Article pubs.acs.org/EF
Wettability Alteration of a Heavy Oil/Brine/Carbonate System with Temperature Tae Wook Kim* and Anthony R. Kovscek* Department of Energy Resources Engineering, Stanford University, Stanford, California, United States S Supporting Information *
ABSTRACT: The wettability of reservoir rock is a crucial factor controlling displacement efficiency and ultimate oil recovery. In this study, the wettability of carbonate reservoir rocks as a function of temperature has been studied by measuring the Amott index to water using an X-ray computed tomography (CT) scanner. The cores for the Amott test were carefully prepared and aged at reservoir conditions to achieve restoration of reservoir wettability. The reservoir cores contain dolomite and chert based on the results of Fourier transform infrared spectroscopy (FT-IR) and energy dispersive X-ray spectroscopy (EDS). The porosity, permeability, and saturation profiles were measured with a core-flooding system and an X-ray CT scanner. The wettability test was carried out at reservoir temperature (70−80 °C) and elevated temperatures (130 °C, 170 °C). The rock components were dissolved at elevated temperature (170 °C) and resulted in a slight increase of porosity and absolute permeability. Also, OOIP and Amott water index increased at elevated temperature. We infer that while the rock is mixed-wet to weakly water wet, it became more water-wet as the temperature increased. In addition, the zeta potentials between rock and brine were also measured under several pH and different solution conditions to corroborate inferences regarding the wettability of reservoir rock. Zeta potential measurement is consistent with a surface that is not strongly water wet under experimental conditions.
1. INTRODUCTION There are enormous, well-known resources of heavy oil, extraheavy oil, and bitumen in the USA, Venezuela, Canada, Russia, and other countries. These resources are potential energy sources that present an opportunity to offset decreasing conventional oil production. Although not well quantified, a portion of these heavy-oil resources is held in carbonate formations. To produce heavy-oil stably and continuously, various enhanced oil recovery (EOR) methods are needed based on crude-oil viscosity and the basic reservoir properties, such as wettability and relative permeability. The wettability of reservoir rock is a critical factor controlling displacement efficiency and ultimate oil recovery. Wettability is defined as the relative ability of a fluid to spread on a solid surface in the presence of another fluid. Critical properties of oil reservoirs, including relative permeability, capillary pressure, and fluid saturations, are determined by the wettability. Also, the interfacial tension between oil and brine is related to the capillary pressure of reservoirs.1 When two immiscible fluids make contact in the reservoir, these fluids are well separated due to interfacial tension of the fluids. The fluid−fluid and rock−fluid interactions are governed by the interfacial tension of fluids as a function of composition, pressure, and temperature. The reduction of interfacial tension of oil−brine with the addition of surfactant and alkali is an issue of current interest for EOR projects.2,3 Many carbonate reservoirs exhibit naturally fractured geologic formations, low porosity, heterogeneous distribution of permeability, and oil to mixed-wet conditions.4 The combination of high permeability and low pore volume in the fracture network leads to early breakthrough of injected fluids in the producing wells and less than optimal hydrocarbon recovery.5,6 Therefore, a number of wettability studies on carbonate reservoir rock have © 2013 American Chemical Society
been carried out with several methods including the Amott wettability test, United States Bureau of Mines (USBM) test, and contact angle measurement to determine how rock and fluid properties have an impact on ultimate recovery.7 Among these tests, contact angle measurements on smooth homogeneous surfaces are a direct way to determine the wettability of rock according to the range of the contact angle measured. This method, however, does not represent conditions particular to the pore space of heterogeneous carbonate rock. Recently, Al-Yousef et al.8 studied the wettability behavior of Saudi Arabian carbonate reservoirs. They observed the wettability of rock samples with Cryo-SEM (Scanning Electron Microscope), conducted core floods, and obtained Amott and USBM indices. These rocks exhibited a mixed-wettability state. A similar study was carried out by Okasha et al.9 They also observed the wettability of carbonate rocks from Saudi Arabia. The Amott and USBM wettability indices showed large variation of wettability with depth from strongly oil-wet to intermediate-wet. Marzouk10 presented the wettability indicated by the Amott method under ambient conditions in two main oil reservoirs of Abu Dhabi. He observed a wide range of carbonate rocks covering several types of limestones and dolomites. In particular, grainstones and dolomite indicated greater oil-wet character.10 Esfahania and his colleagues studied the wettability of two Iranian carbonate rocks using light oil at room and reservoir temperatures. They observed that the wettability of these rocks was altered to the tendency of oil-wet conditions with increasing temperature.11 There were other wettability studies for consolidated Received: February 2, 2013 Revised: April 15, 2013 Published: April 18, 2013 2984
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Table 1. Brine Composition, mg/L synthetic brine 1 synthetic brine 2 field original brine
Na+
Ca2+
Mg2+
Br‑
Cl‑
SO42‑, CO32‑, Fe3+
TDS
pH
7012.7 7012.7 7012.5
882.2 882.2 880.0
72.93 72.93 72.9
0 24361.5 0
12581.21 1772.5 12350.0
0 0 375.6
20549.0 34101.8 20691.0
6.7 6.6 7.0
Figure 1. Apparatus: (a) core sample and (b) schematic diagram of setup.
