June 18, 2011 § Leave a comment
A recent story posted by the Worldwatch Institute addresses this issue. The story in of itself has nothing new, in that it discusses the various elements in play but offers no new insights. But it does cause us to mull the issue, because it has come up repeatedly at lectures I have given on natural gas-related matters.
We have blogged on and published the view that shale gas production will keep gas prices low. This is largely due to shale gas wells being on land and shallow by industry standards. These wells can be in production in 30 to 60 days after commencement. This short duration effectively keeps a lid on the price. If the three month strip is seen as going up, new wells can be in production well within three months. This sort of certitude will also discourage speculative investment in the commodity. The floor price will get set by the conversion from coal to gas for electricity. 50 percent of coal plants not expected to meet the latest EPA standards on mercury and NOx are over 40 years old. So these fully depreciated plants will not be refurbished. The only options are new coal, nuclear and natural gas. New coal is disadvantaged on price alone until a natural gas price of $8 per million BTU. Today that price is $4.40. So, with the aforementioned ceiling, coal is not the economic choice. Nuclear has suffered a blow due to the Fukushima Daiichi disaster. So, natural gas will be the fuel of choice. Eventually, the shift to gas will cause the price to rise, but the lid will still be around $8.
Cheap natural gas will also cause a shift from oil to gas whenever possible. This additional demand will keep the price up in the medium term. So, let us assume a price of $8 as the stable price. At this price, electricity will be delivered at a little under 7 cents/kWh. This is the grid parity price that alternatives will have to meet on a direct economic basis.
This benchmark price is lower than the fully loaded price of new nuclear plants, which will be over 10 cents. Currently, wind delivers at 9 to 16 cents, depending on where it is. Offshore wind may be higher yet at this time. Wind also often suffers from the need to add transmission infrastructure. This is especially the case for offshore facilities. There is also the celebrated case of Boone Pickens terminating a major land-based investment due to absence of concrete plans to add transmission lines.
Strictly from a techno-economic standpoint wind still has an upside. Engineered solutions are likely to drop the price from current levels. But it continues to suffer from diurnality, and so needs to be companioned to another source or to storage mechanisms.
Policy Matters: Without a price on carbon, the carbon-free alternatives of wind, nuclear and solar are seriously disadvantaged. Taxes are anathema to the current Congress. Cap and trade has not worked particularly well in Europe, in part due to the uncertainty, which effectively increased the discount rate on investment. Also, any cap and trade conceived by Congress will undoubtedly have numerous exclusions and grandfathering. The province of Alberta in Canada has an interesting model. They tax high carbon footprint heavy oil production over a certain volume. The money is placed in a special fund expressly for the purpose of addressing environmental issues associated with oil and gas. Such directed use of tax proceeds is more palatable. Conceivably, the fund could subsidize renewables for a period of time.
Finally, one could resort to the current method of imposing a renewable portfolio standard. This in effect is a tax on the consuming public because the renewable energy costs more. The solar subsidy in Germany is passed on directly to the consumer as well. But that is largely possible due to the considerable influence of the Green Party. Short of taxing conventional oil and gas, consideration could be given to decreasing the incentives and redirecting those funds.
Conclusion: Cheap natural gas will place every other source of electricity production, including renewables, at a disadvantage for the short to medium term. Reliance on market forces alone will slow the introduction of renewable energy. Policy mechanisms are needed to level the playing field, at least from the standpoint of carbon neutrality. The most equitable methods may be a U.S. analog to the method used in Alberta. By all accounts, that policy is embraced by the public and industry alike.
April 10, 2011 § 1 Comment
High oil/gas price ratios will transform the petroleum derivatives industry
The recent unrest in the Middle East has caused a spike in the price of oil, with immediate impact on gasoline price, while the price of natural gas has remained stable. This underlines the principal difference in these two essential fuels. Oil is a world commodity while gas is regional. They also serve largely different segments of end use. Consequently, the fact that today’s gas is one-fourth the price of oil in terms of energy content has little relevance in the main. However, if the energy industry believes that this differential will hold for a long time, technology enabled switching will occur. In this blog post, we will predict a shale gas enabled future of gas at low to moderate price for a long time. At the same time, we subscribe to the view of an upcoming plateau in oil production, which will drive oil prices higher. These two trends taken together assure a high oil/gas price ratio. This will cause systematic switching where possible. We discuss two essential areas where this is likely: transport fuels and propylene, the latter being the precursor to many important industrial goods, principally polypropylene.
