Testing and Monitoring Plan for ADM CCS#2 Page C1 of 23

Permit Number: IL-115-6A-0001 

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 location: 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 CO2 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 testing 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 CO2 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 CO2 stream as described in Section 6A.1 of the permit 

application and presented below. 

Analytical Parameters

ADM will analyze the CO2 for the constituents identified in Table 1 using the methods listed. 

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. 
Testing and Monitoring Plan for ADM CCS#2 Page C2 of 23

Permit Number: IL-115-6A-0001 

Table 1. Summary of analytical parameters for CO2 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)

CO2 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 

CO2 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 markings. 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 

chromatography, 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 C3 of 23

Permit Number: IL-115-6A-0001 

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

ADM will install 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 be 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 over 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 at least once per 5 seconds. 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 C4 of 23

Permit Number: IL-115-6A-0001 

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 master control system. 

ADM 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 obtained 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 = A0 + A1*P + A2*P2 + A3*P3 + A4*P4 

Where ρ is the density, P is the pressure in psi, and A are coefficients determined by the 

equations: 

Ai = bi0 + bi1*T + bi2*T2 + bi3*T3 + bi4*T4 

T is the temperature in degrees Celsius and the b coefficients are presented below: 
Testing and Monitoring Plan for ADM CCS#2 Page C5 of 23

Permit Number: IL-115-6A-0001 

Pressure < 3000 psi 

bi0 bi1 bi2 bi3 bi4

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 

Bi0 Bi1 Bi2 Bi3 Bi4

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 will 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 annulus 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 C6 of 23

Permit Number: IL-115-6A-0001 

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 C7 of 23

Permit Number: IL-115-6A-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 be 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 changes 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 Table 3: 
Testing and Monitoring Plan for ADM CCS#2 Page C8 of 23

Permit Number: IL-115-6A-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 sampled 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 requirements 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 CO2 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 C9 of 23

Permit Number: IL-115-6A-0001 

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

Equipment Coupon Material of Construction 

Pipeline CS A106B

Long String Casing (Surface - 4,800’) Carbon 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 CO2 will be 

routed from the pipeline through the corrosion monitoring system and then back into a lower 

pressure point upstream in the compression system. This loop will operate any time injection is 

occurring. No other equipment will act on the CO2 past this point; therefore this location will 

provide representative exposure of the samples to the CO2 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 0.0001 gm).
Testing and Monitoring Plan for ADM CCS#2 Page C10 of 23

Permit Number: IL-115-6A-0001 

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 project 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 C11 of 23

Permit Number: IL-115-6A-0001 

Figure 3. Location of existing shallow groundwater monitoring wells and planned deep wells.
Testing and Monitoring Plan for ADM CCS#2 Page C12 of 23

Permit Number: IL-115-6A-0001 

Table 5. Direct Monitoring of Ground Water Quality and Geochemical Changes above the Confining Zone

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: SemiAnnual

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

IrontonGalesville

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 the 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 injection.

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 C13 of 23

Permit Number: IL-115-6A-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 

IrontonGalesvillePulse 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 

Notes: 

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 C14 of 23

Permit Number: IL-115-6A-0001 

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

Table 7. Summary of analytical and field parameters for groundwater samples

Parameters Analytical Methods (1)

Quaternary/Pennsylvanian

Cations:

Al, Ba, Mn, As, Cd, Cr, Cu, Pb, Sb Se, and Tl

ICP-MS,

EPA Method 6020

Cations:

Ca, Fe, K, Mg, Na, and Si

ICP-OES,

EPA Method 6010B

Anions: 

Br, Cl, F, NO3, and SO4

Ion Chromatography,

EPA Method 300.0

Dissolved CO2 Coulometric titration, 

ASTM D513-11

Total Dissolved Solids Gravimetry; APHA 2540C

Water Density(field) Oscillating body method

Alkalinity APHA 2320B

pH (field) EPA 150.1

Specific conductance (field) APHA 2510

Temperature (field) Thermocouple

St Peter 

Cations:

Al, Ba, Mn, As, Cd, Cr, Cu, Pb, Sb Se, and Tl

ICP-MS,

EPA Method 6020

Cations:

Ca, Fe, K, Mg, Na, and Si

ICP-OES,

EPA Method 6010B

Anions: 

Br, Cl, F, NO3, and SO4

Ion Chromatography,

EPA Method 300.0

Dissolved CO2

Coulometric titration, 

ASTM D513-11

Isotopes: δ13C of DIC Isotope ratio mass spectrometry

Total Dissolved Solids Gravimetry; APHA 2540C

Water Density(field) Oscillating body method

Alkalinity APHA 2320B

pH (field) EPA 150.1

Specific conductance (field) APHA 2510

Temperature (field) Thermocouple
Testing and Monitoring Plan for ADM CCS#2 Page C15 of 23

