n muller relative permeability tpm 2011

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Transport in Porous Media ISSN 0169-3913Volume 87Number 2 Transp Porous Med (2011)87:367-383DOI 10.1007/s11242-010-9689-2

Supercritical CO2-Brine RelativePermeability Experiments in ReservoirRocks—Literature Review andRecommendations

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Transp Porous Med (2011) 87:367–383DOI 10.1007/s11242-010-9689-2

Supercritical CO2-Brine Relative PermeabilityExperiments in Reservoir Rocks—Literature Reviewand Recommendations

Nadja Müller

Received: 7 July 2010 / Accepted: 18 November 2010 / Published online: 17 December 2010© Springer Science+Business Media B.V. 2010

Abstract The relative permeability of carbon dioxide (CO2) to brine influences theinjectivity and plume migration when CO2 is injected in a reservoir for CO2 storage orenhanced oil recovery (EOR) purposes. It is common practice to determine the relative per-meability of a fluid by means of laboratory measurements. Two principal approaches are usedto obtain a relative permeability data: steady state and unsteady state. Although CO2 has beenemployed in enhanced oil recovery, not much data can be found in the open literature. Thefew studies available report wide ranges for CO2 relative permeability in typical sedimentaryrocks such as Berea sandstone, dolomite, and others. The experimental setups vary for eachstudy, employing steady and unsteady state approaches, different experimental parameterssuch as temperature, pressure, rock type, etc. and various interpretation methods. Hence, it isinherently difficult to compare the data and determine the origin of differences. It is evidentthat more experiments are needed to close this knowledge gap on relative permeability. Thisarticle concludes that standards for lab measurements need to be defined a. to establish areliable CO2-brine relative permeability measurement method that can be repeated under thesame conditions in any lab and b. to enable comparison of the data to accurately predict thewell injection and fluid migration behavior in the reservoir.

Keywords CCS · Carbon sequestration · Relative permeability · CO2-brine ·Experiments

1 Introduction

Carbon dioxide (CO2) release to the atmosphere is considered the major drive behind climatechange. Geologic storage of CO2 in deep saline aquifers is proposed as a climate mitigationsolution (IPCC 2005). In deep saline aquifers CO2 can be trapped structurally, by dissolu-tion in formation waters, through capillary forces (residual trapping), or by mineralization

N. Müller (B)CO2CRC Ltd., School of Earth Sciences, The University of Melbourne, Room 449/Level 4, Melbourne,VIC 3010, Australiae-mail: [email protected]

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reactions. These trapping parameters are directly influenced by the interaction of the reservoirrock or caprock formations with CO2 and brine in terms of CO2/water/rock interactions andfluid transport characteristics.

The injectivity of CO2 is influenced by properties of the rock, the fluids in the host forma-tion, pressure and temperature. The formation fluids and CO2 flow together in porous media.Multiphase flow systems behave differently from single-phase flow systems. The phases areless mobile than in single-phase flow (Dullien 1992). The mobility determines the injectionrate and pressure increase during CO2 injection and the distance that the injected (CO2) andreplaced (brine) fluid travels from the injection point through the formation (plume migra-tion). Usually reservoir simulations are used to predict the injection capacity and plumemigration in a reservoir. The key parameters used to determine the mobility are relative per-meability and capillary pressure, in addition to porosity and permeability. The uncertaintyof a simulation result is greatly influenced by these parameters. Whereas porosity and per-meability can be obtained from logs or routine core lab measurements, relative permeability,and capillary pressure are inherently more difficult to derive and require special experimentalprotocols and equipment.

This study focuses on the review of experimental methods for gas–liquid relative per-meability and the supercritical CO2 and brine relative permeability laboratory experimentsavailable in the open literature. In addition, future laboratory protocols are proposed.

2 CO2 Properties and Factors Influencing Relative Permeability

Currently not much data are available on CO2-brine relative permeability. CO2 storage is arelatively new field. Enhanced oil recovery by CO2 injection has now a large global applica-tion and was first utilized in the 1970’s during the high oil price period. The largest ongoingCO2 EOR operation is located in the carbonates of the Permian Basin, Texas (Manrique et al.2007). However, the knowledge in this field is limited. Questions arise in regard to densephase behavior of supercritical CO2 and the reactivity of carbonic acid, once CO2 dissolvesin brine. Does supercritical CO2 have different wetting behavior on a reservoir rock thanother fluids known in hydrocarbon production? Does the carbonic acid interaction with thevarious minerals of the host rock result in porosity and permeability changes? How do thesefactors affect relative permeability?

Mineralogical changes can be observed in nature and in laboratory experiments. Usually,quartz- and feldspar-rich clastic sediments show very limited alteration in aqueous CO2 sys-tems. Clay minerals and carbonates on the other hand react with carbonic acid quite rapidly,which can lead to pore space geometry changes in a relatively short time (Grigg and Svec2003; Marini 2007). Clay minerals in particular are very susceptible to changes in the sur-face layer chemistry, which affects the wettability and consequently the relative permeability(Busch et al. 2008).