Why natural gas price will stay low to moderate: Shale gas has unique economic characteristics when compared with conventional gas. It is located on land and at relatively shallow depths. The exploitation of the resource does have environmental hurdles, but with the proper combination of technology, transparency and regulatory oversight, these can be traversed.
If allowed to be accessed, shale gas offers the promise of cheap gas for decades. If demand drives up price, this resource can be accessed within 90 days of the decision to do so, provided access and delivery infrastructure are available. This single fact will keep a lid on the price and discourage speculators. To give a frame of reference, conventional offshore gas has a lead time of at least four years. That is the sort of lead time this industry is accustomed to. So a fast response lid on prices is a new phenomenon, driven by this unusual new resource.
Natural gas prices can be expected to stay in a tight band between $4 and $6.50 per million BTU, with excursions to $8. The floor will be driven by demand and the ceiling by the aforementioned fast response to new production. At least two oil companies operating in the Marcellus in Pennsylvania have stated that at $4, they have strong profits. Newer technologies and further experience will continue to drive down production costs. One example is refracturing of existing wells after initial production tails off. A unique feature of this type of reservoir is that a properly designed refrac will deliver new gas approaching initial production numbers. This would be at a fraction of the original cost because the well already exists. This and other technological advances will, in most instances, more than offset the costs of better environmentally driven practices.
Impact of predictably low gas prices: High oil/gas price ratios will drive oil substitution. Here we will discuss just two areas of impact. The obvious high volume one is a replacement of the oil derivatives for transport. Technology exists today to convert natural gas to gasoline, diesel or jet fuel. Predictably low cost natural gas will spur further improvements regarding the economics of these processes. Also, Liquefied Natural Gas (LNG) for long haul transport and Compressed Natural Gas (CNG) for buses, taxis and even cars will be strongly enabled.
An interesting analysis is the impact on petrochemicals such as propylene. One of the derivatives, polypropylene, is ubiquitous in our lives: roofing, carpets, bottles and bendable plastics, to name a few. For years when oil and gas pricing was in greater parity, propylene was a bi-product of ethylene production in oil refineries. It is also produced by tweaking the catalytic cracking process, at the cost of a smaller gasoline fraction. A refinery can change the mix essentially at will, presumably based on the relative profit potential.
But with a worsening oil/gas price ratio, ethylene production increasingly switched to a gas feed stock. Unfortunately, this process produces very little propylene as a bi-product. So, as reported recently in the Economist, in the last two years propylene price has gone up 150%.
A predictably low price for gas will allow for plants dedicated to propylene production from gas. At least three companies, Lurgi, Total and UOP, have the technology at an advanced state. This would make the greatest sense for gas that is otherwise stranded – Prudhoe Bay gas comes to mind. The gas pipeline from Alaska is no longer viable if shale gas production in the US and Canada continues apace. Produced gas continues to be reinjected. The real price for this gas is well below the price in the Lower 48. The economics of conversion to transport fuel or plastics feed stock is compelling.
Sustained high oil/gas price ratios are predicted. This will drive a secular shift from oil to gas.
July 24, 2010 § 4 Comments
Basking in a Bangalore breeze, with a mango tree swaying outside the window, I am reminded of a fairly recent article concerning liquefied natural gas (LNG) imports into India. This story discussed a plan to import LNG from Qatar. There were a couple of points of note that are grist for this particular posting mill. First was the contemplated price of about $13 per mmBTU and the second was the mechanism for arriving at that price.
But first some background relative to Qatari motivation for long term deals such as this. The abundance of shale gas in the US has essentially taken that country out of the running as a Qatari LNG destination. Europe continues to be a valid target, but shale gas will likely be a factor there as well. Russia could well react to domestic shale gas in Poland and elsewhere with price drops. LNG may face lower prices but unlikely to see a US type debacle. Relatively close markets such as India shave 50 cents or more off a US delivered price. So, India could be important.
