MIT Natural Gas Report Glosses Over Environmental Issues

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.

Produced Water

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. 

Contamination of Drinking Water

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

The Energy/Water Nexus

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.

Natural Gas as a transition fuel for Carbon Mitigation

February 11, 2010 § Leave a comment

Synopsis:

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.

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