An Experimental Study of the Effect of Rock/Fluid Interaction on Resistivity Logs during CO<sub>2</sub> Sequestration in Carbonate Rocks

doi:10.4236/gep.2014.23001

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Journal of Geoscience and Environment Protection, 2014, 2, 1-7

Published Online June 2014 in SciRes. http://www.scirp.org/journal/gep

http://dx.doi.org/10.4236/gep.2014.23001

How to cite this paper: Adebayo, A., & Mahmoud, M. (2014). An Experimental Study of the Effect of Rock/Fluid Interaction

on Resistivity Logs during CO2 Sequestration in Carbonate Rocks. Journal of Geoscience and Environment Protection, 2, 1-7.

http://dx.doi.org/10.4236/gep.2014.23001

An Experimental Study of the Effect of

Rock/Fluid Interaction on Resistivity

Logs during CO2 Sequestration in

Carbonate Rocks

Abdulrauf Adebayo, Mohammed Mahmoud

Petroleum Engineering Department, King Fahd University of Petroleum & Minerals, Dhahran,

Saudi Arabia

Email: [email protected]

Received January 2014

Abstract

Accurate laboratory measurements and analysis of electrical properties of core samples are a

prerequisite step to the evaluation of oil and gas reserves. In recent times, this evaluation tech-

nique has been adopted in carbon dioxide sequestration projects for estimating and monitoring

carbon dioxide (CO2) accumulation in saline aquifers. Several papers have reported laboratory

success in the use of resistivity measurements to monitor the flow and also estimate the volume of

CO2 plume in geological formations. Such laboratory experiments did not capture the effect of CO2

-brine-rock interaction (CBRI) on saturation estimation. The possibility of a change in value resis-

tivity due to CO2/brine/ rock interactions, and the possible effect on CO2 monitoring and estima-

tion are of immediate interest here. Preliminary results of an ongoing research work showed that

a much longer experiment time accommodates CO2-brine-rock interaction which ultimately lead

to change in rock resistivity. We hereby present the electrical behavior of carbonates to CO2/

brine/rock interaction during prolonged CO2 sequestration and the effect on saturation estima-

tion. This electrical behavior and its possible effect on CO2 monitoring and estimation are dis-

cussed.

Keywords

Carbon Dioxide Sequestration and Monitoring, Resistivity Log, Rock Fluid Interaction,

Archie Equa tion

1. Introduction

CO2 is normally injected into underground formation at high pressure and temperature such that the CO2 exists

in a supercritical state. The supercritical state will reduce the volume of rock space occupied by injected CO2 per

unit volume of CO2 existing at atmospheric condition. The pressure and temperature at which CO2 exist in this

state can be found in aquifers at depth of about 800 meters or more. Hence candidate formations for carbon cap-

A. Adebayo, M. Mahmoud

ture and sequestration (CCS) must be at this depth (Benson, 2008). While CO2 is injected into a subsurface for-

mation, four major trapping mechanisms ensue namely: 1) Physical/Structural trapping—a process whereby

impermeable cap rock at the top of the formation prevent the CO2 from escaping out of the formation, keeping it

in place (Benson, 2008; W ang, 2010), 2) Solubility trapping—a process whereby injected CO2 dissolves in for-

mation pore water, 3) Mineral trapping—occurs when aqueous CO2 reacts with formation rock minerals pro-

ducing precipitates of carbonate minerals, and 4) Residual or Capillary trapping which occurs after CO2 injec-

tion stops and water begins to imbibe into the aquifer displacing the CO2 already in the aquifer. Not all the CO2

is displaced but some are left behind as residual CO2 (residual trapping). Dissolved CO2 can acidify formation

water and subsequently mobilize and transport trace metals as it migrates in the formation (Gaus, 2010). A stor-

age formation with strong cap rock is thus crucial to avoid leakages of trace metals and compounds into overly-

ing portable aquifers. There is also the need for proper monitoring of CO2 migration so as to observe its behav-

ior, distribution, and possible leakages. Hence, evaluation of the reliability of CO2 monitoring techniques should

be first step in risk assessment of any CCS project (Wang, 2004). Techniques required for monitoring CO2 mi-

gration can be borrowed from a variety of other applications such as those used in the oil and gas industry, and

those used in ground water monitoring (Benson, 2008). Examples of such techniques are seismic, gravity, and

resistivity measurements. Seismic is the most extensively used technique. The use of resistivity measurements is

also promising. Resistivity technique is applicable because rocks contain saline water and are thus conductive.

