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Relative Permeability Characteristics and Wetting Behavior of Supercritical CO2 Displacing Water and Remaining Oil for Carbonate Rocks at Reservoir Conditions Xianmin Zhou, Fawaz Al Otaibi, and Sunil L. KOKAL Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.9b01053 • Publication Date (Web): 07 May 2019 Downloaded from http://pubs.acs.org on May 8, 2019

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Energy & Fuels

Relative Permeability Characteristics and Wetting Behavior of Supercritical CO2 Displacing Water and Remaining Oil for Carbonate Rocks at Reservoir Conditions Xianmin Zhoua, Fawaz Al-Otaibib, Sunil Kokalb, a Centre

for Integrative Petroleum Research, College of Petroleum Engineering & Geosciences, King Fahd University of Petroleum & Minerals, Dhahran 31261, Saudi Arabia b Saudi Aramco, Dhahran 31311, Saudi Arabia

Abstract Relative permeability characteristic and wetting behavior of reservoir rocks are crucial for oil recovery. Supercritical CO2 (sc-CO2) miscible flooding as an enhanced oil recovery (EOR) method has been successfully used in both sandstone and carbonate reservoirs. The sc-CO2 is miscible with the remaining oil left after water flooding at injection pressures above MMP, and then higher recovery can be achieved. To describe the flow characteristics and performance of sc-CO2 displacing remaining oil and water, the characteristic parameters such as the water (Krw) and miscible phase (Krm) relative permeability curves and wetting bahavior are required, which applies to reservoir numerical simulation for predicting production performance of sc-CO2 miscible injection. Surprisingly, publications of experimental data included water and miscible phase are relatively rare due to the lack of proper experimental methods in laboratory. In this paper, we proposed a modified method based on Corey’s model to calculate water and miscible phase relative permeability using endpoint values of oil/water system and water/miscible phase (sc-CO2 dissolving into oil) system. In addition, relative permeability reduction and the change of wetting behavior of core plug after sc-CO2 miscible injection were evaluated. Four core flooding experiments were carried out on carbonate composite cores using live oil at reservoir conditions. Experiment included seawater injection and sc-CO2 injection for each core plug to obtain the endpoint values from both injections. The Corey’s model was used directly to calculate oil/water relative permeability of the carbonate composite cores. A modified Corey model proposed in this paper was used to calculate water and miscible phase relative permeability and obtain the relationship of relative permeability vs. miscible phase saturation. The co-flow characteristics in water and miscible phase system was described using these endpoints and relative permeability cruves. As a result, relative permeability to water and miscible phase can be calculated using modified Corey model based on endpoint values when co-flow of water and miscible phase in core plug. The evaluation of relative permeability reduction of core plugs was made by comparing endpoint relative permeability of sc-CO2 at residual state of water/phase phase system with that of water at residual oil saturation of oil/water system. The values of endpoint relative permeability to sc-CO2 are extremely low, which are in the range of 1.57% to 5% after sc-CO2 injection. The wetting behavior had slightly changed by observing photographs of water droplets and oil droplets on the surface of core plugs before and after sc-CO2 injection. The relationship between relative permeability to water and miscible phase vs. miscible saturation has been developed when the water saturation is decreasing during sc-CO2 miscible injection process. It is an obvious influence of water and miscible phase relative permeability when the Corey exponents, Nw and Nm are changed. Keywords: Modified Corey model; Miscible phase; Relative permeability to water and miscible phase; Residual water and oil saturation; Supercritical CO2 injection; Reservoir rocks; wetting behavior; relative permeability reduction. ACS Paragon Plus Environment

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1. Introduction To predict the process of injecting sc-CO2 into a carbonate reservoir, the relative permeability to scCO2, water and remaining oil after water flooding is taken into consideration in reservoir simulation as important parameters. Unfortunately, there is no proper way to measure sc-CO2 and oil relative permeability at miscible conditions in the reservoirs. The method of measuring experimentally sc-CO2 and oil relative permeability curves under miscible flooding conditions is not available in the laboratory. Because remaining oil is displaced by sc-CO2 in the way of the extraction of light and intermedium hydrocarbons and dissolution of sc-CO2 into oil at displacing pressure above minimum miscibility pressure (MMP). All publications discuss and emphasize the study of CO2-water relative permeability for a CO2-water system except the paper published by Li.1 There are two ways to predict relative permeability to water and CO2 such as experimental methodology and/or modeling technique. The CO2 flooding relative permeability curves under miscible and near miscible conditions were predicted using modeling technique.2 - 5 Several studies for measuring experimentally the relative permeability for water/CO2 and H2S/CO2 systems and evaluating the effect of interfacial tension and pore-size distribution/capillary pressure, temperature and pressure on CO2 relative permeability have been done by ressearchers.6 - 10 Bennion and Bachu11 presnted the characteristics of drainage and imbibition relative permeability of CO2/brine and H2S/brine systems were summarized for different rocks such as intergranular sandstone, carbonate, shale, and anhydrite rocks. Researches on water/gas and water/CO2 systems have been focused on measuring accurately relative permeability in the laboratory and modifying the procedure of experiment and apparatus.1,12 - 14 A set of relative permeability to natural gas/water tests of three core plugs has been completed experimentialy at both room and reservoir conditions (temperature of 160oC and injection pressure of 116 MPa) using the unsteady-state method.14 The program of Industrial Standard SY/T 5345-2007 (test method for two-phase relative permeability in rock) was used to process the relative permeability data. They showed that the relative permeability to water and gas at reservoir conditions were higher than that at room conditions. The results from core 2 and core 3 showed residual water saturation at room conditions is higher than that at reservoir conditions. The experiments of CO2/oil relative permeability were conducted in a secondary mode of displacing live oil by CO2 in the slim tubes and sandstone core plugs at reservoir conditions. The Corey model for oil/gas system was used with history matching method to obtain the relative permeability curves of displacing live oil by CO2 at miscible conditions.1 The aim of Li’s study is to investigate the effect of core length on relative permeability curves in the slim tubes and natural core plugs. The lengths of slim tubes and cores were 1,528cm, 101cm, and 74cm, 7.2cm for long and short, respectively. The results showed that the oil/gas relative permeability for long slim tube and natural core plug are higher than that of short slim tube and nature core plug at given oil or gas saturation. In current study, a modified Corey model appropriated to water and miscible phase flow is proposed based on the process of decreasing water saturation and increasing miscible phase saturation during displacing remaining oil by supercritical CO2 after water flooding at reservoir conditions (as tertiary oil recovery mode). The endpoints, residual water saturations (Swr) as residual phase at the end of sc-CO2 injection is introduced into normal Corey model to predict the water/miscible relative permeability for scCO2 injection. In addition, relative permeability reduction and wetting behavior after sc-CO2 injection were evaluated in this paper.

