Laboratory Study of CO2 Foam Flooding in High Temperature, High

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Laboratory Study of CO2 Foam Flooding in High Temperature, High Salinity Carbonate reservoirs Using Co-injection Technique Ali M. AlSumaiti, Muhammad Rehan Hashmet, Waleed S. AlAmeri, and Evans Anto-Darkwah Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.7b03432 • Publication Date (Web): 31 Dec 2017 Downloaded from http://pubs.acs.org on January 1, 2018

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Laboratory Study of CO2 Foam Flooding in High Temperature, High Salinity Carbonate reservoirs Using Co-injection Technique Ali M. AlSumaiti, Muhammad R. Hashmet*, Waleed S. AlAmeri, Evans AntoDarkwah ADNOC Research and Innovation Center, The Petroleum Institute, Khalifa University of Science and Technology, P.O. Box 2533, Abu Dhabi, United Arab Emirates

Keywords: co-injection, foams, shear thinning, apparent viscosity, mobility reduction factor

ABSTRACT In this research, an Ethoxylated amine surfactant is co-injected with CO2 in a series of coreflooding experiments at typical Middle Eastern reservoir conditions of high temperature, high salinity and in-situ foam is generated to reduce gas mobility in the absence of oil. The effects of reservoir permeability, injection rates, and foam quality on mobility reduction factor (MRF) and apparent viscosity of foam are discussed. In the absence of oil, an optimum foam quality of 80 % is obtained using 1 wt% of surfactant solution. Shear thinning foams with viscosities ranging between (0.9-2.4 cP), were formed at all velocities tested in this study. MRFs of 50 and 70 were obtained respectively in 70 and 240 mD cores at 80 % foam quality confirming that, foam strength increases with increasing rock permeability. After determination of optimum foam quality and flow rate, a final coreflooding experiment was conducted in the 1 ACS Paragon Plus Environment

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presence of oil to quantify the effect of oil presence on foam generation and to observe the recovery performances of supercritical CO2 and CO2 foam for secondary and tertiary recovery injections. In the presence of oil, relatively weak foams were generated in a 50 mD core having apparent viscosities of 0.66, 1.65 and 3.29 cP at the tested co-injection flow rates of 0.2, 0.5 and 1 ml/min at 80% foam quality. Total recovery factor of 88.32% was obtained, with CO2 and CO2 foam floods contributing 79.34% and 8.98% respectively. INTRODUCTION Gas injection (N2, CH4, CO2) for improved oil recovery (IOR) remains viable and proven. Among other problems related to gas injection, gravity override, viscous fingering,

and

chanelling are the most serious issues encountered with gas injection for oil recovery [1-4]. These problems ultimately reduces the volumetric efficiency of the gas flooding processess. The density contrast between reservoir fluids and injected gas is enormous, and therefore the injected gas moves to upper sections of a reservoir leading to

gravity segregation. When gravity

segregation occurs, the lower portions of the reservoir is not contacted by the injected gas and therefore volumetric efficiency is reduced significantly [5]. Carbon dioxide injection has gained more attention than other gas injections. This is due to its ability to mitigate some of the problems enumerated above much easily than other gases. To solve the issue of gravity segregation, CO2 gas can be compressed to a supercritical state (Sc) above its critical pressure and temperature of 1074 psig and 31.04 oC respectively. This is to increase its density to a range of 0.5-0.9 g/cm3 which reduces the density contrast significantly [1]. The miscibility and viscosity of CO2 increases significantly in supercritical phase as compared to other gases used in gas injection processes [6]. However, the viscosity contrast

