As have other operators with lean feed acid gas containing benzene, toluene, and xylene (BTX), Saudi Aramco has dealt for years with chronic Claus catalyst deactivation, low sulfur recovery, and frequent shutdowns to replace catalyst.
After a process selection study identified the most cost effective solution to the problem, the company installed regenerable activated-carbon beds upstream of the sulfur-recovery units (SRUs) to remove aromatic contaminants before they reach the converter beds. Saudi Aramco completed construction of seven BTX-removal units to treat acid feeding downstream sulfur plants in December 2005. Commissioning took place in spring 2006.
Part I of this two-part series discusses the history of the BTX problem and how it was eventually addressed. A process description provides an understanding of the steps in the cyclic regeneration process. The concluding article will discuss design issues and start-up and commissioning experience for the units, their performance, and impact on the downstream Claus catalyst.
Master Gas System
For years Saudi Aramco faced rapid and chronic Claus catalyst deactivation induced by aromatics in feed acid gas at two of its largest gas plants. Until the late 1970s, solution gas produced with crude oil (“associated gas”) was flared. To make use of this resource, the Kingdom directed Saudi Aramco to gather and process this gas into fuel gas and NGL products. The capital-spending program to accomplish all this was called the Master Gas System.
Selecting an amine to treat sour associated gas to a ¼ grain H2S/100 std. cu ft pipeline specification was one of many design goals. It’s easy to forget sometimes how far the gas processing industry has come in the last 30 years in terms of understanding the capabilities and limitations of various amines. At that time, process simulators were in their infancy and the extensive database of thermodynamic and kinetic properties for many amines used today did not exist.
The selection process that led to choosing Diglycolamine (DGA) is described by Huval and van de Venne (OGJ, Aug. 17, 1981, p. 93). Their article mentions a concern that DGA would be prone to coabsorption of heavy hydrocarbons, which could lead to poor sulfur product quality. It also describes how fuel-gas spargers were installed in the bottom of the rich-amine flash drum to mitigate this. Because of its other advantages, though, primarily the ability to treat sour gas at high temperatures, it was selected for the Master Gas System.
Because DGA removes essentially all H2S and CO2 from treated gas, the H2S:CO2 ratio in acid gas is determined by the ratio of these components in the sour gas. At Saudi Aramco’s Shedgum and Uthmaniyah gas plants, this results in an acid-gas composition of 17-30% H2S. For these low levels of H2S, a reaction furnace bypass is necessary even after preheating the air and acid gas in fired preheat furnaces.
About half the acid gas bypasses the furnace. Hydrocarbons co-absorbed by the DGA solution and transferred to the acid gas make their way via the bypass to Claus catalyst in the converters (Fig. 1).
Seven 400-tonne/day SRUs were built as part of the Master Gas System at Shedgum and Uthmaniyah. From the time the gas plants were commissioned, Claus catalyst life was noticeably shorter than expected.
In 1984, a new source of nonassociated gas from the Khuff reservoir was introduced to the plants. Immediately the sulfur trains began to experience much faster deactivation of the catalyst, especially in the first converters. Subsequent measurements on Khuff gas showed it had a significantly higher BTX content than associated gas.
It was determined that 10-15% of the BTX in sour gas is transferred to acid gas by the treating units. Some of these aromatic compounds reach the converters through the reaction furnace bypass. There, they crack on active sites inside the Claus catalyst pores, leaving coke deposits that prevent further reaction at those sites. As more and more active sites are blocked, the catalyst progressively loses activity.
Over the next several years, it was necessary to perform periodic catalyst regenerations to restore performance. This procedure involves operating the converter at elevated temperature with a slight excess of oxygen in process gas to burn off coke deposits.
While this procedure is normally anathema for sulfur-plant operators, it was the only way to restore partial catalytic activity until the next planned shutdown to change catalyst. Even with this aggressive practice, it was still not possible to maintain 95% sulfur recovery over 2 years.
Process selection study
Evolving environmental awareness and regulations mandated that a solution be developed that would allow the SRUs to operate as designed. More stringent emissions limits were on the horizon and before process retrofits could be considered, catalyst deactivation had to be definitively addressed.
