Miscible CO2 Simultaneous Water-and-Gas (CO2-SWAG) Injection in

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Miscible CO2 Simultaneous Water-And-Gas (CO2-SWAG) Injection in the Bakken Formation Yanbin Gong, and Yongan Gu Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.5b01182 • Publication Date (Web): 27 Aug 2015 Downloaded from http://pubs.acs.org on August 31, 2015

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Miscible CO2 Simultaneous Water-And-Gas (CO2-SWAG) Injection in the Bakken Formation

Yanbin Gong and Yongan Gu*

Petroleum Technology Research Centre (PTRC) Petroleum Systems Engineering Faculty of Engineering and Applied Science University of Regina Regina, Saskatchewan S4S 0A2 Canada

*Corresponding author. Tel.: 1-306-585-4630; Fax: 1-306-585-4855. E-mail address: [email protected].

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ABSTRACT: In this paper, miscible CO2 simultaneous water-and-gas (CO2-SWAG) injection in the tight Bakken formation is experimentally studied. The effective viscosities of high-salinity water and supercritical CO2 mixtures with twelve different water volume fractions are measured at the actual reservoir conditions by using a capillary viscometer. A total of six coreflood tests with four different miscible CO2-EOR schemes are conducted in the tight reservoir core plugs collected from the Bakken formation (Canada). It is found that the measured effective viscosity of the saline water‒CO2 mixture increases with the water volume fraction and can be reasonably modeled by using the Arrhenius equation. The coreflood test results indicate that the miscible CO2-SWAG injection with an injected water‒gas ratio (WGR) of 1:3 in volume has the highest oil recovery factor (RF). The miscible CO2 water-alternating-gas (CO2-WAG) injection achieves a slightly higher oil RF than that of the miscible CO2 flooding, whereas the waterflooding followed by the miscible CO2 flooding has the lowest oil RF. In addition, the WGR shows strong effects on the fluid production trends of the miscible CO2-SWAG injection. A water bank might be formed ahead of the water‒CO2 mixture in the miscible CO2-SWAG injection with a higher injected WGR of 3:1 or 1:1. Furthermore, the mobility ratio of the injected fluid(s) to light crude oil is calculated based on the measured steady-state flow rate and pressure gradient in each coreflood test. In comparison with water or CO2 alone, the water‒CO2 mixture has a lower mobility in the tight reservoir core plugs. Hence, the highest oil RF of the optimum CO2-SWAG injection with the lowest injected WGR of 1:3 is attributed to a well-controlled water‒CO2 mobility and a substantially weakened waterblocking effect. Keywords: CO2-EOR; CO2 simultaneous water-and-gas (CO2-SWAG) injection; Effective viscosity of water‒CO2 mixture; CO2-mobility control; Tight Bakken formation.

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1. INTRODUCTION Since the 1950s, carbon dioxide (CO2) flooding has been studied and applied as an important enhanced oil recovery (EOR) method. Many CO2-EOR projects have been conducted in the USA and other countries. However, a low volumetric sweep efficiency has always been a technical issue for continuous CO2 flooding because of an extremely low viscosity and a relatively low density of CO2 in comparison with those of the other reservoir fluids. In particular, the displacement front in the continuous CO2 flooding is inherently unstable and the viscous fingering may cause an early CO2 breakthrough (BT).1,2 Several CO2-EOR processes have been developed in order to effectively control CO2 mobility and increase the sweep efficiency of CO2 flooding. They include carbonated water injection (CWI), CO2 cyclic solvent injection (CO2CSI), and CO2 water-alternating-gas (CO2-WAG) injection. In the CWI process, a limited amount of CO2 is dissolved into the water phase prior to its injection. As a result, the mobility of the displacing phase (i.e., the carbonated water) is greatly reduced by eliminating the gas phase. With a minimal CO2 consumption, this EOR method is particularly attractive for the oilfields with little access to CO2 source.3 Nevertheless, the CWI performance is considerably compromised because of a low CO2 solubility in water phase, especially in the deep reservoir brine with a high salinity. In CO2-CSI, CO2 injection period is followed by a shut-in or soaking period, during which CO2 phase is dissolved into the crude oil before the oil production period starts. Gas molecular diffusion and oil viscosity reduction play important roles in the oil recovery process. This EOR method can be successfully applied in the oil reservoirs with poor inter-well connectivity.4 In the CO2-WAG injection, the flooding front of the displacing phase is stabilized by injecting small water and CO2 slugs alternately. The water injection process improves the volumetric sweep efficiency, whereas the CO2 injection process enhances the microscopic


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displacement efficiency.5 In the field applications, however, a large amount of the residual oil is still left behind after CO2-WAG injection is applied in an oil reservoir. Moderately enhanced oil recovery factors (RFs) of 5‒10% of the original oil-in-place (OOIP) are obtained in the successful CO2-WAG projects.6 In comparison with continuous CO2 flooding, CO2-WAG injection requires more parameters (e.g., the slug size and ratio) to be optimized and may have some operational problems due to frequent alternation of water and gas injection. Laboratory studies and pilot tests have shown that the oil recovery factor (RF) can increase by reducing the slug size of a CO2-WAG injection.7,8 In this regard, CO2 simultaneous waterand-gas (CO2-SWAG) injection can be considered as modified or special CO2-WAG injection, in which water and CO2 are injected simultaneously rather than alternately. By means of coinjecting CO2 with more viscous water, it is anticipated that CO2 mobility is substantially controlled due to the CO2 effective permeability reduction and water‒CO2 mixture viscosity increase.9 Moreover, it is well known that the performance of CO2-WAG injection strongly depends on the slug ratio.10 Similarly, the water‒CO2 ratio of the co-injected water‒CO2 mixture in CO2-SWAG injection is expected to have a strong effect on its EOR performance. Here, the co-injected water‒gas ratio (WGR) is defined as the volume ratio of the injected water phase to CO2 phase under the actual reservoir conditions. If the WGR is too high, the excessive water phase may block the residual crude oil from being contacted by CO2 phase directly and hinder the crude oil–CO2 multi-contact miscibility development.11 On the other hand, if the WGR is too low or a large amount of CO2 is injected, CO2-mobility control by co-injected water may not be effective enough and an early CO2-BT can still occur. Hence, it is necessary to identify an optimum WGR in order to achieve the best CO2-mobility control and oil recovery factor under the given reservoir conditions.