temperature conditions. In particular, the Amott index to water is used to estimate the wettability of these rocks. The Amott index to water is the ratio of oil recovery by spontaneous imbibition upon the combination of spontaneous and forced imbibition recoveries. We make a narrow focus of the effect of temperature on the wettability. Different from reference studies, in situ visualization was established using a CT scanner to observe saturation profile, porosities, and fluid-phase distribution. The cores are from the upper Cretaceous and lower Paleocene zones of a producing reservoir. Cores are composed of breccias derived from dolomitized limestones.
limestone and dolomite rocks from extra heavy/medium oil carbonate reservoirs of Iranian oil fields.12 Relative permeability experiments were conducted at reservoir pressure and original fluid saturations for a temperature range of 100−500 °F. Based on this experiment, they presented that the rock became more water-wet in the dolomite/heavy-oil system with increasing temperature. The irreducible water saturation increased linearly with increasing temperature. In addition, surfactants were applied to make a wettability alteration to improve oil recovery from fractured carbonate reservoirs.13,14 In this study, we investigated the wettability of tight matrix carbonate reservoir rocks using core flooding tests at different 2985
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Table 2. Interfacial Tension for the Brine−Oil System at Reservoir Salinity (pH 7.0) temp (°C)
IFT (mN/m)
60 70 80 90
31.0 27.3 26.3 24.9
2. EXPERIMENTAL SECTION This paper proceeds with a description of the various experimental techniques used to characterize the crude oil and rock. Then the apparatus and techniques to study crude-oil rock interactions are laid out. 2.1. Sample Preparation. Several cores for laboratory testing were drilled from reservoir rock that corresponded to a productive interval. The rock samples were extremely oily and porous. Cores were chosen to capture the petrophysical properties and conditions of fields. We refer to this field as M. Core samples of 1.5 in. diameter and various lengths were prepared. Table 1 shows the brine composition. Synthetic brine was prepared from several chemicals (NaCl, CaCl2•2H2O, and MgCl2•6H2O). Synthetic brine 1 exactly matches the analysis data of field brine except for SO42‑, CO32‑, and Fe3+. These three components are negligible for this study. In particular, CO32‑ ion reacts with Ca2+ and precipitates CaCO3. We have measured the fluid CT numbers (where the CT number is proportional to X-ray attenuation). Under room temperature condition, the CT number of the synthetic brine 1 and dead M crude oil are remarkably similar. We were concerned that sufficient contrast between the oil and aqueous phases might not exist to allow quantitative imaging of oil saturation in an X-ray Computed Tomography (CT) scanner. Therefore, we prepared a new brine formulation (synthetic brine 2) that has the same total dissolved solids (TDS) of the synthetic brine 1. Substitute sodium bromide (NaBr) is substituted for sodium chloride (NaCl) because NaBr solutions can be attenuated X-rays strongly at the energies available from our CT scanner thereby increasing the contrast between brine and crude oil. The synthetic brine 2 also eliminates the SO42‑, CO32‑, and Fe3+. 2.2. Core Flooding Setup. The coreholder and core flooding apparatus were adapted from previous studies.15,16 The coreholder is a high temperature, high pressure, Hassler-type apparatus. End-caps are made from stainless steel. The outer sleeve is hard-anodized aluminum
Figure 3. Viscosity (cP) versus temperature for M crude oils. to allow visualization of the core using X-ray computed tomography (CT), Figure 1. The core-sample was first wrapped with FEP (fluorinated ethylene propylene) heat-shrinkable tube to conserve vugs and pores of rock and then coated with high temperature Dow Corning silicone gel (730 solvent resistant sealant, Figure 1a-A). The core was wrapped a second and third time with heat-shrinkable FEP tubes. High temperature silicone gel was placed between each tube (Figure 1a-B). The high temperature Dow Corning silicone gel is nonwetting and nonpenetrating. This layer of gel prevents fluid bypass around the core. The FEP-silicone gel composite functions as a high temperature sleeve (heat resistant until 500 °F). Finally, the core was dried 5 days at room temperature (Figure 1a-C). It was then placed inside of the aluminum coreholder, and a confining pressure of 3.45 MPa was applied for cleaning and permeability-measurement. The experimental apparatus is shown in Figure 1(b). The entire apparatus consists of a coreholder, high pressure syringe pump (ISCO), temperature controller, back pressure regulator, several fluid cylinders, and pressure gauges. This coreholder was placed in the gantry of an X-ray Computed Tomography (CT) scanner (GE HiSpeed CT/i). A high pressure syringe pump (ISCO) injected fluids across the inlet face of the core. The outlet of the core was closed after completion
Figure 2. Schematic design for pendant drop type interfacial tension measurement system. 2986
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Table 3. Summary of Test Properties for Reservoir Cores test
sample no.
