September 18, 2014 § 2 Comments
The oil export ban is an anachronism and needs to be lifted. The original energy security beliefs no longer hold water. We are fast approaching the point at which domestic production augmented with that of the near neighbors Canada and Mexico will serve the bulk of our oil needs. Combine this with the fact that an overabundance of natural gas will inexorably displace oil in many sectors, beginning with key chemicals such as ethylene and derivatives.
The most compelling argument until recently was the nature of the oil that we produce. It is light (API gravity greater than 40) and sweet (less than 0.4% sulfur), making it highly desirable to all but the US refineries. This anomalous situation comes about from the fact that most US refineries are outfitted with expensive process equipment to handle heavy crude (API gravity less than 20) often with high sulfur and heavy metals. Heavy crude sells for a discount of 15 – 30% to the benchmark West Texas Intermediate (WTI). So they are loath to pay full WTI price for crude that does not effectively utilize their expensive equipment. The result is that oil from the Bakken has sold in 2014 for a discount to WTI ranging from $5 to $15 per barrel. WTI in turn is selling at a discount to the North Sea benchmark Brent price. In 2014 that spread was between $5 and $12. US refiners love this spread because their raw material is cheaper. They also love the shale oil to sell at a discount to WTI. They are the principal opponents to lifting the crude export ban.
A segment of the public believes that oil exports will lead to higher gasoline prices. Since oil is fungible, with a world price, this argument is not viable. However, one could argue that export ban mediated lower cost oil would allow US refiners to produce gasoline for less and pass on that reduction to the consumer. The fly in that particular ointment is that gasoline exports are permitted by law. So refiners will necessarily sell to the highest bidder. In fact, export of US diesel to Europe is believed to be in part responsible for the shutdown of refineries there.
This last point brings us to the second reason to consider lifting the ban: possible oil diplomacy. Europe currently imports over 3 million barrels per day (bpd) from Russia, in addition to 14.7 billion cubic feet per day (bcfd). Retaliation for sanctions is likely to come in the form of energy supply tightening. US oil exports to Europe will have two positive outcomes. One is just the gesture of coming to their aid and the corollary benefit that this quality oil is well suited to “simple” refineries, especially in Eastern Europe. The other benefit is to the US GDP. This oil will sell for Brent price, which as we noted before is $10 to $27 over what Bakken oil sells for today. Even at just a million bpd, that results in additional revenue to US producers of up to $10 billion per year. Keep in mind also that US shale oil production has been seeing annual increases of a million bpd for the last two years. The figure reproduced below from Platts is striking.
Over the period February 2012 to May 2014 US production increase has single handedly made up for a net drop of 2 million bpd from the rest of the world. While this US production rate is expected to slow in 2014 to closer to 0.75 million bpd, the contribution will continue to be large, and the bulk of this is not suited to US refineries. So the domestic glut of light sweet crude is likely to continue. Exporting oil is good for the economy and a potentially important political gesture at a time when European allies are needed to combat the latest threat in the Middle East.
August 31, 2014 § 2 Comments
A recent story in Forbes tells the tale of the rise, fall and rise of LyondellBasell, a Houston based chemical manufacturer. At first blush the story is a gripping tale of savvy investing, risk taking and two opposite bets by equally shrewd investors. But the true message is really none of that. It is entirely the plus side of the Ethane Dilemma that I discussed in my shale gas book two years ago. It is also a lesson in the possibility that behind every problem lurks an opportunity.
The tale unfolded in 2007 when Basell, a European chemical company bought struggling Lyondell Chemicals. By 2009, in part beset by the recession, the newly named LyondellBasell sought Chapter 11 bankruptcy. Apollo Global Management saw an opportunity and essentially purchased the company for about $2 billion. Meanwhile, billionaire Len Blavatnik, one of the principals in Basell also bought into positions in the restructured company after himself having lost serious money on the bankruptcy. The company took off and Apollo cashed in about $12 billion in 2013. Not a bad profit in five years. Blavatnik, with a similar proportional profit in hand, instead of cashing out, continued to buy and is reported to be sitting on $ 8 billion in largely unrealized profits. The Forbes story focuses on how savvy billionaire investors took different paths at this point.