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Although CO2-SWAG injection tends to have better CO2-mobility control than CO2-WAG injection,12 few studies have been conducted to examine its EOR performance in comparison with CO2-WAG injection. Caudle and Dyes9 conducted the first laboratory SWAG injection study in 1958. Their test results showed that for a five-spot flooding model, the ultimate sweep efficiency increased from about 60% for continuous gas flooding to about 90% for SWAG injection. More recently, Sohrabi et al.13 conducted visualization tests to compare the displacement efficiency of near-miscible continuous methane (CH4) injection and that of CH4SWAG injection. They found that the oil RF of CH4-SWAG injection was almost the same as that of continuous CH4 injection, though the methane consumption for CH4-SWAG injection was much lower. Nevertheless, neither of these two studies investigated the EOR potential of CO2SWAG injection. Aleidan and Mamora14 carried out three coreflood tests of miscible CO2SWAG injection in carbonate core plugs with an average permeability of k = 90 mD. It was found that the CO2-SWAG injection resulted in a higher oil RF than continuous CO2 flooding or CO2-WAG injection. In the past, a few field applications of CO2-SWAG injection have been undertaken. In the Joffre Viking pool (Canada), CO2-WAG injection offered little improvement than continuous CO2 flooding. On the other hand, a CO2-SWAG injection pilot project showed the best sweep efficiency and the highest oil RF, in comparison with continuous CO2 flooding and CO2-WAG injection.15 Also higher oil recovery was obtained and more stabilized water and gas production trends were found for CO2-SWAG injection field trial in the Rangely Weber oilfield, Colorado, USA, in comparison with CO2-WAG injection.8 So far no laboratory tests have been conducted to study the EOR mechanisms of CO2-SWAG injection process and explore its potential to recover the light crude oil in a tight oil formation, such as the Bakken formation. Located in the Williston Basin, the Bakken formation has recently


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become a vast and vital unconventional oil resource in North America and its OOIP is estimated to be 300 billion barrels.16 Nevertheless, the primary oil RF of this extremely tight oil formation is as low as 1–3% of the OOIP. Hence, there is a great potential for CO2-EOR processes to unlock the tight oil.7,17 In this paper, the effective viscosities of water‒CO2 mixtures with twelve different water volume fractions from 0 to 1 at the actual reservoir pressure and temperature are measured by using a high-pressure capillary viscometer. The first three different coreflood tests are conducted under the actual reservoir conditions to compare three different water and miscible CO2 injection schemes in the tight reservoir core plugs collected from the Tatagwa oilfield (Canada) in the Bakken formation. They are miscible CO2 flooding, waterflooding followed by miscible CO2 flooding, and miscible CO2-WAG injection. The last three miscible CO2-SWAG injection tests with different injected WGRs of 1:3, 1:1, and 3:1 are performed to examine the WGR effects on the overall oil recovery process. During each coreflood test, the oil RF, average gas production rate, cumulative water production, injection and production pressures are monitored and measured.

2. EXPERIMENTAL SECTION 2.1. Materials. The original light crude oil was collected from the Steelman oilfield in Saskatchewan, Canada. The obtained light crude oil was cleaned by using a centrifuge (Allegra X-30 Series, Beckman Coulter, USA) to remove any sands and brine. Also an inline filter (SS-2TF-0.5, Swagelok, Canada) with a pore size of 0.5 µm was used to further remove any fine solids from the light crude oil. The density and viscosity of the cleaned light crude oil were measured to be

ρoil = 0.819 g/cm3 by using a densitometer (DMA 512P, Anton Paar, USA) and µoil = 0.76 cP by 6 ACS Paragon Plus Environment

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using a viscometer (DV-II+, Brookfield, USA) at the atmospheric pressure and Tres = 51.1 °C. The molecular weight of the light crude oil was measured to be 188.8 g/mol by using an automatic high-sensitivity wide-range cryoscopy (Model 5009, Precision Systems Inc., USA). The asphaltene content of the cleaned light crude oil was measured to be wasp = 0.15 wt.% (npentane insoluble) by using the standard ASTM D2007-03 method and filter papers (No. 5, Whatman, England) with a pore size of 2.5 µm. The compositional analysis result of the cleaned light crude oil was obtained by using the standard ASTM D86 method and is given in Table 1. The total mole percentage of C2‒10 is 49.55%. The high percentage of the light to intermediate hydrocarbons (HCs) indicates that this light crude oil is especially suitable for CO2-EOR. In this study, the equilibrium interfacial tensions (IFTs) between the Steelman light crude oil and CO2 at eleven different equilibrium pressures of Peq = 1.08–8.74 MPa and Tres = 51.1 °C were measured by applying the axisymmetric drop shape analysis (ADSA) technique for the pendant drop case and are plotted in Figure 1. The detailed experimental setup and procedure for measuring the equilibrium IFTs were described in the previous work.18 The minimum miscibility pressure (MMP) between the light crude oil and CO2 was determined to be 10.8 MPa at Tres = 51.1 °C by using the measured equilibrium IFT versus pressure data and applying the vanishing interfacial tension (VIT) technique. The reservoir brine sample collected from the Steelman oilfield was cleaned and analyzed. Its detailed physicochemical properties are listed in Table 2. The concentration of its total dissolved solids (TDS) was measured to be 180,000 mg/L at 110 °C. The dominant cation is sodium and the dominant anion is chloride. In this study, however, a synthetic brine was prepared by dissolving sodium chloride (NaCl) into a deionized water to reach the same TDS or salinity and used in all coreflood tests to substitute the reservoir brine. This was because fine solids in the