Permit Number: IL-115-6A-0001 

Parameters Analytical Methods (1)

Ironton-Galesville

Cations:

Al, Ba, Mn, As, Cd, Cr, Cu, Pb, Sb Se, and Tl

ICP-MS,

EPA Method 6020

Cations:

Ca, Fe, K, Mg, Na, and Si

ICP-OES,

EPA Method 6010B

Anions: 

Br, Cl, F, NO3, and SO4

Ion Chromatography,

EPA Method 300.0

Dissolved CO2 Coulometric titration, 

ASTM D513-11

Isotopes: δ13C of DIC Isotope ratio mass spectrometry

Total Dissolved Solids Gravimetry; APHA 2540C

Water Density(field) Oscillating body method

Alkalinity APHA 2320B

pH (field) EPA 150.1

Specific conductance (field) APHA 2510

Temperature (field) Thermocouple

ICP = inductively coupled plasma; MS = mass spectrometry; OES = optical emission spectrometry; GCP = 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 in 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 approval 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 Log
Testing and Monitoring Plan for ADM CCS#2 Page C16 of 23

Permit Number: IL-115-6A-0001 

Description of MIT(s) that may be employed 

Temperature Logging 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 provided. The following procedures, as described in Appendix G of 

the CCS #2 permit application, will be employed for temperature logging: 

The well 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 CO2

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 same 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 operational 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 C17 of 23

Permit Number: IL-115-6A-0001 

Temperature Logging Using DTS Fiber Optic Line

CCS#2 is equipped with a DTS fiber optic temperature 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 and 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, record 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 Logging

To ensure the mechanical integrity of the casing of the injection well, logging data will be 

recorded across the wellbore from surface down to primary caprock. Bottom hole pressure data 

near the 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 C18 of 23

Permit Number: IL-115-6A-0001 

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 intervals containing high noise 

levels.

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

injection 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 base 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 increase 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; flow 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) Logging

To ensure the mechanical integrity of the casing of the injection well, logging data will be 

recorded across the wellbore from surface down to primary caprock. Bottom hole pressure data 

near the packer 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 Gamma 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 the 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 must 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 C19 of 23

Permit Number: IL-115-6A-0001 

7. Take, at a minimum, a 15 minute stationary reading at a location approximately midway 

between the base of the lowermost USDW and the confining interval located 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 CO2 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 falloff 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 the 
Testing and Monitoring Plan for ADM CCS#2 Page C20 of 23

Permit Number: IL-115-6A-0001 

falloff test; however, several months of injection prior to the falloff will likely be part of the preshut-in injection period and subsequent 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 least 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 and 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 ADM will use to monitor the 

position of the CO2 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 monitor 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 

Table 11. ADM will deploy pressure/temperature monitors and distributed temperature sensing 

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 CO2 saturation. Time-lapse 3D vertical seismic profiles (VSPs) will 

be used to image the developing CO2 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 C21 of 23

Permit Number: IL-115-6A-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 (2018) 

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 4th quarter before or the 1st quarter of the calendar year shown or 

alternatively scheduled with the prior approval of the UIC Program Director.
Testing and Monitoring Plan for ADM CCS#2 Page C22 of 23

Permit Number: IL-115-6A-0001 

Table 10. 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 events over M1.0 within 

the AoR. 

Continuous
Testing and Monitoring Plan for ADM CCS#2 Page C23 of 23

Permit Number: IL-115-6A-0001 

Table 11. Summary of analytical and field parameters for fluid sampling in the Mt. Simon 

Parameters Analytical Methods (1)

Cations:

Al, Ba, Mn, As, Cd, Cr, Cu, Pb, Sb Se, and Tl

ICP-MS,

EPA Method 6020

Cations:

Ca, Fe, K, Mg, Na, and Si

ICP-OES,

EPA Method 6010B

Anions: 

Br, Cl, F, NO3, and SO4

Ion Chromatography,

EPA Method 300.0

Dissolved CO2

Coulometric titration, 

ASTM D513-11

Isotopes: δ13C of DIC Isotope ratio mass spectrometry

Total Dissolved Solids Gravimetry; APHA 2540C

Water Density(field) Oscillating body method

Alkalinity APHA 2320B

pH (field) EPA 150.1

Specific conductance (field) APHA 2510

Temperature (field) Thermocouple

ICP = inductively coupled plasma; MS = mass spectrometry; OES = optical emission spectrometry; GCP = gas chromatography - pyrolysis.

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

Appendix 

Quality Assurance and Surveillance Plan.