Author Archives: jppierre2013

A decreasing trend of water usage in the Eagle Ford Shale Play

Producing hydrocarbons from tight formation source rocks, through the advent of improved technologies in hydraulic fracturing, has become one of the most important changes in the North American petroleum industry in decades.  In the last decade, the practice has evolved from a novelty concept to a common method of extraction.  Between 2009 and 2011, permits acquired for the Eagle Ford Play (EF) went from 50 to 600 (Driskill et al., 2012).  Tapping the shale resources in the EF is advancing at an astonishing pace; today the permitted well count stands at 5,458 wells in the EF (Texas Railroad Commission, accessed April 13, 2013).  A multitude of recent studies has found that the hydraulic fracturing process itself has had very little impact on environmental quality and most incidences of contamination occurred on the surface (Duncan, 2012).

Under Texas state water code, groundwater withdrawal for oil and gas exploration, fracking included, is exempt from the regulatory authority of the groundwater conservation districts (Rahm, 2011).  Interdependency exists between energy and water production.  Shale gas production currently accounts for less than 1% of statewide water withdrawals in Texas; however, impacts on a local level vary with competing demands and water availability.  Between the years 2006 and 2010 shale gas production increased by an annual average rate of 50%.  To date, most studies have focused attention on water quality effects from shale gas activity.  Published studies on the environmental impacts of hydraulic fracturing and the quantity of water used are few.  In his June 10th, 2011 presentation to a Laredo, Texas town hall meeting, Robert Mace (2011) from the Texas Water Development Board demonstrated how the Groundwater Availability Model (GAM) simulates groundwater levels in the Carrizo-Wilcox Aquifer well below desired future conditions which limit groundwater level decline to 23 feet (Mace 2011).

Mace GAM 2011

 

Source: (Mace presentation, 2011)

 

Although water for oil and gas production is less than 1% in Texas, Mace estimates the water for oil and gas production will be responsible for less than 10% of all water consumption in the EF region.  There is currently some focus on using brackish groundwater for fracking; however, the commonly used polyacrylamide friction reducers do not perform as well in slightly saline water (Nicot and Scanlon, 2012).   In September of 2012, Nicot and al. (2012) updated their projected water use analysis based on recent shifts in hydraulic fracturing technologies.  Water use had increased in the EF, however, the increased use was due to an additional 1400 wells coming on line in 2011.  The operators in the EF have managed to halve their water consumption per well in approximately four years.  This is due to a transition into the practice of using cross-linking gels to deliver the proppant.  Mauer (2011) reports that the massive fracs required in the EF range in cost from $3 to $5 million each.  According to Mauer (2011), current technologies typically require 4 million gallons of water, five million pounds of proppants and 40,000 horsepower worth of high pressure pumping capability.  Mauer estimates potential savings for well operators of 1$ to 1.5$ million per well with the accelerated developments in cross-linking gels as the proppant carrier in the Eagle Ford Play.  The use of gels has proven to facilitate improvements to hydrocarbon recovery while eliminating complications caused by the use of more water intensive fracturing while also not requiring such big expensive pumps.  The use of gels has proven to also be more compatible with flowback water reuse and the use of brackish water (Mauer, 2012; Nicot et. al. 2012).  Advancement in fracing techniques has allowed Nicot et al. (2012) to reduce projections of anticipated water use of 13 million gallons per well to approximately 5 million gallons per well.  However, the EF Play has been projected to have the most wells, at approximately 100,000 drilled with a high lateral density, compared to other shale plays in Texas (Nicot and Scanlon, 2012).

 Eagle Ford Shale Water Intensity:

EF water intensity nicot et al 2012

 Source: (Nicot et. al., 2012)

Eagle Ford Shale county-level average lateral spacing.

EF lateral intensity nicot et al 2012

Source: (Nicot et. al., 2012)

 

Shale gas production may be limited by water availability in semi-arid regions (Arthur et.  al. 2009). Surface water is scarce in the EF play.  To date, most of the fresh water used to produce the EF has been drawn from the Carrizo-Wilcox aquifer, except for small usages of water drawn from the Rio Grande at the border of Mexico.  Nicot and Scanlon (2012) estimate the net water use for EF production to reach 1870 Mm3 (1515 kAF) with peak consumption in the year 2024 at 58Mm3(48 kAF).  However, these projections are likely to change in light of Nicot et al. (2012) findings which show a decreasing water intensity trend for the EF Play.  Nicot et al. (2012) estimate the net water usage in the EF for 2011 to be 24kAF.    As shale plays develop it is likely that unique fracing blends will evolve for specialized regions within each play (Mauer, 2012; Nicot et al, 2012).

