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Polymer Flooding Enhanced Oil Recovery Evaluated with Magnetic Resonance Imaging and Relaxation Time Measurements Ming Li, Laura Romero-Zeron, Florin Marica, and Bruce J. Balcom Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.7b00030 • Publication Date (Web): 03 Apr 2017 Downloaded from http://pubs.acs.org on April 8, 2017
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Polymer Flooding Enhanced Oil Recovery Evaluated with Magnetic Resonance Imaging and Relaxation Time Measurements Ming Lia,b, Laura Romero-Zerónb, Florin Maricaa, Bruce J. Balcoma,*
a
MRI Centre, Department of Physics, P.O. Box 4400, University of New Brunswick,
Fredericton, NB, Canada E3B 5A3 b
Department of Chemical Engineering, P.O. Box 4400, University of New Brunswick,
Fredericton, NB, Canada E3B 5A3
*Corresponding author Tel: (506) 458-7938 Fax: (506) 453-4581 E-mail:
[email protected] Keywords: Polymer flooding, enhanced oil recovery, SPRITE MRI, T2 log mean ratio, oil distribution, wettability, stripping mechanism
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Abstract Magnetic resonance imaging (MRI) and magnetic resonance (MR) T2 lifetime measurements were employed to monitor oil displacement by waterflooding and polymer flooding in two different rock core plugs. In-situ oil saturation profiles were determined from the MRI measurements. Water-wet and oil-wet core plugs saturated with crude oil and mineral oil showed different oil saturation profile changes and T2 relaxation time variations during core flooding. The T2 Log Mean Ratio (TLMR) is proposed to normalize T2 trends from different rock/fluid samples. The polymer stripping mechanism in the oilwet rock core plugs was consistent with in-situ oil saturation profile changes and relaxation time trends observed during oil displacement.
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1. Introduction Polymer flooding has been the subject of intense interest for enhanced oil recovery, worldwide, for many decades.1-8 Improvement of the macro sweep efficiency, due to a more favorable water/oil mobility ratio, is a well understood mechanism for polymer flooding. Whether or not polymer flooding can improve the pore level displacement efficiency is still controversial.1,4-6 Studies of micro scale mechanisms have primarily been undertaken with etched glass micro-models.2,6,7 Such models are however twodimensional,2 and they are not reservoir rocks. The mineralogy of a reservoir rock has a great influence on pore wettability9-11 and polymer retention/adsorption.12 In the current work, magnetic resonance imaging (MRI) was employed to monitor the in-situ oil saturation profile during waterflooding and polymer flooding. Magnetic resonance (MR) T2 lifetime measurements were undertaken to ascertain pore level changes in oil behavior. These measurements permit examination of the displacement mechanisms of polymer flooding for enhanced oil recovery in rock cores. MRI and MR relaxation time measurements have been employed in the petroleum industry to measure a wide range of rock and fluid system properties. These properties include fluid viscosity, fluid type, rock wettability, permeability, capillary pressure and pore size distributions.13-21 Romero-Zerón et al.16 employed MRI to visualize oil distribution during polymer flooding with different wettability conditions. Li et al.22 employed π-EPI MRI to map 3D oil saturation distribution at a low magnetic field to monitor core flooding processes. Mitchell et al.17 used 2D MR methods (T1-T2 and Diffusion-T2) to quantitatively monitor oil recovery during brine, polymer and alkalinesurfactant-polymer flooding. Marica et al.18 employed MRI to measure the spatially 3 ACS Paragon Plus Environment
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resolved porosity of rock core plugs. Thorsen et al.19 applied MRI and T2 measurements to determine porosity, fluid saturation, permeability and facies characterization of a chalk reservoir. Devereaux20 and Zhang et al.21 measured MR relaxation times and found that sandstone cores changed to more oil-wet conditions after contacting crude oil. Mitchell et al.23 applied MR Pulsed Field Gradient Diffusion measurements to investigate polymer flooding elastic turbulence mechanism in 3D porous structures. Li et al.24 employed k-t accelerated Spin-Echo Single Point Imaging to monitor oil displacement processes and acquired spatially and temporally resolved T2 relaxation distributions. A comprehensive review of MRI in rock core analysis has been provided by Mitchell et al.14 Wettability controls fluid flow behavior during flooding and is thought to affect oil recovery with polymer flooding.3,16,25,26 Fluid properties certainly affect oil recovery by polymer flooding. Crude oils with polar components tend to attach to pore surfaces, changing the wettability