Small Scale Field Test Demonstrating CO2 Sequestration

This web page is in support of "Small Scale Field Test Demonstrating CO2 Sequestration in Arbuckle saline aquifer and by CO2-EOR at Wellington field, Sumner County, Kansas."

CO2 Sequestration Summary Pages and Web Apps

We are recording all monitoring/production data on our CO2 Data Summary Page. Users can access a variety of applets to interpret and analyze the geochemistry, production data, and earthquake events around Wellington Field in real time.


updated March 21, 2016

Photos on the CO2 Injection Project moved to their own page.


updated June 2016

Inaccuracy of End Points of CO2-Brine Relative Permeability Curves, by Mohsen FazelAlavi, Mina FazelAlavi, and Maryam FazelAlavi. Carbon Capture, Utilization & Storage Conference, June 14-16, 2016, Tysons, VA. (Acrobat PDF, 4 MB)

Pilot Scale CO2 EOR at Wellington Field in South-Central Kansas, by Yevhen Holubnyak, Lynn Watney, Jason Rush, Mina Fazelalavi, and Dana Wreath. Carbon Capture, Utilization & Storage Conference, June 14-16, 2016, Tysons, VA. (Acrobat PDF, 4 MB)

Lessons Learned from Waste Water Disposal in Kansas: Applications for CO2 Geological Storage, by Yevhen Holubnyak, Lynn Watney, and Tandis S. Bidgoli. Carbon Capture, Utilization & Storage Conference, June 14-16, 2016, Tysons, VA. (Acrobat PDF, 5 MB)

Geologic Carbon Sequestration Research in Kansas: Subsurface Storage Capacities and Pilot Tests for Safe and Effective Disposal, by W. Lynn Watney and others. Kansas NextStep Oil and Gas Seminar, Hays, Kansas, April 5-7, 2016. (Acrobat PDF, 13 MB)

Induced Seismicity--Physical Mechanisms and Temporal Trends in Kansas, by Tiraz Birdie and Lynn Watney. Kansas Hydrology Seminar, November 20th 2015. (Acrobat PDF, 3.1 MB)

Technical Economic and Regulatory Challenges Facing Large Scale Adaption of Carbon Geologic Sequestration, by Tiraz Birdie, Lynn Watney, and Jennifer Hollenbach. Carbon Management Technology Conference, November 18th 2015. (Acrobat PDF, 3.3 MB)

Advanced Subsurface Characterization for CO2 Geologic Sequestration and Induced Seismicity Evaluations, by Tiraz Birdie, Lynn Watney, Aimee Scheffer, Jason Rush, Eugene Holubnyak, Mina Fazelalavi, John Doveton, Jennifer Raney, Saugata Datta, Dennis Hedke, and Jennifer Roberts. Carbon Management Technology Conference, November 19th 2015. (Acrobat PDF, 2.5 MB)

Advanced Subsurface Characterization for CO2 Geologic Sequestration and Induced Seismicity Evaluations, by Tiraz Birdie, Lynn Watney, Aimee Scheffer, Jason Rush, Eugene Holubnyak, Mina Fazelalavi, John Doveton, Jennifer Raney, Saugata Datta, Dennis Hedke, and Jennifer Roberts. Carbon Management Technology Conference, November 19th 2015. (Acrobat PDF, 2.5 MB)

CO2-EOR in the Wellington Field, Sumner County, South Central Kansas, by W. Lynn Watney. 2015 KU TORP Improved Oil Recovery Conference, May 4, 2015. (Acrobat PDF, 26 MB)

Modeling CO2 Sequestration in Saline Aquifer and Depleted Oil Reservoir to Evaluate Regional CO2 Sequestration Potential of Ozark Plateau Aquifer System, South-Central Kansas, by W. Lynn Watney and Jason Rush. Wrap-up presentation, DOE-NETL, Pittsburgh, PA, February 12, 2015. (Acrobat PDF, 17 MB)

