Testing and Monitoring Plan for ADM CCS#2 Page C 1 of 23 Permit Number: IL -1 15

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### ATTACHMENT C : TESTING AND MONITORING PLAN

Facility Information

Facility name: Archer Daniels Midland, CCS#2 Well IL -115-6A-0001

Facility contact: Mr. Mark Burau, Plant Manager, 4666 Faries Parkway, Decatur, IL (217 ) 424-5750, mark.burau@adm.com

Well l ocation: Decatur, Macon County, IL; 39o53’08”, -89o53’19”

This Testing and Monitoring Plan describes how ADM will monitor the CCS#2 site pursuant to 40 CFR 146.90. In addition to demonstrating that the well is operating as planned, the carbon dioxide plume and pressure front are moving as predicted, and that there is no endangerment to USDWs, the monitoring data will be used to validate and adjust the geological models used to predict the distribution of the CO 2 

### within the storage zone to support AoR reevaluations and a non-endangerment demonstration.

Quality Assurance Procedures

A quality assurance and surveillance plan (QASP) for all t esting and monitoring activities pursuant to 146.90(k) is provided in Appendix A to this Testing and Monitoring Plan.

Carbon Dioxide Stream Analysis

ADM will analyze the CO 2 

### stream during the operation period to yield data representative of its chemical and physical characteristics and to meet the requirements of 40 CFR 146.90(a). Sampling will take place quarterly, by the following dates each year: 3 months after the date of authorization of injection, 6 months after the date of authorization of injection, 9 months after the date of authorization of injection, and 12 months after the date of authorization of injection

. ADM will sample and analyze the CO 2 

### stream as described i n Section 6A.1 of the permit application and presented below.

Analy tical Parameters

ADM will analyze the CO 2 

### for the constituents identified in Table 1 using the methods listed

. Sampling will take place q uarterly, by the following dates each year: 3 month s after the date of authorization of injection, 6 months after the date of authorization of injection, 9 months after the date of authorization of injection, and 12 months after the date of authorization of injection.Testing and Monitoring Plan for ADM CCS#2 Page C 2 of 23 Permit Number: IL -1 15

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- 0001 Table 1 . Summary of analytical parameters for CO 2 gas stream.

Parameters Analytical Methods (1)

Oxygen ISBT 4.0 (GC/DID)

GC/TCD

Nitrogen ISBT 4.0 GC/DID

GC/TCD

Carbon Monoxide ISBT 5.0 Colorimetric
ISBT 4.0 (GC/DID)

Oxides of Nitrogen ISBT 7.0 Colorimetric

Total Hydrocarbons ISBT 10.0 THA (FID)

Methane ISBT 10.1 GC/FID)

Acetaldehyde ISBT 11.0 (GC/FID)

Sulfur Dioxide ISBT 14.0 (GC/SCD)

Hydrogen Sulfide ISBT 14.0 (GC/SCD)

Ethanol ISBT 11.0 (GC/FID)

CO 2 Purity ISBT 2.0 Caustic absorption Zahm

- Nagel

ALI method SAM 4.1 subtraction method (GC/DID)

GC/TCD

Note 1: An equivalent method may be employed with the prior approval of the UIC Program Director.



### Sampling methods

CO 2 

### stream sampling will occur in the compressor building after the last stage of compression. A sampling station will be installed with the ability to purge and collect samples into a container that will be sealed and sent to the authorized laboratory.

All sample containers will be labeled with durable labels and indelible marking s. A unique sample identification number and sampling date will be recorded on the sample containers.

Laboratory to be used/chain of custody procedures

Samples will be analyzed by a third party laboratory using standardized procedures for gas chromato graphy, mass spectrometry, detector tubes, and photo ionization. The sample chain -ofcustody procedures described in Section B.3 of the QASP will be employed.Testing and Monitoring Plan for ADM CCS#2 Page C 3 of 23 Permit Number: IL -1 15

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### Continuous Recording of Injection Pressure, Rate, and Volume; Annulus Pressure

ADM will i nstall and use continuous recording devices to monitor injection pressure, rate, and volume, the pressure on the annulus between the tubing and the long string casing, and the annulus fluid volume added.

ADM will perform the activities identified in Table 2 to verify internal mechanical integrity of the injection well and monitor injection pressure, rate, volume and annular pressure as required
at 40 CFR 146.88, 146.89, and 146.90 (b) . All monitoring will b e continuous for the duration of the operation period, and at the locations shown in the table.

Table 2. Sampling Locations for Continuous Monitoring

Test Description Location Annular Pressure Monitoring Surface
Injection Pressure Monitoring Surface
Injection Pressure Monitoring Reservoir - Below Packer
Injection Rate Monitoring Surface

Injection Volume Monitoring Surface

Temperature Monitoring Surface

Temperature Monitoring Reservoir - Below Packer

Temperature Monitoring Along wellbore using distributed temperature sensor (DTS)



### The injection well will have pressure/temperature gauges at the surface and in the tubing at the packer. In addition there will be distributed temperature sensing fibers in the injection well.

Pressure and temperature instruments shall be calibrated ove r the full operational range at least annually using ANSI or other recognized standards. Pressure transducers shall have a drift stability of less than 1 psi over the operational period of the instrument and an accuracy of + 5 psi. Sampling rates will be a t least once per 5 second s . Temperature sensors will be accurate to within one degree Celsius.