The truly curious aspect to the story cited is that the landed price is tagged to a Japanese crude oil basket price. For a few years now there has been a disconnect between oil and gas prices based on calorific value. Curiously, the more environmentally challenged one, oil, is currently priced at roughly three times gas price. That is commodity pricing. The disparity is even greater when one factors in refining costs. Transportation is something of a wash, although gas is cheaper to move than crude oil or refined products, at least on land. All of this is singularly premised upon the internal combustion engine being the workhorse of transportation.
Natural gas pricing is regional, largely due to the high cost of ocean transport. If local gas price is low, it is difficult for LNG to compete, which is why the US will be off limits unless demand takes a huge jump. Even then the abundance of the shale gas will likely keep the status quo. Local gas price in India was under $3 per mmBTU until recently. It is now $4.20, close to current prices in the US. That is the controlled price paid to domestic producers of gas. So, to contemplate imported gas at three times the price is the sort of action possible only in settings such as these: government control on commodity pricing. But pegging the price to an oil market basket, a Japanese one no less, is where logic takes flight.
Oil prices in coming years are likely to see sustained increases. Natural gas, on the other hand, will see a moderation in the US due to shale gas. If shale gas resources are found in other countries, one could expect similar pricing behavior. So, pegging any natural gas price, LNG or otherwise, to oil prices will result in a windfall for the producer and one that is not justified by supply and demand arguments.
Consequently, the main problem with the contemplated Qatari deal is not even the current high price. It is the possibility of up to a doubling in ten years. At anything close to that the incentive to use natural gas evaporates. Entire industries will shift offshore. It will be cheaper to make fertilizer, polypropylene and the like abroad and import the finished product. This will have a lasting negative impact on domestic jobs and the balance of trade.
An interesting subplot in the Qatari deal is the statement by them that they supplied cheap gas in India’s hour of need a few years ago. It was landed at $2.53 and has crept up to around $7 more recently based on whatever oil linked formula was used. The implication is that they should be rewarded now with a better deal. A fairly high fixed price would fit that scenario while still being unfair to domestic production. Pegging to oil defies logic and is simply bad business. The story is now four months old. Perhaps sanity prevailed. It nevertheless gave us an opportunity to discuss the underlying fallacies.
July 1, 2010 § 1 Comment
MIT’s most recent report on energy is on the Future of Natural Gas, following similar reports on coal and nuclear energy. It is co-edited by Ernest Moniz and Tony Meggs. The latter recently left BP as CTO. As reported in Forbes recently, the report emphasizes the role of shale gas in enabling natural gas substitution of coal. The authors see this as a transitional strategy for a low carbon future. We agree with that and have expressed similar ideas in the Directors Blog.
However, the report is surprisingly shy about discussing the environmental issues seen as facing shale gas exploitation. While we believe these are indeed tractable, they merit much more discussion than they were given. Accordingly we repair some of that omission here.
The most significant issues center on three matters: fresh water withdrawals, flow back water and collateral issues, and produced water handling and disposal.
Fresh Water Withdrawals and Flow Back Water: Typical wells use between 3 and 5 million gallons per well. Industry practice has been to use fresh water as the base for fracturing fluid. The water that returns to the surface after the fracturing step is known as flow back water. Shale operations are unique in that only about a quarter to a third of the water returns, the rest staying in the formation. Also, the flow back water is usually more saline than the injected water. So, in principle it cannot be re-used.
Handling salinity is the first step to water conservation. The key is ability of the fracture water to tolerate some level of chlorides. Recent research has shown that not only is this possible, but that it can be beneficial. The chlorides actually stabilize the clay constituents of the shale and improve production, although companion chemicals such as friction reducers need to be modified. This has two possible implications to water withdrawals. One is that after some measure of treatment, the flow back water should be usable. But because all of it does not return, withdrawals for make-up water will be necessary. This is where the second implication comes in. Moderately saline water from another source could be used since salinity is tolerable. The most important implication of the foregoing is that flow back water could over time be completely re-used and this then ceases to be an issue with respect to discharge.
