Exploration and Production Technologies

Field Test of TDA's Direct Recovery Oxidation Process for Sulfur Recovery

DE-FC26-01BC15333

Program
This project was selected in response to DOE's Oil Exploration and Production solicitation DE-PS26-01NT41048, focus area Effective Environmental Protection. The goal of the program was to reduce compliance costs and improve environmental performance by providing lower-cost technologies, and/or provide sound scientific basis for cost-effective, risk based regulatory decisions.

Project Goal
The goal was to field test a process for removing sulfur contaminants from natural gas that could prove to be much less complex and lower in cost than conventional cleanup technologies.

Performers
TDA Research, Inc. Wheatridge, CO 
Whiting Petroleum Gas Plant Plains, TX 
Gas Technology Institute (GTI) Chicago, IL

Project Results
This project was a Phase III pilot plant test of TDA's gas sweetening process done under realistic conditions. TDA Research Inc. successfully completed the test at Whiting Petroleum's Sable San Andreas gas plant. The feed was about 228,000 standard cubic feet per day (SCFD) of gas that contained about 60 vol % CO2, 20 vol % CH4 and 10 vol % C3+ and higher hydrocarbons. The feed was associated gas from CO2 flooding operations carried out on Whiting's oil wells. The gas is collected and piped to the Sable gas plant, where it is normally flared. The pilot plant was sited in line with the flare in order to remove hydrogen sulfide (H2S) prior to flaring. The average H2S concentration in the gas during the field test was 7,341 ppm. The sulfur recovery process was shown to be low-cost, compact, and efficient for amine offgas.

Benefits
The selectivity of process for converting H2S into elemental sulfur was essentially 100%, and the catalyst converted 90% of the H2S into sulfur and water (the remaining 10% of the H2S passed through unconverted). Importantly, no catalyst deactivation was observed for over the course of the more than 1,000-hour test. Minimal (about 10-15 ppm) of SO2 was formed during the test.

About 3.6 tons of elemental sulfur was recovered from a total inlet of 3.9 tons of sulfur (as H2S). The total amount of SO2 released from the plant (taking into account flaring of the unconverted 10% H2S) was 0.86 tons. This amount of SO2 is much lower than the normal 8 tons that would have been emitted if all of the H2S were flared over the time of the pilot plant test.

The pilot plant was simple to operate and required much less operator intervention than is typical for a new unit being commissioned. The ease of use and low capital and operating costs of the direct oxidation process makes it an attractive technology to be used where traditional sulfur recovery technologies are too expensive (e.g., small to medium-size plants).

Background
The direct oxidation process makes use of a catalyst developed by the project performer that partially oxidizes hydrogen sulfide (H2S) to sulfur and water, without the formation of substantial amounts of SO2. The catalyst was developed and demonstrated at the bench scale using funds from DOE SBIR Phase I and Phase II grants. GTI and Unocal Corp. together funded the design and fabrication of a pilot plant at a cost of $1,300,000 to test the process. The process was originally scheduled to be field-tested on a Unocal platform in Mobile Bay. Unocal expected that the offshore platform would be subjected to more stringent environmental regulation and saw the direct oxidation process as a way to allow increased gas production on the platform while reducing SO2 emissions. However, the environmental regulations on the platform were not tightened, and therefore, Unocal decided not to incur the additional costs needed to install and operate the pilot plant. Construction of the pilot plant was stopped until a new field site was identified.

The project performer has identified an alternate site in Alberta, Canada, to conduct the field test. The pilot plant was modified to accommodate the requirements of the new site, shipped there, operated on a slipstream from the amine unit, and subjected to parametric and long term-testing. The performer collaborated with URS Radian to undertake the field test.

Although the catalyst has been tested in the laboratory (with simulated amine offgas) for over 600 hours, catalyst stability data using an actual slipstream from a gas processing plant is crucial to determining the reliability of the process on a commercial scale. The pilot plant data enabled the researchers to evaluate the economics of the process and compare them to state-of-the-art small-scale sulfur recovery technologies, such as liquid redox processes. A successful pilot test will provide the confidence to potential customers to adopt a new technology.

Project Summary
The start-up and shakedown of the plant was completed the week of October 7, 2002. It included installation of the main electric gas heater, tuning of the process control program and establishing the flow of process gas. The plant was built using two levels because its original destination was to be the Unocal offshore platform; therefore, the unit is quite compact. The sulfur condenser, the sulfur seal, and the sulfur bins are located on the bottom level.

The fixed-bed reactors are located on the level above the sulfur condenser. There are two fixed-bed reactors on the unit because of the original requirements for the offshore application (one was to be filled with desiccant); however, in this field test, only one reactor was used. The gas inlet is at the top of the reactor, and the outlet is at the bottom. The gas inlet is a smaller pipe that enters the top of the reactor at the elbow. A large flange at the top is removed for installing the ceramic balls and catalyst. Solids are kept from falling out of the reactor by means of a cylindrical cover screen that has a cap. The first layers added to the reactor are a 6-inch-thick layer of 1-inch ceramic balls followed by a 6-inch layer of ½-inch balls followed by a 6-inch thick layer of ¼-in balls. A mesh stainless steel screen is then placed over the balls. The catalyst is placed on top of this screen.

For the test, 1,708 lb of partial oxidation catalyst (Mo Nb/TiO2) was loaded into the reactor. A mesh stainless steel screen was then placed on top of the catalyst bed, followed by a single 6-inch-thick layer of ½-inch ceramic balls. The balls act as a flow distributor for the feed gas. 

Whiting's Sable San Andreas Gas Plant is used to collect and flare associated gas from CO2 flooding operations. The total gas flow varies somewhat but averages about 300,000 SCFD and contains 6,000-8,000 ppm of H2S. The gas contains about 18% methane and 59% CO2, along with modest amounts of ethane (8.7%), propane (6.5%), and butanes (3%). The gas also contains hydrocarbon liquids.

Current Status (October 2005)
The project is complete. Currently, TDA's direct oxidation process has been exclusively licensed to SulfaTreat, and is being offered commercially under the trade name SulfaTreat-DO®. The first plant is expected to be installed in 2005.

Project Start: March 13, 2001
Project End: February 29, 2004

Anticipated DOE Contribution: $703,540
Performer Contribution: $684,462 (48% of Total)

Contact Information
NETL - Jesse Garcia (jesse.garcia@netl.doe.gov or 918-699-2036)
TDA - Girish Srinivas (srinivas@tda.com or 303-422-7763)

Direct oxidation process pilot unit near Plains, TX.

 
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