2. Experimentation 2.1 Preparation of fluids 2.1.1 Brines

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Table 1 shows two types of brines used in this study, field connate water and seawater. We used field connate water to saturate the core plugs for the pore volume calculation, measure brine permeability, and set up initial water saturation. Seawater was used for water flooding test. The components of both brines are listed in Table 1. The total dissolved solids of the field connate water and seawater were 213,734 ppm and 57,670 ppm, respectively. Table 2 shows the properties of these brines at ambient (25oC) and reservoir conditions (temperature: 102oC and pore pressure: 3200psi). 2.1.2 Dead and Live Crude Oils A dead crude oil from a carbonate reservoir was used to set up initial water saturation (Swi) for the core plugs in this study. Separator crude oil and gas were collected from the same reservoir for recombining the live crude oil sample, which was then used as an oil phase for the water flooding and the sc-CO2 miscible flooding experiments. Table 2 shows the properties of the dead and live crude oils at reservoir conditions (temperature: 102oC and pore pressure: 3200psi). The gas to oil ratio (GOR) is about 530 scf/bbl. The molecular weight of the recombined live crude oil in this study was 121. Supercritical (Sc-CO2): sc-CO2 was also used as a displacing agent for tertiary oil recovery at a pressure of 3,200 psi and temperature of 102°C to create the miscible condition of live crude oil in the reservoir. The viscosity and density of the sc-CO2 are listed in Table 2. The minimum miscibility pressure (MMP) was 2,600 psi for this particular reservoir crude oil with CO2. 2.2 Materials 2.2.1

Core flooding apparatus

Four core flooding experiments were completed using live oil and carbonate rocks at reservoir conditions. Two long composite core experiments were conducted using single core flooding apparatus, and two short core experiments were run using dual core flooding apparatus. Single and dual core flooding apparatus were used to conduct a series of experiments of displacing oil and evaluating the characteristic of injection and differential pressure profiles by seawater and sc-CO2 miscible flooding using carbonate core plugs at reservoir conditions. A typical single core flooding apparatus used in this study has been described in the publications.15,16 Two long core flooding experiments were completed with an orientation of horizontal and vertical flooding.16 A dual core flooding apparatus was custom designed to perform experiments on two short composite core plug samples. A schematic of flow chart and the experimental procedure of the dual core flooding apparatus was represented in detail by Zhou et al.15 2.2.2

Core Plugs

The core plugs were selected from a carbonate reservoir and scanned to ensure consistency, i.e., no fractures or permeability barriers within a given core plug. Nuclear magnetic resonance (NMR) analysis was also conducted to ensure that all core plugs were a similar rock type. Routine core analysis was firstly conducted to measure the dimensions, air permeability, porosity and helium PV of the core plugs. Based on the routine core analysis, NMR and computed tomography scan results, two long composite cores, each composite core consisted of five core plugs were chosen for single core flooding. For the dual core flooding experiment, two short composite cores, each composite core included two plugs were selected for experiments. The core plugs were then saturated with field connate brine and the PV was calculated by the material balance method.15 Table 3 shows the dimension and routine data of the core plugs used in this study. 3.3 Set up Initial water saturation (Swi) and original oil in core (OOIC), Soi

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The individual dry core plugs were vacuumed for 24 hours and then saturated with field connate water. Brine volume and porosity were determined from the change in weight. The saturated core plugs were left immersed in field connate water for about 10 days to establish ionic equilibrium between the rock constituents and the field connate water. The original connate water was then displaced with about 10 PVs of fresh connate water during the course of measuring the individual core plug brine permeability (Kb). The long core plugs, composite-1S,HF and 4S,VF were desaturated using centrifuge method to set up initial water saturation. For short core flooding, composite-1D, HF and 10D, HF were desaturated by dead oil flooding method.15 The core plugs were then assembled into a stack as a composite core using Teflon tape, aluminum foil and Teflon shrink tube. The aluminum foil functioned as a diffusion barrier between the core plug and the overburden sleeve. The procedures of desaturating and aging core plugs using dead oil has been described by Zhou et al.15 Table 4 shows initial water saturation and original oil in core at reservoir conditions. 3.4 Aged composite core plugs with live oil at reservoir conditions After Swi and Soi of core plugs were determined with dead crude oil, and live crude oil flooding was conducted for all core plugs at a reservoir conditions with a pore pressure of 3,200 psi, confining pressure of 4,500 psi and temperature of 102°C. One PV of live oil was injected into composite core plug per day at a flow rate of 1.0 cc/min to check the stabilization of differential pressure and effective oil permeability of core plugs for three weeks. After composite core plugs aged with dead and live oil, these carbonate plugs were expected to be weakly oil-wet or mixed-wet.17 - 19 3.5 Seawater flooding experiment After four composite cores were aged with live oil at reservoir conditions, the composite cores with initial water and original oil is initially flooded by seawater using both single and dual core flooding apparatus. The detail procedure of seawater flooding using single and dual core flooding apparatus can be found in the papers.15 -16, 20 In order to obtain water flooding endpoint parameters, seawater flooding experiments were conducted using single and dual core flooding apparatus. Seawater flooding was generally stopped when the water cut reached ~ 99%. The endpoint parameters of seawater flooding, the maximum water saturation (Sw(max)), remaining oil saturation (Sorw) at the end of seawater flooding and relative permeability to water at Sw(max) are calculated based on water flooding data such as, injection rate, differential pressure and the dimension of core plug. During seawater flooding process for each composite core plug, oil production and volume of seawater injected vs. time were recorded for calculation of oil recovery factor. 3.6 Sc-CO2 miscible flooding Following the seawater flood, continuous sc-CO2 was injected into composite cores to displace the remaining oil and water after seawater flooding until no more oil and water is produced. The endpoint parameters of sc-CO2 injection, the maximum sc-CO2 saturation (Ssc-co2(max)), residual oil and water saturation(Sr(o+w)) after sc-CO2 flooding and relative permeability to sc-CO2 at Ssc-co2(max) are calculated based on sc-CO2 flooding data such as injection rate, differential pressure and the dimension of core plug. During sc-CO2 miscible flooding for each composite core plug, oil production, and volume of sc-CO2 injected vs. time were recorded for calculation of oil recovery factor. Water production was measured with time to evaluate water-producted performance.