Flow will be monitored with a coriolis mass flowmeter at the wellhead. The flowmeter will be calibrated using accepted standards and be accurate to within + 0. 1 percent. The flowmeter will be calibrated for the entire expected range of flow rates.

Injection Rate and Pressure Monitoring

ADM will monitor injection operations using the distributive process control system, as described in Section 6A.2.2.3 of the CCS#2 permit application and presented below.Testing and Monitoring Plan for ADM CCS#2 Page C 4 of 23 Permit Number: IL -1 15

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### The Surface Facility Equipment & Control System will limit maximum flow to 3,300 MT/day and/or limit the well head pressure to 2,284 psig, which corresponds to the regulatory requirement to not exceed 90% of the injection zone’s fracture pressure. All injection operations will be continuously monitored and controlled by the ADM operations staff using the distributive process control system. This system will continuously monitor, control, record, and will alarm and shutdown if specified control parameters exceed their normal operating range.

More specifically, all critical system parameters, e.g., pressure, temperature, and flow rate will have continuous electronic monitoring with signals transmitted back to a m aster control system. A DM supervisors and operators will have the capability to monitor the status of the entire system in two locations: the compression control room (near the main compressors), and the main Alcohol Department control room.

Calculation of Injection Volumes

Flow rate is measured on a mass basis (kg/hr). The downhole pressure and temperature data will be used to perform the injectate density calculation.

The volume of carbon dioxide injected will be calculated from the mass flow rate ob tained from the mass flow meter installed on the injection line. The mass flow rate will be divided by density and multiplied by injection time to determine the volume injected.

Density will be calculated using the correlation developed by Ouyang (2011). The correlation uses the temperature and pressure data collected to determine the carbon dioxide density. The density correlation is given by:

ρ = A 0 

### + A 1 

### *P + A 2 

### *P 2 

### + A 3 

### *P 3 

### + A 4 

### *P 4


### Where ρ is the density, P is the pressure in psi, and A are coeff icients determined by the equations: A i 

### = b i0 

### + b i1 

### *T + b i2 

### *T 2 

### + b i3 

### *T 3 

### + b i4 

### *T 4 

### T is the temperature in degrees Celsius and the b coefficients are presented below :Testing and Monitoring Plan for ADM CCS#2 Page C 5 of 23 Permit Number: IL -1 15

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### Pressure < 3000 psi b i0 

### b i1 

### b i2 

### b i3 

### b i4

i=0

- 2.148322085348E+05 1.168116599408E+04

- 2.302236659392E+02 1.967428940167E+00

- 6.184842764145E

- 03
i= 1 4.757146002428E+02

- 2.619250287624E+01 5.215134206837E

- 01

- 4.494511089838E

- 03 1.423058795982E

- 05 i = 2

- 3.713900186613E

- 01 2.072488876536E

- 02

- 4.169082831078E

- 04 3.622975674137E

- 06

- 1.155050860329E

- 08 i = 3 1.228907393482E

- 04

- 6.930063746226E

- 06 1.406317206628E

- 07

- 1.230995287169E

- 09 3.948417428040E

- 12 i = 4

- 1.466408011784E

- 08 8.338008651366E

- 10

- 1.704242447194E

- 11 1.500878861807E

- 13

- 4.838826574173E

- 16



### Pressure > 3000 psi
B i0 

### B i1 

### B i2 

### B i3 

### B i4

i=0 6.897382693936E+02 2.730479206931E+00

- 2.254102364542E

- 02

- 4.651196146917E

- 03 3.439702234956E

- 05

i= 1 2.213692462613E

- 01

- 6.547268255814E

- 03 5.982258882656E

- 05 2.274997412526E

- 06

- 1.888361337660E

- 08 i = 2

- 5.118724890479E

- 05 2.019697017603E

- 06

- 2.311332097185E

- 08

- 4.079557404679E

- 10 3.893599641874E

- 12 i = 3 5.517971126745E

- 09

- 2.415814703211E

- 10 3.121603486524E

- 12 3.171271084870E

- 14

- 3.560785550401E

- 16 i = 4

- 2.184152941323E

- 13 1.010703706059E

- 14

- 1.406620681883E

- 16

- 8.957731136447E

- 19 1.215810469539E

- 20



### (From: Ouyang 2011, “New Correlations for Predicting the Density and Viscosity of Supercritical Carbon Dioxide Under Conditions Expected in Carbon Capture and Sequestration Operations,” The Open Petroleum Engineering Journal, 2011, 4, 13-21. )

The final volume basis wil l be calculated as follows:

Volume basis (m3/hr) = Mass basis (kg/hr) / density (kg/m3).

Continuous Monitoring of Annular Pressure

ADM will use the procedures below to monitor annular pressure, as described in Section 6A.3.1 of the CCS #2 permit application.

The following procedures will be used to limit the potential for any unpermitted fluid movement into or out of the annulus:

1. The annulus between the tubing and the long string of casing will be filled with brine. The brine will have a specific gravity of 1.25 and a density of 10.5 lbs/gal. The hydrostatic gradient is 0.546 psi/ft. The brine will contain a corrosion inhibitor.

2. The surface annulus pressure will be kept at a minimum of 400 pounds per square inch (psi) during injection.

3. During periods of well shut down, the surface annu lus pressure will be kept at a minimum pressure to maintain a pressure differential of at least 100 psi between the annular fluid directly above (higher pressure) and below (lower pressure) the injection tubing packer set at 6,320 ft KB.Testing and Monitoring Plan for ADM CCS#2 Page C 6 of 23 Permit Number: IL -1 15

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### 4. The pressure within the annular space, over the interval above the packer to the confining layer, will be greater than the pressure of the injection zone formation at all times.