Small Scale Field Test Demonstrating Sequestration in Arbuckle Saline Aquifer and by CO2-EOR at Wellington Field, Sumner County, Kansas, by W. Lynn Watney, Jason Rush, and Jennifer Raney. Presentation given at U.S. Department of Energy National Energy Technology Laboratory FY15 Carbon Storage Peer Review March 2-6, 2015. (Acrobat PDF, 9 MB)

Small scale field test demonstrating CO2 sequestration in arbuckle saline aquifer and by CO2-EOR at Wellington field, Sumner County, Kansas, by W. Lynn Watney, Jason Rush, and Jennifer Raney. Presentation given at NETL Carbon Storage R&D Project Review Meeting, Aug. 12-14, 2014. (Acrobat PDF, 5 MB)

Small scale field test demonstrating CO2 sequestration in Arbuckle saline aquifer and by CO2-EOR at Wellington field, Sumner County, Kansas, presentation given at DOE Carbon Storage R&D Project Review Meeting, Aug. 21-23, 2012. (Acrobat PDF, 4 MB)

Business Implications of A Class VI Permit--The Long View? A Kansas Perspective, presentation given in Golden, CO, April 4-5, at the Colorado School of Mines. (Acrobat PDF, 8 MB)

Quarterly Reports

August 2016

Q19_2016.pdf, Aug. 11, 2016 (Adobe Acrobat PDF file, 7 MB)

  1. Completed injection of 1,101 truckloads, 21,784 US tons, 19,803 metric tons, approximately 374,000 MCF of CO2 on June 21, 2016. Total expenditures for purchasing CO2 were $1,964,000. Our overall price for CO2 was $90.16 per US ton from Linde Group.
  2. Injected completed in 165 days or approximately 5 months with an average of 120 tonnes per day of CO2 injected.
  3. Linde Group was able to provide nearly continuous CO2 supply to the site outside of a five day of interruption in April 2016.
  4. Successful monitoring of CO2 injection, prior to and during injection, and post-injection
    1. a. Recorded volumes of CO2 injected and CO2, oil, and brine recovered,
    2. b. Sampled fluids via on-site and lab-based geochemistry from 17 wells,
    3. c. Reduced well based monitoring to seven wells after CO2 ended and continuous water injection began,
    4. d. Operated Wellington seismometer array installing two accelerometers outside of field to improve location and magnitude of events,
    5. e. Since mid-April 2016 have recorded continuous (1-sec) baseline pressure measurements of the perforated lower Arbuckle zone in shut-in Class VI injection.
    6. f. Confirmed that SAR satellite images obtained to date have useful images for InSAR and moving to new ERS satellite with new radar with improved coherency of response in humid temperate climate. Also, frequency of scenes has been reduced from every 20 days to 8 days.
  5. The primary CO2 plume has been managed by pressure maintenance including use of two nearby injection wells and varying fluid withdrawal in eight surrounding wells. Also, fluid flow barriers and baffles with lower permeability lie south and east and downdip of the injection well, which have apparently limited CO2 migration beyond those areas. The CO2 injection thus far has verified the geomodel based on the well and seismic interpretations.
  6. The simulation used to forecast the design of pressure maintenance and injection of CO2 and to forecast the oil response has demonstrated its usefulness. Simulation forecasts are again being confirmed during the initial stages of waterflooding where oil production has reached a new well, #45, to the north of the injection well and one well location out from the inner ring of producing wells.
  7. The CO2 plume remains within the nearby producing wells that surround the injection well indicating conformance of this flood, demonstrating the matrix controlled permeability vs. fractures.
  8. Since the CO2 injection stopped in June 21st and continuous water injection began and this phase of injection is viewed upon as a success due to
    1. high level of sweep efficiency,
    2. lack of notable CO2 fingering beyond the plume,
    3. evidence for a bank of oil recognized by well production with notable increase incremental oil, but lack of significant CO2 production
  9. Cumulative ratio of produced/purchased CO2 is only 11% (as of July 25). No notable changes occurred until CO2 injection ceased and water injection was increased from 50 to 750 barrels on July 14th when the daily CO2 produced has begun falling from ~450 MCFD to half that rate on July 25th.
  10. A rate of 50 BWDP following CO2 injection was maintained to keep the plume stable until a 2D seismic profile could be acquired passing through the injection well. Producing wells were shut-in during the actual seismic survey.
  11. Acquisition of the 2D seismic was designed to have sufficient offset to allow optimized AVO (Amplitude vs. Offset) to evaluate this approach for detection of the CO2 plume during the Arbuckle injection.
  12. The new 2D seismic survey was acquired and will be processed in the same manner as the original 3D seismic survey. Moreover, 3D survey will be reprocessed to bring it to date with current methods offered by Fairfield-Nodal.

