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.


Afghani Lithium: Much Ado About Perhaps Little

June 15, 2010 § Leave a comment

Afghanis should rejoice that people are discussing Afghani lithium, not opium.  But, based solely on the popularly reported data, initially by the NY Times, there is little reason for celebration.

The original Times story was largely about the mineral finds in general.  An Afghani economy strongly dependent on opium should welcome diversification into minerals.  But the subsequent stories underlined the lithium, including quoting the Pentagon as referring to Afghanistan as the Saudi Arabia of Lithium.  Hyperbole has an honored place in selling copy, and often has a basis in fact.  We went looking for it.  Here is what we found.

The bulk of the underlying data are at least three years old.  The current release by the Pentagon, including General Petraeus’ use of the word “stunning”, is clearly tactical.  The lithium is found as an ore (mixture of oxides) as well as in salt or brine deposits.  We were unable to find the relative distribution of these.  The importance of this is that the cost of extraction from the ore is two to three times more than from brine.  This despite the fact that the ore has more of the stuff, up to 7.5%, compared to a fraction of a percent in brine.  The economic fact renders most ores impractical at this time, even if easily accessible, which this one might not be.  For example, the US imports the vast majority of lithium it uses, despite substantial domestic ore deposits, most of which are in my home state of North Carolina.  The domestic production, such as there is, is from brines.  Lithium from ore is commercially attractive only if there is collateral production of other values, such as potash.  A breakthrough in smelting technology could change all that.  None is known to be in the offing.

Lithium salt deposits are either brine (salty solutions) in lakes, or associated crystalline salt formed from natural evaporation.  These chlorides are relatively easily reacted with soda ash to make lithium carbonate.  This then is the marketed commodity from which all else is made, including metallic lithium.  The reported values of lithium content of Afghani brine is roughly .028%.  This is at the lower end of commercial concentrations.  In other words good, but not great.

Why, then, was lithium singled out from the mineral mix in the story?  It is the key ingredient in batteries for electronic devices today, and for electric vehicle batteries for at least the next twenty years.  All electric vehicles such as the Nissan Leaf will use over 30 Kg of lithium carbonate per vehicle (Hybrids such as the Prius use a tenth of that).  The vast majority of lithium brine deposits are in South America, with nearly half of that in Bolivia.  There is concern about trading oil dependency for lithium dependency.  The questionable stability of the sources is a factor.  This is why a vast new source is seen as news.

Based on the data revealed to date this is much ado about possibly very little.

Deep Water Completions Urgently Need Innovation

January 25, 2010 § Leave a comment

The cost of completions in deep water has progressively increased to the point where it can represent over sixty percent of the total well cost.  We are already to the point where this is impacting the economic prospectivity of reservoirs. While this trend is manifest in conventional deep water, it is exacerbated in deep water combined with deeply buried reservoirs such as the Paleogene, variously referred to as the Lower Tertiary.  The recent exit of Devon from the sector is a signal, even though it was undoubtedly driven by a host of factors.  This in one of the most critical issues facing the industry today, in part because deep water activity has to date been relatively immune to the economic travail faced by the industry.  The rig count in floaters in fact went up in 2009 compared to the prior year, and some are forecasting ultra deep (defined as water depths in excess of 7000 feet) rigs to more than double in three years.  The industry can ill afford a hiccup in this bastion of stable growth.  We will enunciate the issues, describe the underlying factors and discuss the viability of innovations to ameliorate the problem.

Sand Management: For conventional deep water prospects this is the single most critical issue.  Deep water sediments are almost always young in age, typically less than 10 million years old, and therefore relatively poorly compacted.  The majority of the prolific reservoirs are in a class known as turbidites.  The unusual manner in which they were formed caused each layer to have relatively uniform particles.  When particles of like size are packed together it allows for good pore communication.  As a result these reservoirs have high permeability, often in excess of a Darcy.  However, the associated high production rates put a strain on the sand body, inducing the production of sand due to the low sand to sand grain adhesion caused by the youth of the rock.  Dealing with this is the principal component in the high cost of deep water completions.

