02×10-6

25

24.91

PT

CC E A

km (mD)

ED

FNP-1 NPs=0.1wt.% NaCl=1wt.% H=85 µm T=25°C P=1000psi

kfr (mD)

M

3-cm).

FNP-4 NPs=1wt.% NaCl=3wt.% H=102 µm T=25°C P=1000psi

26

8.67×10-6

45

44.81

FNP-5 NPs=1wt.% NaCl=3wt.% H=102 µm T=50°C P=1500psi

26

8.67×10-6

45

44.81

FNP-6 NPs=1wt.% NaCl=3wt.% H=102 µm T=75°C P=2000psi

26

8.67×10-6

45

44.81

FNP-7 NPs=1wt.%

35

2.24×10-5

60

59.58

Q (ml/ min) 1 3 6 8 10 12 1 3 6 8 10 12 1 3 6 8 10 12 1 3 6 8 10 12 1 3 6 8 10 12 1 3 6 8 10 12 1 3

18

ΔP (psi) 0.47 1.47 3.01 4.35 5.47 7.01 0.53 1.65 3.39 4.78 6.06 7.43 0.51 1.62 3.39 4.58 8.9 11.59

µapp (cP) 1.830 1.908 1.954 2.118 2.130 2.275 2.064 2.142 2.200 2.327 2.360 2.411 1.986 2.103 2.200 2.230 3.466 3.762

0.57 1.77 3.61 4.89 6.24 7.66 0.57 1.75 3.56 4.81 6.1 7.49 0.55 1.75 3.58 4.93 9.14 11.86 0.57 1.78

2.220 2.298 2.343 2.381 2.430 2.486 2.220 2.272 2.311 2.342 2.376 2.431 2.142 2.272 2.324 2.400 3.560 3.849 2.220 2.311

MRF 1.017 1.060 1.085 1.176 1.184 1.264 1.147 1.190 1.222 1.293 1.311 1.340 1.103 1.168 1.222 1.239 1.926 2.090 1.233 1.277 1.302 1.323 1.350 1.381 1.233 1.262 1.284 1.301 1.320 1.350 1.190 1.262 1.291 1.333 1.978 2.138 1.233 1.284

𝛾̇fracture (s-1) 470.588 1411.765 2823.529 3764.706 4705.882 5647.059 470.588 1411.765 2823.529 3764.706 4705.882 5647.059 470.588 1411.765 2823.529 3764.706 4705.882 5647.059 326.797 980.392 1960.784 2614.379 3267.974 3921.569 326.797 980.392 1960.784 2614.379 3267.974 3921.569 326.797 980.392 1960.784 2614.379 3267.974 3921.569 126.413 379.239

𝛾̇matrix (s-1) 47.561 142.683 285.365 380.487 475.609 570.730 47.561 142.683 285.365 380.487 475.609 570.730 47.561 142.683 285.365 380.487 475.609 570.730 33.884 101.652 203.304 271.072 338.840 406.608 33.884 101.652 203.304 271.072 338.840 406.608 33.884 101.652 203.304 271.072 338.840 406.608 27.638 82.915

NaCl=3wt.% H=164 µm T=25°C P=1000psi

35

2.24×10-5

60

59.58

FNP-9 NPs=1wt.% NaCl=3wt.% H=164 µm T=75°C P=2000psi

35

2.24×10-5

60

59.58

3.6 4.97 6.35 7.77 0.57 1.78 3.67 5.11 6.52 7.89 0.58 1.79 3.69 5.19 9.36 11.98

2.337 2.420 2.473 2.522 2.220 2.311 2.382 2.488 2.539 2.561 2.259 2.324 2.395 2.527 3.645 3.888

1.298 1.344 1.374 1.401 1.233 1.284 1.323 1.382 1.411 1.423 1.255 1.291 1.331 1.404 2.025 2.160

758.477 1011.303 1264.128 1516.954 126.413 379.239 758.477 1011.303 1264.128 1516.954 126.413 379.239 758.477 1011.303 1264.128 1516.954

165.829 221.105 276.382 331.658 27.638 82.915 165.829 221.105 276.382 331.658 27.638 82.915 165.829 221.105 276.382 331.658

IP T

FNP-8 NPs=1wt.% NaCl=3wt.% H=164 µm T=50°C P=1500psi

6 8 10 12 1 3 6 8 10 12 1 3 6 8 10 12

At the Q of <8 ml/min, the 𝛾̇ in both fracture and matrix were below the critical value

SC R

and no foam was thus generated. At this stage, 68% of injected fluid was allocated to

the fracture. In contrast, the foam was generated in both matrix and fracture, while the

U

Q of ≥8 ml/min was applied and, therefore, 52% of injected fluid was allocated to the

N

fracture. Together these results provide important insights into the effect of the

A

CC E

PT

ED

M

A

concentration of NP and NaCl on the quality of generated foam.