5. The pressure in the annular space directly above the packer will be maintained at least 100 psi higher than the adjacent tubing pressure during injection.

Figure 1 shows an example of the injection well annulus protection system. The final design configuration of the annular monitoring system may differ from the example. The final design of the annular pressure system will be submitted to UIC Program Director with the construction completion report.

The annular monitoring system will consist of a continuous annular pressure gauge, a brine water storage reservoir, a low- volume/high -pressure pump, a control box, fluid volume measurement device, fluid, and electrical connections. The control box will receive pressure data from an annular pressure gauge and will be programmed to operate the pump as needed to maintain approximately 400 psi (or greater) on the annulus. A means to monitor the volume of fluid pumped into the annulus will be incorporated into the system by use of a tank fluid level gauge, flow meter, pump stroke counter or other appropriate devices.

Pressure will be monitored by the ADM control system gauges. The pump will be controlled by two pressure switches –one for low pressure to engage the pump and the other for high pressure to shut the pump down. Anticipated range on the switches would be 400 psi or higher for the low pressure set point and 500 psi or higher for the high pressure set point.

Annulus pressure will be monitored at the ADM data control system. A brine storage tank will be connected to the suction inlet of the pump. A hydrostatic tank level gauge will be installed in the brine storage tank with data fed into the ADM monitoring system. The brine in the storage tank will be similar to the brine in the annulus. Any changes to the composition of annular fluid will be reported in the next report submitted to the permitting agency.Testing and Monitoring Plan for ADM CCS#2 Page C 7 of 23 Permit Number: IL -1 15

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- 0001 Figure 1 : The annular monitoring system general layout.



### If system communication is lost for greater than 30 minutes, project personnel will perform field monitoring of manual gauges every four hours or twice per shift for both wellhead surface pressure and annulus pressure, and record hard copies of the data until communication is restored. Average annular pressure and fluid volume changes will be recorded daily.

Casing-Tubing Pressure Monitoring

ADM will monitor the casing -tubing pressure as described in Appendix G of the CCS#2 permit application and presented below. During the injection timeframe of the project, the casing

- tubing pressure will b e monitored and recorded in real time. Surface pressure of the casing -tubing annulus is anticipated to be from 400 to 700 psi. As detailed in the Emergency and Remedial Response Plan (Attachment F to this permit)

, significant change s in the casing -tubing annular pressure attributed to well mechanical integrity will be investigated

. Collection and recording of monitoring data will occur at the frequencies described in T able 3:Testing and Monitoring Plan for ADM CCS#2 Page C 8 of 23 Permit Number: IL -1 15

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- 0001 Table 3. Sampling and Recording Frequencies for Continuous Monitoring

Well Condition Minimum sampling frequency: once every Minimum recording frequency: once every

For continuous monitoring of the injection well when operating : 5 seconds 5 minutes 1

For the injection well when shut

- in: 4 hours 4 hours

1 This can be an average of the sampled readings over the previous 5

- minute recording interval, or the maximum (or minimum, as appropriate) value identified over that recording interval

Notes: Sampling frequency refers to how often the monitoring device obtains data from the well for a particular parameter. For example, a recording device might sample a pressure transducer monitoring injection pressure once every two seconds and save this value in memory.

Recording frequency refers to how often the samp led information gets recorded to digital format (such as a computer hard drive). Following the same example above, the data from the injection pressure transducer might be recorded to a hard drive once every minute.



### Corrosion Monitoring

To meet the req uirements of 40 CFR 146.90(c), ADM will monitor well materials during the operation period for loss of mass, thickness, cracking, pitting, and other signs of corrosion to ensure that the well components meet the minimum standards for material strength and performance. This monitoring will occur quarterly, by the following dates each year: 3 months after the date of authorization of injection, 6 months after the date of authorization of injection, 9 months after the date of authorization of injection, and 12 months after the date of authorization of injection

. ADM will monitor corrosion using the corrosion coupon method and collect samples according to the description below and in Section 6A.3.5 of the CCS#2 permit application.

Sample Description

Samples of material used in the construction of the compression equipment, pipeline and injection well which come into contact with the CO 2 

### stream will be included in the corrosion monitoring program either by using actual material and/or conventional corrosion coupons. The samples consist of those items listed in Table 4 below. Each coupon will be weighed, measured, and photographed prior to initial exposure (see Sample Monitoring section for measurement data).Testing and Monitoring Plan for ADM CCS#2 Page C 9 of 23 Permit Number: IL -1 15

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- 0001 Table 4. List of Equipment Coupon with Material of Construction.

Equipment Coupon Material of Construction
Pipeline CS A1 06B
Long String Casing (Surface

- 4

, 8 00’ ) C arbon Steel
Long String Casing (4,800’

– TD) Chrome Alloy
Injection Tubing Chrome alloy

Wellhead Chrome alloy

Packers 1 Chrome alloy



### Sample Exposure

Each sample will be attached to an individual holder (Figure 2a) and then inserted in a flowthrough pipe arrangement (Figure 2b). The corrosion monitoring system will be located downstream of all process compression/dehydration/pumping equipment (i.e., at the beginning of the pipeline to the wellhead). To accomplish this, a parallel stream of high pressure CO 2 

### will be routed from the pipeline through the corrosion monitoring system and then back into a lower
pressu re point upstream in the compression system. This loop will operate any time injection is occurring. No other equipment will act on the CO 2 

### past this point; therefore this location will provide representative exposure of the samples to the CO 2 

### composition, temperature, and pressures that will be seen at the wellhead and injection tubing. The holders and location of the system will be included in the pipeline design and will allow for continuation of injection during sample removal.