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between supercritical CO2 and reservoir fluids still remains high and therefore viscous fingering remains a significant problem for CO2 injection[7, 8]. A noble method to reduce the mobility of injected gas for improved oil recovery was first described by [9]. In their patent, they described the use of foams as mobility control agents. The foam was generated in porous media by injecting a desirable concentration of surfactant prior to gas injection. The surfactant and the injected gas form the foams which are highly viscous as compared to the viscosities of its constituent substances. Through the increase in viscosity, the mobility of subsequent injected gas is reduced to ensure high displacement efficiency. Foam EOR is well studied in literature [1, 10-13] and has also been applied in the fields [14-16]. Factors Affecting Foam Propagation in Porous Media: Various parameters including surfactant concentration [17], foam quality [18], injection rate [19], permeability of rock [20] and injection technique [21, 22] affect propagation of foam in porous media. Foam quality refers to the amount of gas dispersed in liquid (surfactant) to generate foam. Foam quality investigation is crucial as it determines the optimum amount of gas fraction in surfactant solution to generate strong in-situ foams to reduce gas mobility in porous media. Jones et al., (2016) report an increase of apparent viscosity with foam quality in foam experiments conducted using nitrogen gas. In their work on testing of switchable non-ionic to cationic surfactants, Ameri et al., (2017) observed foam apparent viscosity increased with foam quality for all tested surfactants.

The trend of apparent viscosity with foam quality is

characterized with two distinct flow regimes in the absence of oil: a low and high flow regime [23-26]. In the low quality regime, the foam strength is stronger and the pressure gradient is independent of liquid superficial velocity whereas in the high-quality regime foam strength is weak and the pressure gradient along the core is independent of gas superficial velocity [24]. 3 ACS Paragon Plus Environment

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Foam generation and propagation in porous media has also been investigated in the literature. There is a consensus that, there exist a minimum pressure or velocity to generate and propagate foams from the wellbore to the deeper parts of the reservoir [27, 28]. The impact of velocity on foam strength and rheology is mixed. In the high quality regime, shear thickening behavior has been observed [29, 30], whereas a shear thinning behavior has been reported in other literatures [31, 32]. Gas mobility in heterogeneous reservoirs remains a major challenge for gas injection methods. In porous media, the permeability contrast leads to gas channeling and subsequently early breakthrough. Various researchers have pointed out the ability of foams to block high permeability layers and subsequent diversion of flow to low permeability regions [1, 11]. Heller, (1994) observed an increase of apparent viscosity with permeability in a baker dolomite. Liu et al., (2006) observed a higher gas mobility decrease in high permeability segments of an Indiana core at fixed gas quality. The selective mobility reduction (SMR) capability of CO2-foam gives it optimal advantage over other forms of foams[1]. The objectives of this study are: 1. To test the foamability and mobility of an ethoxylated amine in carbonate cores at the conditions stated for this studies. 2. To investigate the effect of foam quality on foam strength. 3. To investigate the effect of flow rate (velocity) on foam rheology and propagation in porous media. 4. To investigate the effect of permeability on gas mobility reduction. 5. To investigate the recovery efficiency of CO2 for secondary injection and CO2 foam for tertiary recovery. EXPERIMENTAL DESCRIPTION 4 ACS Paragon Plus Environment

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Materials Core samples: Carbonate outcrops were purchased from Kocurek Industries. The cores were cleaned in a Soxhlet apparatus using methanol and subsequently dried in an oven at 90oC for 48 hours. The core diameter, length and dry weight were measured. The cores were vacuumed for 4 hours in an automatic saturator and subsequently the formation brine was imbibed into the cores under pressure of 2000 psig for 72 hours. All the saturated cores were kept in a covered beaker filled with same formation brine until coreflooding was performed on them. The porosity and pore volumes of cores were determined from the wet and dry weights by using the brine density. Petrophysical properties of cores samples used in this study are presented in Table 1. Table 1 Petrophysical properties of core samples Property

CF1

CF2

CF3

Length, cm

7.6

15.2

15.0

Diameter, cm

3.8

3.8

3.75

Porosity, %

40.0

15.9

23.4

34.5

27.6

37.75

Absolute brine permeability, mD

240.0

70

50

Effective permeability to CO2 , mD

70

41

4

Brine Saturation

1

1

0.115

PV, cm

3

Brine solution: Typical Middle Eastern reservoirs have very high salinity formation brine. A synthetic brine of 220000 ppm (22 wt%) was prepared for all coreflooding experiments conducted in this study. The composition of the synthetic brine is shown in Table 2.


