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Study impact of sample treatment and insitu fluids on shale wettability measurement using NMR
Journal of Petroleum Science and Engineering 176 (2019) 352–361
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Study impact of sample treatment and insitu fluids on shale wettability measurement using NMR
T
Ishank Gupta∗, Chandra Rai, Carl Sondergeld The University of Oklahoma, USA
A R T I C LE I N FO
A B S T R A C T
Keywords: SRA NMR wettability Preserved wettability Cleaned wettability Dried wettability
Nuclear Magnetic Resonance (NMR) is a good alternative to conventional Amott-Harvey imbibition test or US Bureau of Mines (USBM) test, to measure wettability in shales. The conventional methods do not work primarily because of the long time it takes to flow through the nano pores in the shales. Contact angle measurements typically used in shales do not account for pore connectivity. Hence, NMR is becoming a standard reliable method to measure wettability in shales. This study focuses on two aspects of wettability measurement in shales. First, Looyestijn and Hofman (2006) proposed an equation to calculate wettability using NMR data based on their experiments on carbonate rocks. Sulucarnain et al. (2012) applied this method to shales. In their method, the residual fluids in the plugs are neglected because it is difficult to ascertain what proportion of residual fluids is hydrocarbon and what proportion is water. However, in liquid-rich shales like Eagle Ford, there could be significant amount of residual fluids which must be accounted in the wettability calculation. This study integrates Source Rock Analysis (SRA), NMR and helium porosity data to determine the nature of the residual fluids and account for them while doing wettability calculations. Thus, an improved equation for wettability is proposed by modifying the original equation. Second, in this study, wettability measurements on preserved, dried and cleaned sample states were carried out. The comparison of the three states suggest that drying and cleaning the samples, changes the original wettability of the system and make the rocks appear more oil wet. The effects of drying are more pronounced than cleaning. The above argument is supported both by SRA data and Scanning Electron Microscope (SEM) images. The SRA data shows an increase in S1 and a corresponding decrease in S2 peak which suggests that heating the sample at 100 °C may crack the heavy hydrocarbons in the sample. The SEM image analysis also show the possible movement and resolidification of bitumen and other heavy hydrocarbons. These mobile fractions are believed to flow into the water-wet pores and turn them oil-wet.
1. Introduction
reduction of mechanical strength and Young's modulus (Gupta et al., 2017a), fracture design and stimulation methods. The most commonly used methods for wettability calculation in conventional reservoirs are Amott-Harvey imbibition test and US Bureau of Mines (USBM) test (Donaldson et al., 1969). The conventional methods do not work in shales primarily because of the low porosity and permeability in the shales. Contact angle measurements have been used by many researchers to calculate the wettability in shales (Teklu et al., 2015; Zeng et al., 2018; Okasha, 2018). However, this method is affected by surface roughness and does not account for pore connectivity. In unconventional shales, due to large heterogeneity (TOC, clays, quartz, etc.) and complex wettability systems, the wettability at the surface can be very different from the actual wettability of
Wettability governs the ability of a certain fluid to wet a solid surface compared to another fluid. The key variables that control wettability are oil composition, brine chemistry and rock matrix composition (Anderson, 1986). Mathematically, it is a balance between the surface and the interfacial forces. The wettability plays an important role in governing other petrophysical properties like residual saturations, relative permeabilities, saturation estimates from logs, etc. This means that wettability controls the well productivity, water flood performance and selection of EOR methods. (Donaldson et al., 1969; Jennings, 1987; Abdallah et al., 2007). In unconventional reservoirs like shales, wettability is also critical to proppant embedment,
∗
Corresponding author. E-mail address: [email protected] (I. Gupta).
https://doi.org/10.1016/j.petrol.2019.01.048 Received 9 October 2018; Received in revised form 26 December 2018; Accepted 13 January 2019 Available online 14 January 2019 0920-4105/ © 2019 Elsevier B.V. All rights reserved.
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made at ambient temperature and pressure conditions using the CPMG pulse sequence. The minimum signal to noise ratio was around 50 and a minimum of 300 scans were taken for each sample. To measure wettability, two sequences of fluid imbibition were carried out with the two parallel plugs acquired at each depth. The preserved or native spectra of the parallel plugs were compared to confirm that the plugs were identical or very similar. In Sequence 1 (SQ1), one of the plugs was imbibed in 2.5% KCl brine for 60 h followed by NMR T2 measurement. Thereafter, the same plug was spontaneously imbibed with dodecane for 60 h followed by NMR T2 measurement. In Sequence 2 (SQ2), the reverse process was followed with the other plug. The plug in SQ2 was first imbibed with dodecane followed by 2.5% KCl brine. Brine and dodecane have different hydrogen index. A correction was applied to the dodecane spectra for the differences in the hydrogen index so that the brine and dodecane spectra can be compared. This was done by measuring the NMR T2 response of same volume of bulk fluids (brine and dodecane) and then taking the ratio. The ratio was then used to correct the T2 spectra of dodecane. For the first plug (SQ1), we measured native state (preserved, dried or cleaned depending on the experiment) T2 porosity, then brine imbibed T2 porosity and finally dodecane imbibed T2 porosity. We can get incremental water imbibed by subtracting the native T2 porosity from brine imbibed T2 porosity. Similarly, we can get incremental dodecane imbibed by subtracting the brine imbibed T2 porosity from dodecane imbibed T2 porosity. In the second plug (SQ2), we measured native state T2 porosity, then dodecane imbibed T2 porosity and finally brine imbibed T2 porosity. Using this data, we got the incremental dodecane imbibed (subtracting native T2 porosity from dodecane imbibed T2 porosity) and incremental brine imbibed (subtracting dodecane imbibed T2 porosity from brine imbibed T2 porosity). The process to get incremental imbibed volumes can be done in two ways. First, directly subtracting the T2 measured porosities. Second, subtracting the raw signals and then inverting it to porosity. For more accuracy, the second method was followed. Wettability was calculated for each sequence using the formula given below (Looyestijn and Hofman, 2006; Sulucarnain et al., 2012).
the connected pore network. Lan et al. (2014) observed intact Horn River shale samples to be primarily water wet but the wettability measured on same samples in crushed state showed they were oil wet. They concluded that the connected pathway in the Horn River shale samples is water wet while the remaining majority of the rock is oil wet. NMR has been proposed as an alternative to measure wettability in shales. Several NMR based methods have been proposed in the literature to determine wettability of rocks. Majority of these methods have been applied to conventional sandstone and carbonate reservoirs (Hsu et al., 1992; Howard, 1998; Fleury and Deflandre, 2003; Looyestijn and Hofman, 2006). Valori and Nicot (2018) presented a review of the different NMR methods to calculate wettability developed in last six decades. They also pointed out the methods such as T1/T2 ratio, restricted diffusion, etc. which can be potentially applied in the field. Some of these methods especially saturation based (Looyestijn and Hofman, 2006) have been recently applied to unconventional shales (Odusina, 2011, Sulucarnain et al., 2012; Gannaway, 2014; Wang et al., 2018). These authors proposed T2-spectrum based models to characterize wettability of several oil and gas shale reservoirs namely Woodford, Wolfcamp, Eagle Ford, Barnett, Longmaxi, among others. The authors also observed that higher TOC generally causes higher oilwet character while higher clay content causes higher water-wet character in the shales. Developing accurate methods to determine the wettability is not enough for measuring accurate wettability of the insitu-state rock. This is because the native wettability of the reservoir core samples can be affected and altered by the coring and core handling processes: during coring and core recovery, through invasion of and contact with, drilling mud components/additives; pressure and temperature losses; and potential oxidation of oil and/or rock components (Velazco et al., 2018). Some of these concerns may not be applicable to shales because of their ultra-low permeability but the same property can make it extremely difficult to restore samples to insitu state by aging with reservoir crude oil (Anderson, 1986), which is routinely done in the conventional rocks. Thus, preserved state samples are the closest proxy to the insitu-state samples and should give the most relevant wettability. In this study, the impact of sample treatment (like cleaning and drying the samples) on the wettability is studied which can further help understand the impact of various core recovery and laboratory processes on the sample wettability. Okasha (2018) studied the effect of temperature and pressure on wettability. He found that increasing temperature and aging time increased the contact angle and hence, made the rock more oil-wet. Okasha (2018) used both dead oil and live oil for these experiments. He used calcite mineral and rock samples (calcite > 90%) as substrates. The measurements were made at various temperatures and pressures (up to 90 °C and 3000 psig).
NMR Iw =
NMR (Sw ) − NMR (Sdo) NMR (Sw ) + NMR (Sdo)
(1)
where NMR (Sw) and NMR (Sdo) are the amount of brine and dodecane imbibed by the samples (NMR T2 porosities in cc) divided by the helium porosity of the sample (fraction). Both for SQ1 and SQ2, we have incremental brine and dodecane porosities from the NMR T2 measurements. Thus, we get a wettability index each for SQ1 and SQ2 which can be averaged to get the wettability index for that particular sample depth. The wettability index from NMR (NMR Iw) varies between −1 and 1. The value of 1 represents completely water wet while value of −1 represents completely oil wet. The value of 0 represents neutral wet. Values between −0.5 and 0.5 generally represent mixed wet. Values between 0.5 and 1 represent strongly water wet while between −0.5 and −1 represent strongly oil wet.
2. Experimental procedures The study used three set of samples belonging to different formations namely Devonian-Mississippian, Eagle Ford and Green River. The preserved samples were available in Devonian-Mississippian and Eagle Ford, while outcrop samples were taken for Green River shale. The samples were preserved by immediately wrapping them with saran wrap and aluminum foil upon recovery and then dip in wax. The Devonian-Mississippian samples belonged to gas maturity window, Eagle Ford samples belonged to oil maturity window and Green River samples were immature. Different petrophysical measurements were carried out as a part of this study namely NMR-based wettability, mineralogy, helium porosity, TOC, SEM images and SRA.