In South Texas, many large springs have disappeared and a transition from gaining to losing streams is already occurring due to extensive over pumping by the Winter Garden region for irrigation.  Water level declines greater than 60m over a 6500km2 region have been observed (Nicot and Scanlon, 2012).  It is unknown whether the large Carrizo-Wilcox aquifer with extensive water reserves can recover from transient stress quickly enough to also accommodate additional demand from population increases.  However, in a recent personal communication with Dr. Charles Kreitler who works for both the University of Texas at Austin and LBG Guyton Associates,  he stated “This is a problem that developed in the outcrop area of the Carrizo in the first half of the 20th century.  Pumpage has been down significantly in the 80’s and 90’s in the confined section of the Carrizo (SE of Carrizo Springs) and the water levels have responded” (Kreitler, 2013).   Nicot and Scanlon (2012) stress the need for financial resources to be assigned to better understand the sustainability and rebound potential of the Carrizo-Wilcox Aquifer.  Mean annual precipitation is 740mm/yr in the EF play.  The area goes through frequent periods of wet/drought cycles and is likely to be more pronounced with climate change.  Brownlow (2010) estimates the impact to the Carrizo-Wilcox Aquifer to be very minimal over the life of the EF play.  He states that currently 275,000 acre feet are withdrawn annually from the Carrizo-Wilcox and that 300,000 acre feet would be the total withdrawal for EF production over a 10-15 year life of the play.  Brownlow (2010) also calculates an acre foot value of Carrizo-Wilcox water of $520,000 by landowners receiving oil and gas royalties versus $250 acre foot value to those growing crops with this water (Brownlow, 2010).

 

References:

 

Arthur, J.D., D. Bohm, and D. Cornue. 2009. “Envrironmental Considerations of Modern Shale Gas Development.” Society of Petroleum Engineers SPE 122931: 10. http://www.spe.org/atce/2009/pages/schedule/documents/spe1229311.pdf.

 

Brownlow, Darrel T. 2010. “Eagle  Ford Shale Play and the Carrizo Aquifer.” Fountainhead 4th quarter 2010: 4. http://www.tgwa.org/downloads/newsletter/Fountainhead-Q4-2012.pdf.

 

Duncan, Ian. 2012. “Fact-based Regulation for Environmental Protection in Shale Gas Resource Development.” The Energy Institute: 127. http://groundwork.iogcc.org/sites/default/files/UT%20Energy%20Inst%20%20Fracking%20Report%202-15-12%20.pdf.

 

Kreitler, Charles, Ph.D. 2013.

 

Mace, Robert E. 2011. “Fracking and Water Resources: The Pearsall/Eagle Ford Shale and South Texas.” Presentation atTown Hall Meeting June 10, 2011; Laredo, Texas (June 10): 24. http://safefrackingcoalition.files.wordpress.com/2011/08/2011-0610-mace-laredo-fracking.pdf.

 

Mauer, Dr. William. 2011. “JIP to Improve Eagle Ford Hydraulic Fracturing Technology.” Mauer Engineering Inc. Austin, TX 78733 TP11-1 (May 9): 46. http://maurerengineering.com/PDFfiles/FRACING%20PROPOSAL%20%20WITH%20SLIDES%20MAY%2010%20PDF.pdf.

 

Nicot, Jean-Philippe, Robert C. Reedy, Ruth A. Costley, and Yun Huang. 2012. “Oil & Gas Water Use in Texas: Update to the 2011 Mining Water Use Report.” Texas Oil & Gas Association, Austin, Texas (September): 117. http://www.twdb.state.tx.us/publications/reports/contracted_reports/doc/0904830939_2012Update_MiningWaterUse.pdf.

 

Nicot, Jean-Philippe, and Bridget R. Scanlon. 2012. “Water Use for Shale-gas Production in Texas, U.S.” Environmental Science and Technology 46: 3580–3586. doi:dx.doi.org/10.1021/es204602t | Environ. Sci. Technol. 2012, 46, 3580−3586.

 

Rahm, D. 2011. “Regulating Hydraulic Fracturing in Shale Gas Plays: ‘The Case of Texas’.” Energy Policy 39: 2974–2981.

 

Texas Railroad Commission. 2013. http://www.rrc.state.tx.us/eagleford/images/EagleFordShalePlay201303-large.jpg.

 

 

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A Look at Carbon Capture and Storage

Global warming has become an accepted phenomenon in the scientific community.  The consensus is that anthropogenic activities are dominant factors in this rapid climate change.  An increase in violent storms and severe droughts are becoming a normal occurrence on a global scale.  The impacts of one species have never before induced global changes in climate.  Limiting global temperature rise to 2 °C above preindustrial temperatures has become an accepted broad political consensus worldwide (1, 3).  The combustion of fossil fuels has been identified as the major contributor to climate change (1, 5, and 7).  Climate change predictions set a deadline of 2020 to significantly reduce greenhouse gases in order to mitigate anthropogenic effects on global warming (3).  Urgent action is needed.

world CO2 by fuel typeworld CO2 emissions per capita

Carbon capture and storage (CCS) has the potential to play a significant role in limiting climate change.  Future global emissions from the combustion of fossil fuels can potentially be reduced by 20% with the implementation of CCS (4).   Currently 3 megatons of CO2 (MtCO2) per year by pilot plants is already being captured from the emissions caused by natural gas cleanup and power plants.  The CO2 is then being stored in geologic formations (3).  Unfortunately, at the present there is a serious lack of funding to provide for new construction of CCS.  This fact will push the learning from these first pilot projects well beyond the year 2020 (3).  Additionally, another drawback to CCS will be the inevitable incremental costs incurred.  For example in the U.K., additional costs per year per household may be increased as much as 10% as a result of CCS implementation (3).