4. The Corey model for water flooding The power law model developed by Corey21 for the prediction of relative permeability of two phase flow, oil and water in the porous medium, classical Corey’s model is ACS Paragon Plus Environment

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and

Krw=Krw (Sorw) (S)Nw

(1)

Kro=Kro (Swi) (1-S)No

(2)

Where Krw is the relation permeability to water as a function of water saturation or oil saturation. Krw(Sorw) is the endpoint relative permeability to water at residual oil saturation (Sorw), Nw is the Corey exponent to water. Kro is the relation permeability to oil as a function of water saturation or oil saturation. Kro(Swi) is the endpoint relative permeability to oil at initial water saturation. No is the Corey exponent to oil. When the permeability basis is oil at initial water saturation, the endpoint relative permeability can be described as follows: Kro(swi) = 1 at initial water saturation; Kro(1-Sorw) = 0 at residual oil saturation; Krw(Swi) = 0 at initial water saturation and Krw(1-Sorw) = Krw(max) at remaining oil saturation. Based on experimental data of displacing oil by water, simplified model of relative permeability as a function of water saturation can be described. The relative permeability curves change as the residual oil saturation is changed. A commonly used an approximation is to express the relative permeability as a function of the normalized water saturation, which is defined as follows: Sw ― Swi

S=1 ― Swi ― Sorw

(3)

Where S is normalized water saturation. Sw is water saturation. Swi is initial water saturation (irreducible water saturation). Sorw is remaining oil saturation at end of water flooding. A typical relative permeability curve calculated using Corey model has been showed in Fig. 1.

5. Modification of the Corey Model for sc-CO2 miscible flooding In the process of injecting sc-CO2 into core plug after water flooding, there are two phases flow, water phase and miscible phase of remaining oil and sc-CO2. During sc-CO2 flooding, water phase relative permeability decreases with decrease in water phase saturation, and miscible phase relative permeability increases with increase in miscible phase saturation. The miscible phase means that a mixture of oil and sc-CO2 has been engendered in the formation. At beginning of injecting sc-CO2 into core plug, oil is mostly in the mixture of remaining oil and sc-CO2. With increasing the pore volume of sc-CO2 injection, the oil in the mixture is decreasing until reaching to residual oil state and the maximum sc-CO2 saturation, residual water (Srw) and oil saturation (Sor(sc-co2)) and maximum sc-CO2 saturation (Ssc-CO2(max)) at the end of sc-CO2 injection. Therefore, we proposed a modified Corey Model to study the flow characteristics of water and calculate relative permeability of water-miscible phase system as below. For water phase and miscible phase relative permeability, the modified expressions are 1 ― 𝑆𝑟(𝑜 + 𝑤) ― 𝑆𝑚

Krw(w/m) = Krw (Sw(max)) (1 ― 𝑆𝑟(𝑜 + 𝑤) ― 𝑆𝑜𝑟𝑤)Nwm

(4)

and 𝑆𝑚 ― 𝑆𝑜𝑟𝑤

Krm(w/m) = Krsc-co2 (Ssc-co2(max)) (1 ― 𝑆𝑟(𝑜 + 𝑤) ― 𝑆𝑜𝑟𝑤)Nm

(5)

Where Krw(w/m) is relative permeability to water as a function of miscible phase saturation of oil and scCO2 in water and miscible phase system. Krw (Sw(max)) is relative permeability to water at the maximum water saturation of the end of water flooding. Sr(o+w) is the summation of residual water (Swr(sc-co2)) and residual oil saturation (Sor(sc-co2)) at the end of sc-CO2 flooding. Sm is miscible phase saturation of oil and sc-CO2, Krm(w/m) is relative permeability to the miscible phase, as a function of miscible phase saturation.


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Krsc-co2(Ssc-co2(max)) is the maximum relative permeability to sc-CO2 at the maximum sc-CO2 saturation at the end of sc-CO2 injection. Nwm and Nm are exponent to water and miscible phase in water/miscible system, respectively. It is important to point out that the residual saturation at the end of sc-CO2 injection includes two portions, residual water (Swr(sc-co2)) and oil saturation (Sor(sc-co2)), which Sr(o+w) is represented in equation 4 and 5. Residual oil saturation is determined by material balance after sc-CO2 flooding test. Residual water saturation is measured by Dean Stark test. A typical relative permeability curve calculated using a modified Corey model has been shown for composite-4S, VF in Fig. 2. The point A represents the maximum water relative permeability at residual oil saturation (Sorw) or the maximum water saturation (Sw(max)) after water flooding. The point B shows the maximum water saturation (Sw(max)) and miscible phase saturation (Sm) where Ssc-CO2 = 0, Sorw = 26.3% and Sw(max) = 73.7%. The point C indicates sc-CO2 relative permeability, Kr(sc-co2) = 0.0475 at the maximum sc-CO2 saturation, Ssc-CO2(max) = 74.15% and residual water and oil saturations (Swr(sc-co2) = 22.85% and Sor(sc-co2) = 3.0%) at the end of sc-CO2 injection. The point D represents the residual saturation of water and oil and the maximum sc-CO2 saturation.

6. Review of Corey exponents, Nw and No for oil/water system, and Nwm and Nm for water/miscible phase system When Corey model is used to calculate oil/water or oil/gas relative permeability, two types of components, endpoints and shape factors or Corey’s exponents must take into consideration. In general, endpoints can be obtained from any core flooding tests such as initial water saturation (Swi), the maximum water saturation (Sw(max)), residual oil saturation (Sorw) and relative permeability to water at Sw(max) for oil/water system, and initial water saturation (Swi), residual oil saturation (Sorg), initial gas saturation (Sgi) and relative permeability to gas at the maximum gas saturation (Sg(max)) for oil/gas system, which relate to oil recovery study. Shape factors or exponents control the shape of relative permeability curve. The shape factor depends on the wettability of rock,22 - 26 injection pressure 27 and fluid/fluid interactions, such as interfacial tension.28 The exponents are comprehensive parameters, which impact the values and characteristics of relative permeability curves. 6.1 Exponents, Nw and No for oil/water system The empirical Corey exponents can be obtained by optimizing a core flow numerical simulator to fit the experimental relative permeability data (history matching) by Steady State and Unsteady State methods. A number of investigators have attempted to correlate exponents with wettability of rocks. Taking into consideration the wettability and type of rocks, a search of Corey exponents for carbonate rocks was conducted. The variation of Corey exponents for different wettability of carbonate and dolomite rocks is shown in Table 5. The restored-state core plugs were used for the study of relative permeability of seawater and sc-CO2 flooding in this paper. The wettability of restored-state core plugs aged with dead and live crude oil was weakly oil-wet or mixed-wet at the beginning of seawater flooding.18-19 Fig.3 (a) shows the characteristic of wettability of the core plugs before seawater flooding. The wetting behavior of the core plug after seawater and sc-CO2 flooding was similar to that before injecting any fluids into core plug as shown in Fig.3 (b). According to Table 5, the exponent to seawater, Nw is in the range of 1.4 to 4.7, and exponent to oil, No is in the range of 3.3 to 5. The evaluation and selection of exponents to seawater and oil are discussed in the section of effect of exponents, Nw and No on oil/water relative permeability. 6.2 Exponents, Nwm and Nm for water/miscible phase system At present there is no proper method to measure relative permeability curves of water/sc-CO2 system under miscible conditions. Because the mechanism of miscible process between oil and supercritical CO2 extracts the light end and intermediate compound of oil into sc-CO2, and dissolves crude into scCO2.29,30 Actually, miscible phase between oil and sc-CO2 is the result of single and multiple contract process, as one phase in the formation. Li et al.27reported an empirical criterion to evaluate exponent to ACS Paragon Plus Environment