2.2. Mineralogy The mineralogy of the samples is determined using transmission Fourier Transform Infrared Spectroscopy (FTIR). Different minerals have different signatures on the absorbance spectrum. The inversion package developed in house allows quantification (in wt. %) of the following 16 minerals; quartz, calcite, dolomite, aragonite, siderite, oligoclase, albite, orthoclase, illite, chlorite, kaolinite, smectite, mixedlayer clays, apatite, anhydrite, and pyrite. The detailed procedure is explained by Sondergeld and Rai (1993), Ballard (2007).
2.1. Wettability Wettability measurements were done using spontaneous imbibition. NMR was acquired using an Oxford Geospec2TM, at a frequency of 12 MHz and using an echo-spacing of 57 μs. The measurements were 353
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2.3. Total organic carbon (TOC)
4. Results
TOC measurements were done using dry pyrolysis technique (Law, 1999). The sample was crushed to fine particles (35 Mesh) and acidized to remove carbonates. The crushed acidized sample was cleaned with water to remove acid and dried in an oven at 100 °C. Thereafter, the sample was oxidized inside the TOC apparatus. The organic carbon combusts to generate carbon dioxide, which was measured and converted to TOC by wt. %.
4.1. Petrophysical characterization Table 1 and Table 2 show the mineralogy from FTIR and helium porosity for the different samples used in this study. The tables show samples taken from Devonian-Mississippian are rich in quartz while samples from Eagle Ford are rich in carbonates. The Green River samples taken from an outcrop are rich in feldspars. The Green River shale samples also had the lowest porosity among the three formations. Table 3 shows the geochemical data i.e. S1 and S2 peaks from source rock analysis and TOC from LECO apparatus. S1 peak from SRA represents the mobile, free and extractable organic matter while S2 peak represents the heavy, immovable kerogen, resins and asphaltenes that could potentially be converted to hydrocarbons. S2 represents the potential of the source rock to generate hydrocarbons in future. The S1 values for Eagle Ford samples are more than three times that of Devonian samples suggesting higher fraction of movable oil. The Green River samples show very high values for both S1 and S2, possibly comprising of large amount of immature organic matter like organic acids, etc. Bitumen is the portion of organic matter in sedimentary rocks which is soluble in organic solvents. It generally comprises of intermediate to heavy hydrocarbons. The term bitumen is also used to describe organic matter that may be thermally extracted from rocks, and used informally to mean tar, pitch, and asphalt. It is generally immobile under room conditions (25 °C, 14.7 psia) but may become mobile at higher temperatures. The temperature at which bitumen becomes mobile depends on the composition of the bitumen. Fig. 2 shows a typical pyrogram for bitumen-lean Devonian-Mississippian samples and bitumen-rich Eagle Ford samples. Fig. 3 shows the NMR T2-spectra (left) and T1-T2 maps (right) for the preserved state samples from Devonian-Mississippian and Eagle Ford. On the T1-T2 maps, water lies close to 1:1 line and occurs to the left due to lower T2 relaxation time. The hydrocarbon, on the other hand, due to higher viscosity lies above the 1:1 line. The higher T2 relaxation time also pushes the hydrocarbon towards the right. It is evident that in the preserved samples, Devonian-Mississippian samples consists mainly of water/brine as residual fluids while in Eagle Ford, the residual fluids mainly comprise of hydrocarbons. The next section shows how the SRA, NMR and helium porosity data was integrated to quantify the amount of air-filled pores and the fraction of hydrocarbons and brine in the residual fluids, for the samples in all the three formations.
2.4. Scanning Electron Microscope (SEM) images SEM images were analyzed to see the distribution of organics. The images were analyzed using FEI Helios Nanolab 600 Dual-Beam Focus Ion Beam (FIB) and Scanning Electron Microscope (SEM). The detailed procedure for SEM in shales is explained in Curtis et al. (2012a) and Curtis et al. (2012b). 2.5. Source rock analysis (SRA) SRA analysis is done by a pyrolysis flame-ionization detection (PFID) technique. During the first stage, the sample is heated at the rate of 25 °C per minute up to 300 °C. During this stage, volatile hydrocarbons are released which are measured as a S1 peak. In the next stage, sample is heated to a higher temperature of 550 °C. During this stage, kerogen in the sample is pyrolyzed and recorded as S2 peak. Generally, S1 peak corresponds to movable hydrocarbons and S2 represents immovable hydrocarbons. More details are available in Tissot and Welte (1984). In this study, the first stage (S1 peak) was further divided into four substages with the average temperatures in each substage being 125 °C, 175 °C, 225 °C, and 275 °C, respectively. This is done to better characterize the movable hydrocarbons and understand the impact of drying and cleaning on the movable hydrocarbons. 2.6. Helium porosity The helium porosity was measured using the technique developed by Karastathis (2007). In Karastathis's method, the bulk volume is measured using a mercury-immersion technique. Boyle's law is used to measure the grain volume in a porosimeter. Finally, the helium porosity is calculated from bulk and grain volumes. 3. Methodology
4.2. Modified wettability equation correcting for in situ fluids
Samples were acquired from three formations namely DevonianMississippian (4 depths), Eagle Ford (2 depths) and Green River shale (2 depths). The samples were one inch in diameter and varied between 1 and 1.5 inch in length. The workflow for the study is shown in Fig. 1. Triplet plugs were acquired at each depth - one plug was used for the petrophysical measurements i.e. SRA, TOC, helium porosity, mineralogy, etc. and the remaining two plugs were used for measuring wettability using NMR. Wettability was first measured on preserved state samples (native state for Green River shale), followed by drying the samples and then measuring the wettability again. Finally, the samples were cleaned in Soxhlet apparatus with methanol-toluene (20:80) mixture as the solvent for four days (Gupta et al., 2017b), followed by wettability measurement on the cleaned samples. T1-T2 maps were also acquired after every step along with T2 spectra to qualitatively characterize the type of fluids in the core. This helped validate the quantitative analysis of the residual fluids obtained by integrating the SRA, NMR T2 spectra and helium porosity data. After the samples were dried and cleaned, end trims from one of the plugs was taken for SRA to characterize the change in S1 and S2 peaks after drying and cleaning, respectively. The same end trims were also used for acquiring SEM images to visually study the impact of drying and cleaning.
Sulucarnain et al. (2012) applied the Looyestijn and Hofman (2006) method to the shales. Their equation to calculate wettability is given below where NMR (Sw) and NMR (Sdo) are the amount of brine and dodecane imbibed by the samples (NMR T2 porosities in cc) divided by the helium porosity of the sample (fraction).
NMR Iw =
NMR (Sw ) − NMR (Sdo) NMR (Sw ) + NMR (Sdo)
(2)
To calculate the wettability using the Sulucarnain et al. (2012) method, two duplicate plugs are taken and they are used for two sequences of fluid imbibition. Fig. 4 shows the typical NMR spectra acquired for measuring wettability using NMR. The procedure is explained in detail in the ‘Measurement Procedures’ section. First, we measure preserved state T2 spectra using NMR on both the plugs to quantify the residual fluids. Then, we imbibe the plug in SQ1 in brine, and the plug in SQ2 in dodecane. Then, we cross imbibe the plugs, SQ1 plug is imbibed with dodecane while SQ2 plug is imbibed with brine. In the next step, we calculate difference spectra (shown on right) to characterize the incremental brine and incremental dodecane imbibed in both the sequences. Once, we have those incremental volumes, we 354
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Fig. 1. Workflow for the study. Triplet plugs were acquired at each depth - one plug was used for the petrophysical measurements i.e. SRA, TOC, helium porosity, mineralogy, etc. and the remaining two plugs were used for measuring wettability using NMR. Wettability was first measured on preserved state samples (native state for Green River shale), followed by drying the samples and then measuring the wettability again. Finally, the samples were cleaned in Soxhlet apparatus with methanol-toluene (20:80) mixture as the solvent for four days, followed by wettability measurement. (For interpretation of the references to color in this figure legend, the reader is referred to the Web version of this article.)
Table 1 Mineralogy and Porosity for the Devonian-Mississippian and Eagle Ford samples. Sample
Formation
Carbonates (wt. %)
Quartz (wt. %)
Clays (wt. %)
Feldspars (wt. %)
Others (wt. %)
Porosity (vol %)
DM1 DM2 DM3 DM4 E1 E2
Devonian-Mississippian Devonian-Mississippian Devonian-Mississippian Devonian-Mississippian Eagle Ford Eagle Ford
23 32 33 30 91 70
48 44 41 40 0 0
14 12 16 18 1 10
5 3 5 3 1 8
10 9 5 9 7 12
10.1 9.6 10.2 10.3 5.5 6.6
inter-granular clay mineral water-wet pores, comprise of the smallest pores. The dodecane imbibition in SQ2 shows that dodecane creates a bimodal T2 response with majority of the dodecane imbibition happening after T2 relaxation time of 1 ms. This can be due to larger relaxation time of the dodecane molecules in the smaller water-wet pores or in oil-wet pores which are larger than the water-wet pores. Subsequent imbibition with brine in SQ2 (Fig. 4), shows a distinct peak below 1 ms (like SQ1) suggesting that brine gets access to the smaller inorganic clay pore network. In this method, we neglected the residual fluids as we subtracted the preserved state spectra to calculate the incremental volumes. The residual fluids could not be accounted because it was not possible to distinguish what fraction was oil and what fraction was water. In this study, we integrated NMR, SRA and helium porosity data to characterize the residual fluids. This becomes especially important for liquid-rich shales which have a large amount of residual fluids. S1 value from SRA represents the movable hydrocarbons. The S1 values are measured in mg/gm of rock. Using the density of oil, S1 values can be converted to cubic centimeter (cc) per gram of rock.
