Shale represents an astonishingly large, new source of natural
gas and natural gas liquids (NGLs). However, a common
misconception seems to be that, for the most part, shale gases
are sweet and do not need to be treated.
Although not highly sour in the traditional sense of having
high H2S content, and with considerable variation
from play to play and even from well to well within the same
play, shale gas often contains tens or hundreds of parts per
million of H2S, with wide variability in
CO2. Gas in the Barnett shale play of North Texas,
for example, contains several hundred parts per million by
volume (ppmv) of H2S and several percentages of
CO2far from pipeline quality.
In other shales, such as Haynesville and the Eagleville
field of the Eagle Ford play, H2S is known to be
present. In other cases, such as the Antrim and New Albany
plays, underlying sour Devonian formations may communicate with
and contaminate the shale formations.1 Some plays in
Western Canada have low CO2 but enough
H2S to require treating. Thus, after removing the
NGLs, there are many situations in which the shale gas may
still need to be treated to pipeline specifications, at least
for sulfur content.
Difficulties posed by shale gases.
The challenge in treating such gases is the very low
H2S-to-CO2 ratio and the desire to meet,
but not exceed, pipeline specifications on CO2
content. In terms of cost and effectiveness, the solvent of
choice for H2S removal and CO2 slip is
N-methyldiethanolamine (MDEA) used in a traditional
gas treating plant. But how does one go about taking the
H2S content from, for example, 100 ppmv down to 4
ppm without taking out excessive CO2 at the same
time? Another related issue is what to do with the acid gas
from the amine unit, since it will likely be of substandard
quality for a Claus plant.
This article uses specific examples to show, quantitatively,
how various process plant parameters affect selectivity and, in
particular, the ability to treat a variety of shale gases to
pipeline specifications. Solvent selection, strength,
temperature and circulation rate, as well as the type and
quantity of internals used in the contactor, are some of the
process parameters and design variables considered.
Problem-solving with trays.
A new tactic is to use multi-pass trays even when,
hydraulically, a single-pass tray is more than adequate to
handle the flows. The key is to understand that trays operating
in the froth vs. spray regimes have radically different
mass-transfer performance characteristics. A critical element
in the underlying analysis is the availability of a real-mass
and heat-transfer rate-based simulation capability, because the
selectivity issue is intimately tied to the separation taking
place from a mass-transfer rate perspective. Ideal
stages are incapable of dealing with this properly because, no
matter how embellished by efficiencies and residence times, an
ideal or equilibrium stage is completely oblivious to the
effect of hydraulics on mass transfer.
Rather than devoting column space to discussing what a
mass-transfer rate model is and how it works, we will instead
present a set of case studies and simply refer interested
readers to a previous Hydrocarbon Processing
article2 for model details. However, it will be
important in what follows to understand this fact:
H2S absorption is a process controlled by resistance
to mass transfer in the gas phase, whereas CO2
absorption is liquid-phase-resistance controlled. Therefore,
whatever can be done to lower gas-phase resistance and increase
liquid-phase resistance will improve H2S pickup and
increase CO2 slip.
The reaction between CO2 and MDEA is so slow that
reaction kinetics play a very minor role in determining
CO2 absorption rates. Carbon dioxide and hydrogen
sulfide absorption are controlled strictly by the mass-transfer
characteristics of the specific trays or packing under the
hydraulic conditions being used.
TRAYS OPERATING AT LOW LIQUID
During 2007 and 2008, several plants were found to be
producing gases with unbelievably low concentrations of
H2S and astonishingly high CO2 slip
values. These values were far outside the range suggested by
any simulator, whether mass transfer rate-based or ideal-stage.
In each case, the absorber contained trays. More importantly,
the weir liquid load (volumetric flow rate of solvent per unit
length of weir) was always quite small.3 Later,
performance data was found for six more plants also operating
at low weir liquid loads and, as Fig. 1 shows, the data from
all nine plants show remarkable quantitative consistency with,
and support for, the spray-regime explanation.4
1. The correction factor for
operation varies with weir liquid
Froth vs. spray regime.