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Table 2 Synthetic Brine Composition Component

Weight (g)

NaCl

182.32

CaCl2.3H2O

77.24

MgCl3.6H2O

25.62

Distilled water

1000

Surfactant Solution: The surfactant used in our studies is Ethomeen (C12) which is a nonionic ethoxylated amine. Adjusting the pH of Ethomeen (C12) solution to below 7 protonates or switches Ethomeen from nonionic to cationic state which improves its thermal stability considerably [18]. The phase behavior and interfacial studies on Ethomeen (C12) conducted previously [18, 33] makes it a favorable surfactant candidate for application in the reservoir target conditions of 3500 psig and 120oC of this study. Further information on the surfactant concentration and experiments conducted are summarized in Table 3. Table 3 Surfactant concentrations used in coreflooding experiments

Experiment

CF1

CF2

CF3

Surfactant

Ethomeen

Ethomeen

Ethomeen

Surfactant Concentration, %

1

1

1

Type of experiment

Foam quality

Total flow rate

Recovery study

Experimental Apparatus:


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A schematic of the high pressure and temperature coreflooding system used in this study is shown in Figure 1. The system is comprised of two dedicated syringe-pumps for injection of brine and surfactant. A third and fourth pumps are dedicated for setting confining and back pressures respectively. A fifth Tyledyne pump was connected to an accumulator containing CO2 to enable smooth delivery of CO2 during the co-injection process. The injection fluids are loaded into the floating piston accumulators, and are delivered to core by using refined mineral oil. The core sample is set horizontally and pressure drop is measured using three differential pressure transducers at the inlet and outlet of core. The CO2 and surfactant are delivered through two separate lines which meet at the surface of the core. The series of coreflooding experiments have been conducted in the absence and presence of oil. Confining pressure of 5500 psig, backpressure of 3500 psig and temperature of 120oC were used in all experiments.


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Figure 1 Schematic of coreflood system.

Experimental Procedure Absolute permeability: The core was loaded in an Aflas sleeve which is suitable for CO2 flooding. Brine was injected at 0.2 ml/min for about 10 PV to drive out any air remaining in the core. During the injection of brine, the back and confining pressures were raised to the desired experimental conditions at slow intervals of 100 psig for every 30 minutes. Brine permeability was determined at several flow rates ranging between 0.05 – 5 ml/min at ambient and reservoir conditions. Foam experiments: During brine injection, carbon dioxide was also compressed in accumulator A using a dedicated ISCO Tyledyne pump to supercritical state (sc-CO2). Two types of foam experiments were conducted: Foam quality scan and Total flow rate experiments.


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Foam quality experiments: In this type of experiments, the total flow rate of surfactant and carbon dioxide was fixed at 1 ml/min, while co-injecting the CO2 and surfactant in different fractions from maximum gas fraction of 1 (baseline) to minimum of zero (surfactant fraction equals 1). The experiment was continued at each fraction until steady state pressure drop was obtained and subsequently the fraction was changed. The gas and surfactant fraction were determined using Equation 1 below: QT = Q g + Q L = 1ml / min

(1)

Total flow rate experiments: In this type of experiments, the foam quality was kept constant whilst the flow rates of gas and surfactant were varied from low to high. The gas and surfactant fractions were co-injected until steady state pressure drop was achieved across the core and subsequently the flow rates of gas and surfactant were changed while maintaining the same foam quality. The flow rates of gas and surfactant were determined from combination of Equations 1 and (2) below:

Fg =

Qg QT

(2)

Recovery studies/Effect of oil on foam strength: Absolute permeability was determined at several flow rates as already mentioned above. 10 PV of a reservoir oil having a viscosity of 8 cP at 25oC was injected to displace brine from the core. After the oil drainage experiment was performed, the core was aged within an ageing cell containing the same reservoir oil at a temperature of 120oC for 3 months. A second oil drainage experiment was performed on the core to further reduce the residual brine saturation. After 10 PV of oil injection, the water saturation was reduced to 11.5%. Recovery studies began with Sc9 ACS Paragon Plus Environment

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CO2 flooding at 1cc/min until no more oil was produced. Co-injection of surfactant and CO2 was performed at a foam quality of 80% at total flow rates of 0.2, 0.5 and 1 ml/min in increasing order to reduce any capillary end effects. RESULTS AND DISCUSSION Foam strength in porous media is measured by the apparent viscosity developed during flow of gas and surfactant in porous media. The steady state pressure drops were converted to apparent viscosity using Equation 3 by rearranging Darcy’s law as:

