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Keep up the pace: Part One

Hydrocarbon Engineering,

The unconventional gas revolution has enabled a transformation of the US energy mix. However, each new gas supply brings challenges for treating, natural gas liquid (NGL) recovery, gas quality, and gas distribution infrastructure. This can be particularly true of shale gas, as the composition can vary significantly from one field to another. Additionally, shale gas resources can exist in remote regions challenged by limited water, infrastructure, and other logistical challenges requiring innovative processing solutions.

Exploration and production (E&P) companies need to partner with solution providers to assure they can monetise their resources in a timely, capital efficient manner. The rapid growth in shale production, especially in geographically diverse locations from traditional production, has led to the need for a rapid expansion of midstream assets. This rapid expansion requires a strong partnership between operators and suppliers to focus a large portion of the US equipment production capacity on designing, installing and operating these new plants in parallel with field developments and gas production estimates.

The parallel processing of production assets and gas processing facilities make it particularly challenging to design new facilities based on gas quality information from a few initial wells. It was also challenging to be flexible while dealing with potential variations as more wells were drilled in the same area. In addition, operators often wanted to design gas processing plants before they had detailed gas compositions from pilot wells. This uncertainty in future gas quality adds to the complexity of plant design and can increase the risks associated with the profitability of overall field development.

Gas processing options

Unconventional gas is often contaminated with CO2, and removal is required when the produced gas contains higher levels than the downstream pipeline will accept, which is typically 2 - 3 %. In addition, when NGL recovery is desirable, cryogenic systems will require CO2 concentrations to be lowered to approximately 0.5 - 1%, depending on the richness of the gas and the level of NGL recovery desired. High levels of CO2 can lead to freeze out at the normal operating temperatures below -125 °F. Y-Grade NGL specifications for cryogenic liquid production normally limits CO2 to 0.35 LV% CO2/C2 or 1000 ppmw. The right technology for acid gas removal depends on the amount of acid gas in the feed and the desired contaminant level in the product. The most common processes for removing CO2 are amine treating, membranes and a molecular sieve.

Conventional and unconventional gas will be water saturated at the temperature pressure where the well is produced. This water vapour must be reduced to avoid corrosion and freezing in downstream processing units and pipeline distribution networks. The most prevalent solutions for pipeline gas is contacting the gas with 99% triethylene glycol (TEG) to dry the gas to below 7 lbs/000 ft3. Cryogenic NGL recovery will require deeper drying in a molecular sieve unit to dry the gas to below 100 ppmv.

NGLs contained in shale gas provide an economic incentive for recovery beyond just treating for pipeline sale. These NGLs are recovered for refinery, petrochemical or other distributed fuel uses where their value exceeds what is recoverable on a strictly British thermal units (Btu) basis than if the NGLs are left in the natural gas stream. Local market conditions can vary significantly with regard to ethane and liquid petroleum gas (LPG) values. In many new shale gasfields, there can be significant local price dislocations due to lack of takeaway capacity for specific products. This requires a flexible cryogenic plant design if the operator wants to react to local market conditions and maximise profitability from shale production.

The modular plant solution

The ‘fast gas’ rapid NGL recovery model has enabled the shale gas revolution by aligning supplier capabilities and operators’ needs for rapid and economical development of new shale production. The rapid increase in dry shale gas production placed downward pricing pressure on natural gas to the point that dry natural gas was ‘borderline’ economical for operators. At this point, attention shifted to ‘wet gas’, or shale gas that contained significant volumes of NGLs that command a market price tied to crude oil that is higher than natural gas prices. The traditional plant delivery model, which takes two or more years to implement, created a costly delay. This formed a barrier to developing these vital resources.

Entrepreneur, Tom Russell, developed a solution to this problem; a model for providing preengineered, factory built modular plants that enabled the delivery and installation of NGL recovery plants at least six months faster than the stick built alternatives. The Russell approach does not require the operator to know exactly how rich his gas stream was upfront. Plant fabrication could occur in parallel to drilling, fracturing and well testing. For operators developing new resources, these new capabilities to parallel the field and plant development processes were critical to bringing on new assets quickly. They also provided a rapid return on the large capital outlays required to meet growing shale development.

Written by Mark Schott and Neil Eckersley, UOP LLC, A Honeywell Company. Edited by Emma McAleavey.

To examine modularised plants in action see also 'Keep up the pace: Part Two'.

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