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reservoir brine might further reduce the low permeability of the tight reservoir core plugs during the reservoir brine injection process. A number of tight reservoir core plugs were collected from an oil well (Well No.: 15-24-06-16W2) located in the Tatagwa oilfield (Canada) in the Bakken formation at the reservoir depths of 1,790‒1,792 m. The purity of carbon dioxide (Praxair, Canada) used in this study was equal to 99.998 mol.%. 2.2. Effective Viscosity Measurements. In this study, the co-injected water‒CO2 mixture at each water volume fraction was assumed to be a pseudo single-phase fluid. To measure the effective viscosity of the water‒CO2 mixture at the tight oil reservoir conditions, a high-pressure capillary viscometer was constructed and its schematic diagram is shown in Figure 2. A 23-ft long stainless steel tubing (15-9A1-006, High Pressure Equipment Co., USA) was coiled to form a capillary tubing. The outer diameter (OD) and inner diameter (ID) of the capillary tubing were equal to 1/16 in. and 0.006 in., respectively. This long and small capillary tubing was chosen to ensure that a pressure drop along it was large enough to accurately measure the low effective viscosity of the water‒CO2 mixture, including water or CO2 alone. The synthetic brine and CO2 were injected separately and commingled together at a T-union (SS-200-3, Swagelok, Canada) before the water‒CO2 mixture was injected through the capillary viscometer. When the water‒CO2 mixture passed through the capillary tubing, the pressures at the inlet and outlet of the capillary viscometer were measured by using a digital pressure indicator (PM, Heise, USA) and recorded in a personal computer. A backpressure regulator (BPR) (BPR-50, Temco, USA) was installed near the outlet of the capillary viscometer. The constant temperature of Tres = 51.1 °C during each effective viscosity measurement was maintained by placing the capillary viscometer inside an oven (OF-21E, JEIO Tech, Korea). In addition, synthetic brine and CO2 cylinders were wrapped with two heating 8 ACS Paragon Plus Environment

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tapes (TBSO-101-060, BriskHeat, USA), whose temperatures were kept at Tres = 51.1 °C by using a temperature controller (Standard-89000-00, Digi-Sense, USA). Prior to each effective viscosity measurement, the entire injection system was pressurized by gradually increasing the working pressure of the BPR until the outlet pressure of the capillary viscometer reached Pprod = 15.0 MPa. Afterward, the synthetic brine (TDS = 180,000 mg/L of NaCl) and CO2 were injected separately at different constant volume injection rates and commingled together so that a series of twelve different water volume fractions can be obtained. The effective viscosities reported in this study were measured by gradually increasing the water volume fraction in the water‒CO2 mixture from 0 (i.e., 100% CO2) to 1 (i.e., 100% synthetic brine). For each water‒CO2 mixture, three total constant volume injection rates (qmix = qbrine + 3 q CO 2 = 0.1, 0.2, 0.3 cm /min) were used. A distilled water with µw = 0.537 cP at 1 atm and Tres =

51.1 °C was used as a standard viscosity liquid and injected through the capillary tubing at different constant volume injection rates (qw = 0.1‒1.0 cm3/min) to calibrate the capillary viscometer. The Hagen‒Poiseuille equation was applied to determine the so-called “effective radius” of the capillary tubing and the effective viscosity of each water‒CO2 mixture:

µ mix =

π ( r eff ) 4 ∆P 8 q mix l

,

(1)

where µmix is the effective viscosity of the water–CO2 mixture at Pprod = 15.0 MPa and Tres = 51.1 °C; ∆P and qmix are the measured steady-state pressure drop and pre-specified total constant volume injection rate of the water–CO2 mixture through the capillary tubing; reff and l are the “effective radius” and actual length of the capillary tubing.


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2.3. Miscible CO2 Coreflood Tests. The schematic diagram of the high-pressure coreflood apparatus used in this work and its detailed technical description can be found in the previous study.18 The general procedure for preparing each CO2 coreflood test in this study is briefly described below. First, three 1-inch reservoir core plugs were placed inside a Dean–Stark extractor (09-556D, Fisher Scientific, Canada) and thoroughly cleaned with toluene, methanol, and chloroform in sequence to remove hydrocarbons, salts, and clays, respectively. After the reservoir core plugs were cleaned and dried, they were assembled in series in a horizontal coreholder (RCHR-1.0, Temco, USA) and vacuumed for 24 h. Then the synthetic brine was used and injected to measure the porosity of the composite reservoir core plugs. Afterward, the synthetic brine was injected as a working fluid at different constant volume injection rates (qbrine = 0.01–0.1 cm3/min) to measure the absolute permeability of the composite reservoir core plugs. As will be given at a later time in Table 3, the measured porosities were in the range of ϕ = 14.33–16.47% and the measured absolute permeabilities were in the range of k = 0.98–10.08 mD. Next, the original light crude oil was injected at qo = 0.025 cm3/min through the synthetic brine-saturated reservoir core plugs at the ambient temperature of Tlab = 22 °C until no more brine was produced, when the initial oil saturation and the irreducible water saturation were reached. The measured initial oil saturation was in the range of Soi = 45.30‒58.82%. After the initial oil saturation and irreducible water saturation were achieved, a heating gun (HG 1100, Makita, USA) and a temperature controller (Standard-89000-00, Digi-Sense, USA) were used to increase the temperature inside an airbath to Tres = 51.1 °C and maintained this temperature for at least two days. A total of 3–5 pore volumes (PVs) of the original light crude oil was further injected to pressurize the reservoir core plugs by gradually increasing the working