CO2 is a supercritical fluid under reservoir conditions (critical pressure and tempera-ture: 7.38 MPa, 31!C). Above and below the critical point its density and solubility in waterchanges significantly. In its supercritical state, CO2 becomes denser with increasing pressureto a point where its density can exceed water at standard pressure and temperature conditions.More water dissolves into supercritical CO2 than gaseous CO2. The solubility of water intoCO2 is an order of a magnitude less than the solubility of CO2 into water (Spycher et al.2003). The solubility of water into CO2 can lead to formation dry-out close to the injectionpoint (Muller et al. 2008; Pruess and Muller 2009).

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Supercritical CO2-Brine Relative Permeability Experiments in Reservoir Rocks 369

In most cases when gas and water are present in a porous medium, the water willbe the wetting phase. The few laboratory measurements confirm the same behavior forCO2-brine systems, although CO2 can exhibit weakly wetting behavior under certain con-ditions (Chalbaud et al. 2007; Chiquet et al. 2007b). Weakly wetting means that the contactangle ! is between 170! to 130!. Contact angle laboratory measurements by Chiquet et al.(2007b) showed a substrate and phase dependency. In their experiment, supercritical CO2wetted the surface of muscovite more than quartz. At low pressure and CO2 in gas phase,! was for both substrates between 170! and 150!. A more CO2 wetting behavior was observedunder supercritical conditions: !quartz was "140! and !mica"120!. Chalbaud et al. (2007)modeled a decreased contact angle ! of 125!, when the substrate (carbonate core and glassmicromodel) was pre-treated with asphaltenes.

The wettability also depends on the interfacial tensions (IFT) of the CO2/water. Vari-ous laboratory experiments demonstrated that IFT values decrease with increasing pressure(Chiquet et al. 2007b; Chun and Wilkinson 1995; Hebach et al. 2002). The pressure rangebetween 7 and 10 MPa correlates to 70 to 25 mN m#1. The IFT changes rapidly around thecritical point of CO2. At pressures above 10 MPa, IFT is rather constant, ranging between25 and 35 mN m#1. The range above 10 MPa is comparable to most gas–oil systems (Dake1978). Small changes in pressure and temperature, especially around the critical point, canlead to significant variations in capillary pressure, because the capillary pressure changeswith the cosine of the wetting angle.

3 Experimental Methods Overview

The measurement of relative permeability in the laboratory can usually be obtained by twoprincipal approaches: steady state and unsteady state.

Most experimental set ups consist of a Hassler-type core holder with a pressurized sleeveto exert confining pressure. The cylindrical cores are capped with porous disks at both endsto provide a mixed and evenly distributed flow. Fluid flows axially through the core, enteringat the inlet and exiting at the outlet. Most tests start with the core sample at 100% saturationof the wetting phase (drainage experiment, Fig. 1). The outlet is usually maintained at aconstant pressure, using a backpressure regulator. The fluid flow and pressure are controlledby pumps, and the temperature has to be maintained constant.

The fluid saturations are measured during the displacement. The traditional methods aver-age the saturation on the core face and provide a saturation of each fluid. Examples fortraditional methods:

• Volumetrically, where the volume of fluids in vs. fluids out are compared.• Weighing the core, knowing the fluid densities of both fluid phases.

The advanced methods utilize continuous techniques, where the fluid saturation profile isrecorded along the core axis during the displacement. Examples for advanced techniques:

1. Electric resistance method, where electrodes are inserted in the test section, and theresistivities of the different fluids have to be known.

2. X-ray CT scans, where the accuracy depends on the contrast in absorption by the twofluids, e.g., the non-wetting fluid CO2 is less absorbing than the wetting fluid (brine).Depending on the set up and type of CT-scan, the images can be resolved in 3D highresolution microtomography.

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Fig. 1 Schematic drawing of a steady state set up (graph on the left) and an unsteady sate experiment (graphon the right)

3.1 Steady State Technique

The steady-state method can be described as driving a fixed ratio of two phases at constantrate through a porous medium until the saturation and the differential pressure along thesample become constant and the produced ratio equals the injected ratio (Abaci et al. 1992;Dullien 1992; Bear 1988).

To obtain relative permeability curves, the injection ratio of CO2 to brine is repeatedlychanged. At each injection ratio the fluids are flowing until the system is in a steady statemode. The saturation at each injection ratio is measured. The injection ratio is varied untila complete relative permeability curve is obtained (Dullien 1992). The differential pressureand fluid production data are used to derive relative permeability curves by numerical mod-eling. The saturation profiles have to be known for numerical modeling, which can only beestablished by method 1 and 2 listed above. As mentioned, all steady state methods needto be corrected for the capillary end effects, when capillary forces at the outlet retain anartificially high saturation of the expelled phase. The capillary end effect can be strongin gas–water drainage experiments and reduces the saturation range due to apparent highresidual water saturations. Usually steady state experiments require a long time for flowstabilization, depending on the sample rock properties.

