Injection Well Plugging Plan for ADM CCS#2 

Permit Number: IL-115-6A-0001 Page D1 of 5 

ATTACHMENT D: INJECTION WELL PLUGGING PLAN

The Permittee will submit a final injection well plugging plan using the as-built well construction 

schematics. This will be submitted with the injection well completion report.

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” 

Injection well plugging and abandonment will be conducted according to the procedures below, 

which are based on information submitted by ADM in November 2013. 

Upon completion of the project, or at the end of the life of the CCS #2 injection well, the well 

will be plugged and abandoned to meet the requirements at 40 CFR 146.92. The plugging

procedure and materials will be designed to prevent any unwanted fluid movement, to resist the 

corrosive aspects of carbon dioxide/water mixtures, and to protect any USDWs. Any necessary 

revisions to the well plugging plan to address new information collected during logging and 

testing of the well will be made after construction, logging and testing of the well have been 

completed. The final plugging plan will be submitted to the UIC Program Director.

After injection has ceased, the well will be flushed with a kill weight brine fluid. A minimum of 

three tubing volumes will be injected without exceeding fracture pressure. Bottom hole pressure 

measurements will be made and the well will be logged and pressure tested to ensure mechanical 

integrity inside and outside the casing prior to plugging. If a loss of mechanical integrity is 

discovered, it will be repaired prior to proceeding with the plugging operations. Detailed 

plugging procedure is provided below. All casing in this well will be cemented to surface at the 

time of construction and will not be retrievable at abandonment. After injection is terminated 

permanently, the injection tubing and packer will be removed. After the tubing and packer are 

removed, the balanced-plug placement method will be used to plug the well. If, after flushing,

the tubing and packer cannot be released, an electric line with tubing cutter will be used to cut off 

the tubing above the packer and the packer will be left in the well, and the cement retainer 

method will be used for plugging the injection formation below the abandoned packer.

All of the casing strings will be cut off at least 3 feet below the surface, below the plow line. A 

blanking plate with the required permit information will be welded to the top of the cutoff 

casing.
Injection Well Plugging Plan for ADM CCS#2 

Permit Number: IL-115-6A-0001 Page D2 of 5 

Planned Tests or Measures to Determine Bottom-hole Reservoir Pressure

ADM will record bottom hole pressure from a down hole pressure gauge and calculate kill fluid 

density. 

Planned External Mechanical Integrity Test(s)

ADM will conduct at least one of the following tests to verify external MI prior to plugging the 

injection well as required in 40 CFR 146.92(a). 

Test Description Location

Temperature Log Along wellbore using DTS or wireline 

well log

Noise Log Wireline Well Log

Oxygen Activation Log Wireline Well Log

Information on Plugs

The volume and depth of the plug or plugs will depend on the final geology and downhole 

conditions of the well as assessed during construction. The cement(s) formulated for plugging 

will be compatible with the carbon dioxide stream. The cement formulation and required 

certification documents will be submitted to the agency with the well plugging plan. The 

operator will report the wet density and will retain duplicate samples of the cement used for each 

plug. Figure 1 presents a plugging schematic.

Plug #1 Plug #2 Plug #3 Plug #4 Plug #5 Plug #6 Plug #7

Diameter of Boring in Which 

Plug Will be Placed (inches)

8.681 8.835

Depth to Bottom of Tubing or 

Drill Pipe (ft)

7000 4000

Sacks of Cement to be Used 

(each plug)

1333 1443

Slurry Volume to be Pumped 

(cu. ft)

1480 1703

Slurry Weight (lb/gal) 15.9 15.9

Calculated Top of Plug (ft) 4000 Surf

Bottom of Plug (ft) 7000 4000

Type of Cement or Other 

Material 

CO2

resistant

Class A

Method of Emplacement (e.g., balance method, retainer method, or two-plug method) Balance Method 
Injection Well Plugging Plan for ADM CCS#2 

Permit Number: IL-115-6A-0001 Page D3 of 5 

Narrative Description of Plugging Procedures

Notifications, Permits, and Inspections 

Notifications, permits, and inspections procedures are planned to include: 

1. In compliance with 40 CFR 146.92(c), notify the regulatory agency at least 60 days 

before plugging the well and provide updated plugging plan, if applicable. 

2. Move-in (MI) Rig onto CCS #2 and rig up (RU). All CO2 pipelines will be marked and 

noted with rig supervisor prior to MI. 

3. Conduct and document a safety meeting. 

4. Record bottom hole pressure from down hole gauge and calculate kill fluid density 

5. Open up all valves on the vertical run of the tree and check pressures. 

6. Test the pump and line to 2,500 psi. Fill tubing with kill weight brine (9.5 ppg or 

determined by bottom hole pressure measurement). Bleeding off occasionally may be 

necessary to remove all air from the system. Test casing annulus to 1000 psi and monitor 

as in annual MIT. If there is pressure remaining on tubing rig to pump down tubing and 

inject two tubing volumes of kill weight brine. Monitor tubing and casing pressure for 1 

hour. If both casing and tubing are dead then nipple up blowout preventers (NU BOP’s). 

Monitor casing and tubing pressures. 