The experimental data from which the fundamental
mass-transfer coefficient correlations are drawn in a mass
transfer rate-based model all corresponded to trays operating
in the froth regime, in which the biphase on the trays
is a frothy liquid containing a dispersed gas. However, the
trays in these nine low-weir-load instances were all operating
in the spray regime, with some operating with
essentially pure sprays (left side of Fig. 1) and others with
mostly froths but with a modicum of spray (right side).
In froths, the liquid is continuous and the gas is dispersed
as large and small gas bubbles and jets; in sprays, the liquid
is dispersed as droplets (about 1 mm in diameter in aqueous
systems) bouncing across the tray and finding their way into
the downcomer through a continuous gas phase.
Hydraulically, the flows are radically different, and so is
the mass transfer. The spray regime has much higher
liquid-phase resistance (to mass transfer) because, internally,
the liquid drops are almost stagnant. The lack of mixing
produces lower CO2 absorption rates (remember:
CO2 absorption is liquid-phase
controlled)i.e., increased CO2 slip.
On the other hand, gas-side mass transfer is much improved
because of the highly turbulent flow of gas around the
dropshence, better H2S absorption. This
scenario is completely consistent with what was seen in the
performances of all nine plants. Thus, to improve
H2S removal and to slip more CO2, trays
should be operated in the spray regime if possible.
Spray regime challenges.
It is unfortunate that, in the distillation community, tray
operation in the spray regime has a bad rap. However, the poor
reputation is the fault of many tray designers who repeatedly
fail to use a seal pan to ensure that downcomer bottoms are
positively, hydrostatically sealed (vs. dynamically
A good seal prevents gas from blowing up the downcomers
(rather than through the tray deck), causing massive
entrainment of liquid and an undeserved bad reputation. In
fact, in the spray regime, trays having positively sealed
downcomers actually have higher jet flood capacity
than conventionally operated trays. Attempting to seal
downcomers dynamically, at very low liquid rates, is an
invitation to failure.
The gas-treating benefit of the spray regime was the subject
of a 1981 patented tray design.5, 6 However, the
patented design failed to gain popularity, perhaps because of
the limited area of application 30 years ago. Nonetheless, the
spray-regime operation of trays has promising application in
shale gas treating today.
TREATING A GAS FROM THE BARNETT SHALE
The gas plant in question is one of three units in Texas
between Dallas and Houston intended to process gas from fields
in the Barnett shale. As built, this particular plant was
intended to treat 330 million standard cubic feet (MMscfd) of
gas containing 750 ppm H2S and 2.5% CO2
at 960 pounds per square inch absolute (psia) to pipeline
qualityi.e., 4 ppmv H2S and < 2%
The absorber was designed with 12 single-pass valve trays
using an equilibrium-stage simulator and assumed tray
efficiencies. From startup in mid-2009, the plant has
consistently failed to produce on-specification gas at more
than 60% of the nameplate production capacity, even with reboiler and circulation pumps running
at full capacity. The generic MDEA solvent was gradually spiked
with a stripping promoter, allowing it to treat 240 MMscfd, or
73% of capacity. However, the internals were inadequate to move
beyond this limit, and a revamp of the towerperhaps even
a new and taller columnwas required.
Literally hundreds of cases were run using a mass transfer
rate-based amine simulator to determine the right course of
action. Focusing on the absorber, the tray count was varied
from 12 to 26, and solvent rates, amine strength, gas
temperature and solvent temperature were varied. Consideration
was given to tray type and design, the use of structured
packing and even a combination of packing and trays in the same
column to achieve the nameplate rate with on-specification gas.
The results were somewhat surprising and very educational.
Traditional thinking would suggest that, if a plant is not
meeting treating specification, a higher solvent circulation
rate and a more aggressively reboiled regenerator should
improve treating. However, in the present case, the oil flow to
the regenerator reboiler and the circulation rate
through the unit were already at equipment limits. Furthermore,
the solvent was already at 50 wt% MDEA and contained a
stripping promoter, so only a small increase was possible by
raising the MDEA strength by 5 wt% or 10 wt%certainly not
enough to increase performance significantly.