Ethane Price as Compared to WTI
Figure courtesy of Dow Chemical Company
The Forbes story credits the shale gas revolution with the performance. In a sense that is true but the explanation is more nuanced than that. First is the fact that the bulk of LyondellBasell profits come from ethylene and derivatives. Second is that ethane prices started to drop relative to oil in 2009. By mid-2010 ethane was nearly half the price of oil on the basis of energy content (see figure above). Ethylene is conventionally produced from the oil derivative naphtha. Ethylene from $4 per MM BTU ethane is about $ 600 cheaper to make per tonne, and a tonne of ethylene sells from $1000 to $1500 (the price in 2014) depending on market conditions. This was the primary reason for LyondellBasell profitability coming strongly out of bankruptcy. In the Forbes story there is a quote: “Billionaire hedge fund manager Dan Loeb used more than half of his first-quarter letter to his investors wondering why Dow Chemical Co.–where returns have trailed LyondellBasell significantly over the last three years–wasn’t more like its rival”. In my shale gas book I mention that 33 of 36 US crackers are on the Gulf Coast, with just two in the mid-west and one small one in Kentucky. Those two just happen to belong to LyondellBasell and are very close to ethane supply. In recognition of this, the company quickly added capacity to these two. Result: enormous profits capitalizing on the low raw material prices and LyondellBasell was uniquely positioned with respect to competitors such as Dow. Besides, Dow, while a major ethylene producer, has a much broader portfolio than LyondellBasell.
In 2013, when Apollo cashed out and Blavatnik increased his stake, ethane pricing simply dropped through the floor (see figure above). In fact the spot price of ethane in the mid-west is even less than that shown in the figure. This explains why the company profits continued to climb and the stock stands at 50% over the figure when Blavatnik last purchased stock from Apollo. In the Forbes interview Blavatnik attributes the success of his strategy to luck and hopes the luck will continue. More likely is the possibility that he saw the trend, which started in 2012. The fundamentals underlying the trend, low natural gas price and high prices for propane and butane, will continue to cause wet gas to be produced preferentially. Half of that is ethane, with no value unless converted to a chemical. Consequently, ethane will continue to be a glut until crackers show up. But unlike expansions of LyondellBasell crackers, new ones take many more years, significant financing, and ethane pricing crystal balls extending twenty years. In late 2013 Shell postponed indefinitely a cracker destined for Pennsylvania. Small, distributed, crackers as suggested in previous posts could be a factor in this game. Cheap stranded ethane represents a business opportunity. LyondellBasell merely happened to be in the right place at the right time.
June 26, 2014 § 1 Comment
Fly ash has been in the news since the Dan River, NC contamination incident earlier this year. Much of the attention has been on remedying the current situation: ash in unlined pits, especially proximal to surface water. This is appropriate because future contamination events from existing disposal sites need to be prevented. Current proposals place the timing of resolution out in the fifteen year timeframe.
So, what happens to all the fly ash produced in the interim? It could go to lined pits. In this regard there is similarity with the measures for temporary storage of liquid drilling wastes. Neither has been classified as a hazardous waste by the EPA. But in current draft NC legislation, liquid drilling wastes will be required to be stored in double lined pits with sensors between the layers. The same could do the trick for fly ash in solid or liquid form. The former is vastly preferable. This is because fly ash is light and fluffy and comprises spherical particles. This material will stay suspended and not easily settle to the bottom as sludge for removal. Bottom ash, the other type of ash in a coal combustion unit, is more amenable for pond settling.