In 2000, Saudi Aramco’s engineering staff undertook a comprehensive process selection study to establish unequivocally the direction to be taken to resolve the BTX issue. After years of discussing the matter with engineering companies, technology providers, and consultants, our belief was that there was no one better suited to evaluate the merits of competing alternatives. In addition, by doing all cost estimating under the umbrella of a single study, we could be certain that all economic inputs were on a common basis. Several alternative processes and solutions had been proposed over time to address the problem. Our process selection study evaluated the following possibilities:
- Oxygen enrichment.
- Fuel-gas cofiring.
- Changing the upstream sour-gas treating amine.
- Refrigerating the feed.
- BTX adsorption from acid gas using molecular sieve.
- Acid-gas enrichment.
- Fuel-gas stripping.
- BTX adsorption from acid gas using regenerable activated-carbon beds.
In the end each of these was rejected as being either technically infeasible or more costly than the carbon-bed process.
Following are the reasons for each being discarded:
Oxygen enrichment does not provide a hot enough flame temperature. For the very lean feed in the design basis, even at 100% O2 enrichment with all acid gas going to the reaction furnace, the calculated flame temperature is barely enough to maintain a stable flame, let alone destroy BTX. Fuel gas cofiring would require so much fuel gas that it would have doubled the SRU pressure drop.
Refrigerating the feed to condense out heavy hydrocarbons would be prohibitively costly in a location where all heat rejection is ultimately to the atmosphere with a 120° F. design ambient temperature.
Use of molecular sieve was actually considered after the fact; that is, after the carbon-bed process was chosen. Carbon is a better adsorbent in that it has a higher capacity for BTX than sieve and perhaps more importantly it can be regenerated with low-pressure steam, whereas sieve requires a fired heater to raise the temperature of the regeneration medium.
Fuel-gas stripping the rich amine and acid-gas enrichment were evaluated in detail. For the stripping process, it was proposed to route the fuel gas to the site’s utility boilers. This set an upper bound on the stripping fuel gas-to-amine circulation rate ratio.
For these conditions, the amount of xylene that could be removed was much less than could be achieved with either carbon adsorption or acid-gas enrichment. It had been established that xylene is by far the most destructive of the aromatics in our acid gas.1 As a result, fuel gas stripping was pursued no further.
It was found that removal of BTX from acid gas by regenerable activated carbon was, by a very wide margin, far less costly than the only technically viable alternative process, acid-gas enrichment. The results of our study were presented in 2002.2 In the course of the study we dispelled two misconceptions that were generally held within the gas processing community and by ourselves up until then.
The first has to do with the idea that DGA would co-absorb significantly more heavy hydrocarbons than other commonly used amines because of the di-glycol component of the molecule. While this may be directionally true, the importance of the effect has been overstated. In reality water in a DGA solution is responsible for picking up a large proportion of the aromatics from sour gas.
This seems counter intuitive at first until one realizes that on a molar basis, water makes up about 85% of the circulating solvent. Since solubility is a molecular phenomenon, it stands to reason that pickup of BTX in the absorbers would depend on the ratio of moles of water to amine in contact with the gas being treated.
Of course, pressure plays an important role as well. When Khuff gas treating at high pressure began in the early 1990s at Shedgum, the SRU receiving acid gas generated from high-pressure treating suffered even more rapid catalyst deactivation.
Because Henry’s law applies, treating at high pressure transfers more BTX than at low pressure. This is not to suggest that there are not other factors involved. For example, we have observed that increasing acid-gas loading decreases BTX pickup.
The point remains, however, that the concern regarding DGA relative to other amines misses the essential fact that water, because its molar concentration, contributes significantly to the pickups of aromatics and heavy hydrocarbons in any amine treating process.
The second is related to the attempt to mitigate the concern regarding DGA solution coabsorption of BTX by installing fuel-gas spargers in the rich-amine flash drum (OGJ, Aug. 17, 1981, p. 93). The concept was that this would perform a physical striping of heavier hydrocarbons from the rich solution.