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oil/CO2 system. When injection pressure is greater than or equal to the minimum miscibility pressure (MMP), the exponent to CO2 is equal to 1, which represents miscible flooding process. When injection pressure is less than critical immiscible pressure, the value of the exponent to CO2 is 3, which represents the immiscible flooding process. Several experiments of CO2/oil relative permeability study under miscible condition has been conducted using the slim tubes and real sandstone core plugs.1 They used Corey model (oil/gas system) with history matching method to obtain CO2/oil relative permeability, and found that the value of exponent to CO2, 1.2 were used to obtain the best matching oil production curve. In this study, one of objectives is to investigate the relative permeability characteristics of water/miscible phase system during sc-CO2 injection. When the exponent is equal to 1, miscible phase relative permeability cruve is straight line, which can not describe the characteristics of two phase flow such as water/miscible phase. Based on the observation of sc-CO2 injection tests and evaluation of effect of exponent to miscible phase, Nm on relative permeability curve, is equal to 2. The detail discussion can be found in the section of effect of exponents, Nm on miscible relative permeability for water/miscible system.

7. Results and Discussion 7.1 Consideration of Corey exponents, Nw and No for oil/water system, and Nwm and Nm for water/miscible phase system 7.1.1 The effect of exponent to water (Nw) on water relative permeability for oil/water system Weakly oil-wet or mix-wet carbonate core plugs were used to study the relative permeability characteristics for displacing water and remaining oil by sc-CO2 after seawater flooding at reservoir conditions. According to review of Corey exponents, Nw and No for oil/water system with different wettability of rocks in Table 5, the range of Corey exponents to water phase (Nw) are from 1.4 to 4.7 for oil wet core plugs. In this study, individual relative permeability to water phase (Krw) was calculated using a series of Corey exponent to water, Nw = 1.5, 2.5 and 3 to evaluate the effect of Nw on water relative permeability. Fig. 4 shows that there is quite obviously the influence of the effect of Nw on water relative permeability. Two facts have been found that with increasing exponent to water (Nw), the value of relative permeability to water (Krw) and the slope of curves decreases when water saturation is constant, which means the flow of water in the pore of rock has been dominated by the wettability of rock.31,32 Based on the consideration of the characteristics of water relative permeability for oil/water system, the value of exponent (Nw) is equal to 3 for calculating water relative permeability using the Corey model. 7.1.2 The effect of exponent to oil (No) on oil relative permeability for oil/water system According to review of Corey exponents to oil (No) for oil/water system with different wettability of rocks in Table 5, the range of Corey exponents to oil phase (No) are from 3.3 to 5.0 for oil-wet core plugs. To choose reasonable exponent (No), individual relative permeabilities to oil phase (Kro) were calculated with No =3.5, 4.0 and 5 using the Corey model in this study. Fig. 5 shows the results of oil related permeability with the variety of exponents. The same trends were found as that of water relative permeability. With increasing exponent to oil (No), the value of oil relative permeability (Kro) and the slope of curves decreases when water saturation is constant. The results of the comparison of oil relative permeability curves shows that the value of oil relative permeability closed to the maximum water saturation (Sw(max)) is 10-4 when No = 3.5, which means that some oil flows in the pore of the rock. However, when No=4 and 5, oil relative permeabilities trend to “0” in both cases. Oil continues to be produced for many pore volumes in weakly oil-wet water-floods to low oil saturation was observed at core flooding experiments.15 – 16, 31 It explains that oil films on the surface of pore result in oil flow, Kro ≠0. Based on the consideration of the characteristics of oil relative permeability for oil/water system, the


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value of exponent (No) is about 3.5 for calculating oil relative permeability when the Corey model is used. 7.1.3 The effect of exponent to water (Nwm) on water relative permeability for water/miscible phase system After conventional water flooding, oil and water fill the pore space of a core plug. It assumes that the wettability of the rock is not varied during short period of water flooding. The wetting behavior of core plug is consistent from beginning of water flooding. The range of exponent to water in oil/water system was used to evaluate the effect of exponent to water (Nwm) on water relative permeability for water/miscible phase system. Modified equation (4) is used to calculate water relative permeability (Krwm) during supercritical CO2 injection. Fig. 6 shows the results of water relative permeability Krwm vs. miscible phase saturation. The miscible phase relative permeability decreases with increase in miscible phase saturation (Sm) and exponent to water. It is obvious from Fig. 6 that the verity of Krwm is notable differences for each Nwm gave. At beginning of sc-CO2 injection the water is mostly produced from core plug, thereby the rate of decline of Krwm when Nwm = 3.0 is quicker compared with that of other cases (Nwm = 1.5 and 2.5). Before end of sc-CO2 injection, the value of Krwm when Nwm=3.0 is early to reach “0”compared with that of other cases (Nwm = 1.5 and 2.5).This explain is consistent with the performance of water production during sc-CO2 injection process. The normalized water production has been shown in Fig.7. The most of water is produced before half pore volume of sc-CO2 injection. The relative permeability at Nwm=3 is the best representative to describe the characteristic of water in the pore of rock for water/miscible phase system. Therefore, the value of exponent to water (Nwm) in water/miscible system is equal to 3 to calculate the water relative permeability in water/miscible system for four experiments of sc-CO2 injection in this study. 7.1.4 The effect of exponent to miscible phase (Nm) on miscible phase relative permeability for water/miscible phase system With referring to the results,1,27 the values of 1.0, 1.2 and 2.0 for exponent to miscible phase (Nm) were selected to predict the relative permeability, respectively. Fig. 8 shows the influence of Krm with verity of Nm for composite 10D, HF. When Nm=1, relative permeability to misclble phase is a straight line, which shows that the gradient is constant and miscible phase has a strong ability to flow at beginning of scCO2 injection. The relative permeability to miscible phase is higher than that when Nm = 1.2 and 2. Actually, when injection pressure is above MMP, the process of displacing water and remaining oil by sc-CO2 is the miscible displacement process. Therefore, there are only two phase, water and misclble phase (a mixture of sc-CO2 and oil) in the formation. We observe that water is produced only at beginning of sc-CO2 injection as shown in Fig. 7, which indicates that water dominates the flow in the most of flow channels. In contrast, the miscible phase generated by dissolving oil into sc-CO2 is gradually formed by single and multiple contact and appears the passivenss of flow. The lower values of relative permeability to miscible describes the characteristics at early sc-CO2 injection. After about 0.27 pv of sc-CO2 injection, miscible phase starts to flow in the pore of core plug, and oil and sc-CO2 was producted with sc- CO2 injection. Gradually, water and miscible phase are simultaneously flow in the pore of core plug. Water relative permeability is decreased slowly, and miscible phase relative permeability is increased slowly as shown in Fig. 6 and 8, respectively. When no oil and water are produced, water and oil become residual phase, and sc-CO2 (single phase) occupies the most of pore in core plug. In other words, residual water and oil saturations are established at the end of sc-CO2 miscible flooding. Relative permeability to water is 0. However, the sc-CO2 relative permeability reaches to the mixmum value. In summary, when Nm equals to 2, miscible phase relative permeability calculated by modified Corey’s model represented the flow characteristics of the process of injecting sc-CO2 injection to displace remaining oil in the formation. The sc-CO2 injection is under miscible conditions of pore pressure is 3200 psi, which is greater than MMP of 2600 psi for this study. The exponent to miscible phase, Nm of 2 ACS Paragon Plus Environment