So, now let us discuss numbers. In current practice the tolerance for chlorides is likely about 40,000 ppm. Flow back water with higher salinity will need to be desalinated to some degree, or diluted by fresh water. In some parts of the country this may be viable. Another option could well be to use sea water, if that were to be the water of convenience. Sea water tends to contain around 30,000 ppm chlorides. That is already in the range of acceptability with the possible removal of some minor constituents. Finally saline aquifers are a potential source. These are in great abundance, with variable salinities. Saline water wells drilled as companion to the gas wells are very likely in areas where fresh water withdrawals compete with agriculture or other endeavors. In general, if the shale gas industry can utilize water unsuited to agriculture and human consumption, then it will be seen in a completely different light.
Water associated with the gas is produced at some stage of the recovery, usually towards the end of hydrocarbon production. In some cases early production occurs due to infiltration of the fractures into the underlying saline water body often present. Whether from connate water or the water layers below, produced water will be very saline, in part because of the age of the rock. Disposal of this water is a major issue, especially in New York and Pennsylvania and can cost upwards of $10 per barrel, when even possible. Concern regarding illegal discharge is high among the residents.
The treatment of produced water represents a significant business opportunity. Several outfits are developing forward and reverse osmosis schemes for desalination. Others are working on bacteria eradication, heavy metal removal and the like, using methods such as membrane filtration and ion exchange. Some of these are already in service on a limited basis.
Produced water offers the promise of being usable for make-up water after some modest treatment. The salinity may be directly tolerable but the bacteria would need to be removed prior to re-use. This is because many of these cause the production of hydrogen sulfide downhole, which makes the gas less valuable and causes corrosion in the equipment.
There have been anecdotal reports of well water contamination by gas, most recently sensationalized by a documentary. The popular literature ascribes two hypotheses to this phenomenon. One is the migration of fracturing operation cracks from the reservoir up to the water body. The other is gas leakage from the well.
Hydraulic fracture cracks will not propagate the significant distances to the aquifers. Were they inclined to do so, they would heal due to the earth closure stresses. In terms of distance, the closest fresh water aquifers are about 5000 ft. and 3000 ft. away, respectively, for the Barnett and the Marcellus. So this really is not likely.
Gas leakage from the well is preventable if the well is drilled and completed correctly. A fundamental feature of regulation has always been to design for isolation of fresh water in all petroleum exploitation, not just in the shale. Between the produced fluids and the aquifer lie two layers of steel encased in cement. The cementing operation is designed for preventing fluid migration. Tests are run to ensure competence of the cement job and remedies are available for shortcomings. At these shallow depths the operation is extremely straightforward and amenable to regulatory oversight.
See Also: New York Times’ response to the study
June 23, 2010 § Leave a comment
This piece is loosely based upon the RTEC Breakfast Forum on June 15, 2010
Sustainable energy can fall in two buckets. One comprises all the means to lower the carbon footprint of current energy sources. This would include clean coal, using natural gas in place of coal to produce electricity, combined cycle approaches to energy production, and the like. The second bucket is that of renewable energy. The outstanding examples of that are biofuels, wind energy and solar energy.
Each of the foregoing has very different water utilization. One billion persons do not have access to drinking water. Should efficiency of water utilization be a factor in our choice of alternatives, and not just carbon footprint? Going further, should water usage be a litmus test in areas in which the citizenry suffer a high level of privation? This was the subject of the RTEC Breakfast Forum on June 15, 2010.
We tend to use fresh water for everything when something less could do the job. This is likely an artifact of water being relatively cheap. If some of the major users were able to tolerate less than fresh water, water would be freed up for human consumption. An extremely topical area for this thought is shale gas drilling in the US. Each well uses up to 5 million gallons per well as the main component of fracturing fluid. Only about a third of the fluid used returns to the surface. Currently it cannot be re-used because of contaminants, salt in particular. Even if this were to be cleaned up for re-use, the other two thirds would need to be made up from fresh water sources.
Fortunately, industry is taking a hard look at the problem and is moving to modify formulations to be able to tolerate significant salinity. So, not only would the flow-back water be re-usable, but other saline waters of convenience, such as sea water, come into play. In an odd twist, it turns out that salinity is actually good for the operation (it stabilizes the clays). Lemonade from lemons, as it were.
