By Sam Golan, CEO, Primus Green Energy
The low prices for natural gas from the Marcellus shale formation are forcing producers to curb production. The U.S. Energy Information Agency’s (EIA) Drilling Productivity Report claims that natural gas production in the Marcellus shale, the country’s top source for natural gas, has dipped for the first time since the onset of the shale gas revolution. In what the CEO of Cabot Oil & Gas Corp., a leading natural gas producer in the Marcellus, called a “draconian down market,” prices have dropped to less than $2 per million British thermal units, compared to $4.25 in December of 2013.
The continuing low prices, combined with high debt at many companies, is squeezing profits, forcing companies to increase efficiency, merge with or spin assets off to larger companies with the deep pockets that will allow them to weather the downturn or to drastically cut costs, including by restricting production or shutting down wells. The number of rigs operating in the Marcellus has dropped by about half since the peak of 140 in early 2012, according to the EIA.
New pipelines are eventually expected to funnel more production from the Marcellus and other shale plays in the Northeast into higher priced markets in the South, but the dark clouds show no sign of lifting for the immediate future.
There is a silver lining, however. What if the oversupply of natural gas could be transformed into more valuable end products? Just as the medieval alchemists sought to transform base metals such as lead into silver and gold, abundant, low-cost natural gas can be transformed through new technologies into the 21st-century equivalent of precious metals – high quality transportation fuels and chemical commodities that are in large demand such as methanol.
The magical process by which this takes place is called gas-to-liquids, or GTL technology, and – in particular, Primus Green Energy’s STG+TM technology. Using natural gas as a feedstock, STG+TM can produce valuable end products including high-octane gasoline, methanol and diluent, with future plans for the production of diesel as well. The zero-sulphur, zero-benzene gasoline produced through the STG+TM process can be sold into a refinery blending pool or directly into the wholesale market as RBOB or CBOB grade gasoline, while methanol can be sold into regional markets at prices that are typically cheaper than those of methanol imported from the Gulf Coast and abroad.
Methanol (CH3OH) is a versatile chemical that can be used in many ways – from serving as a basic chemical building block for paints, plastics and solvents to innovative applications in energy, transportation fuels (it is a biodiesel blending component) and fuel cells. Methanol can also be used onsite in oil and gas production operations, where it functions as a corrosion or scale inhibitor, a friction reducer, an inhibitor of hydrate formation and a fracturing fluid flowback enhancer. Regional methanol production saves oil and gas producers the trouble and expense of sourcing it from distant providers.
Yet another advantage of the STG+TM technology is easy deployment. The pre-fabricated modular systems can be trucked in and assembled at the wellhead. If needed elsewhere, they can easily be reassembled at another site. They are scalable, flexible and modular enough that they can be integrated with existing gas processing operations or completely self-sufficient, depending on need. They also require minimal labour (a single operator during normal plant operations, with remote operation available) and only yearly maintenance, which translates to ultra-low operations and maintenance costs.
Not All GTL Technologies Are Alike
The STG+TM technology is the best-suited for small-scale use because of its advantages over competing GTL technologies, including higher yield, zero wastewater, lower capital and operating costs, reduced process complexity and higher product quality.
The most well known GTL technology is Fischer-Tropsch, or FT, which was used by the petroleum-starved Third Reich to convert coal into diesel. The problem with FT, however, is that it produces a synthetic crude that must be further refined, which adds considerably to the expense, especially at a small scale. While efforts are underway to develop a FT technology that is economically viable at a small scale, the two-step synthesis and refining process is an inherent limitation. Thus far, FT has only been economically viable at very large plants such as Shell’s $24 billion Pearl plant in Qatar.
The other GTL technology is the methanol-to-gasoline (MTG) technology, which was used by Mobil to produce gasoline at a plant in New Zealand for about 11 years starting in 1985. But this process also has serious drawbacks, including limited catalyst lifetime and high capital cost, that restrict viability at small scales.