3.2 Unsteady State Technique

In the unsteady state method only one fluid phase is displaced from the core by injectinganother fluid (Fig. 1). Both, the wetting and non-wetting fluid will exit the core (Fig. 1).Contrary to the steady-state techniques, flow and pressure stabilization are not required, thusunsteady state experiments have a shorter duration (Abaci et al. 1992; Dullien 1992; Bear1988).

The ratio of gas versus water is derived from the cumulative gas injected over time andcumulative water produced over time. The pressure and saturation transients are usually ana-lyzed by numerical modeling to determine the relative permeability. If capillary pressure Pccan be neglected, one can assume Buckley–Leverett displacement and the interpretation canbe done by an analytical solution. In reality, Pc cannot be neglected, and is imperative for acorrect interpretation from simulations. Unsteady-state techniques are particularly sensitiveto heterogeneity; hence the necessity to monitor the fluid saturation with, e.g., CT scans.

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Solutions have been proposed to overcome this issue (Maas et al. 1999). Similarly, unsteadystate methods need to be corrected for capillary end effects.

3.3 Challenges

Several factors impact fluid displacement experiments and have to be considered for datainterpretation.

• Core homogeneity/ heterogeneity• Core material mechanical competence• Fluid saturation (fluids should flow through the entire core, not only parts)• Capillary end effect (the holdup of the preferentially wetting phase at the outlet of a

porous medium during the simultaneous flow of two or more fluids) (Hadley and Handy1956)

• Gravitational forces (gravity can cause segregation of two fluids, depending on densitydifference)

• Fluid solubility, compressibility, and diffusion

Most interpretation tools can correct the effects listed above, with the exception of rockhomogeneity and the mechanical competence. Homogeneity is often an issue because all nat-ural samples, irrespective of origin, have a varying degree of heterogeneity. The mechanicalcompetence of the core can be compromised by its origin, e.g., unconsolidated and friablerock material or by the sampling/retrieve technique, e.g., sidewall cores. Both may lead toincomplete fluid saturation of the core and cause problems in interpreting data. Capillary endeffects occur at both the ends of the core plug, where the capillary pressure abruptly changesbetween rock and the inlet/outlet interface. The design of the fluid inlet and outlet can helpto mitigate the end effects. However, capillary end effects can never be entirely preventedand have to be corrected for. Gravitational forces can interfere with the measurement, if theflow is not vertical.

In general, relative permeability and capillary pressure interfere with each other duringthe experiments. Hence, corrections have to be made. Numerical simulation tools can eval-uate both factors in parallel. Several simulation runs and data sets are required, since onesimulation cannot produce a unique solution from a single data set.

Upscaling laboratory results to reservoir conditions imposes great uncertainty on reser-voir simulations, regardless if one experiments with oil–water, gas–water, or supercriticalCO2-brine systems. How representative are the properties of the few pieces of rock for theentire reservoir? Associated with the upscaling issue is the size of grid blocks that define thegeometry of a simulated reservoir. In general, the lab experiments are conducted on smallcore plugs, size ranging from 0.05 to 0.15 m, but the grid blocks of reservoir model can rangefrom 0.1 to 1,000 m (Christie 2001). Solutions were proposed using generalized mathemati-cal relative permeability functions by (Brooks and Corey 1964; Burdine 1952; Corey 1954;Mualem 1976; van Genuchten 1980) and many others, but these are usually either restrictedto a specific reservoir or cannot predict multi-phase flow in unconsolidated, heterogeneous,carbonate or shaly rocks within a permitted uncertainty range.

Another phenomenon appears when the core is alternatingly flooded with gas and water,the so called hysteresis. Drainage (when the non-wetting gas invades the pores) never leads to100% non-wetting ( = gas) saturation because of non-continuous flow behavior. At residualwater saturation water will occupy the small pores and cover the large pores with a film,but is rendered immobile. During imbition (water is pushed through the pores) the residualsaturation of the non-wetting gas limits the maximum wetting saturation. The de-saturation

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is irreversible. The gas phase becomes discontinuous and “snaps-off”, leading to hysteresis.The hysteretic effect increases with repeated cycles of imbibition and drainage, decreasingthe relative permeability of CO2 (Juanes et al. 2006).

Particular challenges arise when experimenting with supercritical CO2-brine systems, asfollows:• High pressure and temperature, at least above the critical conditions of 7.38 MPa and

31!C, which inflict high strain on selected material of the experimental setup, the variousconnections pieces, and a more elaborate setup with ovens, fluid baths, etc. for temperaturecontrol.

• Corrosive nature of dissociated CO2, carbonic acid attacking experimental equipmentand the rock material itself.