of the pore surface.9,10,27 Refined oil, largely non-polar, tends to occupy the center of pore spaces more so than is the case for crude oil in water-wet samples.10 In the current work, a crude oil and a light mineral oil were utilized in polymer flooding experiments. The T2 relaxation time distribution is commonly employed to characterize fluid behavior in rock cores, and many other physical systems.13,14 Experimental petroleum core flooding commonly takes several days to run. Therefore, many T2 distributions may be acquired while monitoring these core flooding processes. Spatially resolved T2 distributions result in still more data.24 The question then arises how best to analysis this data in a manner that reveals trends and permits comparison between experiments/samples. Plotting multiple distributions and attempting to describe changes 4 ACS Paragon Plus Environment
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in shape and/or peak position is clearly inadequate. There is merit to reduce each distribution to a number,28,29 which may then be plotted as a function of core flooding time. The logical choice for a single numeric description of the T2 distribution is the log mean which is commonly employed in core analysis. The T2 log mean does not entirely solve the problem in work such as that described here, since it is desired to consider trends in behavior for various fluids and different core plug types during flooding experiments. The answer we propose is to normalize the T2 log mean by the bulk T2 of the fluid (oil in this case) in the absence of the rock matrix. With this formalism, it is possible then to consider, in a single number, the differential effect of core plugs with different properties, water-wet or oil-wet for example. In addition, it is possible to determine the behaviors of different fluids during dynamic flooding experiments. The desired normalization and simplification of distribution data is achieved with the T2 log mean ratio (TLMR) proposed in this work. MRI and T2 relaxation time measurements were employed in this study to generate in-situ oil saturation profiles, to determine the oil recovery factor, and to calculate TLMR during waterflooding and polymer flooding. The water phase viscosity increase mechanism1,4,30 and the stripping mechanism4,6 of polymer flooding explain the observed macroscopic and microscopic effects. 2. Materials and Methods 2.1. Fluids. H2O brine, 1 wt% NaCl, was employed for core plug saturation and for permeability tests. D2O (99.9 %, CDN Isotopes Inc., QC, Canada) brine, 1 wt% NaCl, was employed to distinguish oil and water phases in MR/MRI experiments. A
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viscoelastic Alcoflood 935 polymer (Ciba Specialty Canada Inc., ON, Canada), with a molar mass ranging from 8×106 to 10×106 g/mol,16 was employed. A polymer solution, 0.6 wt% concentration, was prepared from D2O brine for core flooding. At a shear rate of 7 s-1, the viscosity of the polymer solution was 130 mPas. Alcoflood 935 polymer has been widely employed for enhanced oil recovery in laboratory experiments and in field applications.16,31-33 Control experiments and previous work showed that the contribution of 1H in the polymer to the solution MR/MRI signal was negligible.22,24 Brine and polymer solution were degassed under vacuum to remove air before injection into the core plugs. A light mineral oil (Sigma-Aldrich, USA), largely non-polar, and a crude oil (Stoney Creek Field, Canada) with polar components34 were employed. Their densities were 0.84 g/cm3 and 0.87 g/cm3, respectively, at ambient temperature. Their viscosities were 27 mPas and 79 mPas, respectively, at 25 °C. The interfacial tension between the mineral oil and brine, and between crude oil and brine, was 51 mN/m and 53 mN/m, respectively. 2.2. Core Plugs, MRI and T2 Measurements. Water-wet Buff Berea core plugs (Kocurek Industries, Caldwell, TX, USA) and oil-wet synthetic core plugs (Northeast Petroleum University, China) were employed in this work. The Synthetic core plugs were natural sands consolidated with epoxy resin. The core plugs physical properties are listed in Table 1. The estimated average pore throat radii are approximately 3 µm for the four core plugs. Three different MR/MRI measurement methodologies were employed to determine the macro-scale oil saturation profile and micro-scale oil behavior (pore scale) during waterflooding and polymer flooding. 6 ACS Paragon Plus Environment
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(i) The bulk Free Induction Decay (FID) was employed to determine the oil saturation and to calculate oil recovery. The FID signal was Fourier transformed to obtain the spectrum. The oil saturation is proportional to the area under the curve in the spectrum when the water phase is D2O. The oil saturation and oil recovery were calculated based on periodic FID measurements. (ii) The Carr-Purcell-Meiboom-Gill (CPMG) method was utilized to measure the T2 distribution of oil in core plugs and bulk oil. When short echo times are employed in low static field measurements,35 as in this work, the T2 of pore fluids is affected by two mechanisms, with rates additive as the reciprocal of the lifetimes