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is selected to calculate miscible phase relative permeability for four sc-CO2 injection experiments. Fig. 8 shows the influence of Krm with verity of Nm for composite 10D, HF.

7.2 Relative permeability for oil/water system and miscible phase/water system 7.2.1 Relative permeability of oil/water system Zhou et al.15 and Al-Otaibi et al.16 described the procedures of seawater and sc-CO2 injection. The procedure for composite 10D, HF is as same as that of composite 1D, HF used in pervious study.15 Dual core flooding experiments were conducted for both cores. Seawater and sc-CO2 injection experiments of composite1S, HF and 4S, VF were carried out using single core flooding apparatus. HF and VF mean horizontal and vertical flooding, respectively. Table 6 shows the endpoints of seawater and sc-CO2 flooding for four core flooding experiments. The oil/water relative permeability were calculated for four seawater flooding experiments based on the values of endpoints of seawater flooding and exponents to water and oil, Nw = 3 and No = 3.5 by Corey’s equation 1 and 2 for oil/water system. Fig. 9 shows a typical oil/water relative permeability curves for the four core flooding experiments by seawater. The characteristic of curves represents weakly oil-wet or mixed-wet system because the value of water saturation at across point less than 50% of water saturation for all tests,33,34 in which indicated that the selected corey’s exponents to water/oil system are reasonable. The relative permeabilites at residual oil saturation (Sor) or the maximum water saturation (Sw(max)) for four water flooding experiments indicate successful water flooding experiments. With increasing in water saturation, water relative permeability increases, and oil relative permeability decreases, respectively. The left remaining oil is potential resource for sc-CO2 flooding. 7.2.2 Relative permeability of miscible phase/water system Following the seawater flooding, continuous sc-CO2 was injected into composite core to displace the remaining oil after seawater flooding. In the single core flooding experiments for the long composite 1S, HF and 4S, VF, continuous sc-CO2 was injected at a constant flow rate of 0.5 cc/min until no more oil is produced. In the dual core flooding experiments for both composite cores, composite 1D-HF from test 1 and composite 10D-HF from test 3, continuous sc-CO2 was injected simultaneously into both dual composite core plugs at a rate of 0.2 cc/min.15 It is noted that the values of end points of dual core scCO2 injection is not affected by the process of dual core flooding because sc-CO2 flows in one of composites to displace oil whatever sc-CO2 breakthrough from high permeable core plug or lower permeable core plug. The endpoints is required to calculate the relative permeability of miscible phase/water system. The procedures of seawater flooding were described by Zhou et al.15 and AlOtaibi et al.16 The values of the endpoints obtained from sc-CO2 flooding have been shown in Table 6. The exponents, Nm and Nwm represents to miscible phase and water phase, respectively. The exponent to miscible phase, Nm eqals to 1 and 3 for water according to mention it above. Modified Corey model, equation (4) and (5) were used to calculate the water and miscible phase relative permeability with the values of the endpoints of sc-CO2 injection as shown in Table 6. Fig. 10 shows the relationship between water/miscible phase relative permeability vs. miscible phase saturation for long composite 1S, HF and 4S, VF during sc-CO2 injection. Fig. 11 and 12 show the verity of Krm and Krwm with miscible phase saturation, respectively. The results show the all water relative permeability curves have the identical characteristic that decline quickly at beginning of sc-CO2 injection, which is similar to that of water flooding. The water occupies the most of the pore in the rock


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after water flooding, and remaining oil in the different way hold in the pores such as oil drops and film left on the corner of the pores and the surface of the rock, respectively. According to the water relative permeability curves of water/miscible phase system, there are three segments in the process of sc-CO2 injection, quicker decline, transitional decline and slower decline. During the segment of quicker decline of water relative permeability, the water was displaced and produced only by sc-CO2 injection. In the meantime, sc-CO2 contacts with remaining oil in the way of single or multiple contact until miscible phase generated with increase in sc-CO2 saturation. The miscible phase relative permeability represents mostly the sc-CO2 relative permeability, which is no more oil moving during sc-CO2 injection. In the second segment, transitional decline of Krw(w/m), The miscible phase bank is created gradually in the rock with increasing sc-CO2 saturation. The miscible phase occupies the most of the pore and dominates the flow of fluids in the rock. The water and miscible phase (oil and sc-CO2) are synchronously produced. The most of oil produced by sc-CO2 occurred in this transitional decline of Krw(w/m). The miscible phase relative permeability increases with increasing in sc-CO2 injection, and water relative permeability decreases and tends to “0” until the maximum miscible phase permeability is reached at residual saturations of water and oil in the third segment. When Krsc-CO2 reaches the maximum value, the single phase flow, sc-CO2 occurs in the pore of the rock. 7.2.3 The effect of water/sc-CO2 reaction in carbonate rock on miscible phase relative permeability for water/miscible phase system Omole et al.35 defined the reaction for a water/CO2/carbonate system as below: H2O+CO2+CaCO3↔Ca(HCO3)2

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The mechanisms by which a precipitate permeability reduction include solid deposition on the walls of the pore resulted in individual mineral particles moving and blocking pore throats, and the accumulation of asphaltenes in larger pore throat caused in reducing the area of pore throats.36,37 Zekri et al.37 studied the effect of CO2-brine interaction on the rock property and reported the permeability loess of 18 and 65% for cores, D-S4 and D-S6 caused by dissolution and precipitation. The higher the permeability of the core, the more the damage occurs during CO2 injection.37 Grigg et al.13 reported the results of dissolution and precipitation for CO2/brine/carbonate rock interaction. The calcium and magnesium concentrations increase after CO2 breakthrough that shows some calcium and magnesium precipitation during core flooding. Fig. 10, 11 and 12 show the values of endpoints at the end of sc-CO2 injection for four experiments. The values of sc-CO2 relative permeability for all composite cores at residual conditions are less than 6%, which means permeability reduction during sc-CO2 injection. In the water/miscible phase (oil+scCO2)/carbonate system in this study, the permeability reduction may be caused by the precipitation of Ca(HCO3)2, fines migration and mineral particles moving or sc-CO2/water/oil-emulsion during sc-CO2 injection. The reaction in the water/miscible phase system resulted in fines migration and mineral particles so that the permeability of rock is reduced. Fang et al.14 and Bennion et al.38 reported a similar results in carbonate rocks. It is found that the relative permeability to CO2 at the irreducible brine saturation for the primary drainage process has a lower value of about 0.08 for the high permeable rock and about 0.43 for the low permeable rocks.