• Still unknown magnitude of rock wettability changes due to the presence of supercriticalCO2.Through the following review of the open literature it becomes evident that the assorted

authors have attempted to solve the manifold challenges by various means. Some proposedto use analogue fluids such as inert gas (N2) or oil (n-decane) to overcome the problemof material corrosion, rock alteration, high pressure, and temperature. The results of thoseexperiments remain inconclusive whether the measured relative permeabilities and residualsaturation endpoints are representative for in-situ CO2-brine floods. Others successfully setuphigh pressure and temperature equipment and used supercritical CO2, but did not achievecomplete fluid displacement due to core heterogeneity, fluid gravity segregation and rockinternal capillary effects.

4 Steady-State Experiment of Brine-CO2 Relative Permeabilityby Perrin et al. (2009)

In this experiment, the core was mounted in a sleeve and an aluminum coreholder. Water wasinjected around the sleeve to create confining overburden pressure. An electric heater insidethe coreholder warmed the water to reservoir temperature. CO2 and brine were co-injectedsimultaneously by a synchronized dual pump system. The pumps were cooled to 5!C toensure constant CO2 volume. The liquids were heated to reservoir temperature in a waterbath and mixed before entering the core face at the inlet. At the outlet of the core, brine, andCO2 were separated by gravity in a separator. Both fluids were recycled and constantly incontact with each other to achieve thermodynamic equilibrium. A backpressure pump keptthe pore pressure at least 1.3 MPa above reservoir pressure to avoid leakage in the core sleeve.The pressure drop across the core was measured with pressure transducers at the inlet andoutlet of the core. The temperature in the coreholder was monitored, as well as the injectionrate and pressure and the volume of each pump. X-ray CT was used to continuously scan thesaturation along the core.

First the brine permeability was measured at several flow rates while the pressure drop wasrecorded. Applying Darcy’s law, using fluid viscosity and densities at reservoir temperatureand pressure, the permeability was calculated. The drainage permeability was evaluated byinjecting CO2 and brine in different proportions of fractional flows. For each fractional flowthe pressure drop and gas saturation were measured. Once they were stabilized, steady statewas assumed. The process was continued with different fractional flows until 100% CO2 wasinjected.

Two different rocks were subjected to CO2-brine core flooding, sandstone from theOtway Basin/Australia and fired Berea sandstone. The cores were 5.08 cm in diameter and15.24 cm long. Both exhibited heterogeneity, more pronounced in the case of the Otway

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Fig. 2 Saturation maps of CO2-brine core flooding of Otway Basin sandstone (Perrin et al. 2009)

sandstone, which had porosity variation of 6 % along the axes. The saturation map of the Ot-way sandstone exhibits very strong heterogeneity perpendicular to the horizontal flow direc-tion (Fig. 2). Reservoir temperature was 63!C and pressure 12.4 MPa. The average porositywas 18.2% and the permeability 50 mD. 6,000 ppm NaCl and 500 ppm CaCl2 brines wereemployed. The core was drained at 2 ml/ min. At 100% CO2 fractional flow the residual watersaturation was high, Sw = 44% and krg = 0.6. At 100% brine fractional flow, Sw = 90%and krw = 0.5. The high saturation end points indicate that the displacement of the brine wasnot complete.

The porosity of the Berea sandstone appeared at first glance quite homogenous along thecore axes at 20.3% on average, with a variability of 1%. The permeability was 430 mD. Res-ervoir temperature was 50!C and pressure 12.4 MPa. The NaCl rich brine had 10,000 ppm.Relative permeability was measured at three different flow rates: 2.6, 1.2, and 0.5 ml/ min.Incomplete gas saturation is visible at all flow rates (Fig. 3a). Apparently capillary barriersprevented flow of CO2 to the bottom part of the core, enhanced by the buoyant nature ofCO2. The effect though could not be modelled with TOUGH2 MP ECO2N (Pruess 2004)(Fig. 3b). Another experiment was conducted with the core turned 180! along the horizontalaxis. The orientation of the residual water saturation did not change despite the differentposition, which indicates incomplete fluid replacement.

In addition, a flow-rate dependency was observed. At the highest injection rate (2.6 ml/l)CO2 was most mobile (Swr = 57% and krg = 0.1), where as at 0.05 ml/l Swr equalled 73%.At 100% fractional flow of brine and 2.6 ml/l injection rate Sw = 95% and krw = 0.5. Theflow-rate dependent results, the high saturation end points, and saturation profile seem toindicate heterogeneity.

It was not reported if the Otway sandstone was flooded at different flow rates. No modelresults have been presented for the Otway sandstone. Both experimental data appear to beheavily influenced by sample heterogeneity and the horizontal setup with long cores, whichlead to incomplete fluid displacement.