Table 2 Mineralogy and Porosity for the Green River shale samples. Sample
Formation
Carbonates (wt. %)
Quartz (wt. %)
Feldspars (wt. %)
Others (wt. %)
Porosity (vol %)
GR1 GR2
Green River Green River
31 21
6 3
60 75
3 1
3.7 4.1
can calculate a wettability index both for SQ1 and SQ2 using equation (1). The preserved spectra for the parallel plugs in SQ1 and SQ2 were very similar. After spontaneous imbibition, T2 spectra of the different sequences shows different characteristics. T2 relaxation time is a combination of pore size, wettability and fluid viscosity. Brine and dodecane have similar viscosities thus, differences are mainly due to pore size and wettability. Relaxation time is lower in smaller pores. Additionally, if the fluid wets the surface, the relaxation time is lower as well. In this shale sample (Fig. 4), in SQ1, sample was first imbibed with brine which shows a T2 peak of less than 1 ms. Thus, it appears that the
Table 3 Geochemical data (S1 and S2 peaks from SRA, TOC from LECO) for different samples. Sample
Formation
S1 (mg/gm rock)
S2 (mg/gm rock)
TOC (wt. %)
DM1 DM2 DM3 DM4 E1 E2 GR1 GR2
Devonian-Mississippian Devonian-Mississippian Devonian-Mississippian Devonian-Mississippian Eagle Ford Eagle Ford Green River Green River
1.1 1.5 0.3 0.9 3.8 5.3 11.2 9.5
16.4 23.3 0.4 12.2 7.4 7.5 197.6 84.3
2.7 3.2 0.9 2.6 2.1 2.6 22.3 11.2
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Fig. 2. SRA pyrograms for Devonian-Mississippian and Eagle Ford samples. The Eagle Ford sample shows presence of large amount of intermediate, heavy hydrocarbons and possibly bitumen. Devonian-Mississippian samples may also have small bitumen fraction in the early part of S2 peak.
Multiplying the resulting expression with bulk density of the rock sample, the amount of movable hydrocarbon (in cc) per unit volume rock (cc) can be obtained. Assuming So’ to be the fraction of NMR porosity (cc/cc) that represents movable hydrocarbon, the expression for So’ is given below.
So′ =
So = So′ ∗
Sair = 1 − Sw′ − So′
(3)
Where do is oil density, ρbulk is the bulk density of the sample and ∅NMR is the NMR T2 porosity. So’ is a fraction and hence, dimensionless. The oil density is estimated (not measured) and it will be later shown through the sensitivity analysis, that its value does not significantly impact the results. In step 2, Sw’ which represents the fraction of NMR porosity that is brine, is calculated by simply subtracting So’ (calculated in Step 1) from 1. Sw’ is also a fraction and hence, dimensionless
Sw′ = 1 − So′
(4)
In step 3, helium porosity is used to calculate actual oil (So), brine (Sw) and air-filled pore (Sair) fractions using the following expressions. NMR porosity measures the total fluids in the pore sample and helium porosity measures the total connected pore space in the sample. Sw, So and Sair represent the fraction of connected pore space which is filled by water, oil and air, respectively.
Sw = Sw′ ∗
∅NMR ∅Total
(6) (7)
This stepwise procedure was carried out for all the samples in this study, and the results are shown in the ternary diagram in Fig. 5. Ternary diagram shows the fraction of brine-filled pores, hydrocarbonfilled pores and air-filled pores in the different samples. The DevonianMississippian samples had little residual oil (2–4 vol %), significant residual brine (18–22 vol %) and majority of the pores were air-filled (70–77 vol %). Eagle Ford samples on the other hand had similar brinefilled (37–39 vol %), oil-filled (24–29 vol %) and air-filled pores (34–36 vol %). The Green River samples were very tight (helium porosity ∼ 4%), and the pores were mainly filled with immature organic matter (57–64 vol %) and brine (34–36 vol %). This method made it possible to modify the existing equation for NMR wettability index (equation (1)), and account for residual fluids to give more accurate wettability results. The modified equation for wettability index is given below.
S1 ∗ ρbulk 1000 ∗ do ∗ ∅NMR
∅NMR ∅Total
NMRIw =
(NMRSw + NMRSwinsitu ) − (NMRSo + NMRSoinsitu ) (NMRSw + NMRSwinsitu ) + (NMRSo + NMRSoinsitu )
(8)
Where NMRSwinsitu and NMRSoinsitu are additional terms introduced in the equation to account for residual brine and hydrocarbon, respectively. Fig. 6 and Fig. 7 show the corrected and uncorrected wettability data for the three formations. The preserved samples in Devonian-
(5)
Fig. 3. NMR T2-spectra (left) and T1-T2 maps (right) for the preserved state samples from Devonian-Mississippian and Eagle Ford. On T1-T2 maps, water generally lies close to 1:1 line and occurs to the left due to faster relaxation time. The hydrocarbon, on the other hand, due to higher viscosity lies above the 1:1 line. 356
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Fig. 4. NMR spectra gathered to calculate wettability index using NMR. The details of the wettability measurement process are given in ‘Measurement Procedures’ section.
Fig. 6. Corrected (modified equation) and uncorrected (Sulucarnain et al., 2012) wettability for the different samples used in the study. On x axis we have sequence 1 wettability index and on the y axis we have the sequence 2 wettability index. The solid circles represent the corrected data and the open squares represent the uncorrected data.
fraction of the hydrocarbons. For Devonian-Mississippian and Eagle Ford samples, the producing oil density was taken while for Green river shale outcrop samples, the oil density was assumed to be 0.8. Since, the oil density is an uncertain parameter, a sensitivity study was carried out to see the impact of its uncertainty (Fig. 8). The oil density was changed from 0.7 to 0.9 and the wettabilities were calculated before and after the correction. It is evident that the absolute values of the wettability change slightly and the conclusions remain unaffected.
Fig. 5. Ternary diagram showing the fraction of brine-filled pores, hydrocarbon-filled pores and air-filled pores in different samples used in the study. The Devonian-Mississippian samples had little residual oil (2–4 vol %), significant residual brine (18–22 vol %) and majority of the pores were air-filled (70–77 vol %). Eagle Ford samples on the other hand had similar brine-filled (37–39 vol %), oil-filled (24–29 vol %) and air-filled pores (34–36 vol %). The Green River samples were very tight (helium porosity ∼ 4%), and the pores were mainly filled with immature organic matter (57–64 vol %) and brine (34–36 vol %). (For interpretation of the references to color in this figure legend, the reader is referred to the Web version of this article.)
4.3. Wettability comparison: preserved, dried and cleaned states
Mississippian formation were water-wet but they appeared mixed wet without correction. Similarly, Eagle Ford samples were mixed-wet but they appeared oil-wet without correction. The Green River outcrop samples were mixed-wet to oil-wet and they appeared water-wet without correction. It is more evident when we plot the average wettability index (Fig. 7). It was mentioned earlier that the method developed to characterize the residual fluids require movable oil density (do) i.e. density of the S1
In this section, the impact of drying and cleaning the samples on wettability is evaluated. Fig. 9 shows the NMR spectra for the samples from the three formations in preserved (or native in case of Green River) state, and dried state. Devonian-Mississippian samples, which mainly had residual water sees a decrease in the water signal and Eagle Ford samples show a decrease in both oil and water signal. Green River samples show the lowest decrease in the T2 signal. The T1-T2 maps were in agreement with the T2 spectra. For example, 357
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compared to the dried state. 5. Discussion The new modified wettability equation was able to account the residual fluids and better characterize the wettability of the samples. It was observed that water-wet samples like Devonian-Mississippian appeared mixed-wet without correction and mixed-wet to oil-wet Green River shale samples appeared water-wet without correction. This likely happens because for the water wet (Devonian-Mississippian) samples, residual fluids comprise mainly of brine/water. These residual fluids reside in the water-wet pores. Thus, a large proportion of the water-wet pores is not accounted for in wettability calculation, and hence the water-wet character is underestimated in the wettability calculation and the water-wet samples appear mixed-wet. Similarly, for the mixedwet to oil-wet samples like Green River, the oil-wet character is underestimated, and hence, they appear more water-wet. When comparing the wettabilities between preserved, dried and cleaned states, it was observed that both drying and cleaning the samples made the samples appear more oil wet. The change in wettability is more severe for the dried samples compared to the cleaned samples. It is to be noted that even the cleaned samples were dried after cleaning (24 h at 100 °C) to remove the solvent. One possible theory why samples turned more oil-wet after drying and cleaning, is that possibly heating the samples at 100 °C for 24 h is cracking the intermediate to heavy hydrocarbons. The resulting products are mobile at the oven temperature (100 °C), they move through the pore system and get deposited on the pore walls. The bitumen may also become mobile at 100 °C, spreading across the water-wet rock surfaces and turning the rock more oil-wet. The Eagle Ford samples in this study exhibited the highest change in wettability. Geochemical characterization (Fig. 2) also showed high intermediate to heavy, and possibly bitumen content in the Eagle Ford samples. Fig. 17 shows the SRA pyrogram for the preserved, dried and cleaned samples in Eagle Ford. It is evident that on drying the samples, the area under the S2 peak reduced while the area under the S1 peaks increased compared to the preserved state. This might indicate cracking of the intermediate/heavy hydrocarbon to generate lighter hydrocarbons in the S1 range. Fig. 18 shows the SEM images taken for Eagle Ford sample after drying (Personal communication, Mark Curtis). The matrix grains were observed to be covered with bitumen and evidence of bitumen mobilization and resolidification were seen all across the sample. Figs. 17 and 18 support the hypothesis that cracking of heavier hydrocarbons and mobilization of bitumen in the samples after drying might be responsible for increased oil-wet character measured in the
Fig. 7. Corrected (modified equation) and uncorrected (Sulucarnain et al., 2012) average wettability for the different samples used in the study. The average wettability is obtained by averaging the SQ1 and SQ2 wettability indexes. The preserved samples in Devonian-Mississippian formation were waterwet but they appeared mixed wet without correction. Similarly, Eagle Ford samples were mixed-wet but they appeared oil-wet without correction. The Green River outcrop samples were mixed-wet to oil-wet and they appeared water-wet without correction. (For interpretation of the references to color in this figure legend, the reader is referred to the Web version of this article.)