There are three methods of CCS currently under investigation.  Pre combustion capture is a process that chemically strips off the carbon leaving only hydrogen to burn.  Oxyfuel combustion burns coal or gas in the presence of denitrified air to yield only CO2 and water.  Post combustion uses chemical solvents to capture the CO2 from the flue gases (1, 2, and 3).   Captured CO2 is then fluidized by pressurizing to 70 bars.  This liquefied CO2 is next transported to a storage site where it can be injected to depths greater than 800m (2, 3).  The selection of storage sites is critical and will require monitoring for leakage for many decades to come.  Additionally, methods to re-mediate deficient storage will need to be readily put into place (1, 2, and 3).  Many of the techniques already being practiced by the oil and gas industry will function quite well as modeling and monitoring tools for CO2 storage.  However, as learning progresses these techniques will need to be evaluated for strengths and weaknesses.  Some examples of these techniques are: horizontal drilling to provide for cost effective storage, modeling techniques to predict groundwater displacement, CO2 migration, CO2 distribution and immobilization, seismic monitoring to image location of underground CO2, and borehole monitoring to heed early warnings of seepage (2, 3).   Teng et. al (2005) have analyzed some theoretical outcomes to physical and economic outcomes of carbon storage with leaking.  Their research highlights the need for critically essential decisions in reservoir selection, project design, and plant operation to avoid project failure (6).

At the moment the largest barrier to deployment of more CCS pilot plants is not a technological barrier but a market barrier.  Current demonstration coal plants have required additional capital in the range of $1.5 billion to complete construction.  Demonstration plants also have the barrier of recovering the operational costs of producing decarbonized electricity (3).  Critical commercial help and subsidies are needed for large scale up of CCS.  Haszeldine (2009) points out that price supports currently used to support renewables are actually supporting a more expensive option per energy unit than it would if it supported the deployment of CCS.  Rapid deployment of CCS is needed to promote learning.  Additionally, the sharing of detailed commercial information instead of tightly controlled company secrets commonly associated with competitive development will be help to straighten the learning curve of a much needed technology (3).

My colleagues seem to have mixed views on the practice of CCS.   The reliability of CO2 available to inject for enhanced oil recovery is a serious dilemma.  How can we implement CCS on a grand scale without the Co2 delivery infrastructure in place?  It is my opinion that this is only a reality because we have not been able to convince investors or the public that CCS is a reliable and safe science for us to be practicing.   It is true.  Until a CO2 distribution network is constructed, a reliable source of CO2 will be a pressing concern.  The practice of CO2 injection for enhanced oil recovery (EOR) has been going on for decades.  EOR is being practiced in areas where we have already disturbed the natural development of the earth.  It seems to me that one of the biggest fears for my colleagues is what will be the consequences of this CO2 injection?  This is also a concern of mine.  It perplexes me that some are so willing to accept similar risks with hydraulic fracturing, but they are not willing to trust the science behind CCS.

Another fascinating topic raised by one of my colleagues was the idea of pore space ownership.  Just like many battles have been fought over the ownership of groundwater, I foresee the same thing happening with CO2 sequestration.  Who will really own the pore space underground?  On the borders of conflicting countries it’s not so simple.  If you use Texas as an example, the wise governing bodies of Texas legislature have given the landowners the right to the resources below them, unless they have sold them off.

1Environmental Non-Government Organisation (ENGO) perspectives on Carbon Capture and Storage (CCS)., 2012.  http://cdn.globalccsinstitute.com/sites/default/files/publications/55041/engo-perspectives-carbon-capture-storage.pdf

2Gibbins, J., and Chalmers, H., 2008, Carbon capture and storage: Energy Policy, v. 36, p. 4317–4322.

3Haszeldine, S.R., 2009, Carbon capture and storage: how green can black be?: Science, v. 325, p. 1647–1652.

4International Energy Agency, 2010, Energy Technology Perspectives: , p. 458.

5Metz, B., Davidson, O., Coninck, H. de, Loos, M., and Meyer Leo, 2005, IPCC special report on carbon capture and storage: Cambridge University Press,, p. 443.

6Teng, F., and Tondeur, D., 2007, Efficiency of carbon storage with leakage: physical and economical approaches: Energy, v. 32, p. 540–548.

7U.S. Energy Information Administration; International Energy Outlook, 2011.  Pg. 6

http://www.eia.gov/forecasts/ieo/pdf/0484%282011%29.pdf

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by | 17 February 2013 · 6:28 pm