19

Apparent viscosity (cP)

3 2.5

A

2 1.5

Q = 8 ml/min 𝛾̇crit = 221.1 s-1

1 0.5 0 10

100

1000 (s-1)

IP T

Shear rate FNP-6 matrix

FNP-3 matrix

FNP-9 matrix

3

SC R

2 1.5 Q = 8 ml/min 𝛾̇crit = 1011.3 s-1

U

1 0.5

N

Apparent viscosity (cP)

B 2.5

0

1000

Shear rate (s-1) FNP-6 fracture

10000 FNP-9 fracture

M

FNP-3 fracture

A

100

ED

Fig. 6. The measured apparent viscosity vs. shear rate at both limestone matrix (A) and fracture (B).

3.3. Factor Affecting the Generation of CO2 Foam

PT

3.3.1. Effect of the Fg

CC E

The µapp, as an essential factor of foam generation, seems to affect the Fg, which determines the volume fraction of CO2 in foam. Worthen et al. [21] indicated that

A

increasing the foam quality reaches the µapp to a maximum level. There appears to be a maximum level of the Fg (i.e. 0.8) that obtained the highest µapp (i.e. 6.96) in the experiments (see Table 1). While producing a significant µapp as a result of sufficient lamellae needs considerable volume fraction of CO2 [16], the amount of CO2 fraction was critically checked as it may reduce the lamellae and decrease their stability. In the case of too high foam quality (i.e. 0.9), there is not a sufficient amount of liquid to 20

form lamellae and they are too thin. Moreover, it is easier to coalesce the thin lamellae as there is possibly only a monolayer coverage of NP. Additionally, sometimes lack of aqueous phase to support the generation of foam decreases its quality. As a result of smaller lamellae proportion at high quality, there is a possible transfer of foam from discontinuous- to continuous-gas foam. In the continuous-gas foam, the unrestricted

IP T

CO2 route caused a considerable growth in the mobility of gas phase and consequently the large CO2 bubbles were yielded (Table 3).

SC R

Moreover, the value of permeability affects the foam quality in which it is dropped

from a high value to a lower one, therefore, caused to decrease the Fg. As a result, a continual decline in the Fg occurs while the value of permeability decreases from 60

N

resists flow as permeability decreases [29].

U

mD to 25 mD. What is curious about this result is that the foam with the low quality

A

Furthermore, the Fg was investigated at different temperatures of 25, 50 and 75 °C. For

M

instance, the highest value of µapp obtained when a foam quality of 0.8 generated at 75

ED

°C rather than at T of 25 and 50 °C. Considering these conditions at two unfractured and fractured core-flood experiments, the 𝛾̇crit decreased from 1516.95 s-1 to 266.66 sas a consequence of the growth of foam quality from 0.45 to 0.8 (Table 3). To test

PT

1

these results, further analyses were conducted at a consistent rate of injection on the

CC E

limestone cores in order to establish their optimum quality of foam. The results showed that there seems to be a correlation between the value of µ app and the quality of foam

A

in all the experiments, which tends to be flat. The quality of foam below the value of 0.31 did not has a significant effect on the µapp. At higher values, the µapp of foam began to decline. The declination of µapp can be elucidated through shifting from discontinuous-gas to continuous-gas foam when further volume of CO2 is applied. Hence, this change was determined as the ideal quality of foam since it produced the

21

highest µapp at a temperature of 75 °C. In contrast to earlier finding, Aroonsri et al.[16] did not find any relation between the increasing T and the Fg. They concluded that the T does not seem to affect the Fg and the trends for all temperatures are the same. In order to the feasibility of methyl-coated SiNPs to stabilize CO2 foam in the carbonate reservoirs, the effect of temperature was also evaluated at higher

IP T

temperatures of 75 °C. At these elevated temperature, the physical properties of carbon

dioxide is changed from liquid phase to supercritical one, therefore, this can affect the

SC R

stabilization of CO2 foam. The results showed that no foam was generated while CO2 and 1 wt.% methyl-coated SiNP in 3 wt.% NaCl were co-injected. These data suggest

U

that the 𝛾̇crit may be increased higher than 266.66 s-1 as the temperature increased to

N

the upper than 75 °C. These results are in line with those of previous studies. Sun et

A

al. [17] reported that increasing temperature has two functions on the foam quality.