5 Unsteady-State Experiment of Brine-CO2 Relative Permeabilityby Bennion and Bachu (2006)

The core flood experiments were conducted in Hastelloy C or titanium equipment. The3.81 cm diameter core was mounted in the coreholder with a pressurized sleeve. Two ports

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Fig. 3 a Saturation map of Berea core at 100% fractional CO2 flow. b Comparison simulation result withsaturation map (Perrin et al. 2009)

were tapped to the inlet and outlet of the core to allow fluid displacement and pressure mea-surement. Radial distribution plates capped both ends of the core to promote uniform fluidflow. Pulsation-free pumps facilitated continuous fluid displacement. The fluids were pumpedthrough a filter before entering the core face to prevent particles from clogging the core. Avalve regulated the backpressure and the pressure between inlet and outlet was measuredwith quartz strain gauges. The coreholder and injection fluids were contained in an oven tomaintain the temperature at reservoir conditions.

Routine air permeability and porosity tests were conducted on the cores. Capillary pres-sures were measured by high-pressure (400 MPa) mercury injection. The core was saturatedwith gas-free brine. The brine was displaced by CO2-equilibrated brine until a constantgas water ratio (GWR) was achieved. At this point, the brine permeability was obtained.Then water-equilibrated CO2 was injected until at the outlet a stabilized pressure drop and aGWR >15,000m3/m3 were observed. The total gas and water rates as well as the pressuredrop were recorded. These data were used to generate drainage kr curves using a numericalregression model. Apparently multiple flow-rate experiments were performed to verify the krendpoints and to evaluate capillary end effects, but the flow rate numbers were not reported.The saturation profile in the core was not verified; no X-ray CT scan or other method wasreported.

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To evaluate imbibition, CO2-saturated brine was injected until the GWR of the effluentequalled the GWR of the injected fluid and the pressure drop stabilized. This was apparentlydone with multiple displacement rates, but once more, no flow rates were reported.

After the flood, the core was depressurized and the remaining fluid extracted by theDean–Stark method (Dandekar 2006) to measure the residual fluid saturation and verify theSw and Sg endpoints.

In summary, three data sets were generated. First the brine permeability was determined.In primary drainage the core was flooded with CO2 and the gas kr endpoints determined. Inimbibition the core was flooded with brine, where CO2 was partly displaced, partly trapped.A strong hysteretic behavior was observed. The kr curves were generated by computer his-tory matched models and the Corey coefficients determined. 14 drainage and 10 imbibitionCO2-brine floods were measured on different rock samples. The rock samples comprisedreservoir rocks like sandstone and carbonate, as well as two shale and one anhydrite caprock.The temperatures ranged from 35 to 75!C, the pressure between 8.6 to 27 MPa, and salinityvaried from 27,000 to 250,000 ppm.

In the 11 experiments, the relative permeability of CO2 observed is rather low. In thedrainage cycle, the average krg is 0.27 at maximum Sg, excluding the three caprock samples.The average maximum Sg is " 50%.

Two samples showed higher relative permeability and lower residual water saturation, theCardium#1 and Basal Cambrian sandstone (Fig. 4). Both had a CO2 kr of " 53% and anirreducible water saturation of 20 and 30%. In the 10 imbibition experiments, half of the CO2is left behind. Starting with " 50% Sg, residual gas saturation at the end of the brine flood is" 25%. The average relative brine permeability is 0.22. Only the Cardium#1 sandstone hada brine krw of 90% at 10% Sgr (Fig. 4).

Cores from the same lithological unit and higher median pore size had generally higherporosity and brine permeability. All data start at 100% brine permeability. The measurementscommenced by flooding the water-saturated core first by gas-saturated water. The relativepermeability of brine will always be 100% under those conditions.

The low CO2 kr end points indicate incomplete displacement of the brine either due toend effects or rock heterogeneity. Since no saturation profiles were measured during theexperiment, it is impossible to say which effect impaired the relative permeability of CO2.

Fig. 4 Relative permeability versus CO2 saturation. Left figure: Cardium# 1 sandstone drainage and imbibi-tion. Right figure: Basal Cambrian sandstone drainage (Bennion and Bachu 2008)

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6 Unsteady-State N2-Brine and CO2-Brine Relative Permeability Experimentsby Chalbaud et al. (2007) and Egermann et al. (2006)

Both studies followed the similar procedures and were conducted by the same authors. Inboth studies carbonate samples were used with the core plug dimension of 20 cm in length and5 cm in diameter. The porosity of the samples was determined by a weighting technique andby the nuclear magnetic resonance (NMR). The permeability was 4 mD and porosity 23.6%.Mercury porosimetry gave a threshold capillary pressure of 0.3 MPa for a mercury-air system.The Buckley–Leverett function was used to correlate this data to CO2-brine system.

The carbonate relative permeability properties were first evaluated by N2-water flood.An unsteady-state technique was applied, by which the core was first water saturated andthen nitrogen injected at ambient conditions. A constant pressure differential pressure wasmaintained between the outlet at atmospheric conditions and the inlet. The core was placedin vertical position and the gas injected at the top.