While not particularly applicable to the shale gas play in the eastern United States, a lot of “tight gas” exploitation occurs in the middle of the country, in areas that are severely drought prone. Here, water for energy competes with that for agriculture. The ability to tolerate salinity would be huge. This is because saline aquifers are plentiful. Supporting technology would be required in areas such as benign biocides. Bacteria in these waters are often pernicious, some being sulfate reducing, and thus producing hydrogen sulfide in situ when used for fracturing fluid. But these are all tractable if the major issue of some level of salinity is traversed and if innovations in cost effective water treatment are forthcoming.
The key to water treatment is to have a fit-for-purpose output. Potable water is the most expensive. An intermediate product could be adequate and meet the economic hurdles. Today almost all desalination approaches have fresh water as the output.
Agriculture tolerant of brackish water is a new area without significant currency today. The most obvious example is algae for bio fuel production. Algae, of course, thrive on salt water (and consume carbon dioxide as another plus). A class of plants known as halophytes make themselves saltier than the salt water, thus causing fresh water to flow into them by osmosis. Most such would likely be for biomass for energy production, not food.
Water used in conventional energy production is also highly variable. The paper by Mulder et al describes water efficiency of different energy production methods. Any eye-opener is the significant difference between closed and open loop cycles. An interesting nuance is also the difference between water withdrawal and water use. For example, if a facility such as a nuclear plant, withdraws water from a river, and then returns hotter water, the subsequent evaporation downstream is not counted in some measures. The withdrawal number remains low, even though the net usage was higher.
Using less water is not always productive. Apparently in some areas drip irrigation leads to salt build up around the plant. Also, drip irrigation returns no water to the aquifer. But on balance that must still be more effective than spraying, where evaporative losses may not necessarily be returned as convective rainfall.
Drought tolerant biomass is highly touted these days. Jatropha in India and elsewhere is seen as an important crop for biodiesel production. However, an interesting twist on this is that these plants can tolerate drought, but they grow much faster with more water. A farmer with water access will draw on it. So, what is needed is clever business models and associated policy drivers to encourage water conservation in the face of a compelling economic driver to use more. An interesting problem for a behavioral economist.
February 11, 2010 § Leave a comment
Natural gas is increasingly being proposed as a transitional fuel for carbon mitigation; even by NGO’s that in the past were firmly opposed to all fossil fuels. RTEC has examined the underlying premise and concludes that it is well placed as an organization to play a significant role in informing on the policies that will drive the energy sector in this area. This is in keeping with a key RTEC goal for this year: to be a more visible player in energy.
Why Natural Gas?
The most popular carbon mitigation strategies center on renewable energy sources. The foremost among these are wind, solar and biofuels, with just the last addressing oil replacement. This discussion will focus solely on power production. The majority of power is produced from combustion of coal, especially so in China and India. Despite strong support for coal in Washington, and the technical viability of clean coal, a confluence of events suggests a slow down in coal combustion is likely. These are discussed below.
- California has already taken the lead to require coal plants to reduce emissions to the levels of natural gas plants, which is a fifty percent reduction, as opposed to ninety percent that previously was seen as a target. Federal legislation is likely to emulate this in some manner. This means that gas burning plants require no CO2 sequestration.
- The lower requirement reduces the cost for sequestration at coal plants. For post combustion capture, depending on the technology, the cost is likely to be in the general vicinity of 3 to 3.5 cents per KWh. The current cost is about 6 to 6.5 cents per KWh. So the fully loaded cost will be close to 10 cents.
- The cost of electricity from natural gas can, as a rough rule of thumb, be estimated to be one cent per KWh for every $ per MMBTU. So, at today’s natural gas price of about $4 per MMBTU, the cost is roughly 4.5 cents per KWh. At $10 per MMBTU the cost would be about 9.5 cents per KWh. In the last two decades, gas spot price has been above $12 for only four months, non contiguous. If domestic supply holds up from the new shale gas reserves, few expect the price to go beyond $8, certainly not $10. $10 is the effective breakeven with cleaned up coal, and with much lower capital investment. Consequently, purely on economics and environmental compliance, gas plants make a lot of sense.
- Gas plants are an effective complement to renewable sources, which have diurnal and other variability.
Why Not Natural Gas?