We reported in 2002 that even using a very high fuel-gas striping rate (relative to amine circulation) and a multistage tower would not be sufficient to cut net aromatics transfer by the order of magnitude necessary to eliminate BTX induced deactivation.2 Hoping to achieve this in the single stage provided by the rich amine flash drum, although directionally valid, was unrealistic.
Thus in 2001 Saudi Aramco undertook to construct seven BTX-removal units upstream of the SRUs with reaction furnace bypasses at Shedgum and Uthmaniyah. There were some further internal reviews and admittedly tough discussions as we proceeded. After all, nowhere else in the world had the process ever been implemented on the massive scale being contemplated.
Nonetheless over the next 5 years, the project evolved through initial scoping, preliminary and detailed design, procurement, construction, and commissioning, culminating in startup during first-quarter 2006.
As the project scope was being defined, the design basis was modified somewhat from what was presented in 2002. The changes reflected the latest projections for capacity needs and BTX content of the acid gas. The carbon units were designed for the following feed basis: acid-gas flow 65 MMscfd, feed pressure 13 psig, feed temperature 100° F., and total BTX content slightly more than 500 ppm (vol).
Process
Fig. 2 shows a schematic of the process. Acid gas from the gas-treating units is cooled in a scrubber with chilled circulating water. From there it goes to an adjacent knockout drum where free liquid disengagement takes place (not shown).
The carbon-bed unit (CBU) is fitted with a bypass so that it can be taken offline and the SRU left in service. During normal operation, acid gas from the knockout drum goes to a preheater. Adsorption of aromatics on carbon is favored at low temperature. There is a competing effect, however: At high relative humidity, water tends to adsorb preferentially to BTX.
The shell and U-tube exchanger uses low-pressure steam to heat the acid gas before going to the carbon-bed vessels. The amount of preheat is set so as to bring the relative humidity of the acid gas to around 50%. This corresponds to a ΔT of about 20-25° F. between winter and summer conditions.
The CBUs were designed with a three-bed configuration with two vessels online at any time with one in regeneration or standby. Removal of BTX using activated carbon is similar in many respects to molecular-sieve dehydration: Both are governed by the fundamental principles of adsorption.
For BTX removal, adsorption takes place with acid gas in upward flow. Regeneration is performed with downward flow of steam, which eliminates the possibility of steam condensing and refluxing on the bed if the opposite flow regime were used. Acid gas passing through the two carbon beds online is stripped of aromatic contaminants and flows to the fired acid-gas preheater upstream of the SRU. The CBUs were built for full stream treatment of acid gas, not just the reaction furnace bypass.
Carbon has a finite capacity to hold hydrocarbons. When the bed is online (adsorption mode) the mass-transfer zone (MTZ) moves from the bottom to the top of the bed. Behind (below) the MTZ, the carbon is saturated to capacity with BTX. Ahead of the MTZ the bed is essentially free of adsorbed aromatics.
Eventually the bed becomes fully loaded with hydrocarbons as the MTZ reaches the top of the bed. Before this happens the bed is taken out of service and regenerated with low-pressure steam. When a bed is taken off line it is replaced in service with a previously regenerated bed.
During regeneration, steam is introduced under flow control to the top of the bed through a distributor. The regeneration pressure is maintained by a backpressure controller on a common line connecting the beds. After the pressure-control valve, steam and desorbed aromatics are condensed in an air-cooled fin-fan heat exchanger.
From there a three-phase mixture of regeneration steam condensate, hydrocarbon liquids, and some noncondensables goes to the pressure-control drum. Liquids flow by gravity to a three-phase separator below.
As its name implies, the pressure-control drum serves to maintain a net positive pressure in the three-phase separator despite the vacuum that is naturally formed when regeneration steam is condensed in the fin-fan cooler. This is achieved with a split-range pressure controller that vents noncondensables to the acid-gas flare header as they build up at the start of regeneration and a fuel-gas supply that pressurizes the vessel when condensing steam would otherwise pull a vacuum.
The amount of noncondensables and hydrocarbon liquids coming to the pressure-control drum varies throughout the course of the regeneration step. Initially there is a physical displacement of trapped acid gas in the vessel that is isolated at the end of the adsorption step.