Beneficial Use of Ash:
All coal deposits contain a certain proportion of minerals associated with the coal. These are oxides of elements such as Silicon, Potassium, Iron and Calcium. Many of these are in the clay family. When the coal is combusted these oxides remain inert. They end up in the bottom of the retort (bottom ash) or fly out of the top (fly ash). Fly ash constituents have a unique character: they comprise small spheres. As a result the material is light and fluffy. Transportation could result in dusting.
Fly ash falls into two classifications: Class F and Class C. Both classes have oxides of the same elements noted above, but Type C will have substantially more lime (CaO). When blended with water the mixture of oxides will form a substance not unlike cement. To get the same cementing consistency with Type F one needs to add lime when completely replacing portland cement. But in either case the material can very usefully replace cement in part or whole in the preparation of concrete. Concrete is essentially sand and/or gravel bound together with cement. Displacing cement is good for the environment because the manufacture of cement is a major producer of carbon dioxide.
Concrete prepared with fly ash based cement is believed to have improved properties over the conventional material. In particular the cement flows better than portland cement in part because of the spherical character of the particles. Improved performance is also claimed for bricks made with fly ash, lime and gypsum. Over 10% of fly ash in India (20 million tons per year) is converted to this product with the strong backing of the World Bank.
Hurdles to Use
Why, then, does not all fly ash get used in this fashion as opposed to being placed in landfills or ponds? One reason is that the producer may not be located close to the potential user and the cost of transport of this low density material could be high. There is also the risk of dusting. Fly ash can have trace amounts of Arsenic, Vanadium and other heavy metals. The original coal is the source. While representing possible hazards in transport, in the use in concrete they are benign. These elements, more than likely in the form of oxides, can be expected to be trapped in the concrete. They will not be subject to leaching because they are in the concrete body. But even when the concrete is converted to rubble at the end of life, they ought to remain in a form not subject to leaching in large measure because they will not be water soluble.
The second, and more important, reason for limited use of fly ash is the carbon content in some ashes. When the EPA introduced laws to reduce oxides of nitrogen (NOx) in the flue gases, the result was more unburnt carbon in the fly ash. When this material exceeds about 6%, it is not acceptable as a cement substitute. Two distinct types of technologies exist to overcome this problem. One is to physically separate the unburnt carbon using for example froth floatation or electrostatic methods. In most such cases the carbon is recycled for use in the combustion process. The other is to perform a controlled burn of the carbon usually utilizing the heat in some way. One elegant technique is to use microwaves. The energy is absorbed only be the carbon and not the ash constituents. This is similar to the fact that in a microwave oven the food absorbs the energy (gets heated) while the ceramic container stays substantially cool. In fact the industrial process can use the same frequency as household ovens, thus making it inexpensive because those components are mass produced.
What North Carolina Ought to Do
According to published reports very little if any of the fly ash produced in North Carolina is being used in concrete manufacture. One manufacturer testified in a state senate hearing that he was importing fly ash from other states for his use. A cursory examination of the fly ash from Duke Energy plants indicates that the majority is Class F. It will need the addition of lime (unless blended with regular cement), but concrete manufacturers actually prefer Class F because Class C ash can harden up spontaneously when wet, whereas Class F can be controlled. The carbon removal will require expense and the resulting sale of the fly ash may not always prove profitable. Of note is that Wisconsin recycles on average 85% of the ash and the national average is over 40%. So the economics are likely not prohibitive in all instances. Policy support from Raleigh could help. Any fly ash not going to land fill is a good thing.
May 30, 2014 § Leave a comment
A recent report by Gal Luft suggests many measures for Europe to be less dependent on Russia for their natural gas. An intriguing one is that the International Energy Agency (IEA) creates and manages a strategic reserve of a liquid fuel that could be run in gas turbines in times of shortage. In effect it would be a strategic gas reserve in that it would guard against disruptions in the supply of gas. He suggests the liquid be an alcohol such as methanol.
