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CO2 capture from SMRs: A demonstration project

09.01.2012  |  Baade, W. F.,  Air Products and Chemicals, Inc., Allentown, PwnnsylvaniaFarnand, S.,  Air Products and Chemicals, Allentown, PennsylvaniaHutchison, R. ,  Air Products and Chemicals, Allentown, PennsylvaniaWelch, K. ,  Air Products and Chemicals, Allentown, Pennsylvania

Technical and economic results from this project will be key in determining the most effective path to commercialization.

Keywords: [CO2 capture] [steam methane reformer] [SMR] [Port Arthur] [pipeline] [DOE] [Department of Energy] [Valero] [sequester]

In June 2010, the US Department of Energy (DOE) selected a gas-specialty company to receive American Recovery and Reinvestment Act (ARRA) funding to design, construct and operate a system to capture CO2 from two steam methane reformers (SMRs) located within the Valero refinery in Port Arthur, Texas. The CO2 removal technology will be retrofitted to the SMRs, which produce hydrogen to assist in the manufacture of petrochemicals and the making of cleaner burning transportation fuels by refinery customers on the Gulf Coast hydrogen pipeline network.

The necessary commercial agreements were signed to proceed with a planned carbon capture and sequestration (CSS) project in Port Arthur, Texas. The refinery is providing the additional land and rights-of-way required for the project, in addition to supplying utilities to support the project. Meanwhile, purified and compressed CO2 will be supplied for injection into enhanced oil recovery (EOR) projects in Texas. CO2 for EOR is beneficial because it:

  • Increases energy security by increasing recoverable oil
  • Creates economic opportunity for the government via increased tax revenues and for individuals via jobs created in domestic oil fields.
  • Provides environmental benefits from capturing, productively using and storing CO2, rather than emitting it into the atmosphere.

Beginning in late 2012, approximately 1 million tons of CO2 annually will be recovered and purified. The DOE is providing a total of $284 million or approximately 66% of the over $400 million project. This includes partial reimbursement of operating costs through the end of the demonstration period (September 30, 2015).

Objectives and scope

The main objective for this CO2 capture project is to demonstrate an advanced technology that captures and sequesters carbon dioxide emissions from large-scale industrial sources into underground formations. In order to be eligible for supplemental funding from the DOE, it was necessary for applicants to meet certain DOE objectives, which are itemized in Table 1.

 



In addition, the DOE evaluated projects on a cost-per-unit basis of CO2 captured and sequestered, as well as on the magnitude of future potential commercialization. This project will provide real-world data illustrating the true costs of CO2 capture and sequestration. It was one of only three projects to receive Phase 2 funding from the DOE, which covers construction and operating and maintenance costs during the demonstration period.

Current Port Arthur site

A new 180-mile-long pipeline is being constructed to connect to existing Louisiana and Texas hydrogen pipeline systems. This integrated pipeline system will unite over 20 hydrogen plants and over 600 miles of pipelines to supply the Louisiana and Texas refinery and petrochemical industries with more than one billion cubic feet of hydrogen per day. The Port Arthur SMRs and the CO2 capture project will be part of the combined pipeline system (Fig. 1).

 
  Fig. 1. The CO2 capture project will be part
  of a hydrogen pipeline system on the US Gulf Coast.



The Port Arthur site was selected to host the CO2 capture facility based on economies of scale of capturing CO2 from the two SMRs on the premises. The proximity of the SMRs accommodated a common drying and compression system that significantly reduced capital when compared to the alternative of isolated drying and compression arrangements.

 
  Fig. 2.  1 million tons of CO2 per year will be captured from the two SMRs. The CO2 will be used for enhanced oil recovery.


Process summary and equipment

Fig. 3 is a block flow diagram for the project that illustrates how the CO2 capture facility will be integrated within the existing SMRs. The facility will utilize a proprietary-designed CO2 vacuum swing adsorption (VSA) system that will be retrofitted to each of the two existing SMR trains (PA-1 and PA-2). Each VSA unit is designed to remove more than 90% of the CO2 contained in the reformer pressure swing adsorption (PSA) feed gas (Fig. 4). Sweet syngas (CO2 removed) will be returned from the CO2 VSA system to feed the existing SMR hydrogen PSAs. CO2 produced from the VSA units will be compressed and dried in a single train located at PA-2.

 
  Fig. 3.  Block flow diagram of Port Arthur
  SMRs and integrated CO2 capture facility.

 
  Fig. 4.  VSA trains are used to remove more
  than 90% of the CO2 contained in the
  reformer PSA feed gas.