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pressure of the BPR until the pre-specified production pressure of Pprod = 15.0 MPa at the outlet of the coreholder was reached. Finally, the light crude oil mobility at the irreducible water saturation was obtained from the pre-set constant oil volume injection rate (qo = 0.025 cm3/min) and the measured stable pressure drop ( ∆ Po ) between the inlet and outlet of the coreholder: ' q A , λo = k o = o µ o ∆Po L

(2)

where λo is the light crude oil mobility; k 'o and µo are the end-point effective permeability and viscosity of the light crude oil under the test conditions; A and L are the cross-sectional area and length of the composite core plugs. In this study, a total of six coreflood tests were conducted to study and compare different miscible CO2 injection processes in the tight Bakken formation. Three different miscible CO2EOR schemes were tested first: miscible CO2 flooding (Test #1), waterflooding followed by miscible CO2 flooding (Test #2), and miscible CO2-WAG injection (Test #3). A constant volume injection rate of qbrine = qCO2 = 0.1 cm3/min was used in the water or CO2 injection process. Then three miscible CO2-SWAG injection tests (Tests #4‒6) with different injected WGRs of 1:3, 1:1, and 3:1 were carried out to study the WGR effects on the overall oil recovery process. The same total volume injection rate of qmix = qbrine + q CO 2 = 0.1 cm3/min was used in Tests #4‒6 and three different injected WGRs of 1:3, 1:1, and 3:1 were obtained by properly choosing the respective constant water and CO2 volume injection rates. Each CO2-based coreflood test was terminated after a total of 2.0 PV CO2 was injected.


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3. RESULTS AND DISCUSSION 3.1. Effective Viscosities of the Saline Water‒CO2 Mixtures. The effective viscosity of each saline water‒CO2 mixture is determined from eq 1 and shown in Figure 3. It is found that the measured effective viscosity of the water‒CO2 mixture monotonously increases with the water volume fraction. The increased effective viscosity of the water‒CO2 mixture indicates that low-viscosity CO2 is viscosified by the co-injected water. In the EOR process, an increased viscosity of the displacing phase (i.e., the water‒CO2 mixture) will lead to an increased overall sweep efficiency and an increased oil RF. It should be noted that, usually, the effective viscosity of a mixture of two immiscible phases (e.g., water and oil) is substantially higher than that of either phase if an emulsion is formed, such as the water-in-oil (W/O) or oil-in-water (O/W) emulsion.19 Nevertheless, such a pattern was not found for the saline water‒CO2 mixtures tested in this study. As shown in Figure 3, the measured effective viscosities of the water‒CO2 mixtures with twelve increasing water volume fractions can be reasonably modeled by applying the classical Arrhenius equation 20: xbrine xCO2 ⋅ µCO , µmix = µ brine 2

(3)

where µmix is the predicted effective viscosity of the water‒CO2 mixture; xbrine and xCO2 are mole fractions of the synthetic brine and CO2 in the water‒CO2 mixture, respectively; µbrine and µCO2 are the calculated respective viscosities of the synthetic brine (TDS = 180,000 mg/L of NaCl) and supercritical CO2 at Pprod = 15.0 MPa and Tres = 51.1 °C by using the CMG WinProp module (Version 2013.20, Computer Modelling Group Limited, Canada) with Jossi−Stiel−Thodos correlation.21 This fact suggests that the high-salinity synthetic brine and supercritical CO2 mixture under the reservoir conditions has an ideal viscosity behaviour and follows a simple 12 ACS Paragon Plus Environment

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mixing rule.22 It is also found from Figure 3 that the predicted effective viscosities of the water‒CO2 mixtures at the high water volume fractions of ϕbrine ≥ 0.5 are closer to the measured data. For the water‒CO2 mixtures of ϕbrine < 0.5, however, the predicted effective viscosities are always lower than the measured values. In the effective viscosity measurements, gas production was found to have large fluctuations when a water‒CO2 mixture of ϕbrine < 0.5 flowed through the capillary tubing. It was speculated that this unstable gas production trend might lead to a slight increase in the measured effective viscosity of the water−CO2 mixture of ϕbrine < 0.5. 3.2. Three CO2-EOR Processes. In this study, the first three coreflood tests were conducted with three different injection schemes of miscible CO2 flooding (Test #1), waterflooding followed by miscible CO2 flooding (Test #2), and miscible CO2-WAG injection (Test #3) in the tight reservoir core plugs. The detailed physical properties of the composite reservoir core plugs, experimental conditions, and oil RFs of these three coreflood tests are summarized in Table 3. The measured oil RFs, average gas production rates, and cumulative water production data for Tests #1‒3 are plotted in Figures 4a–c. Figure 4a shows that in the miscible CO2 flooding (Test #1), both oil and gas were produced rapidly from the beginning. The early produced solution gas was mainly composed of CO2, which was dissolved into the oil phase and co-produced with it. Then the average gas production rate reached its peak value at 0.41 PV, which is referred to as the PV of CO2-BT. At this time, some gas channels might be formed inside the composite core plugs from the inlet to outlet of the coreholder. After CO2-BT occurred, the oil production rate was reduced gradually, while the average gas production rate was always in the high range of 24‒56 cm3/min. It is also found that in the first 0.41 PV of injected CO2, 51.56% of the OOIP was produced. In contrast, the subsequently injected 1.59 PV CO2 only recovered 31.25% of the OOIP. After CO2-BT, the 13 ACS Paragon Plus Environment