Q18_2016.pdf, May 17, 2016 (Adobe Acrobat PDF file, 12 MB)

  1. Continuous CO2 injection in the Mississippian reservoir began on January 9, 2015 and weekly reporting thereof.
  2. Systematic weekly sampling of brine and gases at Wellington for up to 17 wells to understand the behavior of CO2 that is injected including quantifying interaction with the brine, oil, and reservoir rock, and accounting of the same.
  3. Develop databases for field and lab analyses using Java-based web applications with functions including importing brine data and downloading of results. Developed means to compare data by well and by date including 1) Wellington Field CO2 Brine Data Summary Page, 2) Fluid Level Data Summary Page, the latter including oil cut, % and metered CO2, fluid levels and estimated BHP.
  4. Developed additional Java applications to analyze brine and gases including 1) compute correlation matrix and perform Principal Component Analysis on-the-fly for the brine data to identify correlations and outliers of analyses for QA/QC and interpretation and 2) to normalization brine analyses via charge balance of anions and cations so that ratio to within 2% of expected 1:1 ratio.
  5. Built new and refine existing Java web applications to grid, map, and provide animated displays/movie of weekly changes in field and lab well-based measurements, displaying up to three variables using color cube algorithm.
  6. Established clearly defined analytical procedures and protocols for brines and gases involving four labs at KGS and KU for cost saving, efficiency, on-site training, and overall QA/QC.
  7. Have successfully used well based measurements to track CO2 and oil recovery including metered CO2 and incremental oil, oil cut and total fluid by well, and estimates of bottom hole pressure.
  8. Have identified the location of the primary CO2 plume that still lies within the producing wells nearest the injection well, #2-32. CO2 produced amounts to less than 15% of the CO2 has been injected.
  9. Volumetric analysis indicate that the bank of CO2 has extended to the entire ~70 ft thick porous and permeable portion of the Mississippian reservoir that also contains ~23% residual oil saturation.
  10. Compositional fluid flow simulation recently performed has focused on the temperature effects of injecting cold CO2 suggest that a mixed phase plume has developed in the inner ring of wells within 660 ft of the CO2 injection well. CO2 varies from an inner core of cool liquid CO2 and warmer supercritical phase that likely has become miscible with oil.
  11. New analyses of 3D seismic analysis include new sequence stratigraphic interpretation successfully integrating the 3D seismic, well log, and core. Model is consistent with progradation of high frequency parasequences exhibiting transgressive, maximum flooding, highstand and lowstand systems tracks comprising a single large depositional sequence encompassing the entire preserved Mississippian strata at Wellington Field.
  12. The depositional model is consistent with a large regional cool water ramp that occupies large portions of southern Kansas and northern Oklahoma bordering the Anadarko and Arkoma basins.
  13. Faulting along the ramp and at Wellington Field occurred syndepositionally with the Mississippian strata, locally influencing the progradational system and affecting reservoir lithofacies across a medial NE-SW trending fault in Wellington Field.
  14. New AVO (amplitude vs. offset) analysis of the 3D indicates results consistent with the Petrel inversion of porosity. The AVO further indicates that the CO2 is confined to the more higher porous contiguous portion of the reservoir surrounding the CO2 injection well. Results also show the porosity barrier present along the syndepositional fault that bisects the field.
  15. Increased pressure and presence of CO2 noted in well #63 across a small medial fault located to the east of the injection well. The show of CO2 indicates that the fault and associated lithofacies change act as a baffle between CO2 injection well and this producer and are consistent with earlier pulse test and interpretation of 3D seismic imaging.
  16. Seismology team has continued to build and refine earthquake catalog from Wellington seismometer array reporting weekly updates. Magnitude of Completeness established to verify that all events can be identified equal to or great than 1.4 M, a value that will continue to decrease over time as the catalog expands.
  17. Capabilities of existing Java web applications pertaining to earthquakes have expanded to include 1) monthly summary of earthquakes as CO2 Seismic Array Data Summary Page, and 2) 3D Animation/Movie of existing maps and 2D and 3D plots of earthquakes to illustrate by location, magnitude, and time. User can limit events to be shown by time and define what appears on the map.