1 1 1 = + T2 T2,Bulk T2,Surf
(1)
where T2,Bulk is the bulk transverse relaxation time and T2,Surf is the surface transverse relaxation time. The surface relaxation rate (1/T2,Surf) of the wetting phase in a single pore in the fastdiffusion limit is given by36 1 T2,Surf
S = ρ2 V
(2)
where ρ2 is the surface relaxitivity, S is the contact area of the wetting fluid and pore surface and V is the volume of the wetting-phase. (iii) The Double Half k-space Single Point Ramped Imaging with T1 Enhancement (DHK SPRITE)37 MRI method was employed to measure in-situ oil saturation profiles
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along the core plug during core flooding. The image intensity, SI, which is proportional to the oil saturation, for centric scan SPRITE methods is given by −t SI = SI 0 exp *p T2
sin α
(3)
where SI0 is the initial signal intensity, tp is the encoding time, T2* is the effective spinspin relaxation time, α is the flip angle of the radio frequency pulse. tp and α are constant, while T2* is assumed quasi-constant during flooding.16,38 Centric Scan SPRITE MRI has been demonstrated as an accurate technique to quantify the spatially resolved fluid content in porous media, providing results that are consistent with material balance.16 The SPRITE MRI resolution was 1.2 mm in the current work. Two home built programs, Unisort and Acciss, written in the IDL environment (Exelis VIS, CO, USA), were employed to process the MR image data. A Hanning filter was applied when reconstructing the MR images. WinDXP Inverse Laplace Transform software (Oxford Instruments Ltd., UK) was utilized to determine the T2 distribution to calculate the TLMR. 2.3. Oil Recovery, In-situ Oil Saturation Profiles and TLMR. The oil saturation So, calculated based on FID measurements, is given by
So =
SI oil SI H2O ⋅ HI
(4)
where SIH2O is signal intensity when a core plug was fully saturated with H2O brine, SIoil is the signal intensity when the same core plug was saturated with oil and D2O brine, HI is the oil hydrogen index. HI was 1.014 for crude oil and 1.023 for mineral oil.
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The in-situ oil saturation profile along core plugs was determined by the DHK SPRITE MRI signal intensity at each pixel of the MR images. The oil saturation calculated based on SPRITE measurement is given by22
So =
tp tp SI o exp * − * HI ⋅ SI w T2o T2 w
(5)
where SIw is the signal intensity when the sample is fully saturated with H2O brine, SIo is the signal intensity when the core plug was saturated with oil and D2O brine, HI is the oil hydrogen index, tp is the encoding time, T2o* is the effective spin-spin relaxation time of oil and T2w* is the effective spin-spin relaxation time of water in the core plug. The oil recovery during flooding was estimated by Oil Recovery =
S o,i − S o,rem S o,i
× % OOIP
(6)
where So,i is the initial oil saturation before flooding and So,rem is the remaining oil saturation during flooding. OOIP is original oil in place. The T2 Log Mean (T2LM) is given by28
T2LM
∑n [Pi (T2i ) ⋅ ln (T2i )] = exp i =1 n ∑i=1 Pi (T2i )
(7)
where T2i are the discrete values of the relaxation times, Pi(T2i) are the corresponding probabilities.28 TLMR is defined as
TLMR =
T2LM, porous T2LM, bulk oil
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where T2LM, porous is the T2LM of oil in porous media and T2LM, bulk oil is T2LM of bulk oil. In this work, T2LM of the bulk mineral oil and bulk crude oil were 92 ms and 65 ms, respectively. 3. Experimental 3.1. Experimental Setup. Figure 1 shows a schematic of the experimental setup for core flooding and MRI monitoring of the flooding process. The flooding apparatus includes a Dual 100-DX pump (Teledyne ISCO, NE, USA) for fluid injection, three piston-accumulators for oil, D2O brine and polymer D2O solution, respectively, and a homemade core holder which is compatible with the magnetic resonance environment. MRI and T2 measurements were performed on a 0.20 Tesla Maran DRX permanent magnet spectrometer (Oxford Instruments, UK). The 1H resonance frequency was 8.54 MHz. A homemade solenoid RF probe with 1.75 inch inside diameter was employed. The differential pressure across the core plug was monitored with an OMEGA digital pressure transducer (OMEGA Engineering, Laval, QC, Canada). The liquid viscosity was measured with a Bohlin Gemini HR 150 Nano Rheometer (Malvern Instruments, Malvern, UK). The oil and brine interfacial tension was measured with a M6500 Spinning Drop Tensiometer (Grace Instrument, Houston, TX). 3.2. Experimental Procedure. Core plugs were dried at 100 °C to a constant weight and then saturated with 1 wt% NaCl H2O brine. Pore volume (PV) of each core plug was determined through the conventional gravimetric procedure (i.e. weight difference before and after brine saturation converted to volume using the density of the brine). Then, porosity was calculated as the ratio of PV to the bulk volume of the corresponding core plug. H2O brine was injected into core plugs at several constant flow rates while the 10 ACS Paragon Plus Environment