Short term storage of methanol
The concept of methanol as a storage medium for subsequent combustion to generate electricity is not new. But these have all been for short term storage; the methanol to be consumed at the location it was generated. One elegant concept is tied to the “clean coal” technique of power generation known as Integrated Gasification Combined Cycle (IGCC). Here coal is reacted with water to produce synthesis gas or syngas, which is a mixture of carbon monoxide and hydrogen. Typically this is further “shifted” to produce hydrogen and carbon dioxide. The CO2 is destined to be sequestered in some way and the hydrogen is burned for power.
All coal and nuclear plants face the problem that electricity generated at night is of little value and that during the day there can be peak demand periods in excess of 25% over baseline. Yet they cannot be turned on and off. IGCC plants offer the option to convert much of the syngas in the slack period to methanol. This is a simple chemical process. The crude “fuel grade” methanol could be stored and then burned in the specially modified gas turbines at any time. Peak load periods could be served running the stored methanol. The additional cost to convert syngas to methanol would be about USD 6 per million BTU (MMBTU), not much more than would have been to “shift” to hydrogen. However, this portion of the electricity generation would produce CO2 and in that way vitiate an objective of the IGCC. On the other hand this would be a clean burn not that different from natural gas.
Strategic storage of methanol
A strategic reserve of methanol in Europe, as suggested by Luft, would have somewhat different economic considerations than the example given above. In the case of the IGCC the plant would only have to consider the cost of production, not the market price. Also, they were using the higher cost fuel only during peak periods, when the electricity sales prices are high and can sustain a somewhat costlier fuel.
A strategic methanol reserve in Europe would have the following characteristics. The methanol could be raw methanol straight out of the reactor with impurities such as DME. The market price for methanol could be expected to be in the neighborhood of USD 25 per MMBTU. The cost would be lower for an impure product, likely discounting USD 4. This would compare against a nominal natural gas price of around USD 10 per MMBTU. But two other considerations could narrow the gap. Strategic reserves are owned by country governments. These entities could collectively own methanol production facilities that then delivered the fuel on a cost plus basis to each reserve. With USD 4 natural gas, this cost plus number could be expected to be in the vicinity of USD 14. It would be even lower when sourced from Qatar or Iran. The price on release could depend upon the situation. In any case releases would take place only in the event of a severe dip in supply, politically or otherwise driven. In that situation the actual market price would be higher than the nominal USD 10, thus narrowing the gap. Besides, the national energy security benefit and the correlated issues of keeping the traditional suppliers such as Russia in line, have value.
Having the IEA take the lead on a strategic gas reserve has precedent. All 28 member countries of the IEA are required by agreement to hold in reserve oil to the tune of 90 days of consumption in the previous year. Net exporting nations such as Norway are exempt from the requirement. Some countries by treaty support each other, such as the US commitment to support Israel with the US Strategic Petroleum Reserve (SPR). The term “petroleum” is interesting because only oil is being stored and yet the term technically applies to all hydrocarbons ranging from oil to natural gas liquids (NGL’s) to methane. This is because the foregoing is part of a continuum in the conversion of organic matter to hydrocarbons. This is why one finds gas associated with oil (much of it being logistically stranded and hence flared) and liquids associated with gas. In the parlance, though, petroleum has become synonymous with oil. This does not prevent oil import/export statistics from counting NGL’s in the figures!
As we have discussed elsewhere, the concept of the SPR for the US is less compelling now. Domestic production is on a rapid rise and new shale oil wells can be drilled and produced in a matter of weeks. In a sense, the shale reservoirs are our reserve. Consequently, the US could offer arrangements to other countries similar to that with Israel. India is a possibility; their current reserve covers only two weeks of consumption. The US has a diplomatic hole to dig out of with the presumed new Prime Minister, having denied him a visa some time back. This could help.
A strategic reserve to guard against gas supply disruptions in Europe certainly has merit. Methanol appears to be the most viable fluid to keep in the reserve. While the storage mechanism is very straightforward compared to storing oil, the economics need to be worked out considering in particular the externalities.
April 21, 2014 § 4 Comments
In Vikram Rao’s March 31st post entitled “Bear Trap” he examines the potential influence of the U.S. over geopolitics in Eastern Europe if the U.S. were to leverage its Strategic Petroleum Reserve or theoretical LNG exports. If reducing Eastern Europe’s dependence on Russian gas is the objective, then it is worth considering the possibility of developing American-style shale gas and oil production in Poland and Ukraine, particularly as doing so could represent an opportunity to export American equipment, technology and know-how while simultaneously pursuing geopolitical objectives.
Both Poland and Ukraine have significant recoverable shale resources: Poland has 148 trillion cubic feet of shale gas and 1.8 billion barrels of shale oil, while Ukraine has 128 trillion cubic feet of shale gas and 1.2 billion barrels of shale oil (for frame of reference, this gives each country about 11-15% of U.S. shale gas reserves, and about 2-4% of U.S. shale oil reserves). Domestic shale gas would provide Ukraine with 65 years’ worth and Poland with over 250 years’ worth of gas at their current rates of consumption. This is a significant amount given that two-thirds’ of Ukraine’s consumed gas and about half of Poland’s consumed gas is imported from Russia.
At the recent American Association of Petroleum Geologists annual conference, I had the opportunity to discuss shale drilling and fracking (i.e. hydraulic fracturing) in Eastern Europe with members of the Polish Geological Institute. To date, about 60 wells have been drilled in Poland, about 20 of which have been fracked. All of these wells have been exploration wells, meaning that no gas is currently being produced commercially from shale reservoirs.
Though Poland has had some success exploring along the Baltic coast, results to date have mostly been disappointing. Companies attempting to hydraulically fracture shale reservoirs in Poland have not had the same success as they have had in the U.S. The most obvious reason why not is that the geology in Poland is simply more complicated; reservoirs are typically 3-5 km (~2-3 miles) deep rather than the 1-3 km depth of U.S. shale beds such as the Permian basin in west Texas and the Marcellus in Pennsylvania. The Polish basins are not only deeper, but they are also thinner, with pay zones often no more than 10 meters thick, as compared to the 50 meters or more that is often be found in U.S. shale basins.
As with most of Europe but unlike North America, mineral rights in Poland and Ukraine are by default owned by the state rather than the land owner. In Europe when farmland is drilled and gas is produced, instead of farmers getting royalty payments and local municipalities getting increased budgets, regional or federal bureaucrats would manage the royalty income from the energy companies. Such a structure is less conducive to farmers and communities inviting in drilling and production operations as happens in parts of the U.S. Though this appears to be an impediment to scaled shale gas production, there are other incentives that could mitigate the lack of mineral rights. For one, politicians in Poland are primarily interested in job creation (in this way they have a lot in common with our local politicians), and much influence in Eastern Europe is local in nature – a land owner whose land is drilled on will no doubt be able to secure good jobs for his extended family and friends given all of the construction, transportation, and service work required to drill and produce gas from the land. Though the state owns mineral rights, land lease agreements would still be required to drill and travel on private land, and so payments can be arranged through these agreements in lieu of America-style mineral leases. Also, a member of the Polish Geological Institute advised me not to underestimate the seriousness with which Poles take energy security and the collective desire to find a way to produce their own gas in order to reduce reliance on Russia. Here in the U.S. we talk about energy security as an abstract concept, but in Eastern Europe energy security is personal.
What seems to currently be lacking most in Eastern European shale gas exploration drilling is the intuition around how to best drill and complete the wells. So far, replicating American wells has not worked, but then again it took many years to improve U.S. shale drilling and fracking to the point of economic viability, and the process is far from perfected. Optimizing well drilling and completion of shale reservoirs is a process of trial and error that has not had a chance to play out yet in Eastern Europe.
Even if a drilling company cracks the code of Eastern European shale, Russia will still be able to influence whether commercially viable quantities are ever produced. Russia can easily drop gas prices below the economic break-even point for domestic producers and, if need be, is probably patient enough to do so for as long as it takes for the international oil companies to lose interest. It is also conceivable (or in a more cynical perspective, likely) that Russia could make life hard for any energy or oilfield services company involved in the production of European shale gas who also has ongoing business in Russia’s vast oil & gas sector, though this will certainly not deter small players who have no active business in Russia.
Given a concerted effort by Poland or Ukraine, it is only a matter of time, effort, money and thought before the drilling and oilfield services companies figure out the right combination of geological analysis, drilling, and well completion techniques required to economically produce gas from Eastern European shale. But that is a lot of “ifs”, and so there is no guarantee that Poland or Ukraine will ever produce geopolitically meaningful quantities of domestic gas.
Daniel Kauffman, President of TerraCel Energy
March 31, 2014 § 3 Comments
George Soros was recently quoted as suggesting that the US use the Strategic Petroleum Reserve (SPR) as a deterrent to Russian aggression in the Ukraine. No details were given but I thought we could examine the validity of the premise. Certainly it was more promising than the knee jerk suggestion by others that we export LNG to the Ukraine, which too we will debate.
The SPR was created following the Arab Oil Embargo in the early seventies. It is currently near capacity at about 700 million barrels. The intent had been primarily to guard against a disruption of imports. In some ways shale oil has changed much of that. Domestic production has catapulted in the last few years, with the prospect for much more. These are relatively shallow wells drilled quickly compared to offshore wells. A supply disruption would require SPR help for a much shorter period than was envisioned back when the capacity was designed. The country is also using significantly less oil now. Finally, cheap shale gas is going to steadily displace oil.
All of the above argues for the release of the SPR if a national imperative dictates. It could be drawn down significantly without affecting the original mission. One such imperative could be to dampen the expansionist ardor of Russia. Oil represents more than half of all Russian budget revenues and 30% of the GDP. If we were to release 1 million barrels per day for a month, that 30 million barrel deficit would be wiped out by new production (in addition to the current rate) from the Bakken and Eagle Ford in pretty short order. This is, of course, if we want to top up the SPR. In my view that is not necessary. Also, the SPR was filled up at an average cost of a bit under $30 per barrel. A little profit will be made as well by the Treasury. History has shown that a million barrels a day will cause a serious drop in the price of oil. The size of the SPR backing up the threat would also be a factor. The result would be a dramatic impact on the economy of Russia, hopefully just in the short term to change behavior.
This action could not be taken without the active cooperation of the Saudis. Their buffer capacity could make it up in no time. US relationship with the Saudis is at ebb right now due to the Syrian situation. However, in their eyes Russia is a worse actor in Syria than are we. So they may just go along. Also the mere threat may be enough. But it has to be credible. Release for a week may be necessary, much as Russia did in cutting off gas through the Ukraine in 2009 for ten days.
Now for the knee jerk suggestions regarding exporting LNG to the Ukraine to help out. First, could LNG ships navigate the Bosporus Strait? The answer is probably a reluctant yes from Turkey. But LNG goes wherever there is the best price. US sourced LNG would likely go to Asia. Admittedly, however, any US sourced LNG going to Asia now releases Middle East LNG for the Ukraine. The clincher on this whole argument is that any new permits would take at least two years to start export and even that only if the permit was given to an existing LNG import terminal. A brand new terminal would take four to five years. So if curbing Russian aggression in the short term is the intent LNG makes absolutely no sense, even as sabre rattling.
A scant five years ago who would have thought that the US may be in a position to use hydrocarbons as a weapon of political will? Shale oil and gas achieved that single handedly. This is another reason why we have a duty to produce it responsibly.
January 21, 2014 § 6 Comments
The trade secret exclusion in the requirement to disclose all chemicals in fracturing fluids is one of the most contentious issues surrounding shale oil and gas. The public appears concerned that under the veil of trade secrecy industry could use chemicals harmful to human health. Some of the concern is as simple as the need of the public to know what goes in the ground.