Fig. 10 shows the T1-T2 maps for an Eagle Ford sample before and after drying. The scale is different for the two maps. Considering the differences in scale, it is evident that drying the Eagle Ford sample removed both brine and volatile organic matter. Fig. 11 and Fig. 12 show the wettabilities for the different samples in preserved (or native) and dried states. For all the formations, the samples appear more oil-wet on drying. Next, the impact of cleaning the samples on wettability was analyzed. Fig. 13 shows the NMR spectra for the samples from the three formations in preserved (or native in case of Green River), dried and cleaned states. It is evident that on cleaning, there is a further reduction in the NMR spectra, suggesting more removal of the residual fluids. Fig. 14 shows the SRA data (TOC ∼ S1 + S2) for different samples in the preserved, dried and cleaned states. The SRA data is in agreement with the NMR data and it shows a reduction in TOC after cleaning compared to both preserved and dried states. The cleaning probably removed both brine and hydrocarbons, and the decrease in TOC suggests that part of the reduction in the NMR spectra in Fig. 13 is due to removal of hydrocarbons. Fig. 15 and Fig. 16 show the wettabilities for the different samples in the preserved (or native), dried and cleaned states. After cleaning, the samples still appear more oil-wet compared to preserved state but they appear less oil-wet (closer to the preserved state wettability) as
Fig. 8. Sensitivity study where oil density was changed from 0.7 to 0.9 and the wettabilities were calculated before and after the correction. It is evident that the absolute values of the wettability change slightly and the conclusions remain unaffected. 358
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Fig. 9. NMR spectra for the samples from the three formations in preserved (or native in case of Green River) state, and dried state. Devonian-Mississippian samples, which mainly had residual water sees a decrease in the water signal, Eagle Ford samples show a decrease in both oil and water signal. Green River samples show the lowest decrease in the T2 signal. (For interpretation of the references to color in this figure legend, the reader is referred to the Web version of this article.)
Fig. 10. T1-T2 maps for an Eagle Ford sample before and after drying. The scale is different for the two maps. Considering the differences in scale, it is evident that drying the sample in Eagle Ford removed both brine and volatile organic matter.
Fig. 12. The average wettabilities for the different samples in the preserved (or native) and dried states. The average wettability was calculated by averaging the sequence 1 and sequence 2 wettabilities. Again, for all the formations, the samples appear more oil-wet on drying.
Fig. 11. The wettabilities for the different samples in preserved (or native) and dried states. X-axis represents the water first or SQ1 wettability index while y axis represents the oil first or SQ2 wettability index. Again the three colors represent the three formations. For all the formations, samples appear more oilwet on drying. (For interpretation of the references to color in this figure legend, the reader is referred to the Web version of this article.)
samples appear more oil-wet and oil-wet samples appear more waterwet. This is likely happening because for the water wet samples, residual fluids comprise mainly of brine. These residual fluids reside in the water-wet pores. Thus, a large proportion of the water-wet pores is not accounted for while wettability calculation, and hence the waterwet character is underestimated in the wettability calculation and the water-wet samples appear more oil-wet. Similarly, for the oil-wet samples, the oil-wet character is underestimated, and hence, they appear more water-wet. Next, wettability measurements on preserved, dried and cleaned sample states were carried out. The comparison of the three states suggest that drying and cleaning the samples, change the original wettability of the system and make the rocks appear more oil wet. The effects of drying are more pronounced than cleaning. This argument is supported both by SRA data and Scanning Electron Microscope (SEM)
samples. Similar process might be occurring when the samples are heated after being cleaned, but is not evident in the SRA pyrogram (Fig. 17) as a large proportion of hydrocarbons are removed during the cleaning procedure. 6. Conclusions In this study, a modified equation to calculate wettability using NMR is proposed. The equation was modified from Looyestijn and Hofman (2006) where additional terms to include residual brine and hydrocarbon saturations were included in the equation. The residual fluid saturations were calculated using the SRA, NMR and helium porosity data. The results show that without correction, the water-wet 359
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Fig. 13. NMR spectra for the samples from the three formations in preserved (or native in case of Green River), dried and cleaned states. It is evident that on cleaning, there is a further reduction in the NMR spectra, suggesting more removal of the in situ fluids. (For interpretation of the references to color in this figure legend, the reader is referred to the Web version of this article.)
Fig. 14. SRA data (TOC ∼ S1 + S2) shown for different samples in the preserved, dried and cleaned states. The SRA data is in agreement with the NMR data and it shows a reduction in TOC after cleaning compared to both preserved and dried states.
Fig. 16. The average wettabilities for the different samples in the preserved (or native), dried and cleaned states. After cleaning, the samples still appear more oil-wet compared to preserved state but they appear less oil-wet (closer to the preserved state wettability) as compared to the dried state.
Fig. 15. The wettabilities for the different samples in preserved (or native), dried and cleaned states. After cleaning, the samples appear to be closer to the initial state wettability compared to dried state. Fig. 17. SRA pyrogram for preserved, dried and cleaned sample in Eagle Ford. It is evident that on drying the samples, the area under the S2 peak reduced while the area under the S1 peaks increased compared to the preserved state. This might indicate cracking of the intermediate to heavy hydrocarbon to generate lighter hydrocarbons in the S1 range.
images. The SRA data shows an increase in S1 and a corresponding decrease in S2 peak suggesting that heating the sample at 100 °C may crack the heavy hydrocarbons in the sample. The SEM image analysis also show the possible movement and resolidification of bitumen and other heavy hydrocarbons. These mobile fractions are believed to flow into the water-wet pores and turn them oil-wet. The results of this study suggest that when preserved samples are not available, and measurements are done on as received samples, the wettability determination is affected by the sample treatment (drying or cleaning). The shale samples are generally heated or cleaned to remove the pore fluids but an inherent assumption is that matrix is unaffected. This study shows that matrix is also affected as shown by the wettability measurements. However, preserved cores are expensive to acquire and hence, rarely available. Thus, one of the alternatives to measure wettability could be to measure it on as-received plugs, without any sample
treatment. SRA, NMR and porosity measurements can be done to identify the nature of residual fluids (brine versus hydrocarbon) as shown in this study, account for them in wettability calculation and hence, accurately determine wettability. Acknowledgements We would like to thank IC3 consortium members for donating the cores to carry out the study and subsequently provide constructive feedback during the research meetings. 360
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Fig. 18. SEM images taken for Eagle Ford sample after drying (Personal communication, Mark Curtis). The matrix grains were observed to be covered with bitumen and evidence of bitumen mobilization and resolidification were seen all across the sample. These mobile fractions are believed to flow into the water-wet pores and turn them oil-wet.
Appendix A. Supplementary data
Jennings, J.B., 1987. Capillary pressure techniques: application to exploration and development geology. AAPG (Am. Assoc. Pet. Geol.) Bull. 71 (10), 1196 October 1987. Karastathis, A., 2007. Petrophysical Measurements on Tight Gas Shale. M.S. thesis. University of Oklahoma. Lan, Q., Xu, M., Dehghanpour, H., 2014. Advances in understanding wettability of tight and shale gas formations. In: Presented at the SPE Annual Technical Conference and Exhibition Held in Amsterdam, Netherlands, 27-29 Oct 2014, SPE-170969-MS. Law, C., 1999. Evaluating Source Rocks, Chapter 6, AAPG Special Volumes, Petroleum Geology/Handbook of Petroleum Geology: Exploring for Oil and Gas Traps. pp. 61–6-41 Edited by Edward A. Beaumont and Norman H. Foster. Looyestijn, W.J., Hofman, J., 2006. Wettability index determination by nuclear magnetic resonance. In: SPE 93624 Presented at the SPE Middle East Oil and Gas Show and Conference, Bahrain, 12-15 March. Odusina, E., 2011. An NMR Study of Shale Wettability. Master’s Thesis. University of Oklahoma, Norman, Oklahoma. Okasha, T.M., 2018. Investigation of the effect of temperature and pressure on interfacial tension and wettability. In: Presented at the International Symposium of the Society of Core Analysts Held in Trondheim, Norway, 27-30 Aug. Sondergeld, C.H., Rai, C.S., 1993. A new concept of quantitative core characterization. Lead. Edge 12 (7), 774–779. Sulucarnain, I.D., Sondergeld, C.H., Rai, C.S., 2012. An NMR study of shale wettability and effective surface relaxivity. In: Presented at SPE Canadian Unconventional Resources Conference, 30 October-1 November, Calgary, Alberta, Canada, SPE 162236-MS. https://doi:10.2118/162236-MS. Teklu, T.W., Alameri, W., Kazemi, H., Graves, R.M., 2015. Contact angle measurements on conventional and unconventional reservoir cores. In: Presented at Unconventional Resources Technology Conference Held in San Antonio, Texas, USA, 20-22 July, https://doi.org/10.15530/URTEC-2015-2153996. Tissot, B.,P., Welte, D.,H., 1984. Petroleum Formation and Occurrence, 2 ed. SpringerVerlag, New York 699 p. Valori, A., Nicot, B., 2018. A review of 60 years of NMR Wettability. In: Presented at the International Symposium of the Society of Core Analysts Held in Trondheim, Norway, 27-30 Aug. Velazco, M.A., Bruce, A., Ferris, M., Reed, J., Kandasamy, R., 2018. The role of ferrous clays in the interpretation of wettability – a case study. In: Presented at the International Symposium of the Society of Core Analysts Held in Trondheim, Norway, 27-30 Aug. Wang, L., Yin, R., Sima, L., Fan, L., Wang, H., Yang, Q., Huang, L., 2018. Insights into the pore types and wettability of a shale gas reservoir by nuclear magnetic resonance: Longmaxi formation, sichuan basin, China. Energy Fuels 32, 9289–9303. Zeng, T., Miller, C., Mohanty, K., 2018. Application of surfactants in shale chemical EOR at high temperatures. In: Presented at the SPE Improved Oil Recovery Conference Held in Tulsa, Oklahoma, USA, 14-18 April, https://doi.org/10.2118/190318-MS.
