The November issue of JPT quotes the views of Mary Van Domelen, senior engineering advisor at Performance Technologies, given in her presentation “The Pros and Cons of Vertical Integration” in shale gas-related operations. All her examples of current activity are in the realm of the vertical with the operator and a service company offering fracturing and other drilling or completion services. Her presentation was part of the SPE Liquids-Rich Basins Conference, held in September 2013 in Midland, Texas. Interestingly, both dry and wet gas can benefit immensely from a different form of vertical integration provided certain new technologies take hold. This is a vertical involving the producer and a service that monetizes low-value portions of fluids in unique ways.
Wet Gas
Today, almost all the profit is in the wet gas component. But a subplot is that ethane usually makes up nearly half the volume of natural gas liquids (NGLs). Unlike the bigger molecules, such as propane and butane, ethane has no direct use until cracked to make ethylene. Thirty-three of the 36 crackers in the United States are located on the Gulf Coast, about 1,200 miles from the Marcellus shale in Pennsylvania. Consequently, there is an ethane glut, resulting in low prices. Dow Chemical’s David Bem reported in December that ethane dropped to natural gas price levels in 2013 and had begun to track with it (Fig. 1). This would be a windfall for ethylene producers except that the crackers are located at a distance.
Local cracking seemed to be where matters were headed. However, early in November 2013, Shell announced that it had shelved plans to build a cracker in Pennsylvania. This leaves the ethane stranded absent a pipeline to transport it down to the Gulf of Mexico. A better solution would be small crackers, 50 to 100 times smaller than conventional plants, distributed close to the production. Development is in progress to realize this “GTL Lite” concept. The definition of liquid in this context is broad: It could be any high-value liquid, not just diesel that traditionally comes from larger GTL plants.
Security of supply is much simpler with small units, particularly because a lot of the producers themselves are small. And it is immensely simpler if the producer and cracking process owner are vertically integrated. Even long-term pricing would not be a contractual hurdle. But true vertical integration is hampered by the fact that the producer has no domain understanding of the other area, which is essentially downstream in character.
For unconventional hydrocarbons, including heavy oil, a blurring of the upstream, midstream, and downstream sectors is occurring. Small footprint processing, when commonly available, will only serve to hasten this blurring.
Dry Gas
The greater opportunity for distributed processing lies in dry gas. Much dry gas is shut in because of low prices, particularly in eastern Pennsylvania and the Haynesville area. Even if the dry gas had a ready and profitable market, turning it into a liquid has a great deal more profit potential. Fig. 2 shows an April 2013 snapshot of pricing of the various commodities. While there could be some differences today (spot methanol in January 2014 was much higher, for example), the main message is clear: You could sell natural gas for approximately USD 4/MMBtu or process it and sell it for as high as USD 29/MMBtu. Of interest is the parity in pricing between chemicals, such as ethylene and propylene, and fuels, such as diesel and gasoline, despite the fact that the markets are different. A possible reason for this is that all four are traditionally derived from oil refining products. When natural gas competes to produce some of these, divergences are likely to occur.
Small Footprint Production
Distributed production of liquefied natural gas (LNG) is encouraged by the need for LNG to be transported and stored at –161°C. It is kept cold by allowing controlled release and using the latent heat of evaporation to chill the contents. Even if the resulting gas is captured and reliquefied, it has a cost. So LNG tends to have a “use it or lose it” drawback. This is mitigated if production quantities are tuned to consumption and made close to the point of use. Hence, the push for “mini-LNG.” Several industry leaders, including Linde, Shell, and GE, are reported to be pursuing this angle.
In the case of monetization of natural gas stranded for economic or logistical reasons, the argument is reversed. Now production is close to a raw material source. Midstream capability is being seriously stressed and production of liquids close to the source amounts to a “virtual pipeline.” This applies equally to the handling of ethane, as discussed above. But all of this relies upon the techno-economic viability of small-scale conversion. Today, at least a dozen outfits are seriously developing such a capability. Advances in materials science and process controls dealing with the exothermicity of the reactions are key enablers. All the liquids named in Fig. 2 are being targeted. The technically least complicated is methanol, followed by dimethyl ether.
Where GTL is concerned, very few companies have the expertise to finance and manage giant projects. Equally few engineering companies can be relied upon to execute them. Small footprint production opens up the field to smaller players in both regards. In fact, currently all the developers of “GTL Lite” capability are small startups. Expect the economies to come not from scale, but from mass production of the components (capital cost reduction) and in remote or automatic control of processes (operating cost reduction). The subassemblies will be transported to location to be hooked together, in contrast to the current method of custom fabrication at location. The markup associated with plants in remote locations likely will be mitigated.
Other Business Models
Vertical integration would accelerate distributed production of fuels and chemicals. Long-term supply and pricing agreements would be essentially moot. The financing of small footprint plants is also easier because of diminished scope. Time to first product is less than half that of large plants, an important factor for owners of stranded gas possibly continuing to service debt on shut-in wells.
But vertical integration in this domain has the hurdles mentioned above in the context of wet gas. The same remedies apply to dry gas monetization. Additionally, innovative business models could be in play. For example, a service company could be created that builds the conversion units and operates them on location. If done on a tolling basis, ownership of the fluids, incoming and outgoing, would remain with the gas producer. The service company would be paid an agreed-upon fee per unit converted, preferably proportional to the expected profit margin. This overcomes the hurdle of long-term supply and pricing.
Optimum exploitation of unconventional hydrocarbons will rely almost as much on innovative business models as on technology breakthroughs.
Vikram Rao is executive director of the Research Triangle Energy Consortium (www.rtec-rtp.org), a nonprofit group in energy founded by Duke University, North Carolina State University, RTI International, and the University of North Carolina at Chapel Hill. Its mission is to illuminate national energy priorities and, by extension, those of the world, and to catalyze research to address these priorities. Rao advises Energy Ventures AS, BioLargo, Global Energy Talent, Integro Earth Fuels, and a multinational oil company. He retired as senior vice president and chief technology officer of Halliburton in 2008. He also serves on the North Carolina Mining and Energy Commission and chairs the Water and Waste Management Committee. He holds a bachelor’s degree in engineering from the Indian Institute of Technology Madras in India, and a master’s degree and doctorate in engineering from Stanford University. Rao is the author of more than 50 publications and has been awarded 36 US patents and foreign analogs. His book, Shale Gas: The Promise and the Peril, released in 2012, is an informed look at the heated debate regarding hydraulic fracturing for shale gas.