Figure 2a . Coupon holder. Figure 2b . Flow

- through Pipe arrangement.



### Sample Handling and Monitoring

The coupons will be handled and assessed for corrosion using the American Society for Testing and Materials (ASTM) G1 -03, Standard Practice for Preparing, Cleaning, and Evaluating Corrosion Test Specimens (ASTM 2011). The coupons will photographed, visually inspected with a minimum of 10x power, dimensionally measured (to within 0.0001 inch), and weighed (to within 0.000 1 gm).Testing and Monitoring Plan for ADM CCS#2 Page C 10 of 23 Permit Number: IL -1 15

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### Ground Water Quality Monitoring

ADM will monitor ground water quality and geochemical changes above the confining zone during the operation period to meet the requirements of 40 CFR 146.90(d).

The groundwater monitoring plan focuses on the following zones:

• Quaternary and/or Pennsylvanian strata – the source of local drinking water.

• The St. Peter Formation – the lowermost USDW

.

• The Ironton -Galesville Sandstone– the zone above the confining Eau Claire cap rock.

Table 5 and Table 6 show the planned monitoring methods, locations, and frequencies for ground water quality monitoring above the confining zone. All of the monitoring locations are located on ADM property. Figure 3 shows the p roject area and the location of existing shallow groundwater monitoring wells and planned deep monitoring wells.

ADM will also monitor in the Mt. Simon Sandstone (the injection zone). Monitoring in this layer will be to track the carbon dioxide plume and is described under “Carbon Dioxide Plume and Pressure Front Tracking” below.Testing and Monitoring Plan for ADM CCS#2 Page C 11 of 23 Permit Number: IL -1 15

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- 0001 Figure 3. L ocation of exi sting shallow groundwater monitoring wells and planned deep wells.Testing and Monitoring Plan for ADM CCS#2 Page C 12 of 23 Permit Number: IL -1 15

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- 0001 Table 5 . Direct Moni toring of Ground Water Quality a nd Geochemical Changes a bove t he Confining Zo ne

Target Formation Monitoring Activity Monitoring Location(s) Spatial Coverage Frequency (1-5)

Quaternary

and/or Pennsylvanian
strata Fluid sampling Shallow monitoring wells: MVA10LG, MVA11LG, MVA12LG, MVA13LG 4 point locations, 1 sampling interval each. Approx

. depths:

MVA10LG - 101 ft MVA11LG - 135 ft MVA12LG

- 95 ft MVA13LG - 140 ft Baseline; Year 1

- 2: Quarterly;

Year 3

- 5: Semi

Annual

Distributed Temperature Sensing ( DTS ) CCS#1 1 point location, distributed measurement to 6325 KB/5631 MSL Continuous

CCS#2 1 point location, distributed measurement to 6325 KB/5631 MSL Continuous

St. Peter Fluid sampling GM#2 1 point location, 1 interval: 3300 KB/2606 MSL Baseline; Year 1

- 5: Annual
Pressure/ temperature monitoring GM#2 1 point location, 1 interval: 3300 KB/2606 MSL Continuous

DTS CCS#1 1 point location, distributed measurement to 6325 KB/5631 MSL Continuous

CCS#2 1 point location, distributed measurement to 6325 KB/5631 MSL Continuous

Ironton

Galesville Fluid sampling VW#1 1 point location, 1 interval: 4918 - 5000 KB, 4224 - 4306 MSL Baseline; Year 1

- 3: Annual Year 4

- 5: None

VW#2 1 point location, 1 interval: 5000 KB/4918 MSL Baseline; Year 1

- 5: Annual

Pressure/ temperature monitoring VW#1 1 point location, 1 interval: 4918 - 5000 KB, 4224 - 4306 MSL Year 1

- 3: Continuous Year 4

- 5: None

VW#2 1 point location, 1 interval: 5000 KB/4918 MSL Continuous

DTS CCS#1 1 point location, distributed measurement to 6325 KB/5631 MSL Continuous

CCS#2 1 point location, distributed measurement to 6325 KB/5631 MSL Continuous

Notes: 1. Baseline sampling and analysis will be completed before injection is authorized. 2. Quarterly sampling will take place by the following dates each year: 3 months after the date of authorization of injection, 6 months after the date of authorization of injection, 9 months after th e date of authorization of injection, and 12 months after the date of authorization of injection. 3. Semi

- annual sampling will be performed each year by : 6 months after the date of authorization of injection and 12 months after the date of authorization of in jection. 4. Annual sampling will occur up to 45 days before the anniversary date of authorization of injection each year. 5. Continuous monitoring is described in Table 3 of this plan.Testing and Monitoring Plan for ADM CCS#2 Page C 13 of 23 Permit Number: IL -1 15

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- 0001 Table 6 . Indirect Monitoring of Ground Water Quality and Geochemical Changes above the Confining Zone

Target Formation Monitoring Activity Monitoring Location(s) Spatial Coverage Frequency (1 ,2 )