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corresponding differential pressures were recorded, then the absolute permeability to brine was determined based on Darcy’s Law. 39 The average pore throat radius was estimated with the Kozeny-Carman correlation.39 D2O brine was injected to displace H2O brine. DHK SPRITE MRI measurements monitored this displacement. D2O injection ceased when the MRI profile intensity was constant. After displacement of H2O brine with D2O brine, the oil phase was injected to displace D2O brine until no further water production was observed. The oil was then injected from the other end to generate a homogenous initial oil saturation distribution. The oil injection rates were 0.4-3 ml/min, depending on the core wettability and the oil viscosities. Usually 5 to 6 PV oil phase was injected to establish initial oil saturation (Soi) and irreducible water saturation. DHK SPRITE MRI measurements monitored the process of oil displacing water. Table 1 shows Soi and the oils employed for each core plug. The oil saturated core plug was aged overnight inside of the core holder and then waterflooding commenced. D2O brine was the water phase. Waterflooding was switched to polymer flooding after approximately 3 PV waterflooding. 3 PV of water flooding was chosen for all core flooding experiments as a compromise between experimental time and sufficient oil recovery. The volume flow rate was 0.1 ml/min (equivalent to a superficial velocity of 0.42 ft/day) for each core plug during waterflooding and polymer flooding. Flooding was undertaken at 25 °C. The effluent was collected in graduated cylinders. The viscosity of water phase effluent from polymer flooding was measured at a shear rate of 7 s-1.
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Three MR/MRI measurements, FID, CPMG and DHK SPRITE MRI, were employed to monitor oil content variation, T2 and oil saturation profiles during waterflooding and polymer flooding. The MRI and T2 measurement parameters are reported in Table 2. 4. Results and Discussion 4.1. In-situ Oil Saturation Profiles and Oil Recoveries. Figure 2 shows in-situ oil saturation profiles during waterflooding and polymer flooding in the four core plugs. Polymer flooding was initiated after approximately 3 PV waterflooding in each core plug. Figures 2 (a) and (b) show that the oil saturation decreased quickly as waterflooding (D2O) was initiated, then decreased slowly as waterflooding progressed in the water-wet Buff Berea core plugs BB11 and BB21. Polymer flooding mobilized the upstream mobile oil in the BB11 and BB21 core plugs. This moving upstream oil merged with the downstream mobile oil, increasing the volume of the oil bank, showing a clear moving boundary displacement. The oil bank formation is consistent with Wang et al.,7 who named it the "snowball" effect. After the front edge of the oil bank arrived at the outlet of the core plug, its volume began to decrease and the oil saturation decreased rapidly. The magnitude of the crude oil bank in the core plug BB21 is larger than that of the mineral oil in the core plug BB11 during polymer flooding. MRI measurements directly reveal the creation of the oil bank spatially and temporally resolved. This is not readily achieved with other measurement methods. The Buff Berea core plugs BB11 and BB21 were water-wet, in which, oil tends to saturate the center of pores.40,41 Polymer flooding increases the viscosity of the water phase, increasing the viscous forces and improving oil displacement. In this case, it is reasonable to deduce that polymer flooding will firstly mobilize the trapped oil in the 12 ACS Paragon Plus Environment