8. Comparison of relative permeability for oil/water system and water/miscible phase system The endpoint relative permeability presents flow characteristics and degree of permeability reduction at the existence of residual phase. In this study, oil/water system (water displacing oil) and water/miscible phase system (Miscible phase of sc-CO2 and oil displacing water) were completed for each composite core plugs. The endpoint relative permeability for each composite core plugs was calculated based on the ratio of effective permeability to flow phase at residual phase saturation to absolute permeability of ACS Paragon Plus Environment

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core. For the experiment of water displacing oil (oil/water system), effective permeability to water at residual oil saturation was calculated according to displacement parameters such as injection flow rate, differential pressure cross core and dimension of core plug. For the experiment of miscible phase displacing water (water/miscible phase system), effective permeability to sc-CO2 at residual water and oil saturation was calculated according to displacement parameters such as injection flow rate of sc-CO2, differential pressure cross core and dimension of core plug. Fig. 13 presents end point relative permeability for four composite core plug used in this study. The endpoint relative permeability to water for oil/water system represented a normal water drive feature for four core plugs, which has higher water phase permeability in weakly oil wetting core plugs. After sc-CO2 injection, lower relative permeability to sc-CO2 was observed for four core plugs. The value of relative permeability of core plugs dropped from 43% to 5%, 51.58% to 4.75%, 29% to 1.57% and 72.73% to 4.28% for composite – 1S HF, 4S VF, 1D HF and 10D HF, respectively. This can be thought to be the results of the dissolution and precipitation of individual mineral particles. Thereby, individual mineral particles move and block pore throats of rock. The other reason could be that the accumulation of asphaltenes in larger pore throat caused in reducing the area of pore throats.36, 37

9. Evalution of wetting bahavior during sc-CO2 flooding Understanding rock wettability is the key for distribution of fluids in the rock and optimization of oil recovery. In order to characterize the wettability of related to carbonate reservoir, the core plugs used in this study were aged using dead and living crude oil at reservoir conditions to restore reservoir wettability as weakly oil wetting before seawater injection. Fig. 3a shows the wetting state after aging for composite core plug –10D. The change of wettability of rock was observed through 3 drops of water droplets placed on the surface of the rock. The core plug is strong water wetting before aging and intermediate wetting after aging. In other words, the core plug has the charactertics of weakly oil wetting behavior. The injection sequence was to inject seawater first and then sc-CO2 in same core plugs in this study. The composite core plug was unloaded from core holder and then oil and water droplets were placed on the surface of core plug for evaluating the wetting behavior of rock after scCO2 injection. The photographs were taken as shown in Fig. 14 and 15. Fig. 14 shows the side view (a) and the top view (b) of composite core plugs, 10D HF, which had air permeability of 66 mD. Fig. 15 shows the side view of composite core plugs, 1D HF, which had air permeability of 832 mD. Compared with water droplets on the surface of rock before and after seawater and sc-CO2 in Fig. 3a and Fig. 14 for composite core plug-10D HF, we found that wetting state has slightly changed forward to water wett. Compared with the impact of different air permeability of core plugs, Composite-1D HF and -10D HF, in Fig. 14 and 15, we did not find the effect of air permeability on the wettability change during sc-CO2 injection.

10. Dynamic characteristics of seawater and sc-CO2 injection 10.1 Secondary oil recovery by seawater flooding The results represented in this section of this paper is from one of four core flooding experiments. The core ID was composite-4S, VF. The properties of composite-4S, VF are listed in Table 3. Initial water saturation is 12.93% of pore volume. Seawater flooding was conducted at temperature of 102oC and pore pressure of 3200 psi. The flow rate was first set at 1.0 cc/min, followed by 2.0 cc/min and ultimately 4.0 cc/min. Fig. 16 shows differential pressure vs. pore volume of seawater injected with different injection rates. The oil recovery history is shown with pore volume of seawater injected in Fig. 17, and 69.88% of OOIC was recovered at 2pv seawater injected. In other words, 69.88% of OOIC was produced at injection flow reate of 1cc/min. We did not obtain more oil produced when injection flow rate was changed to 2 and 4cc/min. Oil recovery and remaining saturation by seawater floding in % of


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original oil in core (OOIC) were 69.88 and 30.12, respectively. 30.12% of remaining oil left after seawater flooding is aim for tertiary oil recovery by sc-CO2.

10.2 Tertiary oil recovery by sc-CO2 miscible flooding Following the seawater flooding, continuous sc-CO2 was injected into composite-4S, VF to displace the remaining oil at injecttio pressure above MMP. The experimental conditions for sc-CO2 injection were the same as the seawater flooding test. Continuous sc-CO2 was injected at a constant flow rate of 0.5 cc/min until no more oil is produced. Fig. 18 shows differential pressure during sc-CO2 injection. The oil recover curve with pore volume of sc-CO2 injected is shown in Fig. 19. During the process of sc-CO2 injection, 26.74 % of OOIC was recovered and 3.38 % of OOIC left as residucal oil after sc-CO2 injection

11. Conclusions The relative permeability to miscible phase and water for a water/miscible phase system during sc-CO2 injection have been predicted successfully for carbonate rocks using a modified Corey model proposedin this paper. The following conclusions can be drawn: 









Modified Corey model can be used to predict the relative permeability to water and miscible phase with decreasing water saturations or increasing miscible phase saturations during scCO2 injection. Modified Corey model involves three parameters at residual saturation conditions at the end of sc-CO2 injection, residual water saturation (Swr), residual oil saturation (Sor) and the maximum sc-CO2 saturation (Ssc-co2(max)). Corey exponents, Nw and No for oil/water system and Nwm and Nm for water/miscible phase system not only affect the shape of the relative permeability curve but also influence the values of relative permeability. In other words, The relative permeability to water and oil for oil/water system and miscible phase and water for water/miscible phase system are highly sensitive to exponents, Nw, No, Nwm and Nm. The lower values of relative permeability to sc-CO2 at residual saturation conditions are an extreme low, which caused by the precipitation of Ca(HCO3)2 and fines migration or mineral particles moving to block the pore throats of rocks. The permeability reduction during sc-CO2 injection should be taken into account in application of sc-CO2 injecting to carbonate reservoirs. Wetting state of core plugs has slightly changed forward to water-wet during sc-CO2 injection process.