History matching the experimental data with numerical modeling derived the relativepermeabilities of gas/water. The gas/water capillary pressure was calculated scaling the mer-cury-porosimetry data with the Leverett function. Both data sets were able to match theexperimental data. Gas relative permeability was extrapolated numerically until 100% Sg,although the experimental data reached only 80% Sg (Fig. 5).

To test the influence of wettability on the mobility of CO2, the core was first measuredunder water-wetting (WW) conditions. The same core was prepared for intermediate-wetting(IW) conditions by aging the material with an asphaltic crude oil at zero water saturation for3 weeks. During the treatment the absolute permeability was reduced by a factor of 4. Porosityremained the same. Wettability indexes were estimated from Pc curves obtained in a centri-fuge. The indexes were calculated using the USBM method (Anderson 1986; Donaldson etal. 1980).

For the CO2-brine experiment under reservoir conditions, a Hastelloy core holder andpumping system were used to inject gas into the brine saturated (5 g/l) core. CO2 was pushedby water injection though a buffer cell. The core holder and the buffer were located in an

Fig. 5 N2- water relative permeability, experimental and model data (Chalbaud et al. 2007)

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oven to work in a controlled temperature environment. The inflow line from the pumps tothe buffer cell and core holder was heated. The entire system was put under pressure usingbackpressure equipment. The plugs were coated with a non-permeable, temperature resistantlateral material to avoid CO2 uptake, a process commonto elastomer and rubber materials.

The same sample used in the ambient N2 injection experiment was set in the horizontallypositioned core holder transparent to X-rays. The local saturation profiles were measuredduring the experiment to follow the transient evolution and to confirm the stabilization atthe end of each step. The stabilized saturation profiles exhibited fluctuations though, whichis either due to sample heterogeneity or incomplete fluid displacement due to the horizontalsetup. Four injection rates were investigated for each multi-rate unsteady-state experiment:5, 20, 25, and 100 cm3/h. The pressures ranged from 8, 10, 14, and 18 MPa at 60 and 80!C.The differential pressure and brine production were recorded.

When gas injection commenced in the water-wet rock, a distinctive pressure increase of200 mbar was recorded when CO2 reached the inlet face of the core. This is due to thethreshold pressure that has to be overcome to push the gas into the pores. This was seen asan indication that CO2 is non-wetting. In the case of intermediate wetting, the pressure evo-lution was smoother (Fig. 6). The brine production increased more or less linearly until CO2broke through at the outlet. Brine production was slightly less than gas injection because CO2dissolved in the water in the core. After gas breakthrough the differential pressure droppedand stabilized after a while together with the brine production.

Different gas saturations were observed for different flow rates. At high flow rate(100 cm3/h), however, the scatter in the data was high. Probably the pressure had not stabi-lized at highest flow rate, which was due to the pump limitation to 2 l. The fluid flow stoppedbefore fluid pressure stabilized.

The comparison of IW and WW CO2 and N2 injection tests show different replacementmechanisms (Fig. 6), which can be attributed to higher solubility of CO2 into water. Also theIFT’s are different; IFT of N2 is " 2.5 times higher than CO2.

The relative permeabilities were numerically derived. The modelled water relative per-meability is 20% higher in the IW CO2 injection test than under water-wet conditions. Nodifference of water relative permeability was observed between WW and IW conditions inthe N2 injection tests. Similar observations in micro glass models confirmed this behavior(Chalbaud et al. 2007).

The relative permeability of CO2 under IW and WW were the same, although a differentpressure profile was observed. CO2 relative permeability was 100% at Sw = 20%. The otherend point was at krg = 0.001 and Sw " 95% (Fig. 6).

Fig. 6 Left figure: N2 and CO2 production data under wetting and intermediate wetting conditions. Rightfigure: relative permeability of CO2 and water. Water has higher kr at intermediate wetting conditions(Chalbaud et al. 2007)

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The comparison of the experiments at different temperature and pressure was difficult, ifnot impossible. These difficulties were attributed to CO2 density and solubility variability.

The experimental data look reasonable, although the modelled results are not conclusive.The different production behaviors were not included in the modeling effort. Hence, therelative permeabilites and saturation endpoints are questionable.

7 Steady-State Experiment of Brine-Oil-CO2 Relative Permeabilityby Dria et al. (1993)

Although the three-phase relative permeability of oil, brine, and CO2 were evaluated in thisexperiment (steady-state), the study was included to reflect earlier attempts to measure CO2relative permeability.

In this steady-state experiment, the saturations were determined by tracer co-injection.The sample was a 5 by 45 cm dolomite core with a granular matrix. The X-ray CT scan con-firmed a heterogeneous permeability. The absolute permeability was measured on a smallcore with 2.54 cm length. The brine permeability was 24 mD at 100% Sw, and the averageporosity equalled 20.2%.