M

First, increasing temperature to 60 °C increases the foam volume until the maximum foam quality is reached and then the foam volume decreases with temperature higher

ED

than 60 °C. In addition, an experimental demonstration of temperature effect was carried out by Bacho and Bennion [30] who declared that the interfacial tension (IFT)

PT

between CO2 and water molecules at T of higher than 75 °C is about 25% greater than

CC E

the T of 50 °C. On the other words, a 25% more energy is needed to move the NPs to the interface at the T of higher than 75 °C.

A

Table 3. The quality of generated foam in unfractured and fractured limestone cores with 1 wt.% dispersion of NPs and 3 wt.% NaCl concentration.

Experiment CNP-4 CNP-8 CNP-12 FNP-3 FNP-6 FNP-9

T (°C) 25 50 75 25 50 75

P (psi)

k (mD)

1000 1500 2000 1000 1500 2000

25 45 60 24.91 44.81 59.58

22

𝜇𝑓𝑜𝑎𝑚𝐶𝑂2 𝛾̇crit (s-1) (cP) 266.66 3.17 266.66 4.79 266.66 6.96 1.15 5647.06 2.12 3921.57 2.59 1516.95

𝜌𝐶𝑂2 (g/cm3) 0.88 0.67 0.43 0.88 0.67 0.43

𝑉𝐶𝑂2 𝑉𝐶𝑂2 + 𝑉𝐿 0.45 0.64 0.80 0.31 0.56 0.74

3.3.2. Effect of the 𝛾̇crit The effect of the 𝛾̇crit on the generation of foam was demonstrated in the experiments using unfractured and fractured limestone cores. The µapp of NPs below the 𝛾̇crit remains consistently similar to the experiment without NPs. By overwhelming the 𝛾̇crit, the rapid increase of the µapp occurred as foam continued to refine its texture (see Figs.

IP T

4 and 6). A comparison of two experiments revealed that the value of 𝛾̇crit varies with

SC R

the presence of fractures. In addition, the µapp and k affected the value of 𝛾̇crit. In unfractured limestone core, a thinned layer of NPs-St foam observed at low matrix permeability (e.g. 25 mD), however, increasing the µapp to the peak value (i.e. 2.12 cP)

N

3.3.3. NaCl concentration

U

at fractured limestone core caused the NPs-St foam to have this behavior (see Fig. 6B).

A

The concentration of NaCl in the aqueous phase has a positive effect on the generation

M

of foam. According to Binks et al. [31], the addition of salt to an aqueous phase

ED

increases the hydrophobicity between the NPs. As a result, the affinity of NPs at their interfaces enhances when the concentration of NaCl changed from 1 wt.% to 3 wt.%

PT

in the experiments. Worthen et al. [21] demonstrate that increasing the concentration of NaCl improves the contact angle at CO2-water interfaces. This improvement helps

CC E

to adsorb more NPs at the CO2-water interface, generate additional lamellae, and cause higher µapp. As shown in Figure 6B, it can be concluded that the increasing NaCl to 3

A

wt.% increases the µapp at the T of 75 °C and then decreases the value of 𝛾̇crit to generate the foam. The results revealed that adding further NaCl (e.g. 5 wt.%) to the aqueous phase induced to aggregate the NPs, according to the findings established by Worthen et al [21]. 3.3.4. Matrix Permeability 23

The results, as shown in Table 1, indicate that the value of permeability can affect both the µapp and 𝛾̇crit. A comparison of the experiments reveals that the µapp measured in the limestone core with higher permeability (e.g. 60 mD) is greater than the core with lower value of permeability (e.g. 10 mD); considering the same experimental conditions in the temperature and salinity. It is also worth noting that the value of 𝛾̇crit

IP T

for generation of foam is lower when the sample with higher matrix permeability is

matrix permeability of 60 and 10 mD, respectively. 3.3.5. NPs Concentration

SC R

used. These values were 266.66 s-1 and about 653.19 s-1 in the limestone cores with

U

When the concentration of NP increases, the µapp of foam successively increases. A

N

possible explanation for this result might be related to improve the stability of lamellae.