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inlet of a core plug, and then merge it with the mobile oil in the downstream section of the core plug to form an oil bank. The mobilized oil should mainly flow through the center of large connected pores during polymer flooding.42 The viscosity increase for the water phase during polymer flooding can decrease mobility ratio and increase capillary number, both may have contributed to the oil recovery improvement. The crude oil in the BB21 core plug may have changed the wettability of this sample to be less water-wet than the BB11 core plug with mineral oil. This is discussed below in conjunction with TLMR results. Figures 2 (c) and (d) show that oil saturation decreased dramatically at the beginning of waterflooding and then decreased very slowly in the two oil-wet synthetic core plugs S241 and S211. Unlike the oil bank observed in the Buff Berea core plugs, polymer flooding decreased the oil saturation in all cross-sections of the core plugs from the inlet to the outlet in the oil-wet core plugs S241 and S211. Significant oil saturation was observed at the outlet of the S241 and S211 core plugs at the end of waterflooding, and at the outlet of the S211 core plug at the end of polymer flooding. In the oil-wet core samples S241 and S211, oil prefers to occupy small pores and contact large pore surfaces due to solid-fluid interactions.6,40-42 According to Wang et al.6 and Mohammad et al.,43 polymer flooding can reduce the surface oil layer thickness through a stripping mechanism due to the elastic property of polymer solutions. In this case, it is reasonable to assume that the oil layer would become gradually thinner during continuous polymer flooding. This is consistent with the observation that polymer flooding gradually decreased the oil saturation simultaneously throughout the oil-wet core plugs shown in Figures 2 (c) and (d). Additional evidence for this stripping behavior 13 ACS Paragon Plus Environment
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in oil-wet core plugs is reported below in conjunction with TLMR results. Increased oil recovery during polymer flooding due to viscoelasticity has been studied.6,7,44 Figures 3 (a) and (b) show the remaining oil saturation distribution in the four core plugs at the end of waterflooding and at the end of polymer flooding, respectively. In Figure 3 (a), the water-wet Buff Berea core plugs, BB11 and BB21, have relatively homogeneous remaining oil saturation distribution compared to oil-wet synthetic core plugs, S241 and S211. Higher oil saturation is observed at the outlet of the S241 and S211 core plugs. This is consistent with an oil-wet capillary end effect.45,46 MRI of capillary end effects have been employed as an advantage to determine petrophysical information such as relative permeability.47 In Figure 3 (a), the capillary end effect extended over most of the length in the S241 core plug, while the end effect was confined to the vicinity of the outlet of the S211 core plug. Figure 5 below shows that the differential pressure across the S211 core plug was higher by approximately an order of magnitude compared to that across the S241 core plug during water flooding. This is largely due to the oil viscosity difference, 79 mPas for crude oil and 27 mPas for mineral oil. The interfacial tensions between the crude oil and brine, and between the mineral oil and brine were near identical, 53 mN/m and 51 mN/m, respectively. Therefore, the capillary number40 for the S211 core plug was approximately an order of magnitude higher compared to that for the S241 core plug. A low capillary number will result in an extended capillary end effect along a core plug.48 In Figure 3 (b), higher crude oil saturation is still observed for the S211 core plug at the end of polymer flooding; while for the S241 core plug, the oil saturation distribution is relatively homogeneous compared to S211. This suggests that polymer flooding 14 ACS Paragon Plus Environment
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overcame the capillary end effect in S241 with mineral oil but not in S211 with crude oil. It is reasonable to assume in the twin oil-wet core plugs, that crude oil generated more oil-wet behavior in S211 than mineral oil in S241. This assumption is consistent with the TLMR results below. Figure 4 compares the oil recovery increase in the four core plugs during waterflooding and polymer flooding. The oil recoveries, calculated based on FID measurements, agree with the SPRITE MRI measurements. Conventional mass balance methods yield oil recovery for the entire core plug. SPRITE MRI measurement provides the oil recovery results in different positions of the core plug. The oil recoveries from the core plug front and rear sections were calculated based on SPRITE MRI results. Figure 4 (a) shows the oil recovery changes for the water-wet Buff Berea BB11 core plug. During waterflooding, the trends of the oil recovery increase for the core plug front and rear sections are similar. During polymer flooding, the oil recovery in the core plug front section increased earlier than that in the rear section due to the oil bank moving forward, as shown in Figure 2 (a). The final oil recovery from the core plug BB11 front and rear sections was almost identical (48.4 vs. 48.7 % OOIP). Figure 4 (b) shows the oil recovery change for the Buff Berea BB21 core plug that had a similar oil recovery trend to the BB11. Figure 4 (c) shows the oil recovery increase for the oil-wet S241 core plug, initially saturated with mineral oil and irreducible water (D2O). The waterflooding oil recovery in the core plug front section and rear section was significantly different, 47.8 % OOIP and 24.1 % OOIP, respectively. The lower oil recovery from the rear section can be ascribed to the capillary end effect as shown in Figure 2 (c). After polymer flooding, the final oil 15 ACS Paragon Plus Environment