Supplementary data to this article can be found online at https:// doi.org/10.1016/j.petrol.2019.01.048. References Abdallah, W., Buckley, J.S., Carnegie, A., Herold, B., Edwards, J., Fordham, E., Graue, A., Habashy, T., Seleznev, N., Signer, C., Hussain, H., Montaron, B., Ziauddin, M., 2007. Fundamentals of Wettability. Oilfield Review. Schlumberger. Anderson, G.A., 1986. Wettability literature survey- Part 1: rock/oil/bine interactions and the effects of core handling on wettability. SPE J. 38 (11). https://doi.org/10.2118/ 13932-PA. SPE 13932-PA. Ballard, B.D., 2007. Quantitative mineralogy of reservoir rocks using fourier Transform infrared spectroscopy. In: Presented at SPE Annual Technical Conference and Exhibition, Anaheim, California, 11-14 November, . https://doi:10.2118/113023. Curtis, M.E., Sondergeld, C.H., Ambrose, R.J., Rai, C.S., 2012a. Microstructural investigation of gas shales in two and three dimensions using nanometer-scale resolution imaging. AAPG Bull. V. 96 (4), 665–677. https://doi.org/10.1306/ 08151110188. Curtis, M.E., Cardott, B.J., Sondergeld, C.H., Rai, C.S., 2012b. The development of organic porosity in the woodford shale related to thermal maturity. In: Presented at SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 8-10 October 2012. Donaldson, E., Thomas, R., Lorenz, P., 1969. Wettability determination and its effect on recovery efficiency. SPE J. 113–120. Fleury, M., Deflandre, F., 2003. Quantitative evaluation of porous media wettability using NMR relaxometry. Magn. Reson. Imag. 21, 385–387. Gannaway, G., 2014. NMR investigation of pore structure in shales. In: Presented at SPE International Student Paper Contest at SPE Annual Technical Conference and Exhibition Held in Amsterdam, Netherlands, 27-29 Oct 2014. Gupta, I., Sondergeld, C., Rai, C., 2017a. Water weakening: case study from marcellus and woodford. URTec 2669617. In: Presented at Unconventional Resources Technology Conference at Austin, Texas, 24-26 Jul 2017. Gupta, I., Rai, C., Tinni, A., Sondergeld, C., 2017b. Impact of different cleaning methods on petrophysical measurements. In: Presented at the SPWLA 58th Annual Logging Symposium Held in Oklahoma City, Oklahoma, USA, June 17-21. Howard, J.J., 1998. Quantitative estimates of porous media wettability from proton NMR measurements. Magn. Reson. Imag. 16, 529–533. Hsu, W.-F., Li, X., Flumerfelt, R.W., 1992. Wettability of porous media by NMR relaxation methods. In: Presented at the SPE Annual Technical Conference and Exhibition Held in Washington DC, USA, 4-7 October, https://doi.org/10.2118/24761-MS.
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Contents lists available at ScienceDirect
Journal of Petroleum Science and Engineering journal homepage: www.elsevier.com/locate/petrol
Study impact of sample treatment and insitu fluids on shale wettability measurement using NMR
T
Ishank Gupta∗, Chandra Rai, Carl Sondergeld The University of Oklahoma, USA
A R T I C LE I N FO
A B S T R A C T
Keywords: SRA NMR wettability Preserved wettability Cleaned wettability Dried wettability
Nuclear Magnetic Resonance (NMR) is a good alternative to conventional Amott-Harvey imbibition test or US Bureau of Mines (USBM) test, to measure wettability in shales. The conventional methods do not work primarily because of the long time it takes to flow through the nano pores in the shales. Contact angle measurements typically used in shales do not account for pore connectivity. Hence, NMR is becoming a standard reliable method to measure wettability in shales. This study focuses on two aspects of wettability measurement in shales. First, Looyestijn and Hofman (2006) proposed an equation to calculate wettability using NMR data based on their experiments on carbonate rocks. Sulucarnain et al. (2012) applied this method to shales. In their method, the residual fluids in the plugs are neglected because it is difficult to ascertain what proportion of residual fluids is hydrocarbon and what proportion is water. However, in liquid-rich shales like Eagle Ford, there could be significant amount of residual fluids which must be accounted in the wettability calculation. This study integrates Source Rock Analysis (SRA), NMR and helium porosity data to determine the nature of the residual fluids and account for them while doing wettability calculations. Thus, an improved equation for wettability is proposed by modifying the original equation. Second, in this study, wettability measurements on preserved, dried and cleaned sample states were carried out. The comparison of the three states suggest that drying and cleaning the samples, changes the original wettability of the system and make the rocks appear more oil wet. The effects of drying are more pronounced than cleaning. The above argument is supported both by SRA data and Scanning Electron Microscope (SEM) images. The SRA data shows an increase in S1 and a corresponding decrease in S2 peak which suggests that heating the sample at 100 °C may crack the heavy hydrocarbons in the sample. The SEM image analysis also show the possible movement and resolidification of bitumen and other heavy hydrocarbons. These mobile fractions are believed to flow into the water-wet pores and turn them oil-wet.
1. Introduction
reduction of mechanical strength and Young's modulus (Gupta et al., 2017a), fracture design and stimulation methods. The most commonly used methods for wettability calculation in conventional reservoirs are Amott-Harvey imbibition test and US Bureau of Mines (USBM) test (Donaldson et al., 1969). The conventional methods do not work in shales primarily because of the low porosity and permeability in the shales. Contact angle measurements have been used by many researchers to calculate the wettability in shales (Teklu et al., 2015; Zeng et al., 2018; Okasha, 2018). However, this method is affected by surface roughness and does not account for pore connectivity. In unconventional shales, due to large heterogeneity (TOC, clays, quartz, etc.) and complex wettability systems, the wettability at the surface can be very different from the actual wettability of
Wettability governs the ability of a certain fluid to wet a solid surface compared to another fluid. The key variables that control wettability are oil composition, brine chemistry and rock matrix composition (Anderson, 1986). Mathematically, it is a balance between the surface and the interfacial forces. The wettability plays an important role in governing other petrophysical properties like residual saturations, relative permeabilities, saturation estimates from logs, etc. This means that wettability controls the well productivity, water flood performance and selection of EOR methods. (Donaldson et al., 1969; Jennings, 1987; Abdallah et al., 2007). In unconventional reservoirs like shales, wettability is also critical to proppant embedment,
∗
Corresponding author. E-mail address: [email protected] (I. Gupta).
https://doi.org/10.1016/j.petrol.2019.01.048 Received 9 October 2018; Received in revised form 26 December 2018; Accepted 13 January 2019 Available online 14 January 2019 0920-4105/ © 2019 Elsevier B.V. All rights reserved.
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made at ambient temperature and pressure conditions using the CPMG pulse sequence. The minimum signal to noise ratio was around 50 and a minimum of 300 scans were taken for each sample. To measure wettability, two sequences of fluid imbibition were carried out with the two parallel plugs acquired at each depth. The preserved or native spectra of the parallel plugs were compared to confirm that the plugs were identical or very similar. In Sequence 1 (SQ1), one of the plugs was imbibed in 2.5% KCl brine for 60 h followed by NMR T2 measurement. Thereafter, the same plug was spontaneously imbibed with dodecane for 60 h followed by NMR T2 measurement. In Sequence 2 (SQ2), the reverse process was followed with the other plug. The plug in SQ2 was first imbibed with dodecane followed by 2.5% KCl brine. Brine and dodecane have different hydrogen index. A correction was applied to the dodecane spectra for the differences in the hydrogen index so that the brine and dodecane spectra can be compared. This was done by measuring the NMR T2 response of same volume of bulk fluids (brine and dodecane) and then taking the ratio. The ratio was then used to correct the T2 spectra of dodecane. For the first plug (SQ1), we measured native state (preserved, dried or cleaned depending on the experiment) T2 porosity, then brine imbibed T2 porosity and finally dodecane imbibed T2 porosity. We can get incremental water imbibed by subtracting the native T2 porosity from brine imbibed T2 porosity. Similarly, we can get incremental dodecane imbibed by subtracting the brine imbibed T2 porosity from dodecane imbibed T2 porosity. In the second plug (SQ2), we measured native state T2 porosity, then dodecane imbibed T2 porosity and finally brine imbibed T2 porosity. Using this data, we got the incremental dodecane imbibed (subtracting native T2 porosity from dodecane imbibed T2 porosity) and incremental brine imbibed (subtracting dodecane imbibed T2 porosity from brine imbibed T2 porosity). The process to get incremental imbibed volumes can be done in two ways. First, directly subtracting the T2 measured porosities. Second, subtracting the raw signals and then inverting it to porosity. For more accuracy, the second method was followed. Wettability was calculated for each sequence using the formula given below (Looyestijn and Hofman, 2006; Sulucarnain et al., 2012).