A

From the data in Tables 1 and 2, it is apparent that increasing the dispersion of NPs

M

from 0.1 to 1 wt.% into the unfractured and fractured limestone cores (at the Q of 8

ED

ml/min) caused an increase of the value of MRF from 1.71 to 3.86 and 1.18 to 1.4, respectively. These findings indicate that increasing plentiful dispersion of NPs in the

PT

aqueous phase result in covering more surface of CO2 bubbles and prohibit the coalescence of lamellae. Figure 4 shows a clear trend of generating foam at different

CC E

concentration of NPs. From these data, it can be seen that the foam is not generated while the concentration of NPs is low.

A

3.3.6. Effect of SiNPs coating

The properties of NPs surface are essential to the function of generated foam [4]. Because the NPs behaviors vary from the hydrophilic to hydrophobic when they are dispersed to water and accumulated at the CO2-water interphases, respectively. Nguyen et al. [4] indicated that the strong attraction between methyl-coated SiNPs and

24

CO2-water interface reduces the NPs loss to the surface of the core rather than PEGcoated nanoparticles. In addition to this benefit, the methyl-coated SiNPs were more compatible at the carbonate reservoirs with high temperature and pressure conditions. Therefore, 12 nm SiNPs with three coating conditions of 0%, 50%, and 75% by C2H6SiCl2 were used in the core-flood experiments. The findings indicated that no

IP T

CO2 foam was formed with uncoated SiNPs while both the 50% and 75% methylcoated SiNPs formed the stable foam. However, there was a significant difference

SC R

between 50% and 75% methyl-coated SiNPs and referred to the aggregation of 75%

methyl-coated SiNPs in water. Therefore, 50% methyl-coated SiNPs were used for all

N

U

subsequent experiments.

A

3.4. The Behavior of NP-St CO2 Foam in the Presence of HC

M

According to the stability and ability of foam to improve the recovery of oil, the behavior of NP-St CO2 foam was determined in the unfractured and fractured

ED

limestone cores. Returning to the discussion in subsection 3.3, it is now possible to

PT

state that a real mobility control in CO2 EOR process can only be reached when the generated foam still interacts with HC in the reservoir. To achieve this, decane with

CC E

the residual saturation (So) of 30% was applied to study the effect of HC on CO2 EOR process in the aqueous phase associated with 3 wt.% NaCl and CO2. The results

A

revealed that decane is miscible with bubbles of CO2 in both experiments with and without NPs and the So reduces from 30% to 4%. Referring to the miscibility of decane and CO2 bubbles, it was unexpected to remain the So value in the cores. This result may be explained by the fact that the water phase might have prevented the miscibility between HC phase and CO2 bubbles. It can thus be suggested that the miscibility of decane and carbon dioxide proves the ability of the NP-St CO2 foam to reduce the So 25

and control the mobility. Another reason why these experiments were conducted is to measure the recovery of oil and the µapp. Figure 7 shows the plots of µapp vs. PV injected for the experiments with and without NPs. As shown in Figure 7, it was observed that foam still provided a considerable amount of resistance despite the presence of residual oil in core. Considering the same condition of residual oil, the

IP T

highest value of measured µapp in the experiment with and without NPs was 5.35 and

1.55 cP, respectively. The presence of residual oil at the highest value of µapp declined

SC R

the resistance of foam against to flow.

In the experiment without NPs, the generated foam was transmitted slightly faster

U

(PV=0.4) than the experiment with NPs (PV=1.2) across the core. Comparing the lack

N

of residual oil, its presence also supported the fast spread of generated foam. On the

A

other hand, the transmitted time of generated foam in the experiments with and without

M

NPs was 0.45 and 2.91 PV, respectively. It could be concluded that there is a delay to transmit of foam in the lack of HC (see Figs. 3 and 5). It is also worth noting that the

ED

transmitted time is recorded with a prompt response in the presence of HC. This finding suggests that the interaction between the bubbles of CO2 and the residual oils

A

CC E

PT

may mobilize the HC across the core.