µ app (cP ) =

k (mD ) * A(cm 2 ) * ∆P ( psig ) 14700 * QT (cc / s ) * L(cm)

(3)

Where µapp is the foam apparent viscosity, k is the effective permeability to gas, A is the area of the core, ∆p is the pressure differential across the core, QT is the total flow rate of gas and surfactant and L is the length of te core. During foam flow in porous media, the apparent viscosity reduces the permeability of gas which can be quantified through the mobility reduction factor (MRF). The MRF is calculated from the steady state pressure drops during gas and foam flows at the same rates through the porous media as illustrated in Equation 4: MRF =

∆ P foam

(4)

∆ PCO 2

Foam quality experiment: The pressure drops at steady state and the apparent viscosities calculated at different foam qualities obtained across a 240 mD core by co-injecting sc-CO2 and Ethomeen (C12) are shown in Figure 2. The results obtained for 1 wt% Ethomeen (C12) solution indicates that apparent foam viscosity (strength) increases with foam quality until a transition foam quality of 80%, where the maximum apparent foam viscosity of 2.69 cP is achieved. After the transition foam 10 ACS Paragon Plus Environment

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quality, apparent foam viscosity starts to decrease and falls to a minimum. Figure 2 also shows the two distinctive foam regimes on the left-side (low quality) and right-side (high quality) of the transition foam quality which has also been observed by several investigators [11, 25]. The foam strength is higher in the low quality regime owing to the fact that it is dominated by liquid flow and hence gas bubbles are made discontinuous by surfactant lenses leading to better stabilization of water molecules and consequently stronger foams. The behavior of foam in the low quality regime is mostly dominated by bubble trapping. In the high quality flow regime however, continuous gas phase dominates, less surfactant is available to stabilize water molecules, leading to drier or weaker foams.

Figure 2 : Differential pressure (left) and apparent viscosity (right) for CF1 Total flow rate experiments: High pressure gradient (flow rate) may be required to generate and propagate foams from the wellbore area deep into the reservoir. However, higher pressure gradients or flow rates maybe


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attainable only around the wellbore. The effect of flow rate on foam generation and propagation was investigated in these set of experiments. The trend of steady state pressure drop and apparent viscosity at different total flow rates are shown in Figure 3. Our results show that, in the absence of oil, foams have been generated at flow rates as low as 0.05 cc/min, which could be good implication for the use of Ethomeen (C12) and carbon dioxide for generation and propagation of foams in porous media. However, the foam generated at low flow rate is classified as weak foam. At very low flow rates, a shear thickening behavior is observed, there is an increase of apparent viscosity with increasing flow rate until a maximum apparent viscosity of almost 3.4 cP is obtained at 0.2 ml/min. At much higher flow rates (above 0.2 ml/min), a shear thinning behavior is observed, where apparent viscosity decreases with increasing flow rate. The foam behavior observed is desirable in foam experiments and field application of CO2 foam. These results confirm that the foam generated initially at the wellbore area will have smaller viscosity and therefore optimal injection may be obtained. On the other hand, deep inside the reservoir, where foam flow rate is much slower and pressure gradient much lower, the foam will assume a much higher viscosity to reduce gas permeability and subsequently increase in areal sweep and more oil recovery. These results are similar to observations by other investigators in the literature[25, 31].


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Figure 3 : Differential pressure (left) vs apparent viscosity (right) for CF2

Effect of permeability: The selective mobility reduction

of CO2 foams noted by Heller [1] is studied using the

experiments conducted at 80 % foam quality as an illustration. The theory of limiting capillary pressure [11] shows that, higher permeability zones requires a lower capillary pressure (lower water saturation) threshold to form foams and vice versa for low permeable zones. Therefore, it is expected that, foams will block higher permeable layers and subsequently divert injected gas to lower permeable regions to increase sweep efficiency [1, 34].The optimum foam quality for Ethomeen (C12) in a 240 mD core was 80% at a total flow rate 1 ml/min (Figure 4). Using the foam quality of 80%, we investigated the effect of flow rate on MRF using a 70 mD core (Figure 4). A comparison of the MRFs obtained using a total flow rate of 1 ml/min at a foam quality of 80% reveals that: the MRF in the 240 mD core is 70 whereas the MRF for the 70 mD is 50. This


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comparison proves that, foam can reduce the mobility of gas in highly permeable zones than in lower zones. The trend of high MRF in high permeability cores is confirmed in this study.