One of the most influential parameters was simulated to be
the raw gas temperature. (Solvent temperature had a much
smaller effect because the gas-to-liquid ratio was high in this
plant.) However, significantly reducing the gas temperature
would have required a large gas heat exchanger, and any
achievable lower temperature was found to be insufficient to
allow treating at the design rate. Thus, the focus shifted to
the tower internals.
Using the right tray design.
The preference was to use generic MDEA rather than a
specialty amine. Fig. 2 shows that, with generic MDEA, adding
trays will indeed lower the H2S leak into the
treated gas, but not nearly enough to meet the H2S
specification. Note that the weir load in this case is 65
gallons per minute per foot (gpm/ft), requiring application of
a small correction for a small amount of spray.
2. Adding trays does not meet the
specification with MDEA at design
However, the problem with the absorber is that, the more trays
there are, the more CO2 is removed. Already twice as
much CO2 as necessary is being removed from the gas.
Solvent capacity is being used to remove the wrong component
(CO2) instead of the noncompliant component
(H2S). No matter how many trays are used in this
absorber, generic MDEA will not allow the gas specification to
be met at design rates.
Using a stripping additive would permit the originally
intended gas rate to be processed to pipeline specifications,
as Fig. 3 shows. However, mass transfer rate-based simulation
shows that at least 20 absorber trays would be needed, and even
if 20 trays could be shoehorned into the existing shell, twice
the necessary amount of CO2 would be removed. It
turns out that a moderate crimp structured packing could be
used effectively in this particular column, achieving less than
1 ppmv H2S and 1.95% CO2 in a 35-ft bed,
but only with an amine solvent containing a stripping promoter.
With generic MDEA, simulation showed that 67 ppmv
H2S was the best that could be achieved, albeit with
3. The use of a stripping promoter
treat but removes too much
Hydraulically speaking, one-pass trays are perfectly adequate
for handling the gas and liquid flows in the absorber. However,
if two-pass trays were installed, the 65-gpm/ft weir load would
drop to about 40 gpm/ft, and a significant benefit to both
H2S removal and CO2 slip would result.
Furthermore, rich-solution loadings are quite modest, so the
solvent has more capacity than is being used. This situation
suggests that, if the solvent rate were reduced to below the
plant limit, even lower weir load and better H2S
removal and CO2 slip would result. Fig. 4 shows
simulated treating results for a 20-tray absorber containing
two-pass trays as a function of solvent rate.
4. Processing 330 MMscfd at reduced
circulation rate using 20 two-pass trays
50 wt% generic MDEA.
This absorber is simulated to handle the full-design gas flow
(330 MMscfd) using only generic MDEA at just 70% of the
nameplate solvent rate. The keys are using mass transfer
rate-based simulation, and knowing how tower internal details
(e.g., tray passes) affect the absorption process. This kind of
technical sophistication allows a simulation model to be
converted into a virtual plant. An absorber that
was completely unable to meet design criteriano matter
how many trays or how much packing it containshas been
transformed into a success.
As a backup plan, the danger of a small margin for error in
meeting the H2S specification can be mitigated by
using a specialty amine to achieve < 0.5 ppmv quite easily.
Shale gas can be very challenging to treat. However, mass
transfer rate-based simulation and appropriately specified and
designed tower internals can make shale gas treating no harder
than treating any other gas. Without both ingredients, though,
treating shale gas can be a guessing game.
TREATING SHALE GAS
FROM BRITISH COLUMBIA
This particular example has 26 ppmv H2S and about
1.1% CO2, so the gas needs to be treated for
H2S while allowing as much CO2 slip as
possible, since CO2 is already below pipeline
specifications. Due to the very small amount of acid gas
needing to be removed, the absorber has only 12 trays, and
plant data indicate that the rich solvent is lightly loaded.
The treated gas is below 4 ppmv (no measurement is available),
and the unit is slipping about 80% of the CO2. The
weir load is about 30 gpm/ft, so the amount of spray is a
significant fraction of the total biphase on the tray.
Simulation with no adjustment for low-weir-load (spray-regime)
operation suggests a CO2 slip of 54% with 1 ppmv of
However, when proper account is taken of the hydraulic
operating region in which the trays are operating (spray
regime), the simulated CO2 slip is 78% vs. 80%
measured. The H2S treat is 1.3 ppmv, well below the
4-ppmv specification. Obviously, the tray hydraulic operating
region has a profound effect on treating. In particular,
selectivity is a very strong function of a trays
hydraulic operating region. The simulations are truly
out-of-the-box predictions because no input was used beyond
tray construction details and basic plant
flows. Nothing was tweaked to force a match to performance
With the wrong modeling tools, shale gas treating units can
be very challenging to simulate and, therefore, challenging to
build with any reasonable assurance of performance. The
difficulty lies in the very low H2S content of shale
gases, which leads to low liquid-to-gas flowrate ratios in
amine contactors. A critical and essential element in reliable
tower design for shale gas treating is a solid mass transfer
rate-based simulator, because tray hydraulics profoundly affect
not just pressure drop; they also impact mass transfer and the
very separation process itself. Ideal stage calculations are
oblivious to what is actually in the column, let alone the mode
Under conditions that are common in shale gas treating,
trays will often have to be operated in the spray regime, where
care must be taken on the part of tray designers and design
engineers to ensure that downcomers remain positively sealed
against massive bypassing of gas. However, even when trays
operate with froths, there is great potential advantage to be
gained from contriving methods to force operation into the
spray region, and the more spray-like the biphase, the greater
the potential advantage in terms of enhanced selectivity.
Contrary to urban legend, entrainment rates and tray
capacity do not have to be negatively affected by the
sprays that accompany low weir liquid loads. However, tray
designers must be attentive to the need for positive downcomer
seals, preferably through the use of recessed seal pans beneath
the downcomers. Multi-pass trays are an under-appreciated but
powerful weapon that can be brought to bear in amine unit
design to meet the unique treating challenges offered by shale
gases and other gases requiring small liquid flows to treat
large volumes. HP
1 Hunter, J. C., The New Albany Shale from
an Antrim Shale Operators Perspective, RPSEA/GTI
Gas Shale Forum, Des Plains, Illinois, June 4, 2009.
2 Weiland, R. H. and N. A. Hatcher, What are
the benefits from mass transfer rate-based simulation?
Hydrocarbon Processing, July 2011.
3 Weiland, R. H., Tray Operating Regimes and
Selectivity, Laurence Reid Gas Conditioning Conference,
Norman, Oklahoma, February 2225, 2009.
4 Weiland, R. H., N. A. Hatcher and J. L. Nava,
Designing Trays for Selective Treating, SOGAT 2010,
Abu Dhabi, UAE, March 2831, 2010.
5 Resetarits, M., Personal communication,
6 Sigmund, P. W. and K. F. Butwell, US Patent
4,278,621, July 14, 1981.
Ralph Weiland founded Optimized Gas
Treating Inc. in 1992 and has been active in Canada,
Australia and the US in basic and applied research in
gas treating since 1965. He developed the first mass
transfer rate-based model for amine columns for Dow
Chemical and is responsible for the development of the
Windows-based ProTreat process simulation package. Dr.
Weiland also spent 10 years in tray research and
development with Koch-Glitsch LP, Dallas, Texas. He
earned BASc and MASc degrees and a PhD degree in
chemical engineering from the University of
Nate Hatcher joined Optimized Gas
Treating Inc. as vice president of Technology Development in
2009. He is responsible for making improvements and
adding functionality to the ProTreat gas treating
process simulator. Mr. Hatcher has spent most of his
16-year career involved with sour-gas treating and
sulfur recovery, first in design and startup and later
in plant troubleshooting, technical support and process
simulation development. He is a member of the Amine
Best Practices Group and serves on the Laurance Reid
Gas Conditioning Conference advisory board. Mr. Hatcher
received a BS degree in chemical engineering from the
University of Kansas and is a registered professional
engineer in the state of Kansas.