The Impacts of Trace Components on the Design and Operation of Gas Treating and Processing Plants

Our industry commonly expends a great deal of energy on determining the concentrations and how to remove CO2 and H2S from sour natural gas in the design of a gas treating and processing facility. Their presence normally drives the size and cost of much of the facility. However, troublesome trace contaminants such as  mercury (Hg),  carbonyl sulfide (COS),  mercaptans (RSH),  and aromatics (BTEX) and other high molecular weight hydrocarbons (HHC) can strongly influence the design and successful operation of the various gas and recovered liquids treating systems – and ultimately the capital and operating costs of such facilities. The fate of each of these components within a natural gas treating and processing facility will be discussed, along with a review of the design considerations for the following gas and liquids treating systems given a sample feed gas composition:  Primary Gas Treating Unit (GTU) and Dehydration (DEHY),  Acid Gas Enrichment (AGE) optional  Claus Sulfur Recovery Unit (SRU), including Tail Gas Cleanup Unit (TGCU) and Thermal Oxidizer  Natural Gas Liquids Product Treating THE IMPACTS OF TRACE COMPONENTS ON THE DESIGN AND OPERATION OF GAS TREATING AND PROCESSING PLANTS Jeff Matthews, P.E, AECOM, Denver, CO, USA Jane Nichols, P.E, AECOM, Denver, CO, USA Johnny E. Johnson, P.E, AECOM, Denver, CO, USA Sour, Hydrocarbon-Rich Gas Processing Challenges Many major producing oil and gas reserves throughout the world are characterized by gas that is fortunately rich with hydrocarbons and deserves processing for recovery of sales gas and natural gas liquid (NGL) products. The sales gas may be further processed to make LNG or provide feed to Gas-to-Liquids (GTL) and other gas monetization facilities. Unfortunately, many of these same producing reserves often contain up to a few percent each of H2S and CO2, and trace amounts of other components that complicate the gas conditioning and processing requirements. To commercially develop these reserves has involved some “lessons learned” and technology developments, particularly in handling the troublesome trace components such as mercury (Hg), carbonyl sulfide (COS), mercaptans (RSH), and aromatic hydrocarbons (BTEX). These trace components can strongly influence the design and successful operation of the various gas and recovered liquids treating systems, and ultimately the capital and operating costs of such facilities. For further discussion in this article, a feed gas composition as shown in Table 1 has been assumed, which represents many sour, heavy hydrocarbon-rich gas reserves. Table 1 – Example Composition of Sour, Heavy Hydrocarbon-Rich Gas Reserves Contaminant Quantity H2S 0.5 – 3% volume CO2 3 to 15% volume COS 100 ppm volume RSH 300 ppm volume BTEX 500 ppm volume Mercury 100 μg/Nm Some primary challenges treating such gases are summarized below.  H2S-to-CO2 ratio can be much less than 1:1 complicating and adding cost to the sulfur recovery process.  At the above high concentration level, COS removal in the primary gas treating and dehydration systems is difficult and generally incomplete. The molecular sieve dehydration system may even produce additional COS. The cryogenic NGL recovery does remove most of the COS from the gas, but it then fractionates principally into the propane product and requires a more substantial product treating step.  Mercaptans are also difficult to remove in the primary gas treating system. They too can be substantially removed into the mixed NGL product and in turn require a dedicated product treating step for both the propane and butane products, and likely also the C5+ product(s). Alternatively, RSH can be removed using special molecular sieve material in the Dehydration System, but this adds considerable equipment, complexity, and capital and O&M costs.  BTEX are unfortunately partially absorbed into most gas treating solvents in sufficient amount to contaminate the acid gas feed to the SRU. They can lead to short SRU catalyst life and poor sulfur recovery.  Mercury, though present in very low concentration in natural gas (say 0.02 to 400 μg/Nm), can accumulate inside equipment and concentrate in various internal process, effluent and product streams. This can lead to equipment failure, poison downstream processing catalysts and present health issues. Typical Gas Conditioning and Processing Configuration There are different variations on the gas conditioning and processing requirements depending on the ultimate products market and end use for the sales gas. Reference Figure 1 as a block flow diagram that depicts the basic processing steps and reflects many, but not all, of the options available. System depicted in black boxes are generally required, while systems shown in light gray boxes may not always be required or exist, depending on the level of contaminants in feed, the products desired, the product specifications, and the technology employed. For purposes of this paper it is assumed that in all cases ethane, propane, butane (separate normal and iso-butane products), and C5+ liquid products are produced from the gas processing steps, and that mercury removal is included to protect downstream aluminum equipment. Aspects of the diagram will be discussed individually in the sections below. Numerous previous papers have considered some of the details with the various process systems (see references). Therefore, this paper will not go into such detail to explain the fundamentals of each. Instead, an overview will be provided to give some guidance as to the experience of the industry in dealing with various feed gas contaminants and their fate within a gas conditioning and processing facility. Figure 1 – Gas Conditioning, Processing, and Sulfur Recovery Options