the connected pore network. Lan et al. (2014) observed intact Horn River shale samples to be primarily water wet but the wettability measured on same samples in crushed state showed they were oil wet. They concluded that the connected pathway in the Horn River shale samples is water wet while the remaining majority of the rock is oil wet. NMR has been proposed as an alternative to measure wettability in shales. Several NMR based methods have been proposed in the literature to determine wettability of rocks. Majority of these methods have been applied to conventional sandstone and carbonate reservoirs (Hsu et al., 1992; Howard, 1998; Fleury and Deflandre, 2003; Looyestijn and Hofman, 2006). Valori and Nicot (2018) presented a review of the different NMR methods to calculate wettability developed in last six decades. They also pointed out the methods such as T1/T2 ratio, restricted diffusion, etc. which can be potentially applied in the field. Some of these methods especially saturation based (Looyestijn and Hofman, 2006) have been recently applied to unconventional shales (Odusina, 2011, Sulucarnain et al., 2012; Gannaway, 2014; Wang et al., 2018). These authors proposed T2-spectrum based models to characterize wettability of several oil and gas shale reservoirs namely Woodford, Wolfcamp, Eagle Ford, Barnett, Longmaxi, among others. The authors also observed that higher TOC generally causes higher oilwet character while higher clay content causes higher water-wet character in the shales. Developing accurate methods to determine the wettability is not enough for measuring accurate wettability of the insitu-state rock. This is because the native wettability of the reservoir core samples can be affected and altered by the coring and core handling processes: during coring and core recovery, through invasion of and contact with, drilling mud components/additives; pressure and temperature losses; and potential oxidation of oil and/or rock components (Velazco et al., 2018). Some of these concerns may not be applicable to shales because of their ultra-low permeability but the same property can make it extremely difficult to restore samples to insitu state by aging with reservoir crude oil (Anderson, 1986), which is routinely done in the conventional rocks. Thus, preserved state samples are the closest proxy to the insitu-state samples and should give the most relevant wettability. In this study, the impact of sample treatment (like cleaning and drying the samples) on the wettability is studied which can further help understand the impact of various core recovery and laboratory processes on the sample wettability. Okasha (2018) studied the effect of temperature and pressure on wettability. He found that increasing temperature and aging time increased the contact angle and hence, made the rock more oil-wet. Okasha (2018) used both dead oil and live oil for these experiments. He used calcite mineral and rock samples (calcite > 90%) as substrates. The measurements were made at various temperatures and pressures (up to 90 °C and 3000 psig).
NMR Iw =
NMR (Sw ) − NMR (Sdo) NMR (Sw ) + NMR (Sdo)
(1)
where NMR (Sw) and NMR (Sdo) are the amount of brine and dodecane imbibed by the samples (NMR T2 porosities in cc) divided by the helium porosity of the sample (fraction). Both for SQ1 and SQ2, we have incremental brine and dodecane porosities from the NMR T2 measurements. Thus, we get a wettability index each for SQ1 and SQ2 which can be averaged to get the wettability index for that particular sample depth. The wettability index from NMR (NMR Iw) varies between −1 and 1. The value of 1 represents completely water wet while value of −1 represents completely oil wet. The value of 0 represents neutral wet. Values between −0.5 and 0.5 generally represent mixed wet. Values between 0.5 and 1 represent strongly water wet while between −0.5 and −1 represent strongly oil wet.
2. Experimental procedures The study used three set of samples belonging to different formations namely Devonian-Mississippian, Eagle Ford and Green River. The preserved samples were available in Devonian-Mississippian and Eagle Ford, while outcrop samples were taken for Green River shale. The samples were preserved by immediately wrapping them with saran wrap and aluminum foil upon recovery and then dip in wax. The Devonian-Mississippian samples belonged to gas maturity window, Eagle Ford samples belonged to oil maturity window and Green River samples were immature. Different petrophysical measurements were carried out as a part of this study namely NMR-based wettability, mineralogy, helium porosity, TOC, SEM images and SRA.
2.2. Mineralogy The mineralogy of the samples is determined using transmission Fourier Transform Infrared Spectroscopy (FTIR). Different minerals have different signatures on the absorbance spectrum. The inversion package developed in house allows quantification (in wt. %) of the following 16 minerals; quartz, calcite, dolomite, aragonite, siderite, oligoclase, albite, orthoclase, illite, chlorite, kaolinite, smectite, mixedlayer clays, apatite, anhydrite, and pyrite. The detailed procedure is explained by Sondergeld and Rai (1993), Ballard (2007).
2.1. Wettability Wettability measurements were done using spontaneous imbibition. NMR was acquired using an Oxford Geospec2TM, at a frequency of 12 MHz and using an echo-spacing of 57 μs. The measurements were 353
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2.3. Total organic carbon (TOC)
4. Results
TOC measurements were done using dry pyrolysis technique (Law, 1999). The sample was crushed to fine particles (35 Mesh) and acidized to remove carbonates. The crushed acidized sample was cleaned with water to remove acid and dried in an oven at 100 °C. Thereafter, the sample was oxidized inside the TOC apparatus. The organic carbon combusts to generate carbon dioxide, which was measured and converted to TOC by wt. %.
4.1. Petrophysical characterization Table 1 and Table 2 show the mineralogy from FTIR and helium porosity for the different samples used in this study. The tables show samples taken from Devonian-Mississippian are rich in quartz while samples from Eagle Ford are rich in carbonates. The Green River samples taken from an outcrop are rich in feldspars. The Green River shale samples also had the lowest porosity among the three formations. Table 3 shows the geochemical data i.e. S1 and S2 peaks from source rock analysis and TOC from LECO apparatus. S1 peak from SRA represents the mobile, free and extractable organic matter while S2 peak represents the heavy, immovable kerogen, resins and asphaltenes that could potentially be converted to hydrocarbons. S2 represents the potential of the source rock to generate hydrocarbons in future. The S1 values for Eagle Ford samples are more than three times that of Devonian samples suggesting higher fraction of movable oil. The Green River samples show very high values for both S1 and S2, possibly comprising of large amount of immature organic matter like organic acids, etc. Bitumen is the portion of organic matter in sedimentary rocks which is soluble in organic solvents. It generally comprises of intermediate to heavy hydrocarbons. The term bitumen is also used to describe organic matter that may be thermally extracted from rocks, and used informally to mean tar, pitch, and asphalt. It is generally immobile under room conditions (25 °C, 14.7 psia) but may become mobile at higher temperatures. The temperature at which bitumen becomes mobile depends on the composition of the bitumen. Fig. 2 shows a typical pyrogram for bitumen-lean Devonian-Mississippian samples and bitumen-rich Eagle Ford samples. Fig. 3 shows the NMR T2-spectra (left) and T1-T2 maps (right) for the preserved state samples from Devonian-Mississippian and Eagle Ford. On the T1-T2 maps, water lies close to 1:1 line and occurs to the left due to lower T2 relaxation time. The hydrocarbon, on the other hand, due to higher viscosity lies above the 1:1 line. The higher T2 relaxation time also pushes the hydrocarbon towards the right. It is evident that in the preserved samples, Devonian-Mississippian samples consists mainly of water/brine as residual fluids while in Eagle Ford, the residual fluids mainly comprise of hydrocarbons. The next section shows how the SRA, NMR and helium porosity data was integrated to quantify the amount of air-filled pores and the fraction of hydrocarbons and brine in the residual fluids, for the samples in all the three formations.
2.4. Scanning Electron Microscope (SEM) images SEM images were analyzed to see the distribution of organics. The images were analyzed using FEI Helios Nanolab 600 Dual-Beam Focus Ion Beam (FIB) and Scanning Electron Microscope (SEM). The detailed procedure for SEM in shales is explained in Curtis et al. (2012a) and Curtis et al. (2012b). 2.5. Source rock analysis (SRA) SRA analysis is done by a pyrolysis flame-ionization detection (PFID) technique. During the first stage, the sample is heated at the rate of 25 °C per minute up to 300 °C. During this stage, volatile hydrocarbons are released which are measured as a S1 peak. In the next stage, sample is heated to a higher temperature of 550 °C. During this stage, kerogen in the sample is pyrolyzed and recorded as S2 peak. Generally, S1 peak corresponds to movable hydrocarbons and S2 represents immovable hydrocarbons. More details are available in Tissot and Welte (1984). In this study, the first stage (S1 peak) was further divided into four substages with the average temperatures in each substage being 125 °C, 175 °C, 225 °C, and 275 °C, respectively. This is done to better characterize the movable hydrocarbons and understand the impact of drying and cleaning on the movable hydrocarbons. 2.6. Helium porosity The helium porosity was measured using the technique developed by Karastathis (2007). In Karastathis's method, the bulk volume is measured using a mercury-immersion technique. Boyle's law is used to measure the grain volume in a porosimeter. Finally, the helium porosity is calculated from bulk and grain volumes. 3. Methodology
4.2. Modified wettability equation correcting for in situ fluids
Samples were acquired from three formations namely DevonianMississippian (4 depths), Eagle Ford (2 depths) and Green River shale (2 depths). The samples were one inch in diameter and varied between 1 and 1.5 inch in length. The workflow for the study is shown in Fig. 1. Triplet plugs were acquired at each depth - one plug was used for the petrophysical measurements i.e. SRA, TOC, helium porosity, mineralogy, etc. and the remaining two plugs were used for measuring wettability using NMR. Wettability was first measured on preserved state samples (native state for Green River shale), followed by drying the samples and then measuring the wettability again. Finally, the samples were cleaned in Soxhlet apparatus with methanol-toluene (20:80) mixture as the solvent for four days (Gupta et al., 2017b), followed by wettability measurement on the cleaned samples. T1-T2 maps were also acquired after every step along with T2 spectra to qualitatively characterize the type of fluids in the core. This helped validate the quantitative analysis of the residual fluids obtained by integrating the SRA, NMR T2 spectra and helium porosity data. After the samples were dried and cleaned, end trims from one of the plugs was taken for SRA to characterize the change in S1 and S2 peaks after drying and cleaning, respectively. The same end trims were also used for acquiring SEM images to visually study the impact of drying and cleaning.
Sulucarnain et al. (2012) applied the Looyestijn and Hofman (2006) method to the shales. Their equation to calculate wettability is given below where NMR (Sw) and NMR (Sdo) are the amount of brine and dodecane imbibed by the samples (NMR T2 porosities in cc) divided by the helium porosity of the sample (fraction).
