The unconventional gas revolution
Natural gas has proven to be a clean burning, flexible fuel which has gained global acceptance as a preferred choice in the energy fuel mix.
Mark Schott and Neil Eckersley,
UOP LLC, A Honeywell Company
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Supply of natural gas is expected to grow for the next 20 years given the global economic, environmental and geopolitical benefits as gas becomes a more predominant part of the energy mix. Forecasts predict that gas will increase to 25 percent (from 22 percent) of the total energy mix, becoming the only fossil fuel that is increasing on a percentage of total mix perspective. This 3 percent increase in mix equates to a 50 percent increase in absolute consumption volume. To support this demand growth, conventional and unconventional resources must be exploited. Although there will be challenges, the opportunities are great.
The unconventional gas revolution has enabled a transformation of the U.S.’s energy mix. Interest in shale gas has spread to other parts of the world; 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. As in the U.S. shale gas revolution, 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. Project success often hinges on executing gas projects quickly at reduced cost compared to traditional methods, as well as ensuring the projects can maximise the recovery of high value NGL products at low production costs and downtime.
Shale gas in the U.S. has rapidly increased as a source of natural gas. Led by new applications of hydraulic fracturing technology and horizontal drilling, shale gas new source development has offset declines in production from conventional gas reservoirs and has led to major increases in reserves of U.S. natural gas. Largely due to shale gas discoveries, U.S. Dry Natural Gas Proved Reserves have more than doubled from 164 kBCF in 1998 to 334 kBCF in 2011, with more than 70 percent of this increase due to additions after 2006. The economic success of shale gas in the U.S. has led to development of shale gas in Canada, and more recently, has spurred interest in shale gas possibilities in China, Europe, Asia, and Australia. U.S. shale gas continues to change the energy mix within the country and has a substantial impact on U.S. energy self-sufficiency.
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 required a strong partnership between operators and suppliers to focus a large portion of the U.S. 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 made 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 often is contaminated with carbon dioxide (CO2), and removal is required when the produced gas contains higher levels than the downstream pipeline will accept, which is typically 2 to 3 percent. In addition, when NGL recovery is desirable, cryogenic systems will require CO2 concentrations to be lowered to about 0.5 to 1 percent -- 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 -125º F. Y-Grade NGL specifications for cryogenic liquid production normally limits CO2 to 0.35 LV percent CO2/C2 or 1,000 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 vapor 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 percent TEG to dry the gas to below 7 lb/MMcf. 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 BTU basis than if the NGLs are left in the natural gas stream. Local market conditions can vary significantly with regard to ethane and LPG values. In many new shale gas fields, there can be significant local price dislocations due to lack of take-away capacity for specific products. This requires a flexible cryogenic plant design if the operator wants to react to local market conditions and maximise his 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 develop these vital resources.
Just as George Mitchell developed hydraulic fracturing, an entrepreneur emerged with a solution. This entrepreneur was Tom Russell. He developed a model of providing pre-engineered, factory-built modular plants that enabled the delivery and installation of NGL recovery plants at least six months faster than the stick-built alternatives. In addition, the Russell approach did 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.
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