Quaternary

and/or Pennsylvanian
strata Pulse Neutron Logging/RST VW#1 1 point location (12 inches outside well bore) & continuous to full well depth Baseline, Year 2, Year 4

VW#2 1 point location (6

- 12 inches outside well bore) & continuous to full well depth Baseline, Year 2, Year 4

CCS#1 1 point location (6

- 12 inches outside well bore) & continuous to full well depth Baseline, Year 2, Year 4

CCS#2 1 point location (6

- 12 inches outside well bore) & continuous to full well depth Baseline, Year 2, Year 4

St. Peter Pulse Neutron Logging/RST VW#1 1 point location (12 inches outside well bore) & continuous to full well depth Baseline, Year 2, Year 4

VW#2 1 point location (6

- 12 inches outside well bore) & continuous to full well depth Baseline, Year 2, Year 4

CCS#1 1 point location (6

- 12 inches outside well bore) & continuous to full well depth Baseline, Year 2, Year 4

CCS#2 1 point location (6

- 12 inches outside well bore) & continuous to full well depth Baseline, Year 2, Year 4

Ironton

Galesville Pulse Neutron Logging/RST VW#1 1 point location (12 inches outside well bore) & continuous to full well depth Baseline, Year 2, Year 4

VW#2 1 point location (6

- 12 inches outside well bore) & continuous to full well depth Baseline, Year 2, Year 4

CCS#1 1 point location (6

- 12 inches outside well bore) & continuous to full well depth Baseline, Year 2, Year 4

CCS#2 1 point location (6

- 12 inches outside well bore) & continuous to full well depth Baseline, Year 2, Year 4

Note s : 1. Baseline sampling and analysis will be completed before injection is authorized. 2. Logging will take place up to 45 days before the anniversary date of authorization of injection each year or will be alternatively scheduled with the prior approval of the UIC Program Director.Testing and Monitoring Plan for ADM CCS#2 Page C 14 of 23 Permit Number: IL -1 15

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### Table 7 identifies the parameters to be monitored and the analytical methods ADM will employ.

Tab le 7 . Summary of analytical and field parameters for groundwater samples P ara m eters A na l y tical M eth o ds (1)

Quaternary/Pennsylvanian

Cations: Al, Ba, Mn, As, Cd, Cr, Cu, Pb, Sb Se, and Tl IC P

- MS

, EP A M ethod 6 0 20 Cations: Ca, Fe, K, Mg, Na, and Si ICP

- OES, EPA Method 6010B Anions: Br, Cl, F, NO 3 , and SO 4 Ion Chromatography, EPA Method 300.0 Dissolved CO 2 Coulometric titration, ASTM D513

- 11 Total Dissolved Solids Gravimetry; APHA 2540C

W ater D en sit y(field) Oscillating body method

A lkalin it y APHA 2320B
pH (field) EPA 150.1

S pecif i c con d uc t ance (field) APHA 2510

Te m peratu r e (field) Ther m ocouple

St Peter

Cations: Al, Ba, Mn, As, Cd, Cr, Cu, Pb, Sb Se, and Tl IC P

- MS

, EP A M ethod 6 0 20 Cations: Ca, Fe, K, Mg, Na, and Si ICP

- OES, EPA Method 6010B Anions: Br, Cl, F, NO 3 , and SO 4 Ion Chromatography, EPA Method 300.0

Dissolved CO 2 Coulometric titration, ASTM D513

- 11 Isotopes: δ 13 C of DIC Isotope ratio mass spectrometry

Total Dissolved Solids Gravimetry; APHA 2540C

W ater D en sit y(field) Oscillating body method

A lkalinit y APHA 2320B
pH (field) EPA 150.1

S pecif ic con d uc t ance (field) APHA 2510

Te m peratu r e (field) Ther m ocoupleTesting and Monitoring Plan for ADM CCS#2 Page C 15 of 23 Permit Number: IL -1 15

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- 0001 P ara m eters A na l y tical M eth o ds (1)

Ironton

- Galesville

Cations: Al, Ba, Mn, As, Cd, Cr, Cu, Pb, Sb Se, and Tl IC P

- MS

, EP A M ethod 6 0 20 Cations: Ca, Fe, K, Mg, Na, and Si ICP

- OES, EPA Method 6010B Anions: Br, Cl, F, NO 3 , and SO 4 Ion Chromatography, EPA Method 300.0 Dissolved CO 2 Coulometric titration, ASTM D513

- 11 Isotopes: δ 13 C of DIC Isotope ratio mass spectrometry

Total Dissolved Solids Gravimetry; APHA 2540C

W ater D en sit y(field) Oscillating body method

A lkalinit y APHA 2320B
pH (field) EPA 150.1

S pecif i c con d uc t ance (field) APHA 2510

Te m peratu r e (field) Ther m ocouple
ICP = inductively coupled plasma; MS = mass spectrometry; OES = optical emission spectrometry; GC

P = gas chromatography - pyrolysis. Note 1: An equivalent method may be employed with the prior approval of the UIC Program Director

.



### • Sampling will be performed as described in Section B.2 of the QASP; this section of the QASP describes the ground water sampling methods to be employed, including sampling SOPs ( Section B.2.a/b), and sample preservation ( Section B.2.g).

• Sample handling and custody will be performed as described in Section B.3 of the QASP.

• Quality control will be ensured using the methods described in Section B.5 of the QASP.