The uniform approach to handling sand production is to screen it out.   Screens of varying sophistication are used to suit the occasion, but the workhorse method in deep water is a layer of gravel followed by a mesh screen, known as gravel packing.  This has been the standard because by and large it performs.  However, it is rig time intensive and the increasing rates for deep water rigs have contributed to the ever increasing costs of the completion.  Also, the need for remediation at some point is almost certain, and for a period prior to that production rates will be impaired.  Another shortcoming is that the testing methodology for determining the need for sand control is imprecise, and the resulting uncertainty causes virtually all deep water reservoirs to be gravel packed, a conservative approach that adds to the cost for the sector.  We will be discussing this issue in some detail and drawing attention to a technique that improves the certainty of the measurement, thus allowing for an approach that we refer to as informed aggressiveness.   Finally, we note that currently we are responding to the symptom of sand production and ameliorating it through preventing ingress.  We will advocate instead treating the underlying cause of sand production with the expectation that in so doing we would be able to make do with simple screen devices, thus reducing complexity and cost.  Additionally, there would be an expectation of extended production before remediation, and this too, if needed, may be accomplished with a lower cost method.


Figure 1: New test fixture designed to measure cohesion directly using internal pressure to cause the core sample to fail in tension. The fixture allows cohesion to be measured directly with different saturating fluids to observe the saturating fluid’s impact on strength

Testing for Sanding Propensity:

Cohesion of sand grains is the property that determines whether or not one could expect sand production.  This property has proven elusive to estimate.  Current methods utilize compressive stress/strain measurement on core, using a technique known as Mohr Circle Analysis.  This has two shortcomings.  First it assumes elastic behavior of the rock and we know that to be a bad assumption for young deep water rock, which has plastic and visco-plastic tendencies.  Second, in rock mechanics cohesion is defined as the stress required to separate individual sand grains, and this is clearly a tensile property.  Consequently, therefore, we are using a compressive test to assess a tensile property.  All of this causes sufficient uncertainty in the measurement as to force the decision to gravel pack wells when this may not be required.  Finally, cohesion can also change with fluid saturation; therefore any completion design should consider the effects of such events as water break through later in the life of the well.  Conventional sand prediction tools do not allow for this to be included. This is largely because we cannot predict how increased water saturation will affect cohesion in the formation.  All of the foregoing suggests that a new test is needed; one that more precisely assesses sand grain adhesion and one that allows for experimentally determining the effect of fluid saturation.

One such technique is shown in Figure 1.  The core is subjected to internal fluid stresses designed to fail the sample in tension.  This test cell allows the core samples to be exposed to downhole pressure conditions. As pressure is released from the sealed ends of the core sample, the sample is stressed in tension. In this manner, internal pressure generates the tensile force and induces the cohesive failure of the sample.  The fluid properties can be changed to model expected changes in saturation later in life of the well.

Treating the Cause Not the Symptom: As discussed earlier, current methods deal with sand production as inevitable and deal with it by treating the symptom: minimizing entry into the producing bore hole with screening methods.  Over time the screens clog and remediation is required, often an expensive side track of the well.  A more elegant approach would be to treat the sand to improve grain to grain adhesion without compromising permeability.  This has been attempted for decades using the approach of improving the bulk compressive strength to withstand fracture.  This has had limited success in part due to high chemical loading, impairment of retained permeability and cost. Only recently has the thrust changed to primarily address cohesive strength, with much less emphasis on increasing

Figure 2: Scanning Electron Microscope image of formation material that has been strengthened using new placement techniques where the consolidating materials are selectively placed at the contact points leaving pore spaces open for production.

compressive strength.  Part of the reasoning here is that we now believe that the primary cause of sand production is not rock fracture per se, but the detachment of individual grains from each other.  The low chemical loading and the specificity of the resin in primarily gravitating to the grain to grain interface, results in the pore spaces being relatively unaffected, thus minimally impairing fluid flow characteristics.  Figure 2 shows an electron micrograph demonstrating this effect. (Editing note:  the figure legend will describe this more fully)

Importantly, the efficacy of the treatment can simply be tested using the new testing method, and the treatment can be optimized for various anticipated conditions of saturations, draw down and flow rates.  The foregoing offers the promise of fewer wells being treated for sand control, combined with lower cost completions for those that need it.  Formation strengthening, if successful, will allow for far simpler screening complements.  In the limit gravel packing could be eliminated.  Simplification is particularly of interest in horizontal and multi-lateral wells, both of which have advantages relative to formation exposure and reduced draw down for same production rates.  When the Troll Field oil leg was drilled with Level 5 multi-laterals, the lower draw down contributed to the sand production being delayed.  Such wells are very difficult to gravel pack reliably and reproducibly.