Why should there be trade secret exclusion? This question comes up a lot. One reason is that legitimate trade secrets are protectable under the NC Trade Secrets Protection Act embodied in Article 24, Section 66-152 of the North Carolina General Statutes. The other reason concerns the public desire for the industry to create means to use green chemicals. If a company succeeds it ought to be afforded intellectual property protection rights available to all citizens. One means for such rights is patents. The neat feature about patents is that 18 months after filing, all the contents are published whether or not the patent is eventually granted. Rarely would an invention make it to commercialization within that period. So the public will in effect be informed in good time.
Sometimes a company may choose not to patent and to merely hold the innovation as a trade secret. An example is the Coca Cola formula for the syrup. This constitutes intellectual property and it would not be fair to require disclosure which would enable their competitors to copy them. This appears to be the basis for Section 66-152. In these cases companies have stringent procedures to prevent inadvertent public disclosure. Any company claiming the trade secret exclusion ought to be required to submit an affidavit asserting that the claimed item received that same care and that the details had not already been made public. This requirement could be expected to limit the exclusion claims to genuine trade secrets.
So, what are these trade secrets anyway? Without exception the trades secret exclusions are sought by the service company or a supplier to them, not the oil and gas company who will use the products in the well completion process. In many cases the oil company is in the dark regarding the precise formulation. But increasingly the medium to larger oil companies are asserting their purchase power rights to demand fuller disclosure. Apache Corporation, for example, now requires the “elimination of diesel, BTX, endocrine disruptors, and carcinogens” as constituents in fracturing fluid. This is important because service companies know that the customer has choice. This is especially so in shale gas operations, which use “slick water” formulations containing fewer chemicals. Everybody pretty much uses the same chemicals. They may use somewhat different formulations to assert differentiation.
So, the recipe may be the secret. If that is the case it is not a public health issue because the ingredients themselves are fully disclosed. Why is the non-disclosure of the recipe not a public health problem? It is not an issue because the proportions of what went into the ground are not terribly relevant. What goes in is not what comes out. Some constituents are consumed, such as biocides, some are partly reacted and some return in the form introduced. So, more important is to analyze the water that flows back and not worry too much about the proportions of what goes in. The ingredients that are going in inform us on the reaction products that may emerge and we can analyze for those in the return fluid (flowback water).
The way forward: The use of standard chemicals allows for high quality shale gas wells. Companies are becoming increasingly open on this point because of public concern with non-disclosure. Halliburton has posted the precise ingredients it uses. I examined the Marcellus list and each of these has a Chemical Abstracts Service (CAS) number. This number uniquely identifies the chemical and the properties are easily discerned. Virtually all service companies use some variant of these very chemicals. There is no pressing need for substitution of these with others except to make them greener; more on that below. The trade secret exclusion would apply only to substitutes with use advantages. Such a claim will be very hard to substantiate in shale gas wells; the standard chemicals work just fine. However, I recognize that this fast moving sector will be in continuous improvement, especially in recovering a higher fraction of the hydrocarbon in place. This is particularly the case in liquids rich plays and also shale oil wells in the Bakken and elsewhere. But the improvements must not compromise the environment or public health. Full disclosure of the CAS numbers for substitutes ought to be the goal. Oil and gas companies have a lot of choice when it comes to service providers and ought to be discerning on this point.
Greener chemicals are desirable and innovation in this area ought to be granted trade secret status so long as the requirements of the North Carolina General Statutes are met. But since by their very nature these ingredients will be environmentally benign, the secrecy will almost certainly be in the recipe. As discussed above the recipe ought not to be of concern to the public especially when benign ingredients are involved. To the extent the secret is in the green chemical ingredient, it ought to receive trade secret status after some verification.
In conclusion, oil and gas companies ought to strive to employ only those service companies prepared to fully disclose the chemicals used, including the CAS numbers of each. In every case the recipe ought to be accorded trade secret status by the state if claimed, without subjecting it to any process for verification of claim.
January 21, 2014