As the bed is heated to the regeneration temperature, hydrocarbons begin to desorb from the bed, reaching a maximum which then trails off like the elution peak of a chromatogram. The three-phase separator has water and hydrocarbon compartments that are pumped out under level control.
Water is sent to a new waste water stripper designed to treat produced regeneration steam condensate to boiler-feed-water quality. BTX from the three-phase separator is injected into crude oil. The amount of aromatics produced is insignificant compared to oil production and has no measurable effect on the latter.
One final point regarding the regeneration step is to explain the function of condensate collection drum that comes into play in the initial stages of this step. Adsorption takes place at temperatures that range 80-140° F. winter to summer. Regeneration back pressure can be controlled between 20 to 50 psig, which corresponds to a temperature range of around 260-300° F. (Note that the superheat in letting down low-pressure steam from about 65 psi to regeneration pressure is immediately dissipated.)
When steam is first introduced to the carbon-bed vessel, it will condense as the bed, vessel, and internals are heated to the regeneration temperature. This condensate is removed from a center nozzle at the bottom of the vessel.
From there it flows by gravity to a small condensate-collection vessel. At a preset level, the condensate is expelled through a filter to remove carbon fines. From there it joins the main regeneration-steam line, downstream of the regeneration backpressure control valve and before the regeneration steam condenser (Fig. 2).
Fig. 3 shows one of the carbon units with all major vessels.
References
- Crevier, P.P., Dowling, N.I., Clark, P.D., and Huang, M., “Quantifying the Effect of Individual Aromatic Contaminants on Claus Catalyst,” 51st Laurance Reid Gas Conditioning Conference, Norman, Okla., Feb. 25-28, 2001.
- Crevier, P.P., Al-Haji, M.N., and Alami, I.A., “Evaluating Solutions to BTX Deactivation of Claus Catalyst in Lean Feed SRUs,” Brimstone Engineering, Vail Sulfur Symposium, Sept. 9-13, 2002.
The authors
Pierre P. Crevier is a member of the upstream process engineering division in Saudi Aramco, Dhahran, providing process consultancy to the company’s gas plants and refineries. Over the last 15 years, he has led the company’s efforts in resolving chronic Claus catalyst deactivation caused by aromatic contaminants. He worked in operations, design, and business development across Canada before joining Saudi Aramco in 1992. Crevier earned both BS (1980) and MS (1987) degrees in chemical engineering from the University of Waterloo, Waterloo, Ont.
Abdulhadi M. Adab is a lead process engineer with Shedgum gas plant department. He has worked at various processing units in the plant for more than 15 years, focusing on sulfur recovery and was involved with Shedgum gas plant major debottlenecking construction and commissioning. He worked on the design, construction and commissioning of the carbon bed units to remove BTX from the acid-gas feed to SRUs. Adab graduated from King Fahd University of Petroleum and Minerals with a BS (1991) in chemical engineering.
Hassan M. BaAqeel joined Saudi Aramco in 2001as a process engineer in the Shedgum gas plant. His 5 years of experience in gas processing have focused on gas sweetening, sulfur recovery, and utility units. He has led the commissioning of the activated carbon adsorption system in the SRUs, installed to resolve the chronic Claus catalyst deactivation problem. BaAqeel earned a BS (2001) in chemical engineering from the University of Alabama.
Ibrahim A. Hummam joined Saudi Aramco in 2001, working as a process engineer in the inlet and sulfur areas. He participated in commissioning of several projects, including the BTX-removal unit at the Uthmaniyah gas plant. Hummam holds a BS (2001) in chemical engineering from King Fahd University of Petroleum and Minerals.
Adel S. Al-Misfer is a project engineer with the southern area projects department in Saudi Aramco, with 9 years’ gas plant area experience, mainly in sulfur recovery with Saudi Aramco. He began work at Uthmaniyah gas plant as a process engineer, project engineer, and operation foreman. Al-Misfer holds a BS (1998) in chemical engineering from King Fahd University of Petroleum and Minerals.