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recovery in the front and rear sections was 55.4 % OOIP and 52.6 % OOIP, respectively. Polymer flooding largely overcame the capillary end effect, diminishing the oil recovery difference between the core plug front and rear sections. The polymer flooding suppression of capillary end effects is attributed to higher differential pressure49 due to viscous effects (i.e. the higher the viscosity of the polymer solution, the higher the differential pressure across a core plug) as illustrated in Figure 5. Figure 4 (d) shows the oil recovery increase for the oil-wet S211 core plug that also displays differences between the front and rear sections. The differences were 7.8 % OOIP (35.7 vs. 27.9 % OOIP) and 10.1 % OOIP (50.6 vs. 40.5 % OOIP) from waterflooding and polymer flooding, respectively. Polymer flooding did not overcome the capillary end effect in the S211 core plug, and thus did not diminish the oil recovery difference between the front and rear sections in the core plug. The oil recovery in S211 continued to increase at the end of water flooding (not a plateau level). Polymer flooding increased the oil production rate, increasing the oil recovery compared to water flooding with the same fluid injection volume. Figure 5 shows the differential pressure (∆P) across core plugs during waterflooding and polymer flooding. Polymer flooding greatly increased the differential pressure, suggesting that viscous force increased in the core flooding processes.40 Thus polymer flooding displaced more oil after waterflooding. During polymer flooding, the largest differential pressure was observed for the S211 core plug with crude oil. The differential pressure across S211 is larger than that across S241 with mineral oil probably due to the higher crude oil viscosity, 79 mPas, compared to the mineral oil viscosity, 27 mPas.
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During polymer flooding, the differential pressure across the BB11 core plug with mineral oil was higher than that across the BB21 core plug with crude oil, although the viscosity of crude oil was higher by a factor of 3 than that of mineral oil. It is assumed that there was an interaction between the crude oil polar components34 and the BB21 pore surface, rendering it a less water-wet pore surface and decreasing the possibilities of polymer adsorption on the pore surface.12 However, for the mineral oil, lacking polar components in the BB11 core plug, strong water wettability of the core plug may result in more polymer adsorption. Polymer adsorption can decrease the rock core absolute permeability,40,49 increasing the differential pressure across the core plug. Increased oil wettability for the BB21 core plug with crude oil is validated by the TLMR results reported later. Approximately 3 PV polymer solution was injected to displace oil in each core plug after waterflooding. Figure 6 shows the viscosity (µ) of the water phase effluent for the four core plugs during polymer flooding. The viscosities increased as the polymer concentration increased in the effluent until constant concentrations were established for each core flooding. When the water phase effluent viscosity increased, the oil recovery increased rapidly (Figure 4). When the viscosity constant level, the oil recovery increased slowly for the S211 core plug and increased little for the other three samples. The viscosity of the water phase effluent for the core plug S211 with crude oil increased faster than that for the identical core plug S241 with mineral oil. The viscosity of the water phase effluent for the oil-wet synthetic core plugs, S211 and S241, increased faster than the water-wet Buff Berea core plugs, BB11 and BB21 (only considering the first four time points corresponding to 0-1.5 PV polymer solution injection). These differences