- A shift away from coal to natural gas has to meet the critical hurdles of affordable gas and supply assurance. The UK took this step in the belief that North Sea natural gas would be plentiful. This forecast did not hold up, and now the UK is forced to import, often at high cost. For the US, reliance on foreign sources of Liquefied Natural Gas (LNG) would present issues, not the least being the high carbon footprint of LNG. Alaskan gas, while plentiful, has deliverability issues. So the future of such a shift relies upon the ability to exploit the massive shale gas reserves. As noted above, if available, the price of gas is likely to be competitive with that of cleaned up coal. Also, unlike oil, gas will not have any hidden military costs associated with assurance of foreign supply, since it would be entirely domestic.
- The bulk of the shale gas potential is in New York and Pennsylvania, states that are substantially unused to petroleum production (despite Pennsylvania being essentially the birthplace of oil in the US). Public push back has been substantial, on the grounds of pollution believed to be caused by the fracturing operations essential to the production. Drilling in parts of New York has ceased on account of this. When ExxonMobil purchased XTO for over $30 billion, they considered the threat material enough to make closing of the deal conditional on freedom to operate. Resolving the looming impasse could be critical to any strategy to replace coal with natural gas for electricity production.
Role for RTEC
- There does not appear to be any entity that has knowledge in the areas of the issues mentioned above and yet is non-aligned. This is the opinion of executives at two petroleum related companies and two NGO’s with whom we have spoken. A stated goal for RTEC is to identify compelling energy issues and play a key role in matters pertaining to a select few of these issues. RTEC members have in depth understanding of the technology and economics associated with clean coal and natural gas production.
- In the critical area of economic viability of producing shale gas in an environmentally acceptable manner, RTEC will enter the debate with insights regarding the validity of public angst and the ability of industry to be responsive to the issues with merit. In particular, we have been approached by the Sierra Club to work with them and others to craft legislation in Pennsylvania. The Sierra Club, World Watch and EDF have all realized that their absolute objection to new coal derived electricity is not reasonable without support for an alternative. Consequently, they are backing natural gas as a transitional fuel. However, they want this to happen against the backdrop of environmentally secure production of shale gas. Hence their need for a respected third party to weigh in on the issues. RTEC expects to source one or two other non-aligned experts to augment its expertise, provided the costs are borne by the Sierra Club or another entity. The Sierra Club is clear on the point that RTEC does not support their opposition to clean coal and is merely acting as a resource to resolve shale gas issues.
- If we feel we are making a real difference, we will consider measures to have a cadre of experts on call for consults from NGO’s and government bodies. This may require seed funding, especially if a relational data base is part of the solution. Ultimately, this could be a free standing unit whose span of influence could expand into other areas.
Potential Impact on US Energy
If natural gas fired plants are employed for new capacity, either for demand growth or replacement of ageing coal facilities (Progress Energy just closed thirteen coal fired plants in North Carolina), it provides breathing room for alternatives. In particular, it gives time to resolve the issues surrounding clean coal, whether real or perceived. RTEC continues to hold the view that clean coal is a viable part of the energy mix, especially when one considers the world at large. Specifically, we expect post combustion capture and storage to be strongly in play for existing coal fired plants, especially those with many years depreciation remaining.
Eventually new base load capacity could go to Integrated Gasification Combined Cycle (IGCC), the long term clean coal solution. We would expect also, that in the next ten years or so the nuclear option will be selected for new base load capacity and natural gas will begin to be phased out. Price and availability of gas will determine the rapidity of this decline. This is where the shale gas comes in. If the known reserves can be accessed, there is reason to expect availability to be high. Unlike offshore reservoirs, the time horizon between decision to drill and actual production is relatively short. This is likely an effective antidote to rising demand driving up prices to double digits per million BTU. Much of the new shale gas is profitable at $5 per MMBTU. All of this leads to the hypothesis that natural gas prices will stay in single digits. If they do, gas will remain competitive with clean coal and with lower up front investment, and so a shift away from it may not happen until nuclear power build up is significant.
In conclusion, if shale gas can be recovered in a fashion acceptable to the public, the reserves could be sufficient to support natural gas as a transitional fuel until cleaner alternatives become viable. RTEC is positioned to play a key role, possibly a deterministic role, in the outcome.