NMR Iw =
NMR (Sw ) − NMR (Sdo) NMR (Sw ) + NMR (Sdo)
(2)
To calculate the wettability using the Sulucarnain et al. (2012) method, two duplicate plugs are taken and they are used for two sequences of fluid imbibition. Fig. 4 shows the typical NMR spectra acquired for measuring wettability using NMR. The procedure is explained in detail in the ‘Measurement Procedures’ section. First, we measure preserved state T2 spectra using NMR on both the plugs to quantify the residual fluids. Then, we imbibe the plug in SQ1 in brine, and the plug in SQ2 in dodecane. Then, we cross imbibe the plugs, SQ1 plug is imbibed with dodecane while SQ2 plug is imbibed with brine. In the next step, we calculate difference spectra (shown on right) to characterize the incremental brine and incremental dodecane imbibed in both the sequences. Once, we have those incremental volumes, we 354
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Fig. 1. Workflow for the study. Triplet plugs were acquired at each depth - one plug was used for the petrophysical measurements i.e. SRA, TOC, helium porosity, mineralogy, etc. and the remaining two plugs were used for measuring wettability using NMR. Wettability was first measured on preserved state samples (native state for Green River shale), followed by drying the samples and then measuring the wettability again. Finally, the samples were cleaned in Soxhlet apparatus with methanol-toluene (20:80) mixture as the solvent for four days, followed by wettability measurement. (For interpretation of the references to color in this figure legend, the reader is referred to the Web version of this article.)
Table 1 Mineralogy and Porosity for the Devonian-Mississippian and Eagle Ford samples. Sample
Formation
Carbonates (wt. %)
Quartz (wt. %)
Clays (wt. %)
Feldspars (wt. %)
Others (wt. %)
Porosity (vol %)
DM1 DM2 DM3 DM4 E1 E2
Devonian-Mississippian Devonian-Mississippian Devonian-Mississippian Devonian-Mississippian Eagle Ford Eagle Ford
23 32 33 30 91 70
48 44 41 40 0 0
14 12 16 18 1 10
5 3 5 3 1 8
10 9 5 9 7 12
10.1 9.6 10.2 10.3 5.5 6.6
inter-granular clay mineral water-wet pores, comprise of the smallest pores. The dodecane imbibition in SQ2 shows that dodecane creates a bimodal T2 response with majority of the dodecane imbibition happening after T2 relaxation time of 1 ms. This can be due to larger relaxation time of the dodecane molecules in the smaller water-wet pores or in oil-wet pores which are larger than the water-wet pores. Subsequent imbibition with brine in SQ2 (Fig. 4), shows a distinct peak below 1 ms (like SQ1) suggesting that brine gets access to the smaller inorganic clay pore network. In this method, we neglected the residual fluids as we subtracted the preserved state spectra to calculate the incremental volumes. The residual fluids could not be accounted because it was not possible to distinguish what fraction was oil and what fraction was water. In this study, we integrated NMR, SRA and helium porosity data to characterize the residual fluids. This becomes especially important for liquid-rich shales which have a large amount of residual fluids. S1 value from SRA represents the movable hydrocarbons. The S1 values are measured in mg/gm of rock. Using the density of oil, S1 values can be converted to cubic centimeter (cc) per gram of rock.
Table 2 Mineralogy and Porosity for the Green River shale samples. Sample
Formation
Carbonates (wt. %)
Quartz (wt. %)
Feldspars (wt. %)
Others (wt. %)
Porosity (vol %)
GR1 GR2
Green River Green River
31 21
6 3
60 75
3 1
3.7 4.1
can calculate a wettability index both for SQ1 and SQ2 using equation (1). The preserved spectra for the parallel plugs in SQ1 and SQ2 were very similar. After spontaneous imbibition, T2 spectra of the different sequences shows different characteristics. T2 relaxation time is a combination of pore size, wettability and fluid viscosity. Brine and dodecane have similar viscosities thus, differences are mainly due to pore size and wettability. Relaxation time is lower in smaller pores. Additionally, if the fluid wets the surface, the relaxation time is lower as well. In this shale sample (Fig. 4), in SQ1, sample was first imbibed with brine which shows a T2 peak of less than 1 ms. Thus, it appears that the
Table 3 Geochemical data (S1 and S2 peaks from SRA, TOC from LECO) for different samples. Sample
Formation
S1 (mg/gm rock)
S2 (mg/gm rock)
TOC (wt. %)
DM1 DM2 DM3 DM4 E1 E2 GR1 GR2
Devonian-Mississippian Devonian-Mississippian Devonian-Mississippian Devonian-Mississippian Eagle Ford Eagle Ford Green River Green River
1.1 1.5 0.3 0.9 3.8 5.3 11.2 9.5
16.4 23.3 0.4 12.2 7.4 7.5 197.6 84.3
2.7 3.2 0.9 2.6 2.1 2.6 22.3 11.2
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Fig. 2. SRA pyrograms for Devonian-Mississippian and Eagle Ford samples. The Eagle Ford sample shows presence of large amount of intermediate, heavy hydrocarbons and possibly bitumen. Devonian-Mississippian samples may also have small bitumen fraction in the early part of S2 peak.
Multiplying the resulting expression with bulk density of the rock sample, the amount of movable hydrocarbon (in cc) per unit volume rock (cc) can be obtained. Assuming So’ to be the fraction of NMR porosity (cc/cc) that represents movable hydrocarbon, the expression for So’ is given below.
So′ =
So = So′ ∗
Sair = 1 − Sw′ − So′
(3)
Where do is oil density, ρbulk is the bulk density of the sample and ∅NMR is the NMR T2 porosity. So’ is a fraction and hence, dimensionless. The oil density is estimated (not measured) and it will be later shown through the sensitivity analysis, that its value does not significantly impact the results. In step 2, Sw’ which represents the fraction of NMR porosity that is brine, is calculated by simply subtracting So’ (calculated in Step 1) from 1. Sw’ is also a fraction and hence, dimensionless
Sw′ = 1 − So′
(4)
In step 3, helium porosity is used to calculate actual oil (So), brine (Sw) and air-filled pore (Sair) fractions using the following expressions. NMR porosity measures the total fluids in the pore sample and helium porosity measures the total connected pore space in the sample. Sw, So and Sair represent the fraction of connected pore space which is filled by water, oil and air, respectively.
Sw = Sw′ ∗
∅NMR ∅Total
(6) (7)
This stepwise procedure was carried out for all the samples in this study, and the results are shown in the ternary diagram in Fig. 5. Ternary diagram shows the fraction of brine-filled pores, hydrocarbonfilled pores and air-filled pores in the different samples. The DevonianMississippian samples had little residual oil (2–4 vol %), significant residual brine (18–22 vol %) and majority of the pores were air-filled (70–77 vol %). Eagle Ford samples on the other hand had similar brinefilled (37–39 vol %), oil-filled (24–29 vol %) and air-filled pores (34–36 vol %). The Green River samples were very tight (helium porosity ∼ 4%), and the pores were mainly filled with immature organic matter (57–64 vol %) and brine (34–36 vol %). This method made it possible to modify the existing equation for NMR wettability index (equation (1)), and account for residual fluids to give more accurate wettability results. The modified equation for wettability index is given below.
S1 ∗ ρbulk 1000 ∗ do ∗ ∅NMR
∅NMR ∅Total
NMRIw =
(NMRSw + NMRSwinsitu ) − (NMRSo + NMRSoinsitu ) (NMRSw + NMRSwinsitu ) + (NMRSo + NMRSoinsitu )
(8)
Where NMRSwinsitu and NMRSoinsitu are additional terms introduced in the equation to account for residual brine and hydrocarbon, respectively. Fig. 6 and Fig. 7 show the corrected and uncorrected wettability data for the three formations. The preserved samples in Devonian-
(5)
Fig. 3. NMR T2-spectra (left) and T1-T2 maps (right) for the preserved state samples from Devonian-Mississippian and Eagle Ford. On T1-T2 maps, water generally lies close to 1:1 line and occurs to the left due to faster relaxation time. The hydrocarbon, on the other hand, due to higher viscosity lies above the 1:1 line. 356
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Fig. 4. NMR spectra gathered to calculate wettability index using NMR. The details of the wettability measurement process are given in ‘Measurement Procedures’ section.
Fig. 6. Corrected (modified equation) and uncorrected (Sulucarnain et al., 2012) wettability for the different samples used in the study. On x axis we have sequence 1 wettability index and on the y axis we have the sequence 2 wettability index. The solid circles represent the corrected data and the open squares represent the uncorrected data.
fraction of the hydrocarbons. For Devonian-Mississippian and Eagle Ford samples, the producing oil density was taken while for Green river shale outcrop samples, the oil density was assumed to be 0.8. Since, the oil density is an uncertain parameter, a sensitivity study was carried out to see the impact of its uncertainty (Fig. 8). The oil density was changed from 0.7 to 0.9 and the wettabilities were calculated before and after the correction. It is evident that the absolute values of the wettability change slightly and the conclusions remain unaffected.
Fig. 5. Ternary diagram showing the fraction of brine-filled pores, hydrocarbon-filled pores and air-filled pores in different samples used in the study. The Devonian-Mississippian samples had little residual oil (2–4 vol %), significant residual brine (18–22 vol %) and majority of the pores were air-filled (70–77 vol %). Eagle Ford samples on the other hand had similar brine-filled (37–39 vol %), oil-filled (24–29 vol %) and air-filled pores (34–36 vol %). The Green River samples were very tight (helium porosity ∼ 4%), and the pores were mainly filled with immature organic matter (57–64 vol %) and brine (34–36 vol %). (For interpretation of the references to color in this figure legend, the reader is referred to the Web version of this article.)