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may be related to greater oil wettability for the S211 core plug with crude oil compared to the S241 core plug with mineral oil, and the greater oil wettability for the synthetic core plugs compared to the Buff Berea core plugs. Oil wettability decreases the possibility of polymer adsorption on the pore surface.12 On the contrary, stronger water wettability results in more polymer adsorption, slowing the transport of polymer49 and reducing the concentration of polymer in the effluent, causing a lower water phase effluent viscosity.50 4.2. TLMR and Pore Scale Fluid Behavior. The T2 relaxation time distribution is often used to characterize the fluid behavior in rock cores.13 Figure 7 shows the T2 distribution of bulk oil and oil in the four core plugs before flooding, after waterflooding and after polymer flooding. The obvious change is the signal amplitude decease (y-axis) after waterflooding and after polymer flooding. The T2 peak value (x-axis) did not significantly vary after waterflooding and polymer flooding. CPMG measurements were undertaken to monitor the four core flooding processes. Repetitive T2 distribution curves were acquired based on CPMG measurements for each core plug. Visual differences between the curves are challenging to observe and interpret. A simple numeric average is a better metric compared to the T2 distribution curves. T2 values are affected by the rock matrix and viscosity of the bulk oil.13 Higher viscosity oils usually have shorter bulk T2s.13 In this work, the T2 log mean ratio (TLMR) (Equation 8) is employed to normalize T2 change from different rock/fluid samples. Guan et al.51 considered the ratio of arithmetic mean relaxation times at initial water saturation and residual oil saturation stages to minimize the influence of pore size and geometry to determine wettability effects in core plugs. The T2 log mean is less sensitive than the 18 ACS Paragon Plus Environment
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arithmetic mean to change in the extremes of the discrete values of the relaxation distribution.28 T2 log mean is traditionally employed in MR studies of fluids in rock cores.52 Figure 8 shows the T2 log mean (T2LM) for the four core plugs during waterflooding followed by polymer flooding. Polymer flooding commenced at approximately 3 PV of water injection. The T2LM was determined from bulk CPMG T2 measurements and calculated according to Equation (7). T2LM of mineral oil in the BB11 core plug was longer than in the S241 core plug. T2LM of crude oil in the BB21 core plug was longer than in the S211 core plug. These comparisons are consistent with their wettability properties: BB11 and BB21 are more water-wet than S241 and S211. The T2LMs of mineral oil were always longer than that of crude oil in the four core plugs. Figure 9 shows TLMR for the four core plugs measured during waterflooding and polymer flooding. The TLMR was calculated according to Equation (8). Normalization by the bulk oil T2LM tells one immediately if the oil in question has its pore level behavior modified by the rock matrix. For the water-wet Buff Berea core plugs BB11 and BB21, TLMR slightly increased, and for the oil-wet synthetic core plugs S241 and S211, TLMR decreased when waterflooding commenced (0-0.5 PV). TLMR of mineral oil in the water-wet BB11 core plug remained at essentially 1 throughout the flooding experiment. This suggests that mineral oil in the pore space behaves like bulk oil saturating the center of the pores and polymer flooding has no effect on the pore scale behavior despites substantial changes in saturation as revealed in Figure 2 (a).
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In Figure 9, for the BB21 core plug, TLMR ranged between 0.91 and 0.94, always less than 1, during the flooding experiment. This suggests that the crude oil behavior is affected by the pore surfaces. Crude oil, e.g. through its polar molecules, could be adsorbed on the pore surface, increasing local oil wettability in rock cores, unlike nonpolar refined oil.10,27 Pore surface relaxation decreased T2,36 thereby decreasing TLMR. For the synthetic core plug S241 initially saturated with mineral oil and irreducible water (D2O), TLMR varied from 0.84 to 0.80 during the flooding process. TLMR for mineral oil in the S241 core plug was less than that of crude oil in BB21 core plug although mineral oil had a longer T2LM than crude oil. This may be attributed to the core plug wettability differences. The oil-wet S241 core plug depressed the relaxation time of mineral oil to a greater degree than the water-wet BB21 core plug depressed the relaxation time of crude oil. The synthetic core plug S211, in Figure 9, had TLMR change from 0.75 to 0.70 during flooding. TLMR for crude oil in the S211 core plug was less than that of mineral oil in the S241 core plug. This suggests more interactions between crude oil and the pore surface in the S211 core plug compared to mineral oil in the S241 core plug. Figure 10 shows the TLMR parameter plotted as a function of fluid injected volume as polymer flooding commenced for the four core plugs. In Figure 10 (a), TLMR did not change for the Buff Berea BB11 core plug with mineral oil when waterflooding switched to polymer flooding. This again suggests that mineral oil in the pore space behaves like bulk oil (i.e. oil in the center of pores). This is consistent with the behavior expected for a non-polar oil in a water-wet sample.