VSA system (PA-1 and PA-2). CO2 containing syngas from the steam-methane reformer cold process condensate separator is routed to the VSA system. The CO2 contained in the process gas of the PA-1 and PA-2 SMRs will be removed with multiple VSA units. Each VSA unit includes a series of vessels filled with adsorbent to selectively remove one or more components from the feed gas. In this case, the feed gas is the raw hydrogen stream from the SMR plants upstream of the existing hydrogen PSA.

The VSA cycle is similar to the hydrogen PSA cycle. Adsorber vessels are fed with gas at high pressure, causing selective adsorption of feed components onto the adsorbent bed. The gas that is not adsorbed by the bed is a hydrogen-rich stream and is sent to the H2 PSA for further purification. Then, the vessel undergoes a series of pressure equalizations, with vessels at lower pressures before a CO2 product is drawn off. There are two unique steps in the VSA cycle because the product is now CO2 at high purity. The first is that a vacuum pump is needed to draw off the CO2 product (Fig. 5) to sub-atmospheric pressures in an “evacuation” step. The second is a “rinse” step in which blowdown gas is taken from a lower pressure bed, compressed, and fed to a higher pressure bed. The “rinse” and “evacuation” steps are the keys to achieving a high purity CO2 product.

 
  Fig. 5.  VSA vacuum blowers are used to
  recover CO2 from the VSA beds and deliver
  it to the CO2 product compressor before
  offsite transport via pipeline for use in EOR.

CO2 compressor and dryer (PA-2). Raw CO2 exits the two trains of the VSA systems after cooling and is combined at the suction of the first stage of an eight-stage, integrally-geared centrifugal compressor. Each of the first five compressor stages is followed by an intercooler, which also includes an integral separating section to remove condensate, which is mainly water.

Condensate from the first five intercoolers is combined in a common vessel and piped to the existing plant waste sump. A portion of the PA-2 condensate can be sent to the tri-ethylene glycol (TEG) dryer system, where it serves as water makeup, thereby reducing the overall water requirements of the plant by recycling.

CO2 exiting the fifth stage intercooler is sent to a TEG drying system, where water is removed. After drying, the CO2 is sent to the sixth stage section, where the final compression occurs in stages 6, 7 and 8. After final cooling following the eighth stage, the CO2 exits the battery limits and enters the CO2 pipeline at the required pipeline pressure of over 2,000 psig.

TEG dehydration units have routinely been used for CO2 dehydration for EOR applications, as well as being the standard technology for natural gas drying. TEG has a very high affinity for water, allowing very high removal, and a low volatility, minimizing solvent losses into the CO2 product.

The wet CO2 exits the after cooler following the fifth stage of compression and is contacted with lean dry TEG in the tray or structured packing section of the contactor tower, where water vapor is absorbed in the TEG, thus reducing its water content. The dry CO2 exiting the top of the absorber is heated vs. the incoming lean TEG and sent to the final three stages of CO2 compression, where the CO2 is raised above the critical pressure of 1,071 psia. The TEG content of the dry CO2 is very low.

The wet rich TEG exiting the contactor is depressurized and flows to the regeneration system. The wet rich TEG is then preheated and flashed in a horizontal separator to remove much of the dissolved CO2 and other light gases. The flash gas is sent back to the compressor so that the contained CO2 is not lost. The flashed water-rich TEG liquor is cleaned in charcoal and sock filters and then heated with lean TEG from the regenerator column. The rich heated TEG is then fractionated in the regenerator column and heated in the reboiler, boiling off the absorbed water vapor. The lean TEG exiting the bottom of the regenerator is cooled with rich TEG and then pumped back to the absorber. The reboiler is directly fired with natural gas.

Carbon sequestration system description

The CO2 for EOR will be transported to the site via the pipeline, and will be injected via a CO2 injection pump station in the field connected to 14 CO2 Class II injection wells.

The commercial monitoring program will track the CO2 injected, the CO2 recycled and the performance of the reservoir and wells in retaining CO2. The research program will collect time-lapse data testing alternative and possibly high-resolution techniques for documenting that the CO2 is retained in the injection zone and in the predicted flood area, and that pressure is below that determined to be safe. A report will be prepared evaluating the results of the MVA program, revised model runs showing model match, comparing the effectiveness of the commercial program to the research program in documenting effectiveness and permanence of storage.