The use of resistivity measurements to monitor and quantify CO2 in underground geological formation depends

on the fact that formation resistivity is higher at locations occupied by CO2 compared to locations un-invaded by

CO2, and the resistivity increases as CO2 saturation increases. The amount of resistivity changes depend on the

volume of CO2 present. With the use of Archie’s equation or modified Archie’s equation, CO2 saturation distri-

bution, migration, and volume can be estimated. Many experimental and field studies have successfully used re-

sistivity measurements to monitor CO2 migration (Ramire z, 2003; Wa ng, 2010; Gie se, 200 9; Chr iste nse n, 2006;

Nakat su ka, 2010). Archie’s equation is given in Equation (1).

wmt



=

∅



(1)

where “a” is a constant determined as the intercept passing through 100% porosity on a formation fac-

tor-porosity plot, while “m” and “n” are cementation factor and saturation exponent respectively and are ob-

tained from laboratory resistivity measurements on core samples.

Kiessling et al. (2010) applied Archie’s equation to estimate CO2 saturation distribution in a CO2 SINK test

site close to Ketzin (Germany). Similarly, Nakatsuka et al. (2010) reported the use of Archie and modified

Archie equation to estimate CO2 distribution in the Nagaoka pilot CO2 injection site. Time lapse resistivity

measurements in both cases were used to monitor movement of CO2 to and away from different zones of interest.

Changing resistivity values were interpreted as change in CO2 saturation. Figure 1 shows the time lapse resis-

tivity logs for both cases.

This study is new compared to previous works in the following sense: Many previous laboratory works have fo-

cused on the applicability of electrical resistivity measurements to track CO2 migration by way of resistivity change

as a function of CO2 saturation changes during CO2 sequestration. Such experiments were also conducted only

within several hours or less. The fate of formation resistivity in the event that the CO2 remained trapped in the

pores for an extended period of time and the subsequent effect of the CO2/brine/rock reactions on resistivity and on

CO2 monitoring and estimation has not been addressed. This paper investigates the effect of CO2 brine rock reac-

tion on resistivity and CO2 saturation estimation.

2. Materials and Methods

All samples were collected from the same quarry rock of Indiana lime stone with recorded high level of homo-

geneity. Cylindrical samples with dimension of 3.74 cm diameter and length of 7 cm were cut and surface

grinded to ensure very flat end faces. Samples were cleaned by solvent reflux method and vacuum dried in oven

at 80˚C. Sample properties were then measured and tabulated in Table 1. De-aerated synthetic brine with com-

position and properties shown in Table 2 wer e prepared and used to saturate core samples.

A. Adebayo, M. Mahmoud

(A)

(B)

Figure 1. Time lapse resistivity logs: (A) laboratory data taken with permission from Nakatsu-

ka et al. (2010) (B) field data taken with permission from Kiessling et al. (20 10) .

Table 1. Sample properties.

L D Bulk Vol. He. Pore Vol. 500psi He Porosity (500psi) K

ID (cm) (c m) (cc) (cc) (%) (mD)

209 7.03 3.741 77.37 14.70 19.002 324

206

7.06

3.736

77.43

13.78

17.790

423

Table 2. Synthetic formation brine.

Saline Aquifer

Composition Weight (g/l)

Sodium Chloride 44.5

(NaCl)

Calcium Chloride (CaCl2∙2H2O) 9.65

Magnesium Chloride (MgCl2∙6H2O) 3.41

Sodium Bicarbonate (NaHCO3) 0.15

Sodium phosphate (Na

)

0.28

TDS (g/l) 57.99

Density, g/cc 1.02

Resistivity @ 22.5˚C, (o h m-m) 0.401

3. CO2 Injection Apparatus and Procedure

Figure 1 is the CO2 injection set up. The setup is designed to store supercritical CO2 in a brine saturated core

sample at a typical reservoir condition of 40˚C and 2000 psi overburden pressure. It consists of a CO2 source, a

core resistivity assembly, a test cell, pressure system, a heater, gauges, a LCR meter, and a data acquisition sys-

tem to record resistivity measurement as a function of time as CO2 aging lasts. A 3.7 cm diameter by 7 cm long

carbonate core was placed in a Viton sleeve embedded with two electric current potential electrodes. A Teflon

tape was wrapped along the circumference of the core (except the portion that would be in contact with the elec-

tric potential electrodes) prior to placing it inside the Viton sleeve so as to delay the breakthrough of CO2

through the sleeve. The core together with the sleeve was then coupled with the pore inlet and outlet tubing

which doubled as current inlet and outlet electrodes respectively. The core assembly was placed into a test cell