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injected CO2 tends to flow through the established gas channels. Therefore, the increased oil RF is mainly attributed to the HCs extraction by the supercritical CO2 in the late oil production period.18 In the waterflooding followed by the miscible CO2 flooding test (Test #2), as depicted in Figure 4b, the oil RF increased almost linearly with the PV of injected water at the beginning of the waterflooding till 0.25 PV. In this early quick oil production period, the injected water volumetrically displaced the light crude oil inside the composite reservoir core plugs. Then the oil production rate started to decrease and the cumulative water production increased gradually as water was co-produced with the oil. At 0.72 PV, the composite core plugs were already watered-out. Afterward, the cumulative water production increased linearly with the PV of injected water and no oil was produced till the end of waterflooding at 2.0 PV. The subsequent miscible CO2 flooding can be approximately divided into three different fluid production stages. At the beginning, only minor water was produced with no oil or gas production. The injected CO2 displaced and produced the mobile water through the core plugs. In the second stage, CO2saturated oil was produced and the average gas production rate increased quickly, while water production was quickly diminished as most mobile water had already been produced in the first stage. Finally, CO2-BT occurred at 0.54 PV of injected CO2 and the oil production rate was reduced gradually. In this test, some water channels might be developed inside the core plugs after the mature waterflooding. Hence, the subsequently injected CO2 preferentially followed the water channels and broke through the core plugs. Besides, a large amount of water was left inside the core plugs prior to the subsequent miscible CO2 flooding. This water blocked the residual crude oil from being contacted by the supercritical CO2 and hindered the light crude oil‒CO2 miscibility development, which is known as the waterblocking effect.23


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For the miscible CO2-WAG injection (Test #3) plotted in Figure 4c, a total of three WAG cycles were conducted. The oil RFs of these three WAG cycles were found to be 66.04%, 11.32%, and 5.66%, respectively. More specifically, 4/5 of the total produced oil was recovered in the first WAG cycle and roughly 3/5 of the total produced oil was recovered during three CO2slug injection periods. In the CO2-WAG injection, the average gas production rate was reduced substantially in each water-slug injection period. This fact shows that the injected small water slug helped to effectively control the mobility of the subsequently injected CO2 and stabilize its displacement front. It is also found from Figure 4c that CO2-BT occurred at 0.46 PV of injected CO2 in the first WAG cycle. In the next two cycles, nevertheless, it happened earlier at 0.26 PV and 0.18 PV, respectively. These experimental data indicate that CO2-mobility control by the injected water slug was compromised after more WAG cycles were performed. At a later time, some water and gas channels were formed inside the core plugs. It is worthwhile to note that mature waterflooding followed by miscible CO2 flooding (Test #2) can be considered as miscible CO2-WAG injection of one cycle only with a large slug size of 2.0 PV and a slug ratio of 1:1. With a much reduced slug size (0.222 PV) and a smaller slug ratio (1:3), Test #3 had an oil RF of 83.02%, which was much higher than 65.67% in Test #2. 3.3. WGR Effects on Miscible CO2-SWAG Injection. In addition, three miscible CO2-SWAG injection tests with different injected WGRs of 1:3, 1:1, and 3:1 were conducted in the tight reservoir core plugs to examine their oil recovery factors in the tight Bakken formation and the WGR effects on the overall oil recovery process. The detailed physical properties of the composite reservoir core plugs, experimental conditions, and oil RFs of these three coreflood tests are tabulated in Table 3. The measured oil RFs, average gas production rates, and cumulative water production data for Tests #4‒6 are plotted in Figures 15 ACS Paragon Plus Environment

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5a‒c, respectively. As shown in these three figures, gas production was substantially delayed or gas mobility was well controlled in each miscible CO2-SWAG injection test. In all three tests, no apparent gas-BTs occurred and the average gas production rates were always in a range of 0‒30 cm3/min, which were much lower than those in Tests #1‒3. In particular, gas production in Test #5 with the injected WGR of 1:1 was delayed to total 1.40 PV, which was equivalent to 0.70 PV of injected CO2. Gas production in Test #6 with the injected WGR of 3:1 was much delayed to total 2.04 PV or 0.51 PV of injected CO2. In these three CO2-SWAG injection tests, water production was also delayed to total 1.54 PV, 0.50 PV, and 0.69 PV, respectively. Overall, the mobilities of both CO2 and water phases were considerably reduced in the miscible CO2-SWAG injection. In general, the miscible CO2-SWAG injection combines the technical advantages of both waterflooding and CO2 injection. The oil recovery trend of CO2-SWAG injection is similar to that of waterflooding or CO2 flooding to some extent. As shown in Figure 5a, the entire oil recovery process of CO2-SWAG injection with a relatively low injected WGR of 1:3 in Test #4 was similar to the miscible CO2 flooding (Test #1). The quick oil production together with low gas production started almost immediately from the beginning. The oil production rate was reduced gradually and the final oil RF reached a maximum value. No apparent CO2-BT was found, whereas the water production was much delayed and only a small amount of water was produced at the end. In this case, the CO2 displacement front moved faster than the water displacement front in the tight reservoir core plugs with a miscible CO2 bank being formed ahead of the water‒CO2 mixture. In Tests #5 and #6 with relatively higher injected WGRs as shown in Figures 5b and c, the entire oil recovery processes were more similar to the mature waterflooding followed by the