Q17_2016.pdf, Feb. 9, 2016 (Adobe Acrobat PDF file, 13 MB)

  1. Completed installation of on-site CO2 storage equipment and injection skid.
  2. Begin CO2 injection into the Mississippian reservoir.
  3. Installed equipment to monitor injection and recovery of CO2.
  4. Began systematic monitoring of brine and gases at Wellington to understand the behavior of CO2 and interaction with brine, oil, and reservoir rocks.
  5. EPA's determination of the absence of a USDW for the Class VI permit application.
  6. Submitted and received response from EPA refined conservative AoR model (Revised Section 5 of the Class VI permit.
  7. Received portions of draft Class VI permit to review
  8. Received requirements for the Financial Assurance and the Post Injection Site Care.
  9. Refined and verified 18-seismometer array at Wellington with nearby earthquakes begin updating the earthquake catalog on a weekly basis.
  10. Workflow in place to report notable earthquakes within 24 hours to ensure location and magnitude.
  11. Participate in continued discussion and presentation on induced seismicity in the context of a safe and effective CO2 injection at Wellington.

Q16_2015.pdf, Oct. 12, 2015 (Adobe Acrobat PDF file, 13 MB)

  1. Decision was made in July to build a compositional simulation of the Arbuckle saline aquifer in STOMP, the software used by EPA evaluate the AoR to facilitate the conversion from CMG simulation used by KGS to software platform used by EPA. After consultation with the developer of STOMP at Pacific Northwest National Laboratory, a methodology was developed to import the domain built in the Petrel geomodel into STOMP. The conversion process that was creating difficulties in sharing the CMG model to STOMP was subsequently solved and confirmed with EPA. Employing STOMP at the KGS will facilitate future updates. CMG is now uses the parameters, processes, and rock properties to confirm the AoR with a conservative model. The same domain and input parameters will be used in STOMP.
  2. Existing and new samples of brine from the Mississippian oil reservoir were completed in August and results and displays using java applications are now online with a methodology to normalize the data to account for systematic changes so the results can be mapped. Systematic error of the major constituents, while within the analytical tolerance of ±5%, can assignment of either spatial or temporal anomalies that could be within the real changes in the brine as the reservoir is swept by CO2.
  3. The Mississippian reservoir was revisited and updated in July and August to incorporate new data from the KGS #2-32 drilled in the previous quarter. The core obtained and the log data made a compelling case for slightly inclined stratification of high-frequency depositional cycles. Seismic was reexamined to trace this cyclicity and confirm that the small dip of a few degrees was depositional dip, not structure.

Q15_2015.pdf, Aug. 12, 2015 (Adobe Acrobat PDF file, 4 MB)

  1. The review of the Class VI application has made significant progress, and is nearing the final stages to be approved by EPA.
  2. Freshwater monitoring boreholes have been sampled and indicate no presence of a USDW at the Wellington site.
  3. CO2 suppliers have been secured.
  4. Performed workovers and obtained baseline sampling on surrounding Mississippian Boreholes for production and MVA during CO2-EOR.
  5. MVA components in place to monitor the Mississippian CO2-EOR injection, and revisited design and updated costs to fabricate U-Tube and CASSM for Arbuckle monitoring.
  6. Conducted pulse test at KGS 2-32 Mississippian well.
  7. Installed three new broadband seismometers near injection borehole.
  8. Establish Protocols for InSAR data collection.

Q14_2015.pdf, May 15, 2015 (Adobe Acrobat PDF file, 12 MB)

  1. Participated in DOE peer review in Pittsburgh on March 5.
  2. Class II application was filed with Kansas Corporation Commission in January and approved in February 2015.
  3. Continued conference calls and written communications with EPA regarding review of Class VI application. Submitted responses to requests from EPA for additional information (RAI) in regards to the application. Responded to inquiries regarding evaluation of surface water with drilling, completion, testing, and analyses fit for purpose to evaluate the presence of a USDW.
  4. Drilled and completed three shallow water wells and conducted extensive sampling, pumping, and lab work to evaluate surface waters in AOR. Findings to date is that the shallow bedrock in the AOR is primarily a low yield, brine saturated aquiclude that overlies and is in equilibrium with diffusive dissolution from the underlying shallow Hutchinson salt. Surface water in AOR and immediately vicinity is limited to thin surficial colluvium and alluvial lenses.
  5. Drilled Berexco Wellington KGS #2-32 in March 2015. Surface sampling and wireline logging above surface casing enhanced understanding of the presence of surface aquifer and aquitard system. The Mississippian oil reservoir was cored, evaluated with modern wireline logs, and is undergoing testing. The reservoir at #2-32 consists of an evenly porous (20-25% porosity) interval that is ~60 ft thick. The upper 40 ft is at residual oil saturation indicating that location has been effectively waterflooded and is in communication with one or more injection wells.
  6. KGS #2-28 will be further tested, cores will be analyzed, and models will be adjusted to determine how the reservoir is re-pressured and what the anticipated CO2 plume will be.

Q13_2015.pdf, Feb. 16, 2015 (Adobe Acrobat PDF file, 3 MB)

  1. Kickoff meeting with team on October 15, 2014 to implement plans for BP2.
  2. Teleconferenced with Region 7 EPA in Lenexa, KS Washington office during the quarter to respond to questions Wellington Class VI application.
  3. Obtained completion plans, drilled, and began testing of two of the shallow water wells to evaluate presence of USDW.
  4. Started processing of data obtained from cGPS data to provide baseline for InSAR.
  5. Instituted cost-center based billing through discussions with KGS, KUCR, and DOE to expedite invoicing and justification for DOE.
  6. 15 seismometers seismic array from IRIS-PASSCAL were placed on a cellular network.

Q12_2014.pdf, Nov. 4, 2014 (Adobe Acrobat PDF file, 3 MB)

Q11_2014.pdf, revised Sept. 5, 2014 (Adobe Acrobat PDF file, 4 MB)

Q9_2014r.pdf, March 11, 2014 (Adobe Acrobat PDF file, 3 MB)

Q8_2013.pdf, Nov. 5, 2013 (Adobe Acrobat PDF file, 2 MB)

Q7_2013.pdf, May 6, 2013 (Adobe Acrobat PDF file, 925 kB)

Q6_2013.pdf, May 6, 2013 (Adobe Acrobat PDF file, 485 kB)

Q5_2013.pdf, Jan. 31, 2013 (Adobe Acrobat PDF file, 241 kB)

Q4_2012r2.pdf, Nov. 12, 2012 (Adobe Acrobat PDF file, 3 MB)

Q3_2012r.pdf, Revised Sept. 5, 2012 (Adobe Acrobat PDF file, 3.4 MB)

Q2_2012.pdf, May 2012 (Adobe Acrobat PDF file, 1.4 MB)

Q1_2012rev.pdf, March 2012 (Adobe Acrobat PDF file, 2.7 MB)

Cutter KGS 1 well

updated July 11, 2013

Info on the Cutter KGS 1 well moved to its own web page.

[July 11, 2013] New photos, well report from reperforating work.

[Oct. 5, 2012] Released rig at 12:00 am on 10/5/12. Rig down.

Overview for Cutter KGS 1 site visit, Sept. 10-11, 2012. (Acrobat PDF, 14 MB)

Field Trip; Schedule, updated Sept. 7. (Acrobat PDF, 1 MB)


South-central Kansas CO2 Project is a DOE-funded project of the Kansas Geological Survey. More ...