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Apr-2009

Selecting gas treating technologies

Advances in gas treatment technologies over the past ten to 20 years have widened the range of economically recoverable gas sources

W G “Trey” Brown
Newpoint Gas

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Article Summary

As demand for natural gas continues to increase, new or previously ignored areas of gas supplies are being revisited. Many of these “new” gas supplies have been ignored in the past due to poor gas quality and/or prohibitive costs associated with treating the gas to make it saleable. However, as gas prices have continued to rise and new gas treating technologies have 
been developed, the prospect of treating and selling these gas volumes has become viable.

These new gas sources include coal bed seam gas, landfill gas and bio-digester gas, to name a few. Each of these gas streams can contain up to 50% carbon dioxide (CO2), up to 6% oxygen (O2), hydrogen sulphide (H2S) and nitrogen, all of which need to be removed to meet pipeline specifications. Many of these gas streams also come into the plants at a relatively low pressure, requiring inlet compression.

Existing gas sources that had been shut in or reduced in production 
because of poor quality include vacuum gathering systems and gas wells with high contaminant levels.

Despite the improving economics, the producer still wants/needs to treat their gas stream in the most efficient and cost-effective manner possible. Unfortunately, time constraints often lead the producer to choose what they think is the best option without considering all of the available technologies or doing a detailed evaluation of these alternatives. This article will endeavour to supply several rules of thumb that can be applied when choosing gas treating options and illustrate, through actual examples, how you can make the best decision for your gas processing needs. It will concentrate on gas treating using amine, membranes, H2S scavengers and O2 removal, and their application to the removal of CO2, H2S and O2 from raw gas streams.

Assumptions
The following assumptions are made for this article and may vary to some extent in actual practice. However, they should be representative of what is actually seen in the field:
—   Amine will be regenerated using 
1.0 lb steam generation per gallon of amine circulated (950 Btu/lb). Thus, a 100 gpm amine plant will utilise approximately 5 700 000 Btu/hr of heat input. Assuming 80% heater efficiency, fuel gas for this system will be about 
171 Mscfd (0.12 Mscf/100 gal)
—   30 wt% DEA will remove 4 scf of acid gas/gal, while a 50 wt% amine solution will remove 5 scf acid gas/gal without exceeding a rich amine loading of 0.45 mol/mol
—   Depending on operating pressure, an amine plant will have an electrical power usage of 2.0–2.5 bhp per gallon of amine circulated (ie, a 100 gpm plant will have an operating electrical load of 200–250 bhp)
—   Membranes will only be considered for CO2 removal, although advances are being made to also use this technology for nitrogen (N2) removal
—   Membranes should have a minimum inlet operating pressure of at least 400 psig to operate efficiently and cost effectively, although systems have been operated as low as 125 psig
—   When using two-stage membrane units, the first-stage permeate stream will be recompressed to the first-stage inlet pressure, plus 15 psi, before entering the second stage of membranes
—   A membrane plant will use no more than 5 kW/MMscf, not including compression/recompression horsepower
—   PSA units will only be considered for N2 removal, although recent advances indicate these may also be used in CO2 removal applications
—   H2S scavenger vessels are generally sized to maintain a superficial gas velocity of less than 9 ft per minute
—   One pound of solid-bed H2S scavenger chemical, such as SulfaTreat or Iron Sponge, will recover 0.25 lb of sulphur. The chemical has a density of approximately 93 lb/ft3
—   Unless otherwise noted, all the cases that follow assume a base gas composition of 84% methane, 9% ethane, 3% propane and 4% butane and heavier hydrocarbons, each adjusted proportionately to account for CO2, H2S and N2 in the gas stream being treated
—   Pipeline gas specifications are 2% CO2 (max), 3% total inerts (max), 4 ppmv H2S (max), 20 ppmv O2 (max) and 7 lb H2O/MMscf (max)
—   Reciprocating compressors, operating at 80% efficiency and requiring a heat input of 7200 Btu/hp-hr, are assumed to be used for all compression operations.

How do you decide which gas treating technology best meets your needs? To answer this question, you first need to define what is required and what constraints are in place. This will include knowing what contaminants are present and need to be removed, the inlet and discharge operating parameters and specifications (such as pressure, temperature, flow rate, gas composition and allowable contaminant concentration in the sales gas) and site location and conditions (for instance, power availability, ambient conditions and regulatory restrictions).

Once you have this information, the vetting process can begin and a preliminary evaluation can be performed. Always begin at the front of the process and work through the system, taking care to understand the effect of each contaminant on the immediate process at hand, as well as subsequent downstream processes. The evaluation process should also include a comparison of not only capital costs, but also operating and maintenance costs, material purchase and disposal costs, fuel usage costs and product losses to vents or flares.

It is imperative to understand the capabilities and limitations of the various technologies under consideration and how the different processes may complement or conflict with one another. For example, O2 in the gas stream will have a detrimental effect on amine, but has no impact at all on membranes. Thus, if amine is the technology of choice, an O2 removal system, such as Newpoint’s X-O2 catalytic removal system, should be considered for installation upstream of the plant, whereas this step may not be required if membranes are used, depending on inlet O2 concentrations and pipeline specifications. However, unlike amine, membranes are unable to attain the outlet H2S levels required by most pipeline specifications. In those cases where H2S is present and membranes are to be used, an H2S scavenger may be installed on the inlet or outlet stream, or you might follow up with an amine unit, depending on the H2S concentration. This might also be a viable configuration when trying to minimise overall energy consumption and product losses in high contaminant concentration gas streams.


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