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miscible CO2 flooding (Test #2) and can be approximately divided into four fluid production stages. First, there was neither water nor gas production in the first oil production stage. In the second water production stage, oil production was quickly diminished and no gas was produced yet. In these two stages, the injected CO2 was completely dissolved into the light crude oil. Then CO2-diluted light crude oil was produced rapidly in the third quick oil production stage with a much decreased water production rate and a fluctuating gas production rate. In the final production stage, the oil production rate was reduced gradually and water was produced steadily, while the gas production rate continued to fluctuate in the range of 0‒20 cm3/min. Most oil was produced in the first linear and third quick oil production stages. In these two CO2-SWAG injection tests with relatively higher injected WGRs, the water displacement front was ahead of the CO2 displacement front and formed a water bank. Consequently, the light crude oil inside the tight core plugs was easily trapped or blocked by the injected water. 3.4. Mobilities of Water, CO2, and Water‒CO2 Mixtures. Figure 6a shows the measured pressure drops between the inlet and outlet of the coreholder during different flooding processes in Tests #1‒6. The miscible CO2-WAG injection (Test #3) had the highest pressure drops due to the lowest permeability of the composite reservoir core plugs used in this test. Its pressure drop increased substantially in each water-slug injection period because the high-salinity brine is much more viscous than the supercritical CO2. In contrast, the other three CO2-EOR schemes (Tests #1, #2, and #4‒6) had much more stable and lower pressure drops. It is also seen from Figure 6a that the measured pressure drop became stable near the end of each coreflood test when a steady-state flow was established. In the literature, Heller et al.24 assumed that the steady CO2-foam flow in porous media was uniform. They defined the CO2-foam mobility as the ratio of the superficial flow rate to the 17 ACS Paragon Plus Environment

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steady-state pressure gradient. More recently, Shetty et al.25 made a similar assumption for the CO2-SWAG injection in order to calculate the mobility of the injected water‒CO2 mixture. In this study, as a first approximation, the water‒CO2 mixture is assumed to be a pseudo singlephase fluid in each miscible CO2-SWAG injection test. Hence, an apparent mobility of the injected fluid(s) in each test is equal to: ' A q λf = k f = mix , µ f ∆Pave L

(4)

where λf is the apparent mobility of the injected fluid(s); k 'f and µf are the end-point effective permeability and effective viscosity of the injected fluid(s) under the test conditions; qmix is the total volume injection rate; and ∆Pave is an average steady-state pressure drop between the inlet and outlet of the coreholder near the end of each coreflood test, which is listed in Table 3. To eliminate the influence of a different absolute permeability of the composite core plugs used in each test, the ratio of the apparent mobility of the injected fluid(s) to the mobility of the light crude oil is defined as: M =

λf , λo

(5)

where M is the mobility ratio of the injected fluid(s) to light crude oil; and λ o is the mobility of the light crude oil, which was measured and determined from eq 2, prior to each coreflood test. Table 3 and Figure 6b summarize and compare the mobility ratios of the injected miscible CO2 to light crude oil in Test #1 (miscible CO2 flooding) and Test #2 (miscible CO2 flooding after mature waterflooding), the injected water‒CO2 mixtures to light crude oil in Tests #4‒6 (miscible CO2-SWAG injection tests with different injected WGRs), and the injected water to light crude oil in Test #2 (waterflooding). It is found that the miscible CO2 flooding in Test #1 had the highest mobility ratio of M = 7.58 between the injected supercritical CO2 and light crude 18 ACS Paragon Plus Environment

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oil in the tight reservoir core plugs due to an extremely low CO2 viscosity under the test conditions, as shown in Figure 3. This high mobility ratio can destabilize CO2 displacement front and induce CO2 viscous fingering, which leads to an early CO2-BT. After the mature waterflooding in Test #2, nevertheless, the mobility of CO2 was significantly reduced in the subsequent miscible CO2 flooding, which was due to a trapped water phase after the waterflooding and a possible relative permeability hysteresis.26 In comparison with the mobility of CO2, the mobility of much viscous water was considerably reduced in Test #2. Three CO2SWAG injection tests had the lowest and most favourable mobility ratios (M < 1), especially in Test #4 with the injected WGR of 1:3 and Test #6 with the injected WGR of 3:1, though the effective viscosities of the three respective water‒CO2 mixtures were lower than the water viscosity. In this case, a much reduced effective permeability of the multi-phase fluids resulted in a much reduced mobility of each water‒CO2 mixture. Therefore, a stable and uniform displacement front was formed in the miscible CO2-SWAG injection with a favourable low mobility ratio between the displacing fluids (i.e., the water‒CO2 mixture) and the displaced fluid (i.e., the light crude oil). 3.5. Oil RFs. The respective oil RFs of the miscible CO2 flooding, waterflooding followed by miscible CO2 flooding, miscible CO2-WAG injection, and three miscible CO2-SWAG injection tests are summarized and listed in Table 3. These oil RFs at different oil recovery stages in each test are also plotted and compared in Figure 7. It is found from Table 3 and Figure 7 that waterflooding in Test #2 had an oil RF of 40.94%, which was much lower than 82.81% of the miscible CO2 flooding (Test #1). Waterflooding has a low microscopic displacement efficiency due to a high IFT between the injected water and the light crude oil. Furthermore, with the same amount of 2.0 19 ACS Paragon Plus Environment

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PV of injected CO2 or at the same CO2 consumption, the miscible CO2 flooding after the mature waterflooding in Test #2 had the lowest total oil RF among the six tests. The oil RF considerably increased in the miscible CO2-WAG injection (Test #3) but was only marginally higher than that of the miscible CO2 flooding (Test #1). In consideration of its more complicated field operations and the unstable pressure drops (Figure 6a), the miscible CO2-WAG injection with the slug size of 0.222 PV and slug ratio of 1:3 is not considered to be better than the miscible CO2 flooding in the tight Bakken formation. On the other hand, miscible CO2-SWAG injection with the injected WGR of 1:3 (Test #4) had the highest oil RF and oil production rate (Figure 5a). The lowest mobility ratio led to the most uniform displacement front (i.e., the highest volumetric sweep efficiency) in this test. In Tests #5 and #6 with higher injected WGRs of 1:1 and 3:1, however, both the oil RFs and the oil production rates (Figures 5b and c) were lower. The oil RF of Test #5 was even lower than that of the miscible CO2 flooding (Test #1). In these two CO2-SWAG injection tests, the water bank that was formed ahead of the CO2 displacement front caused a strong waterblocking effect. In order to contact and possibly recover the residual oil, CO2 had to slowly diffuse through the water-barrier phase and miscibly displace the oil phase. Thus a sufficiently long contact time between the two phases is needed in order to achieve a high oil recovery factor.27 This is also the major reason why the oil RF of Test #6 (WGR = 3:1) with the longest injection period was only 9.06% of the OOIP higher than that of Test #5 (WGR = 1:1). At the same CO2 consumption (2.0 PV), miscible CO2-SWAG injection in Test #4 with the injected WGR of 1:3 had the highest oil RF and oil production rate with well-controlled gas production and low water consumption. It was a well-controlled CO2 mobility and a substantially weakened waterblocking effect in this test that jointly led to the optimum miscible CO2-SWAG injection.