4.3. Wettability comparison: preserved, dried and cleaned states
Mississippian formation were water-wet but they appeared mixed wet without correction. Similarly, Eagle Ford samples were mixed-wet but they appeared oil-wet without correction. The Green River outcrop samples were mixed-wet to oil-wet and they appeared water-wet without correction. It is more evident when we plot the average wettability index (Fig. 7). It was mentioned earlier that the method developed to characterize the residual fluids require movable oil density (do) i.e. density of the S1
In this section, the impact of drying and cleaning the samples on wettability is evaluated. Fig. 9 shows the NMR spectra for the samples from the three formations in preserved (or native in case of Green River) state, and dried state. Devonian-Mississippian samples, which mainly had residual water sees a decrease in the water signal and Eagle Ford samples show a decrease in both oil and water signal. Green River samples show the lowest decrease in the T2 signal. The T1-T2 maps were in agreement with the T2 spectra. For example, 357
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compared to the dried state. 5. Discussion The new modified wettability equation was able to account the residual fluids and better characterize the wettability of the samples. It was observed that water-wet samples like Devonian-Mississippian appeared mixed-wet without correction and mixed-wet to oil-wet Green River shale samples appeared water-wet without correction. This likely happens because for the water wet (Devonian-Mississippian) samples, residual fluids comprise mainly of brine/water. These residual fluids reside in the water-wet pores. Thus, a large proportion of the water-wet pores is not accounted for in wettability calculation, and hence the water-wet character is underestimated in the wettability calculation and the water-wet samples appear mixed-wet. Similarly, for the mixedwet to oil-wet samples like Green River, the oil-wet character is underestimated, and hence, they appear more water-wet. When comparing the wettabilities between preserved, dried and cleaned states, it was observed that both drying and cleaning the samples made the samples appear more oil wet. The change in wettability is more severe for the dried samples compared to the cleaned samples. It is to be noted that even the cleaned samples were dried after cleaning (24 h at 100 °C) to remove the solvent. One possible theory why samples turned more oil-wet after drying and cleaning, is that possibly heating the samples at 100 °C for 24 h is cracking the intermediate to heavy hydrocarbons. The resulting products are mobile at the oven temperature (100 °C), they move through the pore system and get deposited on the pore walls. The bitumen may also become mobile at 100 °C, spreading across the water-wet rock surfaces and turning the rock more oil-wet. The Eagle Ford samples in this study exhibited the highest change in wettability. Geochemical characterization (Fig. 2) also showed high intermediate to heavy, and possibly bitumen content in the Eagle Ford samples. Fig. 17 shows the SRA pyrogram for the preserved, dried and cleaned samples in Eagle Ford. It is evident that on drying the samples, the area under the S2 peak reduced while the area under the S1 peaks increased compared to the preserved state. This might indicate cracking of the intermediate/heavy hydrocarbon to generate lighter hydrocarbons in the S1 range. Fig. 18 shows the SEM images taken for Eagle Ford sample after drying (Personal communication, Mark Curtis). The matrix grains were observed to be covered with bitumen and evidence of bitumen mobilization and resolidification were seen all across the sample. Figs. 17 and 18 support the hypothesis that cracking of heavier hydrocarbons and mobilization of bitumen in the samples after drying might be responsible for increased oil-wet character measured in the
Fig. 7. Corrected (modified equation) and uncorrected (Sulucarnain et al., 2012) average wettability for the different samples used in the study. The average wettability is obtained by averaging the SQ1 and SQ2 wettability indexes. The preserved samples in Devonian-Mississippian formation were waterwet but they appeared mixed wet without correction. Similarly, Eagle Ford samples were mixed-wet but they appeared oil-wet without correction. The Green River outcrop samples were mixed-wet to oil-wet and they appeared water-wet without correction. (For interpretation of the references to color in this figure legend, the reader is referred to the Web version of this article.)
Fig. 10 shows the T1-T2 maps for an Eagle Ford sample before and after drying. The scale is different for the two maps. Considering the differences in scale, it is evident that drying the Eagle Ford sample removed both brine and volatile organic matter. Fig. 11 and Fig. 12 show the wettabilities for the different samples in preserved (or native) and dried states. For all the formations, the samples appear more oil-wet on drying. Next, the impact of cleaning the samples on wettability was analyzed. Fig. 13 shows the NMR spectra for the samples from the three formations in preserved (or native in case of Green River), dried and cleaned states. It is evident that on cleaning, there is a further reduction in the NMR spectra, suggesting more removal of the residual fluids. Fig. 14 shows the SRA data (TOC ∼ S1 + S2) for different samples in the preserved, dried and cleaned states. The SRA data is in agreement with the NMR data and it shows a reduction in TOC after cleaning compared to both preserved and dried states. The cleaning probably removed both brine and hydrocarbons, and the decrease in TOC suggests that part of the reduction in the NMR spectra in Fig. 13 is due to removal of hydrocarbons. Fig. 15 and Fig. 16 show the wettabilities for the different samples in the preserved (or native), dried and cleaned states. After cleaning, the samples still appear more oil-wet compared to preserved state but they appear less oil-wet (closer to the preserved state wettability) as
Fig. 8. Sensitivity study where oil density was changed from 0.7 to 0.9 and the wettabilities were calculated before and after the correction. It is evident that the absolute values of the wettability change slightly and the conclusions remain unaffected. 358
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Fig. 9. NMR spectra for the samples from the three formations in preserved (or native in case of Green River) state, and dried state. Devonian-Mississippian samples, which mainly had residual water sees a decrease in the water signal, Eagle Ford samples show a decrease in both oil and water signal. Green River samples show the lowest decrease in the T2 signal. (For interpretation of the references to color in this figure legend, the reader is referred to the Web version of this article.)
Fig. 10. T1-T2 maps for an Eagle Ford sample before and after drying. The scale is different for the two maps. Considering the differences in scale, it is evident that drying the sample in Eagle Ford removed both brine and volatile organic matter.
Fig. 12. The average wettabilities for the different samples in the preserved (or native) and dried states. The average wettability was calculated by averaging the sequence 1 and sequence 2 wettabilities. Again, for all the formations, the samples appear more oil-wet on drying.
Fig. 11. The wettabilities for the different samples in preserved (or native) and dried states. X-axis represents the water first or SQ1 wettability index while y axis represents the oil first or SQ2 wettability index. Again the three colors represent the three formations. For all the formations, samples appear more oilwet on drying. (For interpretation of the references to color in this figure legend, the reader is referred to the Web version of this article.)
samples appear more oil-wet and oil-wet samples appear more waterwet. This is likely happening because for the water wet samples, residual fluids comprise mainly of brine. These residual fluids reside in the water-wet pores. Thus, a large proportion of the water-wet pores is not accounted for while wettability calculation, and hence the waterwet character is underestimated in the wettability calculation and the water-wet samples appear more oil-wet. Similarly, for the oil-wet samples, the oil-wet character is underestimated, and hence, they appear more water-wet. Next, wettability measurements on preserved, dried and cleaned sample states were carried out. The comparison of the three states suggest that drying and cleaning the samples, change the original wettability of the system and make the rocks appear more oil wet. The effects of drying are more pronounced than cleaning. This argument is supported both by SRA data and Scanning Electron Microscope (SEM)
samples. Similar process might be occurring when the samples are heated after being cleaned, but is not evident in the SRA pyrogram (Fig. 17) as a large proportion of hydrocarbons are removed during the cleaning procedure. 6. Conclusions In this study, a modified equation to calculate wettability using NMR is proposed. The equation was modified from Looyestijn and Hofman (2006) where additional terms to include residual brine and hydrocarbon saturations were included in the equation. The residual fluid saturations were calculated using the SRA, NMR and helium porosity data. The results show that without correction, the water-wet 359
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Fig. 13. NMR spectra for the samples from the three formations in preserved (or native in case of Green River), dried and cleaned states. It is evident that on cleaning, there is a further reduction in the NMR spectra, suggesting more removal of the in situ fluids. (For interpretation of the references to color in this figure legend, the reader is referred to the Web version of this article.)
Fig. 14. SRA data (TOC ∼ S1 + S2) shown for different samples in the preserved, dried and cleaned states. The SRA data is in agreement with the NMR data and it shows a reduction in TOC after cleaning compared to both preserved and dried states.
Fig. 16. The average wettabilities for the different samples in the preserved (or native), dried and cleaned states. After cleaning, the samples still appear more oil-wet compared to preserved state but they appear less oil-wet (closer to the preserved state wettability) as compared to the dried state.
Fig. 15. The wettabilities for the different samples in preserved (or native), dried and cleaned states. After cleaning, the samples appear to be closer to the initial state wettability compared to dried state. Fig. 17. SRA pyrogram for preserved, dried and cleaned sample in Eagle Ford. It is evident that on drying the samples, the area under the S2 peak reduced while the area under the S1 peaks increased compared to the preserved state. This might indicate cracking of the intermediate to heavy hydrocarbon to generate lighter hydrocarbons in the S1 range.
images. The SRA data shows an increase in S1 and a corresponding decrease in S2 peak suggesting that heating the sample at 100 °C may crack the heavy hydrocarbons in the sample. The SEM image analysis also show the possible movement and resolidification of bitumen and other heavy hydrocarbons. These mobile fractions are believed to flow into the water-wet pores and turn them oil-wet. The results of this study suggest that when preserved samples are not available, and measurements are done on as received samples, the wettability determination is affected by the sample treatment (drying or cleaning). The shale samples are generally heated or cleaned to remove the pore fluids but an inherent assumption is that matrix is unaffected. This study shows that matrix is also affected as shown by the wettability measurements. However, preserved cores are expensive to acquire and hence, rarely available. Thus, one of the alternatives to measure wettability could be to measure it on as-received plugs, without any sample
treatment. SRA, NMR and porosity measurements can be done to identify the nature of residual fluids (brine versus hydrocarbon) as shown in this study, account for them in wettability calculation and hence, accurately determine wettability. Acknowledgements We would like to thank IC3 consortium members for donating the cores to carry out the study and subsequently provide constructive feedback during the research meetings. 360
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Fig. 18. SEM images taken for Eagle Ford sample after drying (Personal communication, Mark Curtis). The matrix grains were observed to be covered with bitumen and evidence of bitumen mobilization and resolidification were seen all across the sample. These mobile fractions are believed to flow into the water-wet pores and turn them oil-wet.
Appendix A. Supplementary data
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