Figure 4: MRF obtained for CF1 (left) and CF2 (right) Recovery Studies/Effect of oil on foam strength The results displayed in Figure 5 shows the oil volume produced with accompanying differential pressure versus pore volumes injected. CO2 was injected at 1 ml/min to study the secondary recovery performance when carbon dioxide is in a supercritical state as well as being injected above miscibility pressure for CO2. Breakthrough occured at approximately 0.5 PV. The total recovery from CO2 was 79.3% (corresponding to 26.5 ml) . After almost 3.6 PV of CO2 injection, co-injection of surfactant and CO2 was performed at 80% foam quality at a total flow rate 0.2 ml/min. Co-injection at 0.2 ml/min did not produce any additional oil. As evidenced by the pressure differential across the core, very weak foams having an apparent viscosity of 0.66 cP were generated. The initial surfactant injected may have been used up to satisfy the rock adsorpton and hence no oil production was recorded. The flow rate was then increased to 0.5 and 14 ACS Paragon Plus Environment

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1 ml/min to overcome any capillary end effects. An additional 9% receovery was observed during foam flooding. The differential pressures at 0.5 and 1 ml/min indicates a relatively mild foam was generated in the presence of residual oil, and apparent foam viscosities of 1.65 and 3.29 cP were recorded respectively. Although the generated foam is classified as weak foam, however the apparent foam viscosities represent an appreciable reduction in the mobility of CO2 evidenced by the calculated MRFs of 7.90 and 6.08 respectively when compared to the original CO2 viscosity at operating conditions.

Figure 5: Oil produced with accompanying differential pressure across the core during CO2 and CO2 foam flooding versus pore volume injected.


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CONCLUSIONS 1. Foamability of Ethomeen (C12) was confirmed at high pressure, temperature and salinity conditions as evidenced by higher pressure drops obtained during foam flow when compared with single phase gas flow. 2. Foam apparent viscosity increased with increasing foam quality until the transition (optimum) of 80%. Above the optimum foam quality, a decreasing relationship between viscosity and foam quality was observed. 3. Shear thickening foams were obtained at lower flow rates and shear thinning foams were obtained at higher flow rates. Foams with apparent viscosity of 0.9 to 2.4 cP were generated at all flow rates tested at a foam quality of 80%. 4. The MRFs obtained in a 240 mD and 70 mD cores were 70 and 50 respectively at a foam quality of 80%. This implies that foam has a greater effect on gas relative permeability in higher permeable zones. Selective mobility reduction (SMR) behavior was observed in the experiments conducted. This implies that, injected gas for EOR may be confined in the lower sections (less permeable) of the reservoir due to foam blockage in upper sections (highly permeable) of the reservoir. 5. Foam strength decreases in the presence of oil, as evidenced by the low pressure drops and low apparent viscosities of 0.66, 1.65 and 3.29 cP calculated for total flow rates of 0.2, 0.5 and 1 ml/min respectively. 6. CO2 flooding recovered 79.34 % OOIP and CO2 foam recovered 8.98% OOIP, amounting to a total of 88.32 % OOIP. Acknowledgements


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We acknowledge financial support from the ADNOC R&D Oil Sub-Committee and ADCO for providing reservoir characteristics and formation brine composition. We also thank AkzoNobel for providing surfactant samples. Nomenclature A – Cross-sectional area of the core, cm2 Fg - Foam quality (fraction or percentage) GOR – Gas-Oil-Ratio k - Permeability, mD L – Length of the core, cm MRF – Mobility reduction factor OOIP – Original-oil-in-place ∆P - Pressure drop across the core, psig ∆Pco2 - Pressure drop across the core during baseline sc-CO2 flooding, psig ∆Pfoam - Pressure drop across the core during co-injection of sc-CO2 and surfactant, psig QT - Total flow rate, ml/min (Qg + QL) QL – Liquid (Surfactant) flow rate, ml/min Qg – Gas flow rate, ml/min Sc – Supercritical µapp – Apparent viscosity, cP


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