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4. CONCLUSIONS In this paper, it was found that the measured effective viscosity of the high-salinity water and supercritical CO2 mixture increased with the water volume fraction under the reservoir conditions of Pprod = 15.0 MPa and Tres = 51.1 °C. The saline water‒CO2 mixture demonstrated an ideal viscosity behaviour and its measured effective viscosity was reasonably modeled by using the Arrhenius equation. A series of six water- and CO2-based coreflood tests were conducted in the tight reservoir core plugs to compare three different CO2-enhanced oil recovery (CO2-EOR) schemes and study miscible CO2 simultaneous water-and-gas (CO2-SWAG) injection. The detailed experimental results showed that the miscible CO2-SWAG injection with an injected water‒gas ratio (WGR) of 1:3 in volume gave the best performance with the highest oil production rate and oil recovery factor (RF), well-controlled gas production, and low water consumption. The miscible CO2 water-alternating-gas (CO2-WAG) injection with a slug size of 0.222 PV and a slug ratio of 1:3 achieved a marginally higher oil RF than that of the miscible CO2 flooding. The mature waterflooding followed by the miscible CO2 flooding had the lowest oil RF due to water-channeling and waterblocking. Finally, the mobility ratio of the injected fluid(s) to light crude oil was determined in each coreflood test. The three miscible CO2-SWAG injection tests had much lower and more favourable mobility ratios of M < 1 in the tight reservoir core plugs, in comparison with miscible CO2 flooding or waterflooding alone. A well-controlled CO2 mobility and a substantially weakened waterblocking effect jointly resulted in the optimum CO2-SWAG injection with the injected WGR of 1:3 in the Bakken formation.


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ACKNOWLEDGMENTS The authors want to acknowledge the financial support from the Petroleum Technology Research Centre (PTRC) and the discovery grant from the Natural Sciences and Engineering Research Council (NSERC) of Canada to Dr. Yongan Gu. They also thank the present and former research group members, Mr. Longyu Han, Mr. Zeya Li, and Mr. Lixing Lin, for their technical assistance and discussions.

SUPPORTING INFORMATION AVAILABLE This information is available free of charge via the Internet at http://pubs.acs.org/.

REFERENCES (1)

Orr, Jr., F. M.; Heller, J. P.; Taber, J. J. Carbon Dioxide Flooding for Enhanced Oil Recovery: Promises and Problems. J. Am. Oil Chem. Soc. 1982, 59 (10), 810A‒817A.

(2)

Godec, M. L.; Kuuskraa, V. A.; Dipietro, P. Opportunities for Using Anthropogenic CO2 for Enhanced Oil Recovery and CO2 Storage. Energy Fuels 2013, 27 (8), 4183‒4189.

(3)

Riazi, M.; Sohrabi, M.; Jamiolahmady, M. Experimental Study of Pore-Scale Mechanisms of Carbonated Water Injection. Transp. Porous Med. 2011, 86 (1), 73‒86.

(4)

Zhang, Y. P.; Sayegh, S. G.; Huang, S.; Dong, M. Laboratory Investigation of Enhanced Light-Oil Recovery by CO2/Flue Gas Huff-n-Puff Process. J. Can. Pet. Technol. 2006, 45 (2), 24‒32.


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(5)

Kulkarni, M. M.; Rao, D. N. Experimental Investigation of Miscible and Immiscible Water-Alternating-Gas (WAG) Process Performance. J. Pet. Sci. Eng. 2005, 48 (1), 1‒20.

(6)

Christensen, J. R.; Stenby, E. H.; Skauge, A. Review of WAG Field Experience. SPE Res. Eval. Eng. 2001, 4 (2), 97‒106.

(7)

Han, L.; Gu, Y. Optimization of Miscible CO2-WAG Injection in the Bakken Formation. Energy Fuels 2014, 28 (11), 6811‒6819.

(8)

Robie, D. R.; Roedell, J. W.; Wackowski, R. K. Field Trial of Simultaneous Injection of CO2 and Water, Rangely Weber Sand Unit, Colorado. Presented at the SPE Production Operation Symposium, Oklahoma City, OK, April 2‒4, 1995; Paper SPE 29521.

(9)

Caudle, B. H.; Dyes, A. B. Improving Miscible Displacement by Gas‒Water Injection. Trans., AIME 1958, 213 (1), 281‒284.

(10) Chen, S.; Li, H.; Yang, D.; Tontiwachwuthikul, P. Optimal Parametric Design for WaterAlternating-Gas (WAG) Process in a CO2-Miscible Flooding Reservoir. J. Can. Pet. Technol. 2010, 49 (10), 75‒82.