length (cm)
porosity and permeability
P1 P2
6.35 5.0
P3
6.0
P4 P5
8.10 4.7
P6
8.95
test fluid
porosity (%)
temp (°C)
pressure drop (kPa)
permeability (mD)
9.67 6.73
25 25 55 25 70 55 70 100 130 160 70 130 160
427.5 868.7
0.150 0.0058 0.0050 0.056 0.034 0.516 0.557 0.270 0.173 0.030 0.115 0.013 0.0095
0.5% brine synthetic brine 1
11.56 synthetic brine 2 (3.1 wt % NaBr)
9.14 9.12
9.03
689.5 455.1 482.6 310.3
379.2 400.0
Table 4. Summary of Properties for Imbibition Test Cores test
sample no.
length (cm)
test fluid
porosity (%)
temp (°C)
pressure drop (kPa)
permeability (mD)
imbibition
I1
6.30
synthetic brine 2 (3.1 wt % NaBr)
9.37
60 70 130 180 80 130 170 80 130
551.6
1.95 1.15 0.096 2.06 0.10 0.023 0.044 0.22 0.18
I2
4.0
10.38 8.40
I3
4.1
10.85
648.1 275.8 620.5
1034.2
Figure 4. The FT-IR spectra of (a) dark zone and (b) white zone in M core. pressure of 3.45 MPa until the produced fluids were clear. Then, the core was dried at 60 °C under vacuum. Finally, synthetic brine was injected into the core to measure the porosity and permeability of the core at room temperature. The absolute permeability was measured using Darcy’s law.17,18 2.3. Viscosity. The viscosity of gas-free M crude oil was measured with a viscometer (Brookfield LVDV-II Pro) from room temperature
of water (brine) or oil saturation process. At high temperature, a backpressure regulator was used to keep the pore fluid pressure above water saturation pressure. The produced fluid was recorded versus time for calculating permeability and fluid production. Water saturation history along the core was monitored by CT scanning various cross sections. Prior to measurement of the permeability of a core, it was cleaned by injecting n-decane, toluene, and isopropyl alcohol under the confining 2987
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Figure 5. EDS spectra and SEM photos (X500) of (a) normal M rock and (b) silica enriched M rock. (23 °C) to 140 °C (284 °F). Figure 3 presents the data. The heat transfer oil used in our heating bath has a temperature limit of 140 °C; hence, we have no viscosity data greater than 140 °C. Additionally, the composition of crude oil might change at higher temperature due to evaporation, and the viscosity versus temperature trends measured at lower temperature were sufficient for extrapolation. 2.4. Procedures for Wettability Test. The Amott wettability index for water was chosen to investigate the wettability of rock. We chose a sample with well-connected porosity for initial tests (Table 2). The procedures of the wettability test are as follows:13 1. Saturate the core with 100% synthetic brine and measure the singlephase permeability and porosity. 2. Flood the core with oil in a cocurrent fashion to establish initial water saturation (Swi) at a temperature. Measure oil relative permeability at Swi where Swi was calculated with mass balance of fluids. The samples are aged for more than 7 days. 3. Conduct spontaneous, countercurrent water imbibition (SI) by circulating water across one face of the core with 0.5 cm3/min flow rate until no oil product is observed. 4. CT scan the core periodically to measure the in-situ water saturation of the core. 5. Conduct forced water imbibition (FI) by injecting brine until no oil product is observed. 6. Measure water relative permeability at residual oil saturation (Sor). 7. Clean the core again (if needed) and heat the core to a greater test temperature (70, 130, and 170 °C). 8. Measure the absolute permeability again. 9. Repeat steps 2−8.