A. Adebayo, M. Mahmoud

and then subjected to overburden pressure of 500 psi after which the core was circulated with brine to remove

trapped air from the core’s pore space. An inlet valve and outlet valve attached to the core assembly served as

means of either closing up the core after CO2 injection or for fluid sampling at the end of storage. At the end of

brine circulation, cell temperature was raised to 45˚C, the overburden pressure too was raised to 2000 psi and

the system left for over 24 hours for the core to equilibrate with the surrounding temperature and pressure. At

this point, the outlet valve was closed and CO2 was applied at the inlet tubing at a pressure of 2000 psi making

the CO2 to exist in a supercritical state in the core. After few hours, the inlet valve was closed. CO2 inlet was

from the bottom of the core and the outlet tubing was at the top. The outlet tubing was also connected to a pres-

sure gauge used to monitor CO2 pressure (Figure 2). The same procedure applied for the second core. Core

sample IL-206 was aged for 3 weeks (46 days) and IL-209 was aged for (90 days). During these aging times, the

DAQ system recorded measurements of resistivity, pressure, and temperature of the core as a function of time.

3. Results and Discussions

Results after prolonged storage showed that rock electrical signature was constant prior to CO2 injection and

later increased in response to CO2 influx and remained constant again around this resistivity value until after

quite a number of days when constant resistivity pattern changed to a more turbulent pattern suggesting the on-

set of chemical reactions between the three phases—CO2, brine, and carbonate grains. Considering the first 300

hours of CO2 storage (between 200th hour marking the beginning of CO2 storage till 500th hour) in sample

IL-206 (Figure 3(a)). It can be seen that although CO2 pressure is fairly the same during this period but the for-

mation resistivity dropped at about 150 hours after CO2 storage and later increased to the CO2 base line. Esti-

mating CO2 saturation within this period using Equation (1) would give different saturation profile whereas in

the true sense the brine saturation is the same since no outflow was allowed. The same phenomenon can be seen

Figure 2. CO2 sequestration and online resistivity measurement system.

Flask

Temperature Control

and Pressure Bath

Overburden Oil

Pressurized CO2

Cylinde r

Syringe Pump

Analogue to Digital

Converter

C omputer

LCR Meter

Pressure Transducer

Pressure Gauge

Core Holder

Th erm oc ouple

Overburden Pump

Air Supply for

Overburden Oil

Drainage

A. Adebayo, M. Mahmoud

later at about 1000th hour to 1100th hour. The same phenomenon was observed in another experiment done on a

different sample (IL-209) confirming repeatability (Figure 3(b)). The effect of such variation in resistivity

measurements is best described in Table 3. This behavior showed that drop in formation resistivity does not

necessarily mean migration of CO2 away from the location but can be due to CO2/brine/rock interaction. To be

able to explain the reason for such electrical behavior in Figure 3, we carried out elemental analysis (XRFD) on

precipitates seen at the bottom of brine effluents taken from samples at the end of storage (Figure 4). The pre-

cipitates were identified to be carbonate grains which confirm carbonate grain dissolution (Figure 5). Samples’

permeability also reduced from 423mD to 201mD in IL-206 and from 324mD to 297mD in IL-209 (Figure 6).

However, porosity remains either the same or a bit lower.

4. Conclusions

1) Resistivity logging in sequestration project can give information on fluid rock interaction.

(a) (b )

Figure 3. Resistivity versus time while CO2 reacts with brine saturated carbonate (A) IL-206 (B) IL-209.

Table 3. The effect of Archie’s parameters on saturation estimation (Bennion et al., 96).

Effect on Sx (If Under Estimated) Effect on Sw (If Over Estimated) Effect of Small Error

Satnration Exponent (n) Value too low Value too high Strong

Archie Constant (a) Value too low Value too high Moderate

Water Resistivity (Rw) Value too low Value too high Strong

Cementation Exponent (m) Value too low Value too high Moderate

Total Resistivity (Rr) Value too low Value too high Strong

A. Adebayo, M. Mahmoud

Figure 4. Brine effluent after CO2 storage. Sediments seen at

the bottom.

Figure 5. XRFD analysis on precipitates.

2) Successful interpretation of this electrical signature can be a breakthrough in the understanding of miner-

alization process in CO2 sequestration projects.

3) Results showed that drop in formation resistivity does not necessarily mean migration of CO2 away from

the location but can be due to CO2/brine/rock interaction

4) Collected brine effluents from storage showed carbon dioxide-rock fluid-rock interaction while XRFD

analysis on precipitates showed that carbonate minerals and cementing materials dissolved in brine solution.

5) Rock permeability have also been found to be significantly impaired by formation damage while porosity

seems to be slightly improved or remained unchanged.

A. Adebayo, M. Mahmoud

Figure 6. Porosity and permeability for IL-206 and IL-209.

Acknowledgements

The authors are grateful to the King Fahd University of Petroleum & Minerals and the King Abdul-Aziz Center

for Science and Technology-Technology Innovation Center on Carbon Capture and Sequestration (KAC S T-

TIC-CCS) for their support under project number KACST-TIC-CCS-6.

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