Apr-2013

Formulated solvent reduces shale gas processing costs

A gas treating facility is upgraded to a formulated solvent to achieve reduced operating costs compared with operations using a commodity amine blend

ROBERT L DOTSON
Dow Oil, Gas & Mining

Article Summary

With the development of new drilling technology and hydraulic fracturing techniques, global shale gas production has increased significantly over the past five years and is projected to continue increasing for several years. According to the International Energy Agency,1 “by 2020 the United States becomes a net exporter of natural gas and is almost self-sufficient in energy, in net terms, by 2035.” “…as demand increases by 50% to 5 trillion cubic meters in 2035. Nearly half of the increase in production to 2035 is from unconventional gas, with most of this coming from the United States, Australia, and China…” Increases in shale gas production and decreasing energy prices globally will require competitive exploration and operational expenses among the energy options.

In early 2011, after having plant operational issues, poor reliability of gas treating facility equipment and high operational costs, a US gas treating operator met with Dow Oil, Gas & Mining to discuss options to reduce operational costs. Based on the operational performance information provided for newly released Ucarsol Shale Specialty Solvent from Dow, reference facilities, solvent technical performance simulations and no requirement for expensive and complicated chemical additives, the operator decided to offer one unit that was about to start up as a demonstration facility. It was one of two similar units supplied with sour gas from the same gas pipeline and located at the same facility.

Amine/CO2 chemistry
The absorption of CO2 from a gas stream uses the solvent’s ability to accept a proton, which provides a chemical driving force to assist solubilisation of the CO2. This propensity for the aqueous CO2 to act as an acid in the subsequent reaction with an amine takes place due to the higher dissociation constant (pKa) of the amine. The larger the difference in pKa between the amine and the CO2, the more complete the acid/base reaction that will take place. As Table 1 shows, MEA has the highest pKa (9.5 at 25°C) and therefore exhibits the highest degree of reaction of gas treating amines when compared to the pKa of aqueous CO2 of 6.0 at 25°C.2 In comparison, DEA has a pKa of 8.88 and MDEA has a pKa of 8.52 at 25°C.

In spite of its higher pKa compared to MDEA, DEA has disadvantages stemming from its propensity to degrade in the presence of CO2 and corrode carbon steel.3 The degradation reactions of DEA are catalysed by, but do not consume, CO2. Work by Polderman and Steele,4 Kennard and Meisen,5,6,7,8 Blanc et al,9 and Kim and Sartori10 determined the DEA degradation reaction mechanism shown in Figure 1.

According to Kim and Sartori, the DEA-CO2 degradation reactions are initiated by the direct reaction of DEA and CO2 forming (HOCH2 CH2)2NCO2H (DEA-carbamate), which condenses to 3-(2-hydroxyethyl) oxazolidone-2 (HEO). The HEO then reacts with another molecule of DEA, releasing a molecule of CO2 and forming N,N,N’-tris (2-hydroxyethyl) ethyldiamine (THEED). Some of the THEED slowly condenses to form N,N’-bis (2-hydroxyethyl)piperazine (BHEP). Although several of the degradation products may contribute to the corrosivity of the solution, it is unknown which is the primary source of corrosion. Bicine, N-N-bis(2-hydroxyethyl)glycine, is another DEA degradation product that forms in the presence of oxygen or glyoxal (a dialdehyde used for H2S scavenging) in the amine.

Kim and Sartori demonstrated that these CO2-DEA degradation reactions are independent of the H2S concentration, are not initiated by thermal degradation, and are roughly proportional to the CO2 partial pressure. Blanc et al show that CO2 degradation products do not cause corrosion in gas environments that contain a sufficient concentration of H2S. It is generally agreed, per guidelines in API 945,11 that solutions with H2S-to-CO2 ratios of roughly 1:19 reduce corrosion rates substantially by forming a protective iron sulphide film.12 In a “CO2-only” natural gas stream, such as the Haynesville Shale region of the US, there is insufficient H2S concentration to form this stable layer of protective iron sulphide.

MDEA was developed to allow operations at higher amine concentrations without CO2 degradation. However, unlike primary and secondary amines (MEA and DEA), MDEA has been shown to be kinetically limited for CO2 removal, as it does not form a carbamate molecule directly. MDEA is dependent on the CO2 hydrolysis reaction to create carbonic acid, which slowly dissociates to bicarbonate and finally reacts with MDEA for CO2 absorption. The carbonic acid-to- bicarbonate reaction for MDEA is very slow compared to the direct reaction of the carbamate in the MEA and DEA reaction steps, resulting in a reduced CO2 reaction with MDEA,13 allowing CO2 to leave the absorber with limited removal (CO2 slip). Therefore, an activator is utilised as part of the MDEA formulation to effectively assist the reaction rate and tune CO2 selectivity, enhancing CO2 removal in the absorber. For a more detailed understanding of amine gas treating chemistry, refer to Fundamentals – Gas Sweetening, LRGCC.13

Solvent trial
In early 2011, the operator decided to compare Ucarsol solvent with its standard 80 wt% MDEA/20 wt% DEA blend diluted to a 50 wt% amine solution (40 wt% MDEA/10 wt% DEA/50 wt% water). The operator decided it would use the collected data to perform an economic evaluation and an operability evaluation. Data collected during the trial are shown in 
Table 2.

Facility information
Haynesville shale gas composition for this area is shown in Table 3.

Unit 1 MDEA/DEA blend
Unit 1 is a 250 gpm facility with a typical gas treating design:
• 75 MMscfd feed gas treating with bypass
• Absorber: 6ft diameter, 20 trays
• Flash drum: 6ft diameter x 12ft TL-TL
• Regenerator: 5ft diameter, 20 trays
• APV plate and frame L/R exchanger
• Direct-fired Bryan reboiler
• 10 500 gallon system volume
• 50 wt% blended amine (80 wt% MDEA/20 wt% DEA)
• Facility is manned during day operations
• Facility is unmanned during night hours
• Facility uses a digital control system (DCS) and paged alerts.