Which leaves STG+TM the only GTL technology suited to small-scale operations. As a result of its industry-leading efficiency, STG+TM is more cost effective than either FT or MTG at scales of 10,000 barrels per day (bpd) or less, while also offering the same advantages at a larger scale.
The Innovative STG+ TM Technology
STG+TM economically transforms natural gas into valuable liquid end products at scales as small as 5,000 MMBtu per day of natural gas. Furthermore, STG+TM can use a range of natural gas feedstock types, including pipeline gas, dry or wet wellhead gas, “stranded” ethane, residue gas from fractionation plants or mixed natural gas liquids. The fact that it is economically feasible at small scales makes STG+TM ideal for use in the Marcellus, where small volumes may be stranded for economic reasons — the gas does not command a high enough price to make it worthwhile to develop it — or for geographical reasons — there is no pipeline infrastructure to get it to market.
The ability of STG+TM to use wet gas as a feedstock is particularly advantageous in the Marcellus, where much of the gas is wet. Unlike dry gas, which consists mostly of methane, wet gas also includes natural gas liquids (NGLs) such as propane, butane and ethane that can be extracted and sold separately. While energy companies can sell propane into regional local heating markets and transport butane to refineries via truck or rail, there is a glut of ethane, which can only be stripped out through an expensive deep refrigeration process that is often not justified by current low ethane prices.
As a result, ethane is being “rejected” into the natural gas stream to be burned for heating, cooking and electricity generation, or left in the well when rejection limits are reached. STG+TM can be used at midstream gas processing plants to convert this “stranded” ethane into valuable liquid end products.
The Three-Step STG+ TM Process
The proprietary three-step STG+TM process takes place in a continuous gas-phase closed loop, with no intermediate condensation steps. The process starts with steam methane reforming, in which natural gas or other hydrocarbon gases react with steam at a high temperature and pressure to produce synthesis gas, or syngas (a mixture of H2 and CO). As mentioned, the STG+TM process can accommodate a range of natural gas feedstock types, including wellhead gas with no limits on C2+, gas containing up to 25 percent CO2 and residue gas from processing plants.
In the second step, for the STG+ TM gasoline system, the syngas is converted into gasoline via methanol and dimethyl-ether intermediates through a proprietary series of fixed bed catalytic reactors. By comparison with other GTL technologies, the STG+TM process minimizes complexity, improves product quality and increases yield, producing approximately 4 to 5 gallons of gasoline or 10 gallons of methanol per 1 MMBtu of natural gas.
In the third and final step, the reactor output is condensed and separated. The gasoline or methanol is sent to storage. Any unconverted gas is then recycled, with a portion being used to fuel the reformer. The process water is recycled as steam for the reformer, which means that no wastewater is created.
Commercial Rollout Underway
As a global leader in GTL technologies, Primus Green Energy has developed a range of flexible, advanced STG+TM systems to meet the increased demand for natural gas monetization technologies. Primus expects to deploy its first small-scale STG+TM units in North America this year. It is also in discussions with midstream oil and gas companies around the world that are seeking to monetize natural gas from fields where scale and/or lack of pipeline takeaway capacity are limiting factors, as well as with companies that are seeking to comply with increasingly stringent anti-flaring regulations.
The combination of an abundant supply of low-cost natural gas and a strong demand for valuable liquid fuels and methanol is creating an arbitrage opportunity for natural gas companies in the Marcellus to use STG+TM to reap a greater return than can be realized by selling natural gas on the spot market at today’s low prices. The same is true for stranded ethane: with STG+TM, producers can reclaim profit and create a valuable new ethane industry. Finally,
STG+TM offers the opportunity to unlock natural gas resources that are now considered too small to be economically viable.
The Marcellus shale holds tremendous economic importance because of its proximity to large population centers. But absent a favorable pricing environment, realizing the full potential of this spectacular natural gas resource – the nation’s largest natural gas field — depends on the technological capability to transform natural gas into end products whose value justifies the high level of investment required by unconventional drilling technologies. STG+TM provides such a solution.
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