Acknowledgments The authors would like to thank Saudi Aramco and EXPEC Advanced Research Center for their support and permission to publish this article. Special thanks to Amin M. Alabdulwahab, Faris Alghamdi, Mohammed Al-Dokhi and Jassi Al-Qahtani for the preparation of the coreflooding experiments.

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(30) Okuno, R., and Xu, Z. (2013). Mass Transfer on Multiphase Transitions in LowTemperature CO Floods. Presented at the SPE Annual Techical Conferece and Exhibition held in New Orleans, Louisiana, USA, 30 September-2 October. SPE-166345-MS. http://dx.doi.org/10.2118/166345-MS (31) Salathiel, R.A. 1973. Oil Recovery by Surface Film Drainage in Mixed-Wettability Rocks, JPT, October, 1216-24. (32) Morrow, N. R. 1990. Wettability and Its Effect on Oil Recovery. JPT, December, 14761484. SPE-21621-PA. http://dx.doi.org/10.2118/21621-PA (33) Craig, F. F., Jr. 1971. The Reservoir Engineering Aspects of Waterflooding Monograph, Vol. 3, SPE of AIME. Henry L. Doherty Series, Dallas, Tex. (34) Salathiel, R.A. 1973. Oil Recovery by Surface Film Drainage in Mixed-Wettability Rocks, JPT, October, 1216-24. (35) Omole, O., and Osoba, J. S. 1983. Carbon Dioxide - Dolomite Rock Interaction during CO2 Flooding Process. Petroleum Society of CIM. Paper No, 83-34-17 PETSOC. http://dx.doi.org/10.2118/83-34-17 (36) Pruess, K. and Xu, T. 2001. Numerical modeling of aquifer disposal of CO2. Presented at SPE/EPA/DOE Exploration and Production Environmental Conference, San Antonio Texas, 26-28 february, SPE-66537-MS. http://dx.doi.org/10.2118/66537-MS (37) Zekri, A. Y., Shedid, S. A., & Almehaideb, R. A. 2007. An Experimental Investigation of Interactions between Supercritical CO2, Aspheltenic Crude Oil, and Reservoir Brine in Carbonate Cores. Presented at the 2007 SPE International Symposium on Oilfield Chemistry held in Houston, TX, USA, 28 February-2 march. SPE-104750-MS. http://dx.doi.org/10.2118/104750-MS (38) Bennion, D. B., & Bachu, S. 2010. Drainage and Imbibition CO2/Brine Relative Permeability Curves at Reservoir Conditions for High-Permeability Carbonate Rocks. Presented at SPE Annual Conference and Exhibition held in Florence, Italy, 19-22 September. SPE134028-MS. http://dx.doi.org/10.2118/134028-MS


Energy & Fuels

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16

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Component

Field Connate Water (g/L)

Seawater (g/L)

NaCl

150.446

41.041

CaCl2 2HO

69.841

2.384

.

MgCl2 6H2O

20.396

17.645

.

Na2SO4

0.518

6.343

NaHCO3

0.487

0.165

Total dissolved solids

213,734

57,670

Table 1― Recipes of Field Connate Water and Seawater Ambient Temperature, 25oC

Reservoir Condition,102 oC and 3200 psi

Fluids

Density (g/cc)

Viscosity (cP)

Density (g/cc)

Viscosity (cP)

Field Connate Water

1.1462

1.45

1.0906

0.73

Seawater

1.0385

0.97

1.0018

0.5

Dead Crude Oil

0.881

20.51

0.823

2.5

Live oil

X

X

0.755

0.73

Supercritical CO2

X

X

0.5337

0.04

Table 2―Fluid Properties Composite ID

Length

Diameter

Pore Volume

Porosity

Air Permeability

(cm)

(cm)

(cc)

(%)

(mD)

Composite-1S, HF

20.55

3.81

56.49

27.00

50.80

Composite-4S, VF

23.50

3.79

61.60

27.44

260.22

Composite-1D, HF

6.39

3.80

20.56

28.60

831.70

Composite-10D, HF

7.74

3.80

17.13

20.20

66.00

Table 3―Properties of core plugs Type of apparatus Single core flooding

Dual core flooding

Orientation of

Length

Pore volume

Swi

Soi

Keo at Swi

Flooding

(cm)

(cc)

(%PV)

(%PV)

(mD)

Composite-1S, HF

Horizontal

20.55

56.49

18.46

81.54

Composite-4S, VF

Vertical

23.5

61.6

12.93

87.07

Composite-1D, HF

Horizontal

6.394

20.56

24.64

75.36

104

Composite-10D,HF

Horizontal

6.018

14.064

17.56

82.44

3

Composite ID

Table 4―Routine and dynamical data of core plugs for dual and single core flooding Corey Exponents, Nw and No for oil/water system Water-wet

Neutral-wet

Oil-wet

Authors

Nw

No

Nw

No

Nw

No

Morrow et al. (1973)

3.00

1.30

1.80

1.70

1.40

3.30

Masalmeh (2002)

4.50

2.50

3.50

3.50

3.00

5.00

1.4-2.5

3.0-4.5

-

-

1.2-2.4

3.4-5.0

-

-

-

-

2.0-4.7

3.6-4.6

3.00

4.00

2.50

5.00

Ghedan (2007) Al-Gharbi et al. (2007)

Faerstein et al,(2011) 4.00 3.00 Table 5―Summary of Corey exponents, Nw and No for oil/water system


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Energy & Fuels 17

Water flooding Krw at Sw(max) Sw (max)

sc-CO2 flooding Sorw

Krco2 at Sco2(max)

Sco2 (max)

Sorco2

Srw

(% of pv)

(%)

(% of pv)

(% of pv)

(% )

(% of pv)

(% of pv)

(% of pv)

Composite-1S, HF

18.50

43.03

79.40

20.60

5.01

62.02

6.30

31.68

Composite-4S, VF

12.90

51.89

73.70

26.30

4.75

74.15

3.00

22.85

Composite-1D, HF

24.60

29.00

62.88

37.12

1.57

71.90

1.36

26.74

69.44

30.56

4.28

55.67

15.73

28.60

Composite ID

Swi

Composite-10D, HF 18.50 72.73 Table 6 ―The end points of seawater and sc-CO2 flooding

Oil and water relative permeability by water floooding (Composite 1D, HF)