Three fluids were pumped through the long core: 20,000 ppm CaCl2 brine, n-decane, andCO2. The phase properties were estimated and the viscosities, flow rates, and fractional flowscalculated. The water/oil/gas were constantly replenished at 71!C and average core pressureof 9.65 MPa. The flow-through set-up was required to collect the effluents and analyze tracerconcentration. The flow was controlled with constant injection rate coupled with downstreampressure control. The saturations were monitored until a constant pressure drop was achievedat the four internal pressure ports and the inlet and outlet of core faces, and constant effluentflow rate. The three-phase flow velocity was regulated to 0.12 m/day.

The experiment was set up to emulate an EOR field situation. The gas-free core was satu-rated in oil, with residual water remaining. Under these conditions, the initial water saturationhad to equal the residual water saturation, and Sg had to be zero. The core was first floodedwith water and then with CO2. The brine injection would commence an oil/brine two-phaseflow and intermediate two-phase steady-state saturation. The gas injection would decreasethe oil fractional flow. The brine fractional flow would remain at the two-phase flow valuewith following saturation profile:

1. Decreasing brine saturation2. Decreasing oil saturation3. Increasing gas saturation

Apparently the experiment started with a low injection rate (the flow rates were not speci-fied). The permeability was measured and the two and three-phase saturations attained as bystep 2 and 3 above. Then the core was flooded with n-decane and ready for next three-phaseexperiment. The saturation values were evaluated by tracer detection.

Large fluctuations at the intermediate pressure ports were observed at the endpoint gasexperiments, when the fractional flow of gas was 100%. High flow rates were necessary toobtain measurable pressure drop from inlet to outlet. The differential pressure measurementsfrom the 2nd and 3rd port were taken to calculate kr to minimize capillary end effects thatwould be recorded at inlet and outlet of core. The relative permeability reference was krbrine.

The total mobility of three-phase flow was low. The gas and oil permeability weresimilar, probably due to the miscibility of CO2 in oil. CO2 concentration in oil was

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Table 1 Fitted relative permeability end points of three-phase flow oil/brine/CO2 (Dria et al. 1993)

Phase Krj Srj " j (Corey exponent) # j (Corey exponent)

Brine 0.36 0.36 3.1

Oil 0.57 0.16 1.1

Gas 0.28 0.16 1.1

0.6 to 0.7 mole fraction. Also, oil and CO2 wetted the dolomite similarly. CO2 approachedvalues of oil wettability. The Corey exponents for oil and brine were between 2 and 4. Therelative permeability end point of brine at secondary imbibition was kr = 0.365 at Sw = 84%.The experimental parameters were fitted to a simple Corey model, deriving following per-meabilities for three-phase flow (Table 1).

Oil and CO2 were observed as non-wetting and water as the strong wetting phase. The krof each phase seemed to depend on the saturation of the same phase, not on others. The two-phase and three-phase experiments coincide on this observation. The data points of the twoand three-phase experiments are quite scattered, which could be for many reasons, e.g., cap-illary end effects, rock heterogeneity, gas not in contact with tracer, steady-state not reached,etc.

The results were compared with other three-phase experiments by Oak et al. (1990) andSchneider and Owens (1970). The comparison was based on that all experiments used paraf-fin oils, the samples were water wet and well sorted clastic rocks, and that the brine/oil/ N2behaved similar as brine/oil/CO2.

Oak et al. experiments showed that the N2 relative gas permeability was higher than forCO2. Relative brine permeability behaved similarly though. The kr of oil differed from krof N2, whereas the Dria et al. experiments produced similar kr for CO2 and oil. The wet-ting behavior was comparable: N2 strong non-wetting, oil intermediate wetting, and brinewetting.

The experiments of Schneider and Owens presented similar brine data. The N2 relativegas permeability was higher than kr CO2, but not as high as in the experiments from Oaket al. The conclusion from these comparisons was that CO2 is less mobile than N2 and willprobably lead to lower well injectivity.

The low kr CO2 end point indicates that the displacement of the brine was not complete. Itis difficult to judge if capillary end effects, rock heterogeneity, or the horizontal setup with thelong core sample leading to incomplete fluid displacement impaired the relative permeabilityof CO2, since no saturation profiles are available.

8 Conclusions and recommendations

Two steady-state and two unsteady-state studies have been reviewed, at temperatures from50 to 75!C, pressures from 9.6 to 27 MPa and mostly low salinities. Typical reservoir rockswere tested, namely sandstones and carbonates. The summary of the experiments is given inTable 2.