Finally, we calculate the Amott wettability index of water (Iw) as
Iw =
spontaneous oil recovery spontaneous oil recovery + forced oil recovery
(1)
In addition, the dimensionless time (tD) is computed for both spontaneous and forced imbibition as19
tD = t
k σ 1 * λrnw * * λrw ϕ Lc2 M* +
1 M*
(2)
where k is absolute permeability, ϕ is porosity, and σ is interfacial tension. This scaling group (tD) was applied for a wide range of mobility ratios including end-point relative permeabilities for extremely low permeability (0.1−10 mD) diatomite. The characteristic length, Lc, is a function of the bulk volume of the rock sample and the area of the block face open to imbibition.20 Here, the one-end open (OEO) boundary condition was applied, because counter current flow was first applied for a spontaneous imbibition case. Regarding the OEO case, the characteristic length, Lc, is equal to the length of the core.20 Also, λ*ri (= kri/μi) is a characteristic mobility for wetting (w) and nonwetting (nw) phases, and M* (= λ*rw/ λ*rnw) is a characteristic mobility ratio. 2.5. FT-IR, SEM, and EDS Analysis. Powdered reservoir rock samples were characterized by FT-IR (Fourier transform infrared spectroscopy) and EDS (energy dispersive X-ray spectroscopy). The FT-IR spectra of the samples were recorded using a Nicolet 570 FT-IR instrument. The experimental operating conditions were a scan-range from 4000 cm−1 to 400 cm−1, scan numbers 500, and a scan resolution of 2 cm−1. The powdered sample was composed of 10 mg of powdered 2988
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Figure 6. The 3-D images for porosity of (a) P1, (b) P5, and (c) I1. rock mixed with 150 mg of IR spectroscopic-grade KBr and formed into a pellet. The EDS and SEM (scanning electron microscope) analysis was carried out with a JEOL JSM-5600LV SEM. 2.6. Interfacial Tension Measurement. The pendant drop method was used to measure the interfacial tension for the oil−brine system. Figure 2 shows the pendant drop type system that consists of a visual cell, polarizer, injection-syringe (ISCO pump used to inject fluids), safety valve, pressure transducers, and camera.21 The following equation was suggested by Andreas and Stauffer22,23 σ=
Δρgde2 H
and Tecplot 2009 RS were used to construct 2-D and 3-D images, respectively, from the raw data. The CT numbers present the X-ray absorption coefficient for each material according to their density. For reference, the CT number of water and air are ‘0’ and ‘−1000′, respectively. Also, the CT numbers of the fluid phase M crude oil (CTo) and modified brine (synthetic brine 2, CTw) are 40.5 and 185, respectively. Using the CT scanner, we measured the porosity and saturation profile of rocks. With the CT images of the air-saturated and watersaturated core, the porosity distribution was calculated as26
(3)
ϕ=
where Δρ (g/cm3) is the density difference between crude oil and brine, g is the acceleration due to gravity (cm/s2), 1/H is the drop shape factor as the function of ds/de, de is the diameter at the equatorial plane, and ds is the diameter at the plane at a distance de from the tip of the drop. In a traditional method, we can use the drop shape factor table to find out the value 1/H.20 Also, the interfacial tension is fitted and calculated by the Young−Laplace equation to the outer perimeter of the drop size with the equation of Girault et al.24 σ=
ΔρgR o2 β
CTwr − CTar CTw − CTa
(5)
where CT is a CT number (dimensionless unit), and the subscripts w, a, wr, and ar denote water, air, water-saturated rock, and air-saturated (dry) rock, respectively. The CT images also provide us with helpful information on water saturation distribution of the core during an experiment. The water saturation and oil saturation of the core were determined using26 So =
(4)
where β (= 0.02664 + 0.62945S ) is a shape parameter, and Ro is the radius of curvature at the drop apex. Finally, the droplet images were analyzed using the ImageJ software package to determine the ds, de, and Ro parameters for IFT calculation.25 2.7. In Situ Visualization. A CT scanner (GE, HiSpeed CT/i) allows visualization of the core sample and displacement patterns. The CT parameters were 200 mA tube current, 140 KV voltage, 2 s exposure time per slice, 3 mm scan thickness, and 3 mm scan interval. Matlab 2009 2
CTwr − CTow‐exp ϕ(CTw − CTo)
Sw = 1 − So
(6) (7)
where CTow‑exp is the matrix obtained from oil−water on rock during the imbibition process. In addition, So and Sw represent oil saturation and water saturation on rock, respectively. It is expected that the CT numbers increase continuously from an oil-saturated rock with a lighter fluid (oil) to a water-saturated with a denser fluid (water) at residual nonwetting phase saturation during the imbibition process. 2989
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Figure 7. The average porosity of each slice and frequency of porosity in a sample (a) P4, (b) P5, and (c) I1. 2.8. Zeta Potential Measurement. The streaming potential method was applied to measure the zeta potential between rock and brine to judge the wettability of reservoir rock.16 The system consisted of a potential cell, electrometer, pressure gauge, water bath, fluid cylinders, and ISCO pump. We cleaned the rock samples (100 g) by preheating at 80 °C with about 1000 mL of a dilute nitric acid (pH = 3.0) to clean the sample for 2 days, before installing it a potential cell. The cleaned sample was washed with the deionized water several times until pH 7.0. Also, the rock sample (25 g, particle size