1.2 Krw, Nw=3

1

Kro and Krw,

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Kro, No=3.5

0.8 0.6 0.4 0.2 0 0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

Water saturation (Sw), Fig. 1 A typical relative permeability curve for water flooding, Composite 1D, HF


1

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18

Water and Miscible phase relative permeability during sc-CO2 injection (Composite-4S VF)

1

A

Krw and Krm,

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

krm, Nm=1 Krwm, Nw=3.0

0.1

B

0.01 0

0.2

0.4

0.6

Miscible phase saturation,

0.8

1

1.2

Fig. 2 Relative permeability curve for water/miscible phase system, Core ID: Composite-1S, HF

Water drop

Oil drop

Water drops

(a)

(b)

Fig. 3 The wetting behavior of core plug before (a) and after (b) seawater and sc-CO2 injection


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Energy & Fuels 19

The effect of exponent (Nw) on relative permeabilty to water

0.6 Krw, Nw=1.5

Krw, fraction

0.5

Krw, Nw=2.5

Krw, Nw=3

0.4 0.3 0.2 0.1 0 0

0.2

0.4

0.6

0.8

1

Water saturation (Sw), fraction Fig. 4. The effect of exponent (Nw) on relative permeability to water for oil/water system

The effect of exponet(No) on relative permeability to oil

1.2 Kro, No=3.5

1.0

Kro, fraction

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Kro, No=4.0

Kro, No=5

0.8 0.6 0.4 0.2 0.0 0

0.2

0.4

0.6

Water saruration (Sw), fraction

0.8

Fig. 5. The effect of exponent (No) on relative permeability to oil for oil/water system


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Energy & Fuels

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20

The effect of exponent to water (Nwm) on water relative permeability for miscible phase/water system (Composite 10D, HF)

1 Krwm, Nm=1.5

Krwm, fraction

0.8

Krwm, Nwm=2.5

Krwm, Nw=3

0.6 0.4 0.2 0 0

0.2

0.4

0.6

0.8

1

Miscible phase saturation (Sm), fraction Fig. 6. The effect of exponent (Nwm) on relative permeability to water for water/miscible phase system for composite 10D, HF

1.2

Normalized water production

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

1.0 0.8 0.6 0.4 0.2 0.0 0

1

2

3

4

5

# of sc-CO2 Pore volume injected Fig. 7 Normalized Water production vs. sc-CO2 pore volume injected during sc-CO2 injection process for composite 10D, HF


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Energy & Fuels 21

The effect of ponent to miscible phase (Nm) on miscible phase relative permeability for water/miscible system

0.06 krm, Nm=1

krm, Nm=1.2

krm, Nm=2

Krm,

0.04

0.02

0 0

0.2

0.4

0.6

0.8

1

Miscible phase saturation Fig. 8 the effect of exponent to miscible phase (Nm) on relative permeability to miscible phase for water/miscible phase system

Oil/water relative permaebility

1.000 Composite 1S(HF),Krw Composite 1S(HF),Kro

Krw and Kro, fraction

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Composite 4S(VF), Krw

0.100

Composite 4S(VF),Kro Composite1D, Krw 0.010

Composite 1D,Kro Composite10D, Krw Composite10D, Kro

0.001 0

0.2

0.4

0.6

0.8

Water saturation (Sw), fraction

Fig. 9 Oil/water relative permeability for seawater flooding


1

1.2

Energy & Fuels

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22

Miscible phase/water relative permeability, Core ID: Composite 1S, HF and 4S, VF

10.000

Krm and Krwm, fraction

Composite 1S,(HF), krm, Nm=2 Composite 1S,(HF), Krwm, Nwm=3

1.000

Composite 4S,(VF), krm, Nm=2 Composite 4S,(VF),Krwm, Nwm=3

0.100

0.010

0.001 0

0.2

0.4

0.6

0.8

1

Miscible phase saturation (Sm), Fig.10 Miscible phase/water relative permeability vs. miscible phase saturation for sc-CO2 injection, Core ID: Long Composite 1S, HF and 4S, VF

Miscible phase/water relative permeability, Core ID: Composite 4, (VF)

1.000


1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Composite 4S,(VF), krm, Nm=2 Composite 4S,(VF),Krwm, Nwm=3

0.100

0.010

0.001 0

0.2

0.4

0.6

0.8

1

Miscible phase saturation (Sm),

Fig.11 Miscible phase/water relative permeability vs. miscible phase saturation for sc-CO2 injection, Core ID: Composite 1D, HF


Page 23 of 26

Energy & Fuels 23

Miscible phase/water relative permeability, Core ID: composite 10D, (HF)

1.000


Composite 10D, (HF), krm, Nm=2 Composite 10D, (HF), Krwm, Nwm=3 0.100

0.010

0.001 0

0.2

0.4

0.6

Miscible phase saturation (Sm), fraction

0.8

1

Fig.12 Miscible phase/water relative permeability vs. miscible phase saturation for sc-CO2 injection, Core ID: Composite 10D, HF

100

Relative permeability, %

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Seawater injection

sc-CO2 injection 72.73

80 60

51.89 43.03

40

29

20 5.01

4.75

1.57

4.28

0 1S, HF

4S, VF

1D,HF

10D, HF

Composite Core Fig. 13 Comparison of relative permeability for oil/water system and water/miscible phase system at the end of injection


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1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Water drop

Oil drop Oil drop

Water (a)

drop

(b)

Fig. 14 Brine and oil drops on the surface of rock after sc-CO2 injection at HTHP conditions Compsite core plug ID: 10D, Air permeability = 66 mD

Oil drop

Water drop

Fig. 15 Brine and oil drops on the surface of rock after sc-CO2 injection at HTHP conditions Compsite core plug ID: 1D, Air permeability = 814 mD


Page 25 of 26

Energy & Fuels 25

20

Differential pressure, psi

Composite-4S, VF 4.0cc/min

10

Flow rate: 1.0cc/min.

2.0cc/min.

1.0cc/min

0 0

2

4

6

# of pore volume of seawter

8

10

Fig. 16 Differential pressure of srawater flooding for composite-4S, VF

100

Oil recovery, %OOIC

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

80 60 40 20

Composite-4S,VF

0 0

2

4

6

8

# of pore volume of seawater injection

Fig. 17 Oil recovery by seawater flooding for composite-4S, VF


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26

10 9 8

Differential pressure,psi

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Composite-4S, VF

7 6 5 4 3 2 1 0 0

1

2

3

4

# of sc-CO2 injected,

5

6

7

Fig. 18 Differential pressure during sc-CO2 injection after seawater flooding for composite-4S, VF

30 25 Composite-4S, VF

20 15 10 5 0 0

0.5

1

1.5

# of Pore volume Fig. 19 Oil recovery by sc-CO2 after seawater flooding for composite core-4S, VF


2

Relative Permeability Characteristics and Wetting ... - ACS Publications

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