External Mechanical Integrity Testing (MIT)

ADM will conduct at least one of the tests presented i n Table 8 during the injection phase to verify external MI as required at 146.89(c) and 146.90. MITs will be performed annually, up to 45 days before the anniversary date of authorization of injection each year or alternatively scheduled with the prior app roval of the UIC Program Director

.
Table 8. MITs Test Description Location

Temperature Log Along wellbore using DTS or wireline well log Noise Log Wireline Well Log Oxygen Activation Log Wireline Well LogTesting and Monitoring Plan for ADM CCS#2 Page C 16 of 23 Permit Number: IL -1 15

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### Description of MIT(s) that may be employed

Temperature Log ging using Wireline To ensure the mechanical integrity of the casing of the injection well, temperature data will be recorded across the wellbore from surface down to primary caprock. Bottom hole pressure data near the packer will also be pr ovided. The following procedures, as described in Appendix G of the CCS #2 permit application, will be employed for temperature logging:

The w ell should be in a state of injection for at least 6 hours prior to commencing operations in order to cool injection zones.

1. Move in and rig up an electrical logging unit with lubricator.

2. Run a temperature survey from the Base of the Maquoketa Formation (or higher) to the deepest point reachable in the Mt. Simon while injecting at a rate that allows for safe operations.*

3. Stop injection, pull tool back to shallow depth, wait 1 hour.

4. Run a temperature survey over the same interval as step 2.

5. Pull tool back to shallow depth, wait 2 hours.

6. Run a temperature survey over the same interval as step 2.

7. Pull tool back to shallow depth, wait 2 hours.

8. Run a temperature survey over the same interval as step 2.

9. Evaluate data to determine if additional passes are needed for interpretation. Should CO 2 

### migration be interpreted in the top most section of the log, additional logging runs over a higher interval will be required to find the top of migration.

10. If additional passes are needed, repeat temperature surveys every 2 hours until 12 hours, over the s ame interval as step 2.

11. Rig down the logging equipment.

12. Data interpretation involves comparing the time lapse well temperature profiles and looking for temperature anomalies that may indicate a failure of well integrity; i.e. tubing leak or movement of fluid behind the casing. As the well cools down the temperature profile along the length of the tubing string is compared to the baseline. Any unplanned fluid movement into the annulus or outside the casing creates a temperature anomaly when compared to the baseline cooling profile.

*Should operation al constraints or safety concerns not allow for a logging pass while injecting, an acceptable, alternate plan is to stop injecting immediately prior to the first logging pass.Testing and Monitoring Plan for ADM CCS#2 Page C 17 of 23 Permit Number: IL -1 15

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### Temperature Logging Using DTS Fiber Optic Line

CCS#2 is equipped with a DTS fiber optic temp erature monitoring system that is capable of monitoring the injection well’s annular temperature along the length of the tubing string. The DTS line is used for real time temperature monitoring and

, like a conventional temperature log, can be used for early detection of temperature changes that may indicate a loss of well mechanical integrity. The procedure for using the DTS for well mechanical integrity is as follows:

1. After the well is completed a nd prior to injection, a baseline temperature profile will be established. This profile represents the natural temperature gradient for each stratigraphic

zone.
2. During injection operation, r ecord the temperature profile for 6 hours prior to shutting in well.

3. Stop injection and record temperature profile for 6 hours.

4. Evaluate data to determine if additional cooling time is needed for interpretation.

5. Start injection and record temperature profile for 6 hours.

6. Data interpretation involves comparing the time lapse well temperature profiles and looking for temperature anomalies that may indicate a failure of well integrity; i.e. tubing leak or movement of fluid behind the casing. The DTS system monitors and records the well’s temperature profiles at a pre -set frequency in real time. As the well cools down the temperature profile along the length of the tubing string is compared to the baseline. Any unplanned fluid movement into the annulus or outside the casing creates a temperature anomaly when compared to the baseline cooling profile. This data can be continuously monitored to provide real time MIT surveillance making this technology superior to wireline temperature logging.

Noise Log ging To ensure the mechanical integrity of the casing of the inj ection well, logging data will be recorded across the wellbore from surface down to primary caprock. Bottom hole pressure data
near t he packer will also be provided. Noise logging will be carried out while injection is occurring. If ambient noise is greater than 10 mv, injection will be halted. The following procedures will be employed:

1. Move in and rig up an electrical logging unit with lubricator.

2. Run a noise survey from the Base of the Maquoketa Formation (or higher) to the deepest point reachable in the Mt. Simon while injecting at a rate that allows for safe operations.Testing and Monitoring Plan for ADM CCS#2 Page C 18 of 23 Permit Number: IL -1 15

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### 3. Make noise measurements at intervals of 100 feet to create a log on a coarse grid.

4. If any anomalies are evident on the coarse log, construct a finer grid by making noise measurements at intervals of 20 feet within the coarse interva ls containing high noise levels.

5. Make noise measurements at intervals of 10 feet through the first 50 feet above the in

jection interval and at intervals of 20 feet within the 100-foot intervals containing:

a. The base of the lowermost bleed -off zone above the injection interval and

b. The bas e of the lowermost USDW (St. Peter).

6. Additional measurements may be made to pinpoint depths at which noise is produced.

7. Use a vertical scale of 1 or 2 inches per 100 feet.

8. Rig down the logging equipment.

9. Interpret the data as follows: Determine the base noise level in the well (dead well level)

. Identify departures from this level. An incre ase in noise near the surface due to equipment operating at the surface is to be expected in many situations. Determine the extent of any movement; f low into or between USDWs indicates a lack of mechanical integrity; flow from the injection zone into or above the confining zone indicates a failure of containment.