CO2 export pipeline

A 13-mile pipeline will be constructed in conjunction with this project to connect the CO2 capture facility with the Green pipeline. The pipeline is an existing 24-in. pipeline that runs from Donaldsonville, Louisiana, to the Hastings Field, south of Houston, Texas (Fig. 6).

 
  Fig. 6.  Map showing Denbury’s 300+ mile long
  Green pipeline, which was designed to carry
  natural and anthropogenic CO2 to oil fields in
  Texas and Louisiana. Source: Denbury 2011
  Annual Report.


Current status

The CO2 capture project is being executed in three phases and is proceeding right on schedule. Phase 1 established the definitive project basis and has been completed. Phase 2 covers the design and construction of the project and Phase 3 entails operation of the project through the end of the demonstration period. The project is currently in Phase 2. The project is further broken down into three sub-projects: CO2 capture facility, CO2 export pipeline and MVA. The CO2 capture facility and CO2 export pipeline are being executed as a single project, with the MVA portion subcontracted to Denbury.

For the CO2 capture facility, all of the major equipment purchases and detailed design have been completed. The detailed design for work outside the battery limit (OSBL) has been awarded and is complete. The OSBL construction work was kicked off in the spring of 2011. For work inside the battery limit (ISBL), piling began in August 2011 and foundations began October 2011; both have been completed. Mechanical construction began January 2012, and electrical and instrumentation construction began June 2012.

The units are being brought online in sequence to facilitate early CO2 capture and to allow for commissioning learnings from PA-2 to be incorporated into PA-1. Commissioning activities are planned for September 2012, with CO2 product being introduced in the pipeline December 2012.

Forward schedule and plan for the future

The PA-2 CO2 capture unit (including CO2 drying and export compression) is scheduled to be onstream in late 2012 and the PA-1 CO2 capture unit is scheduled to be onstream in early 2013. The demonstration period will continue until September 30, 2015.

Over the past 25 years, the industry has transitioned from amine and potassium carbonate liquid absorption processes to PSAs for two reasons. The first is because of increased hydrogen purity requirements for refining processes. The second involves the increased thermal efficiency afforded by steam export to refineries. Capturing CO2 from existing hydrogen plants with PSAs is more challenging because the thermal efficiency is already highly optimized. VSAs are advantaged for retrofits because they can be more easily incorporated with minimal impacts to hydrogen supply to the existing refinery. This commercial scale demonstration of VSA technology provides an additional option for recovering significant volumes of CO2 for EOR.

Despite a shortage of CO2 for EOR, the existing CO2 market does not support current CO2 capture economics without external funding, which is why the DOE’s support is essential. Technical and economic results from this project will be key in determining the most effective path to commercialization. HP

NOTE

Air Products and Chemicals received the ARRA funding to supply CO2 for EOR.

The authors 

William F. Baade is the global marketing manager for oil, natural gas and transport fuels in Air Products’ Tonnage Gases, Equipment and Energy Division. He has over 35 years of industrial experience in various sales, business development and marketing assignments. Mr. Baade holds a BS degree in chemical engineering from Stevens Institute of Technology and graduated
in 1976. He obtained a MBA degree from Lehigh University in 1982. 

Sarah G. Farnand is a market manager with Air Products & Chemicals. Her current responsibilities include analyzing the global oil and natural gas markets with an eye to identifying opportunities for Air Products in the fields of EOR, GTLs, LNG, refining and alternative fuels. She holds a BA degree in economics from the College of William and Mary and a MBA in finance and strategy from the University of Maryland. 

Robert L. Hutchison joined Air Products & Chemicals in 1979 and is currently the senior project manager for the Port Arthur CO2 recovery project. Mr. Hutchison has held various engineering, operations and commercial positions during his 33 year career at Air Products and has distinguished himself in the management of large, complex industrial gas projects. He holds a BS degree in chemical engineering from the University of Illinois and a MBA degree from Lehigh University.

Ken Welch joined Air Products & Chemicals in 1996 and is currently the HyCO business development manager. Mr. Welch was the principal investigator for the CO2 capture project, working as the asset manager and primary contact for the DOE. Mr. Welch has held various commercial positions during his Air Products career and has distinguished himself in the business development of large, complex HyCO projects. He holds a BS degree in chemical engineering and marketing from Pennsylvania State University. 




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Clayton
01.29.2013

I'm a huge advocate in the projects that will renew oilfields and create a greener environment. I would like and appreciate to know when construction is scheduled to begin in my area, Splendora, TX 77372. I look forward to your comments and hopefully a cool map with a layout.

Thanks,
Clayton

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