Oil & Natural Gas Projects
Exploration and Production Technologies
Field Test of TDA's Direct Recovery Oxidation Process for Sulfur Recovery
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.
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
TDA Research, Inc. Wheatridge, CO
Whiting Petroleum Gas Plant Plains, TX
Gas Technology Institute (GTI) Chicago, IL
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.
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).
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.
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
Project Start: March 13, 2001
Project End: February 29, 2004
Anticipated DOE Contribution: $703,540
Performer Contribution: $684,462 (48% of Total)
NETL - Jesse Garcia (email@example.com or 918-699-2036)
TDA - Girish Srinivas (firstname.lastname@example.org or 303-422-7763)
Direct oxidation process pilot unit near Plains, TX.