Oxygen Activation (OA) Log ging To ensure the mechanical integrity of the cas ing of the injection well, logging data will be recorded across the wellbore from surface down to primary caprock. Bottom hole pressure data near the pack er will also be provided. OA logging will be carried out while injection is occurring. The following procedures will be employed:

1. Move in and rig up an electrical logging unit with lubricator.

2. Conduct a baseline Gamm a Ray Log and casing collar locator log from the top of the injection zone to the surface prior to taking the stationary readings with the OA tool. (1)



### 3. The OA log shall be used only for casing diameters of greater than 1-11/16 inches and less than 13- 3/8 inches.

4. All stationary readings should be taken with the well injecting fluid at the normal rate with minimal rate and pressure fluctuations.

5. Prior to taking the stationary readings, the OA tool must be properly calibrated in a "no vertical flow behind th e casing" section of the well to ensure accurate, repeatable tool response and for measuring background counts.

6. Take, at a minimum, a 15 minute stationary reading adjacent to the confining interval located immediately above the injection interval. This mus t be at least 10 feet above the injection interval so that turbulence does not affect the readings.Testing and Monitoring Plan for ADM CCS#2 Page C 19 of 23 Permit Number: IL -1 15

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### 7. Take, at a minimum, a 15 minute stationary reading at a location approximately midway between the base of the lowe rmo st USDW and the confining interval loca ted immediately above the injection interval.

8. Take, at a minimum, a 15 minute stationary reading adjacent to the top of the confining

zone.

9. Take, at a minimum, a 15 minute stationary reading at the base of the lowermost USDW

.

10. If flow is indicated by the OA log at a location, move uphole or downhole as necessary at no more than 50 foot intervals and take stationary readings to determine the area of fluid migration.

11. Interpret the data: Identification of differences in the activated water’s measured gamma
ray count- rate profile versus the expected count -rate profile for a static environment. Differences between the measured and expected may indicate flow in the annulus or behind the casing. The flow velocity is determined by measuring the time that the activated water passes a detector

. Note 1: Gamma Ray Log is necessary to evaluate the contribution of naturally occurring background radiation to the total gamma radiation count detected by the OA tool. There are different types of natural radiation emitted from various geologic formations or zones and the natural radiation may change over time.

Pressure Fall

- Off Testing

ADM will perform pressure fall -off tests during the injection phase as described below to meet the requirements of 40 CFR 146.90(f).

Pressure fall

- off testing will be performed:

• During injection, approximately half way through the injection phase (i.e., year 2.5) ; and

• At the end of the injection period

ADM will conduct pressure fall-off testing according to the procedures below, as described in Section 6A.3.4 of the CCS #2 permit application.

Pressure Fall -off Test Procedure

A pressure falloff test has a period of injection followed by a period of no-injection or shut-in. Normal injection using the stream of CO 2 

### captured from the ADM facility will be used during the injection period preceding the shut- in portion of the falloff tests. The normal injection rate is estimated to be 3,000 MT/day (the last 3 years of the planned 5-year injection period). Prior to the f alloff test this rate will be maintained. If this rate causes relatively large changes in bottomhole pressure, the rate may be decreased. Injection will have occurred for 2.5 years prior to this test, but there may have been injection interruptions due to operations or testing. At a minimum, one week of relatively continuous injection will precede the shut-in portion of theTesting and Monitoring Plan for ADM CCS#2 Page C 20 of 23 Permit Number: IL -1 15

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### falloff test; however, several months of injection prior to the falloff will likely be part of the pre

shut-in injection period and sub sequent analysis. This data will be measured using a surface readout downhole gauge so a final decision on test duration can be made after the data is analyzed for average pressure. The gauges may be those used for day- to -day data acquisition or a
pressure gauge will be conveyed via electric line (e

- line).

To reduce the wellbore storage effects attributable to the pipeline and surface equipment, the well will be shut -in at the wellhead nearly instantaneously with direct coordination with the injection compression facility operator. Because surface readout will be used and downhole recording memory restrictions will be eliminated, data will be collected at five second intervals or less for the entire test. The shut- in period of the falloff test will be at lea st four days or longer until adequate pressure transient data are collected to calculate the average pressure. Because surface readout gauges will be used, the shut-in duration can be determined in real- time. A report containing the pressure falloff data a nd interpretation of the reservoir ambient pressure will be submitted to the permitting agency within 90 days of the test. Pressure sensors used for this test will be the wellhead sensors and a downhole gauge for the pressure falloff test. Each gauge will be of a type that meets or exceeds ASME B 40.1 Class 2A (0 .5% accuracy across full range). Wellhead pressure gauge range will be 0 -4,000 psi. Downhole gauge range will be 0-10,000 psi.

Carbon Dioxide Plume and Pressure Front Tracking

ADM will employ direct and indirect methods to track the extent of the carbon dioxide plume and the presence or absence of elevated pressure during the operation period to meet the requirements of 40 CFR 146.90(g).

Tables 9 and 10 present the direct and indirect methods that A DM will use to monitor the position of the CO 2 

### plume and pressure front, including the activities, locations, and frequencies ADM will employ.

ADM will conduct fluid sampling and analysis to detect changes in ground water in order to directly m onitor the carbon dioxide plume. The parameters to be analyzed as part of fluid sampling in the Mt. Simon (i.e., the injection zone) and analytical methods are presented in T able 11. ADM will deploy p ressure/temperature monitor s and distributed temperature sens ing to directly monitor the position of the pressure front.