In general, low relative permeabilities are observed for CO2 flow in the experiments,except in the study of Chalbaud et al. and Egerman et al. The relative permeability of brine ishigher in general. Especially during the second imbibition brine seems to effectively “trap”CO2 and limits its flow. The low kr endpoints indicate rock heterogeneity. The saturation

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380 N. Müller

Table 2 Comparison of various relative permeability experiments

(Perrin et al. 2008) (Bennion andBachu 2008)

(Chalbaud et al.2007; Egermannet al. 2006)

(Dria et al.1993)

Method Steady-state Unsteady-state Unsteady-state Steady-state

Rock type Sandst.: Berea/Warre C Sandstonesandcarbonates(11)

Dolomite Dolomite

T (!C) 63/50 35–75 60 71

P ( MPa) 12.4 8.6–27 10 9.65

S (mg/g) 10/6 NaCl 27.1–248 5 NaCl 20 CaCl2k (mD) 430/50 0.3–67 (brine) 4 24 (brine)

Kr CO2(fraction)

[email protected]/[email protected]

[email protected]–[email protected]

[email protected] Sw [email protected] Sg

Kr brine(fraction)

[email protected]/[email protected]

[email protected]–[email protected]

[email protected] Sw [email protected] Sw

Remarks Berea Krflow-ratedependent

Only 4imbibitiontests forbrine

Measurementsstarted at100% brinesaturation

Three-phaseflowexperiment:CO2/brine/oil

profile of Perrin et al. shows heterogeneity during CO2 flooding. The study of Bennion andBachu and Dria et al. did not present saturation measurements, so it is impossible to saywhether rock heterogeneity or experimental issues, e.g., capillary end effects caused low kr .

In horizontal experimental set ups difficulties occur when the brine volume has to be dis-placed by the gas phase throughout the entire core plug. The less viscous gas phase does notreplace the more viscous brine phase in a piston like motion. Viscous fingering can occur,which leads to quick gas breakthrough at the core outlet, without the gas ever reaching allparts of the core plug. In addition, gravity affects the experiments in segregating the gas andbrine phase. CO2 is more buoyant that brine and tends to flow to the top of the coreplug,resulting in incomplete brine displacement. Having a vertical setup instead of a horizontalcan mitigate this issue.

In most of the experiments the CO2 was equilibrated with water to avoid measurementsartifacts due to the solubility into water. Chalbaud et al. and Egermann et al. used unsaturatedbrine and compensated for the solubility effect by modeling their results.

A comparison of N2/brine and CO2/brine relative permeabilities is difficult; it appearsthat the different properties of the gases, e.g., IFT result in different relative permeabilities.CO2 has a lower interfacial tension with the same substrate than N2, about 2.5 times lower(Chiquet et al. 2007b; Chun and Wilkinson 1995; Hebach et al. 2002). The capillary pressureis similar related, the CO2/brine capillary threshold pressures are about 2.5 times lower.

In general CO2 behaves as the non-wetting phase in most of the experiments. Exceptionswere the experiments of Chiquet et al. and Chaldbaud et al. observed weak intermediate wet-ting behavior at supercritical conditions on muscovite substrate. Chaldbaud et al. observedintermediate wetting behavior when the substrate was treated with asphaltic crude oil.

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Due to the difficulties to compare the acquired data by provided documentation, the dataremains inconclusive in terms of the preferences towards steady state or unsteady state setup. Both set ups seem to suffer experimental drawbacks or inconclusive interpretation.

There is a need for accurate, repeatable, and reliable measurements. Laboratory measure-ments have to be ascertained that are standardized and comparable. The recommendationsare as follows:

• Establish first the appropriate measurement protocol with a core material that (a) willnot alter during the core flood due to the corrosive nature of carbonic acid and (b) ishomogenous, before measuring “real” core material of a potential storage formation. Theusage of a clean and homogenous quartz sandstone or artificial core plug like sinteredceramics or glass would be optimal. These materials allow X-ray penetration during thecore flood.

• Confirm homogeneity of core material with X-ray CT scan and/or NMR methods.• Set up experimental equipment in a fashion that allows continuous X-ray CT scan to

monitor the saturation profile while flooding.• Set up the equipment in such a way that gravitational forces are eliminated (e.g vertical

and/or short measurement time).• Maintain the same parameter space. For example, use the same temperature, pressure,

brine consistency, CO2 saturation, fluid velocity, fluid fractions, etc. to compare differentcore materials with each other.

• Monitor and if possible quantify the changes in porosity and permeability distributionthroughout the core due to reactive flow by repetitive measurements on the very samesample.

• When interpreting the measurement results, observe if the fluids where saturated in respectwith each other, if the thermodynamic fluid behavior has to be accounted for (mutual sol-ubility, diffusion, etc).

• Once the experimental protocol has been successfully established, it can be applied withreasonable confidence on heterogeneous and “real” rocks.

In principal, these recommendations do not differ drastically from any oil and gas relativepermeability measurement. The novel aspect is the reactivity of the core material with thecore flood fluid and the resulting permeability, porosity, and wettability alteration. This hasto be factored in the experimental procedure and interpretation.

Acknowledgments Shell International Exploration and Production (SIEP) and Carbon Capture Project(CCP) SMV team supported the literature review. I would like to thank to the colleagues at SIEP and CO2CRC,who provided valuable input, and the anonymous reviewers of the manuscript.

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