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In this work, the CPMG measurement signal-to-noise-ratio (SNR) was defined as the average signal amplitude of the first 4 echoes divided by the standard deviation of the last 64 echo amplitudes (at noise level). For the BB11, BB21, and S241 core plugs, the SNR was approximately 650 during 2-3 PV water flooding and greater than 450 during 4-5 PV polymer flooding. These SNR values were sufficient to ensure high-quality T2 distributions and thus reliable TLMR values. The uncertainty in the TLMR measurement may be evaluated through data such as that displayed in Figures 9 and 10. During intervals when TLMR is quasi-constant (2-3 PV water flooding and 4-5 PV polymer flooding), one may calculate a mean and a standard deviation. For the water-wet core plug BB11 (a), the standard deviation, and thereby uncertainty of the TLMR measurements in Figure 10 (a) is approximately 0.005 during water flooding and approximately 0.003 during polymer flooding. For the core plug BB21 (b), the TLMR uncertainty was approximately 0.003-0.004. The TLMR uncertainty for the oil-wet samples S241 (c) and S211 (d) is less, close to 0.001-0.002, although it is difficult to calculate in the case of (d) since the TLMR is changing throughout the data interval (Figure 4 (d) shows that the oil recovery was increasing during 2-3 PV water flooding and 4-5 PV polymer flooding). Similar uncertainties may be derived from the data of Figure 9 in the flooding interval ranging from 1-3 PV. The error bars in Figures 10 (a)-(c) show the estimated TLMR uncertainties. Observed changes in the TLMR in Figures 10 (b)-(d) are larger than the uncertainties, suggesting the changes are real. In Figure 10 (b), the TLMR is observed to decrease for the Buff Berea BB21 core plug with crude oil as polymer flooding commenced. If we assume that polymer solution 21 ACS Paragon Plus Environment
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will preferentially displace crude oil in the pore center rather than the oil attached to the pore surface, then the average T2 should shift to shorter T2 lifetime. Figures 2 (c) and (d) showed that polymer flooding decreased oil saturation simultaneously in each cross-section of the oil-wet core plugs. Previous discussion in Section 4.1 connected this behavior to the polymer flooding stripping mechanism. This mechanism is examined via the trends in TLMR results in Figures 10 (c) and (d). For the core plug S241 with mineral oil (c), TLMR quickly decreased from approximately 0.825 (2-3 PV data average) to a constant level, approximately 0.802 (4-5 PV data average) after polymer flooding commenced. For the core plug S211 with crude oil (d), TLMR decrease continued when 5 PV fluids was injected. The TLMR difference between S241 with mineral oil and S211 with crude oil is consistent with Figures 2 (c) and (d) (also with Figures 4 (c) and (d)). In Figure 2 (c), mineral oil saturation in the S241 core plug quickly reached quasi-constant level when polymer flooding commenced (3 to 4 PV). In Figure 2 (d), crude oil saturation in the S211 core plug continued to decrease during polymer flooding (3 to 6 PV). In the process of oil layer thinning during waterflooding and polymer flooding, one assumes the volume of oil in the core plugs will decrease while the contact area between oil and the pore surface will not change assuming constant wettability. In Equation (2), V is the oil volume, S is the contact area of the oil and pore surface which is assumed constant, as is the relaxivity ρ2.29,53 Polymer stripping with V decreasing for constant S will result in a TLMR decrease. As shown in Figures 10 (c) and (d), TLMR