Obviously, aggressive means such as those advocated require a high degree of certainty.  The testing method is a key to selecting the best treatment and assessing likely efficacy.  Also, piloting in cheaper wells and in remediation of wells with plugged screens would be prudent first steps.  We describe this approach as Informed Aggressiveness.  Drilling programs have long used this, as for example in the handling of pore pressure/fracture gradient variability.  Real time pore pressure measurement and associated modeling allows the more aggressive operator to drill closer to balance, thus vastly improving rates of penetration and minimizing formation invasion, while largely avoiding kicks and blow outs.

Dealing with Salt: The majority of the important deep water tracts in the world are overlaid by salt diapirs.  These are sheets of salt, which can be from a few hundred to few thousand feet thick.  When these are outcrops on land, they are often mined to produce table salt labeled rock salt.  The sheets in deep water present immense difficulties to seismic exploration due to the relative imperviousness to penetration of sound waves.  Here we concentrate on the effect on drilling and completion.  As these layers extruded out millions of years ago, the rock below was often reduced to rubble, presenting a zone of uncertain character as the drill bit left the salt.  The completion is more directly affected by the nature of the salt itself.  In a sense the salt is still “live”.  A hole drilled in it is subject to the mechanical phenomenon known as creep, a sustained relatively low stress, but one which could buckle the casing.  Accordingly, the casings have to be unusually robust, adding to the cost.

The difficulty of imaging below the salt makes for greater positional uncertainty regarding the location of the highly productive intervals.  This can lead to tortuosity, with attendant completion difficulties.  The foregoing notwithstanding, the techniques to address these are relatively well understood, with technology in active development and deployment.

The Challenge of the Paleogene: Also known as the Lower Tertiary, this represents a new frontier that many believe to be promising.  The primary distinguishing features of these reservoirs from the standpoint of completions are their age and deep burial.  These rocks are in excess of 25 million years old, compared to normal deep water formation in the mid single digits.  The deep burial combined with the age cause these to be very tight.  The required fracturing to enable production is a first for the deep water, where the conventional rock has high permeability, as mentioned earlier.  Hydraulic fracturing at ambient pressures in excess of 15000 psi, and often greater than 20000 psi is a challenge.  Most surface equipment associated is not rated at over 15000 psi, and even that level is hard to come by.  The pumping equipment is itself in short supply at these levels of pressure.  Finally, many of these prospects are in ultra deep water.  Industry is in fact addressing this problem and one solution on offer is an interesting departure from current practice.  Fracture fluids are typically water based, and therefore with specific gravity close to 1.0.  The innovation is to use a higher gravity fluid, thus using the hydrostatic head to advantage as additive to the pump pressure at the surface.  These fluids, with specific gravities up to 1.49, can allow reductions in surface pressure of 3000 psi and higher.  The ability to tolerate lower pressures at the surface has significant advantages in safety and cost.  This would have application to land operations as well, allowing the use of less costly and more easily available equipment (pumps and surface handling) for deeper higher pressure jobs.

Intervention: For most wells intervention is essentially unavoidable.  For deep water the high costs are occasioned by the need to use floaters.  Approaches such as smart wells will delay, but not usually eliminate intervention.  Two approaches are suggested to address this issue.  One would be intervention friendly completions.  These are defined as completions that provide all the needed functionality and yet their design is inherently more amenable to intervention tooling and operations.  One example would be the use of expandable casing to produce a mono-diameter well.  Aside from the advantages of a single bore, the design would allow for a relatively large diameter at the reservoir.  In this context the mono-diameter feature need only commence at the intermediate casing, and not necessarily go all the way to the surface.  Another example would be the use of formation consolidation discussed above.  In the cases when gravel packing is eliminated, one would pick up a hole size, maybe two, and the associated screen would also occupy less annular space.  In general, though, the industry should be encouraged to devise intervention friendly completions.  The second approach addresses the issue of the vessel.  Over the years the industry has taken stabs at purpose designed light vessels which would be cheaper to operate.  The likely reason these did not take hold is the unpredictability of the need for intervention and hence the difficulty of forecasting utilization.  There is need for an innovative business model.  One such might be utilization by subscription: operators buy take or pay time on the vessel and a system is instituted for planning and timely access.  This would be somewhat akin to a time share vacation rental home but hopefully with a higher degree of sophistication such as preferential rights to access.

Where Am I?

You are currently browsing entries tagged with salt at Research Triangle Energy Consortium.

%d bloggers like this: