Apr-2012

A new approach to treating shale gases

Shale gas can be challenging to treat, but mass transfer rate-based simulation and appropriate tower internals can make it no harder to treat than other natural gases

Ralph Weiland and Nathan Hatcher
Optimized Gas Treating

Article Summary

A common misconception is that shale gases are sweet. Although some wells produce pipeline-quality gas, many have significant levels of CO2 and H2S. Gas in the Barnett play, for instance, contains several hundreds of ppmv H2S and several percentages of CO2 — far from pipeline quality. Other plays contain up to 10% CO2, with widely varying concentrations of sulphur. Haynesville, New Albany and some Antrim wells show quite high CO2 concentrations, while some plays in Western Canada have low CO2 but enough H2S to require treating.

Typical shale gases with H2S in the hundreds of ppm range and several percentages of CO2 present unique treating challenges. One is the need for extremely high selectivity when H2S-to-CO2 ratios are low; the other is effectively removing the H2S from the offgas coming from the primary amine unit.

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.

Shale, coal seams and tight sandstones are classed as unconventional natural gas reservoirs. According to the US Department of Energy’s National Energy Technology Laboratory,1 the first US commercial gas well produced gas from shale in Fredonia, New York, in 1821, nearly 200 years ago. Natural gas, including gas produced from shallow, low-pressure fractured shales, was produced in the Appalachian and Illinois basins between 1860 and 1920. Thus, gas has been produced from shale in the US for quite a long time. However, it was not until the 1980s, when Mitchell Energy combined lower-cost, large-scale fracturing with horizontal drilling, that the Barnett Shale became economic. Between 2003 and 2005, gas production from the Barnett Shale overtook the level of shallow, shale gas production from the historic Appalachian Ohio and Antrim plays. Between 2005 and 2010, gas production from the Barnett Shale grew to about 5 x 109 cu ft (142 x 106 cu m) per day and, by 2010, it represented about half the total annual US shale gas production of some 4.5 x 1012 cu ft (127 x 109 cu m). Although production from the Barnett Play has levelled off, other fields such as Fayetteville (Arkansas) and Marcellus (Northeastern US) continue to grow rapidly, and the EIA projects that there is well over 860 x 1012 cu ft (24.36 x 1012 cu m) of recoverable gas from US shales using current technology.

Shale gas is by no means limited to the US, although until about 2007 unconventional gas resources were largely overlooked2 elsewhere. However, this resource is truly enormous globally. Estimated reserves worldwide range from 6.6 x 1015 cu ft (187 x 1012 cu m, Geology.com3) to 16 x 1015 cu ft (0.45 x 1015 cu m, Rogner4), with every continent (except Antarctica) having significant reserves. Within Europe, Poland has the largest known reserve (187 x 1012 ft3, 5.3 x 1012 cu m), followed by Norway, Sweden and Denmark, and with smaller amounts in other EU countries. The biggest known reserve is in China (1.3 x 1015 ft3, 31 x 1012 cu m), but there are several countries with reserves only moderately lower than in the US.

There is no question that shale represents an astonishingly large new source of natural gas and natural gas liquids (NGLs). Currently, the focus in the Marcellus Play is on recovery of the NGLs; however, the residual methane is itself an enormous energy source regardless of the play. A common misconception seems to be that for the most part shale gases are sweet and do not need to be treated. Typically, shale gases do not have a high H2S content, although there is considerable variation from play to play, and even from well to well within the same play.

Nevertheless, shale gas often contains tens or hundreds of pppm of H2S, with wide variability in CO2. The Barnett shale of North Texas is an example. In other plays, such as Haynesville and the Eagleville field of the Eagle Ford play, H2S is known to be present. The Antrim play contains up to 30% CO2. In other cases, such as the Antrim and New Albany plays, underlying sour Devonian formations may communicate with and contaminate the shale formations.1 Thus, after removing the NGLs, there are many situations in which the shale gas itself may still need to be treated to pipeline specifications at least for sulphur content and often for CO2. One of the challenges in treating such gases is frequently the very low H2S-to-CO2 ratio and the desire to meet, but not exceed, pipeline specifications on CO2 content. This means that only a small flow of solvent is needed to treat a large volume of gas, and often selectivity for H2S must be maximised. In terms of cost and effectiveness, the solvent of choice for H2S removal and CO2 rejection is N-methyldiethanolamine (MDEA) used in a traditional gas treating plant. The trick, however, is to take the H2S content from a few hundreds of ppm down to a pipeline specification without simultaneously removing too much CO2.

To help meet the challenge, this article explores a relatively new strategy that uses tray designs tailored specifically to shale gas treating, where one wishes to maximise H2S absorption while reducing CO2 removal to the minimum amount possible. The key to understanding the strategy is knowing that trays have radically different mass transfer performance characteristics when operating hydraulically in the froth versus spray regimes. A critical element in grasping and profitably using the strategy is the availability of a true mass and heat transfer simulation capability. A model grounded not in idealisations but in solid engineering science is key because the selectivity issue is intimately tied to looking at the separation taking place from a mass transfer rate perspective and understanding how the hydraulic operating regime affects transfer rates. Ideal stages are incapable of properly dealing with this because, no matter how embellished by efficiencies, ideal-stage residence times and other frills, an ideal or equilibrium stage is completely oblivious to the effect of hydraulics on mass transfer. An ideal stage does not distinguish what is actually in the column.

The vital elements of a mass transfer rate model and how it works have been discussed at length elsewhere.6 However, to appreciate the effect of tray hydraulics, it is important to understand the following fact: H2S absorption is a process controlled by resistance to mass transfer in the gas phase, whereas CO2 absorption is liquid-phase resistance controlled. In practical terms, whatever can be done to lower gas-phase resistance and increase liquid-phase resistance will improve H2S pickup and increase CO2 rejection. Of course, it is also important to select a solvent that is inherently highly selective for H2S. MDEA is the quintessential selective amine because, being tertiary, it does not react at all with CO2.