Indirect plume monitoring will be employed using pulsed neutron capture/reservoir saturation tool (RST) logs to monitor CO 2 

### saturation. T ime

- lapse 3D vertical seismic profiles (VSPs) will be used to image the developing CO 2 

### plume for indirect plume monitoring. Passive seismic monitoring combination of borehole and surface seismic stations to detect local events over M 1.0 within the AoR will also be performed. Quality assurance procedures for seismic monitoring methods are presented in Section B.9 of the QASP.Testing and Monitoring Plan for ADM CCS#2 Page C 21 of 23 Permit Number: IL -1 15

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- 0001 Table 9. Plume Monitoring Activities

Target Formation Monitoring Activity Monitoring Location(s) Spatial Coverage Frequency (1-4)

Direct Plume Monitoring

Mt. Simon Fluid sampling VW#1 1 point location, 1 interval: 6837 - 6632 KB, 6148 - 5938 MSL Baseline; Year 1

- 3: Annual

VW#2 1 point location, 3 intervals: 6800, 6300, 5800 KB; 6106, 5606, 5106 MSL Annual

Indirect Plume Monitoring

Mt. Simon Pulse Neutron Logging/RST VW#1 1 point location (12" outside wellbore) & continuous to full well depth Baseline, Year 2, Year 4

VW#2 1 point location (12" outside wellbore) & continuous to full well depth Baseline, Year 2, Year 4

CCS#1 1 point location (12" outside wellbore) & continuous to full well depth Baseline, Year 2, Year 4

CCS#2 1 point location (12" outside wellbore) & continuous to full well depth Baseline, Year 2, Year 4

Time

- lapse VSP survey GM#1 Fold Image Coverage ~ 30 acres In 2013, 2014, 2015

3D Surface

seismic
survey Full coverage focusing on the northern

extent of plume area Fold Image Coverage ~ 2,000 acres Baseline, Year 2 (201 8)

Notes: 1. Baseline monitoring will be completed before injection is authorized. 2. Annual monitoring will be performed up to 45 days before the anniversary date of authorization of injection each year or alternatively scheduled with the prior approval of the UIC Program Director

. 3. Logging surveys will take place up to 45 days before the anniversary date of authorization of injection each
year or alternatively scheduled with the prior approval of the UIC Program Director. 4. Seismic surveys will be performed in the 4 th quarter before or the 1 st quarter of the calendar year shown or alternativ el y scheduled with the prior approval of the UIC Program Director



### .Testing and Monitoring Plan for ADM CCS#2 Page C 22 of 23 Permit Number: IL -1 15

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. Pressure

- Front Monitoring Activities

Target Formation Monitoring Activity Monitoring Location(s) Spatial Coverage Frequency

Direct Pressure

- Front Monitoring

Mt. Simon Pressure/ temperature monitoring VW#1 1 point location, 1 interval: 6945 - 5654 KB, 6251 - 4960 MSL Year 1

- 3: Continuous ; Year 4

- 5: None

VW#2 1 point location, 4 intervals: 7000, 6800, 6300, 5800 KB; 6306, 6106, 5606, 5106 MSL Continuous

CCS#1 1 point location, 1 interval: PT @ 6325 KB/5631 MSL; Perfs @

6982 - 7050 KB, 6288 - 6356 MSL Continuous

CCS#2 1 point location, 1 interval: PT @ 6325 KB/5631 MSL; Perfs @

6718 - 6881 KB, 6024 - 6187 MSL Continuous

DTS CCS#1 1 point location, distributed measurement to 6325 KB/5631 MSL. Continuous

CCS#2 1 point location, distributed measurement to 6325 KB/5631 MSL. Continuous

Other Plume/Pressure

- Front Monitoring

Multiple Passive seismic A combination of borehole and surface seismic stations located within the AoR. The passive seismic monitoring system has the ability to detect seismic eve nts over M1.0 within the AoR. ContinuousTesting and Monitoring Plan for ADM CCS#2 Page C 23 of 23 Permit Number: IL -1 15

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. Summary of analytical and field parameters for fluid sampling in the Mt. Simon

P ara m eters A na ly tical M eth o ds (1)

Cations: Al, Ba, Mn, As, Cd, Cr, Cu, Pb, Sb Se, and Tl IC P

- MS

, EP A M ethod 6 0 20
Cations: Ca, Fe, K, Mg, Na, and Si ICP

- OES, EPA Method 6010B
Anions: Br, Cl, F, NO 3 , and SO 4 Ion Chromatography, EPA Method 300.0

Dissolved CO 2 Coulometric titration, ASTM D513

- 11
Isotopes: δ 13 C of DIC Isotope ratio mass spectrometry

Total Dissolved Solids Gravimetry; APHA 2540C

W ater D en sit y(field) Oscillating body method

A lkalinit y APHA 2320B

pH (field) EPA 150.1

S pecif ic con d uc t ance (field) APHA 2510

Te m peratu r e (field) Ther m ocouple ICP = inductively coupled plasma; MS = mass spectrometry; OES = optical emission spectrometry; GC

P = gas chromatography - pyrolysis. Note 1: A n equivalent method may be employed with the prior approval of the UIC Program Director.



### A ppendix

Q uality Assurance and Surveillance Plan

.