7. If the well is not dead or the pressure cannot be bled off of tubing, rig up (RU) slickline 

and set plug in lower profile nipple below packer. Circulate tubing and annulus with kill 

weight fluid until well is dead. After well is dead, nipple down tree, nipple up blow-out 

preventers (BOPs), and perform a function test. BOP’s should have appropriate sized 

single pipe rams on top and blind rams in the bottom ram for tubing. Test pipe rams and 

blind rams to 250 psi low, 3,000 psi high. Test annular preventer to 250 psi low and 

3,000 psi high. Test all Texas Iron Works (pressure valve), BOP’s choke and kill lines, 

and choke manifold to 250 psi low and 3,000 psi high. NOTE: Make sure casing valve is 

open during all BOP tests. After testing BOPs pick up tubing string and unlatch seal 

assembly from seal bore. Rig slick line and lubricator back to well and remove X- plug 

from well. Rig to pump via lubricator and circulate until well is dead. 

8. Pull out of hole with tubing laying it down. NOTE: Ensure that the well is over-balanced 

so there is no backflow due to formation pressure and there are at least 2 well control 

barriers in place at all times. 

9. Pull seal assembly, pick up workstring, and trip in hole (TIH) with the packer retrieving 

tools. Latch onto the packer and pull out of hole laying down same. Next, confirm the 

well’s mechanical integrity by performing one of the permitted external mechanical 
Injection Well Plugging Plan for ADM CCS#2 

Permit Number: IL-115-6A-0001 Page D4 of 5 

integrity tests presented in the table under “Planned External Mechanical Integrity 

Test(s)” above. 

Contingency: If unable to pull seal assembly, RU electric line and make cut on tubing 

string just above packer. Note: Cut must be made above packer at least 5-10 ft MD. If 

unable to pull the packer, pull the work string out of hole and proceed to next step. If 

problems are noted, update cement remediation plan (if needed) and execute prior to 

plugging operations. 

10. TIH with work string to total depth (TD). Keep the hole full at all times. Circulate the 

well and prepare for cement plugging operations. 

11. The lower section of the well will be plugged using CO2 resistant cement from TD 

around 7000ft to around 1000ft above the top of the Eau Claire formation (to 

approximately 4000 ft). This will be accomplished by placing plugs in 500 ft incremental 

lifts. Using a density of 15.9 ppg slurry with a yield of 1.11 cf/sk, approximately 1333 

sacks of cement will be required. Actual cement volume will depend upon actual weight 

of the casing within the plugged zone as well as the length of plug set as determined 

during the plugging operation. It is anticipated that at least six plugs of 500 feet in length 

will be necessary. No more than two plugs will be set before cement is allowed to set and 

plugs verified by setting work string weight down onto the plug. (Calculations: Assume 

47 lb/ft casing for this interval 3000ft x .4110 cu ft/ft x 1.20/ 1.11 cu ft/sk = 1333 sacks.) 

12. Circulate the well and ensure it is in balance. Place tubing just above cement top from 

previous day. Mix and spot 500 ft balanced plug in 9 5/8 inch casing (approximately 180 

sacks Class A/H mixed at 15.9 ppg with yield 1.18 cu ft/sk). Pull out of plug and reverse 

circulate tubing. Repeat this operation until a total of 8 plugs have been set. If plugs are 

well balanced then the reverse circulation step can be omitted until after each third plug. 

Lay down work string while pulling from well. If rig is working daylights only then pull 

10 stands and rack back in derrick and reverse tubing before shutting down for night. 

After waiting overnight, trip back in hole and tag plug and continue. After ten plugs have 

been set pull tubing from well and shut in for 12 hours. Trip in hole with tubing and tag 

cement top. Calculate volume for final plug. Pull tubing back out of well. Nipple down 

BOPs and cut all casing strings below plow line (min 3 feet below ground level or per 

local policies/standards and ADM requirements). Trip in well and set final cement plug. 

Total of approximately 1443 sacks total cement used in all remaining plugs above 4000 

feet. Lay down all work string, etc. Rig down all equipment and move out. Clean cellar to 

where a plate can be welded with well name onto lowest casing string at 3 feet, or as per 

permitting agency directive. (Calculations assume 40#/ft casing and no excess because 

this section is inside the intermediate casing 4000 ft x .4257 cu ft/ft / 1.18 cu ft/sk = 1443 

sacks. 

13. The procedures described above are subject to modification during execution as 

necessary to ensure a plugging operation that protects worker safety and is effective to 

protect USDWs, and any significant modifications due to unforeseen circumstances will 

be described in the Plugging report. Complete plugging forms and send in with charts and 
Injection Well Plugging Plan for ADM CCS#2 

Permit Number: IL-115-6A-0001 Page D5 of 5 

all lab information to the regulatory agency as required by permit. Plugging report shall 

be certified as accurate by ADM and plugging contractor, and shall be submitted within 

60 days after plugging is completed. 

 Figure 1. CCS#2 Injection Well Plugging Schematic. Perforation zone(s) are estimated. 

Bottom of plug #2 = 4,000 ft

Bottom of plug #1 = 7,000 ft