26

6

4 3 2 1 0 1

2

3

4

5

6

7

Pore volume without NPs

with NPs-unfractured

8

9

10

11

12

SC R

0

IP T

Apparent viscosity (cP)

5

with NPs-fractured

Fig. 7. The plots of µapp vs. PV injected for the experiments with (a, b) and without (c) NPs in the

A

3.5. Foam Stability Analysis

N

U

presence of decane with the So of 30%.

M

The stability of NP-St CO2 foam was measured by determination of its half-life time through filling a cylinder with a bulk foam. Due to decomposition of the foam stability

ED

at reservoir condition with high temperatures [17], the half-life time of CO2 foam for both PEG- and methyl-coated SiNPs was studied at different temperatures from 25 °C

PT

to more than 75 °C. In addition, the concentrations of PEG-coated and 50% methyl-

CC E

coated SiNPs were ranged from 0.1 wt.% to 1 wt.%. The results showed that the increasing temperature to 75 °C first increases the bulk foam and then it decreases with applying further temperatures (Fig. 8). These results are in agreement with those

A

obtained by Nguyen et al. [4] and Sun et al. [17]. They indicated that the half-life time of NP-St CO2 foam decreases with increasing the temperature when the bulk foam reaches to the maximum value. Although the half-life time of PEG-coated SiNP was increased considerably, its bulk foam was about 25% lower than that methyl-coated SiNP in the same concentration. As shown in Figure 8, the value of half-life time for 27

methyl-coated SiNPs is about 3.11 times that of PEG-coated at T of 75 °C. As a result, the 50% methyl-coated SiNPs have higher thermal stability.

80

Methyl-coated SiNPs

70

PEG-coated SiNPs

60 50

IP T

Half-life time (min)

90

40 30

SC R

20 10 0 20

30

40

50

60

70

90

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T (°C)

80

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Fig. 8. The analysis of foam stability measured by half-life time at different temperatures from 25 °C to

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4. CONCLUSIONS

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more than 75 °C.

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The present study was designed to determine the mobility control in CO2 EOR process using 12 nm methyl-coated SiNP in unfractured and fractured limestone core-flood

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experiments. The results revealed that the stable CO2 foam was successfully generated through direct co-injection of CO2 and NP dispersion into the cores. The significant

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factor in generating stabilized CO2 foam was the value of critical share rate in the experiments with and without NPs. The value of 𝛾̇crit referred to the factors affecting

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the quality of CO2 foam. By increasing the quality of foam in unfractured limestone core, the 𝛾̇crit was decreased. The results suggest that changing the amount of matrix permeability from a high to a lower one changes the optimum quality of foam. Therefore, the limestone samples with higher matrix permeability had a lower value of 𝛾̇crit for foam generation. Taken together, these results suggest that the pore throats

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simplifies the formation of bubbles and decreases the value of 𝛾̇ required to generate the foam. In addition, the amount of apparent viscosity was crucial for obtaining an optimal quality of foam. Establishing a condition similar to the typical reservoir by posing the optimum quality of foam (i.e. 0.8) at 75 ˚C caused some difficulties in applying NP-St

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CO2 foam. It might be preferable to apply high quality foam (i.e., 0.9) in the oilfields

because there the process demands less water, provides the reservoir with more CO2,

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and increases foam mobility. It needs to be noted that the µapp affected foam quality and was considered as the most crucial factor for the aim of mobility control.

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Therefore, a logical relation between two these factors (i.e. the µapp and foam quality)

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was required in order to efficiently apply mobility control utilizing NP-St CO2 foam.

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It was also shown that the increasing of NaCl concentration caused to drive NPs to the

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interface of CO2 bubbles and brine. Although the NPs was aggregated at NaCl concentration of 5 wt.%, this increasing to 3 wt.% decreased the value of 𝛾̇crit for the

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foam generation thus the µapp of foam was increased at temperature of 75 ˚C. On the

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other hand, increasing the dispersion of NPs from 0.1 to 1 wt.% resulted to cover more surface of CO2 bubbles and prohibited the coalescence of lamellae.

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ACKNOWLEDGMENT The author thanks Thomas Edward Bassett for his editing and Sahar Zarza for her

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