(11) Tiffin, D. L.; Yellig, W. F. Effects of Mobile Water on Multiple-Contact Miscible Gas Displacements. SPE J. 1983, 23 (3), 447‒455. (12) Heidari, P.; Alizadeh, N.; Kharrat, R.; Ghazanfari, M. H.; Laki, A. S. Experimental Analysis of Secondary Gas Injection Strategies. Pet. Sci. Technol. 2013, 31 (8), 797‒802. (13) Sohrabi, M.; Danesh, A.; Jamiolahmady, M. Visualization of Residual Oil Recovery by Near-Miscible Gas and SWAG Injection Using High-Pressure Micromodels. Transp. Porous Med. 2008, 72 (3), 351‒367.

(14) Aleidan, A. A.; Mamora, D. D. SWACO2 and WACO2 Efficiency Improvement in Carbonate Cores by Lowering Water Salinity. Presented at the SPE Canadian


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Unconventional Resources and International Petroleum Conference, Calgary, Alberta, October 19‒21, 2010; Paper SPE 137548. (15) Stephenson, D. J.; Graham, A. G.; Luhning, R. W. Mobility Control Experience in the Joffre Viking Miscible CO2 Flood. SPE Res. Eng. 1993, 8 (3), 183‒188. (16) Mason, J. Bakken's Maximum Potential Oil Production Rate Explored. Oil Gas J. 2012, 110 (4), 76–76. (17) Tight Oil Developments in the Western Canada Sedimentary Basin. Energy Briefing Note, National Energy Board of Canada, December 2011. ISSN: 1917–506x. (18) Cao, M.; Gu, Y. Physicochemical Characterization of Produced Oils and Gases in Immiscible and Miscible CO2 Flooding Processes. Energy Fuels 2013, 27 (1), 440‒453. (19) Arnold, K.; Stewart, M. Surface Production Operations, Volume 1: Design of Oil Handling Systems and Facilities. Gulf Professional Publishing: Houston, TX, 2008; pp. 95‒97.

(20) Bloomfield, V. A.; Dewan, R. K. Viscosity of Liquid Mixtures. J. Phys. Chem. 1971, 75 (20), 3113‒3119. (21) Jossi, J. A.; Stiel, L. I.; Thodos, G. The Viscosities of Pure Substances in the Dense Gaseous and Liquid Phases. AIChE J. 1962, 8 (1) 59−63. (22) Yener, M. E.; Kashulines, P.; Rizvi, S. S.; Harriott, P. Viscosity Measurement and Modeling of Lipid‒Supercritical Carbon Dioxide Mixtures. J. Supercrit. Fluids 1998, 11 (3), 151‒162. (23) Lin, E. C.; Huang, E. T. The Effect of Rock Wettability on Water Blocking during Miscible Displacement. SPE Res. Eng. 1990, 5 (2), 205‒212. (24) Heller, J. P.; Lien, C. L.; Kuntamukkula, M. S. Foamlike Dispersions for Mobility Control in CO2 Floods. SPE J. 1985, 25 (4), 603‒613.


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(25) Shetty, S.; Hughes, R. G.; Afonja, G. Experimental Evaluation of Simultaneous Water and Gas Injection using Carbon Dioxide. Presented at the SPE EOR Conference at Oil and Gas West Asia, Muscat, Oman, March 31‒April 2, 2014; Paper SPE 169690. (26) Fatemi, S. M.; Sohrabi, M. Recovery Mechanisms and Relative Permeability for Gas/Oil Systems at Near-Miscible Conditions: Effects of Immobile Water Saturation, Wettability, Hysteresis, and Permeability. Energy Fuels 2013, 27 (5), 2376‒2389. (27) Grogan, A. T.; Pinczewski, W. V. The Role of Molecular Diffusion Processes in Tertiary CO2 Flooding. J. Pet. Technol. 1987, 39 (5), 591–602.


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Table 1. Compositional Analysis Result of the Cleaned Steelman Original Light Crude Oil (ρoil = 0.819 g/cm3, µoil = 0.76 cP at the Atmospheric Pressure and Tres = 51.1 °C, MWoil = 188.8 g/mol, Well No.: 3-29-3-4W2) with the Asphaltene Content of wasp = 0.15 wt.% (nPentane Insoluble) carbon no.

mol.%

carbon no.

mol.%

C1

0.00

C27

0.84

C2

0.72

C28

0.80

C3

0.40

C29

0.65

C4

1.59

C30

0.57

C5

3.94

C31

0.57

C6

8.26

C32

0.53

C7

12.27

C33

0.37

C8

8.19

C34

0.34

C9

7.66

C35

0.41

C10

6.52

C36

0.31

C11

6.04

C37

0.30

C12

4.58

C38

0.21

C13

4.41

C39

0.27

C14

3.92

C40

0.27

C15

3.65

C41

0.13

C16

2.95

C42

0.12

C17

2.55

C43

0.17

C18

2.43

C44

0.17

C19

2.12

C45

0.10

C20

1.66

C46

0.10

C21

1.84

C47

0.09

C22

1.02

C48

0.08

C23

1.31

C49

0.08

C24

1.12

C50+

1.34

C25 C26

1.07 0.96

Total

100.00


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Table 2. Physical and Chemical Properties of the Cleaned Steelman Reservoir Brine at P = 1 atm (Well No.: 3-29-3-4W2)

temperature (°C)

15

20

40

density (g/cm3)

1.091

1.089

1.081

viscosity (cP)

1.52

1.34

0.81

pH at 20.0 °C

7.81

specific conductivity (µS/cm) at 25.0 °C

245,000

refractive index at 20.0 °C

1.3611

chloride (mg/L)

122,000

sulfate (mg/L)

4,800

potassium (mg/L)

2,190

sodium (mg/L)

59,700

calcium (mg/L)

2,190

magnesium (mg/L)

510

iron (mg/L)

2.1

manganese (mg/L)

Miscible CO2 Simultaneous Water-and-Gas (CO2-SWAG) Injection in

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