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GSBGEN332/LAW515 CO2 Fraccing - 1
CO2 FRACCING:
EVALUATING A NEW OPPORTUNITY FOR CARBON CAPTURE
AND STORAGE
Mark Allen, Minoru Aoki
Stanford Graduate School of Business
December 8th, 2014
GSBGEN332/LAW515 CO2 Fraccing - 2
CONTENTS 1. Overview of the US fracking industry
- Shale oil production - Water management issues
2. CO2 as a fracking fluid
- CO2 for EOR - Fluid flow through hydrocarbon-saturated shales - Project Inquiry Phase
3. CO2 Sourcing and distribution options
- CO2 sources and market - Impact of large scale CO2 fracking sequestration - Capture and distribution options
4. 4. LCOE Calculations evaluating CCS deployment
- Future CO2 Markets and Pricing - Gas-fire power stations - Coal-fire power stations
Tables and Figures
“As nations develop emission regulations, they will come to us to see how we continue to provide
affordable coal power to customers, but in an environmentally sustainable way.”
Bill Boyd, Canadian Minister of Energy and Resources, October 2014 at opening of world’s first post-
combustion CCS project
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1. OVERVIEW OF THE US FRACKING INDUSTRY
Ever since George Mitchell first proposed fracking the Barnett shale to produce
commercial quantities of natural gas in the early 1980’s, the technique has evolved
to become one of the most important energy innovations of the 21st century. It is
also one of the most environmentally controversial due to the risk of groundwater
pollution, the high volume of water consumed, and triggering of minor earthquakes.
Today the most prolific US oil shale basins under development include the
Bakken, Eagle Ford, and Permian, with hundreds of drilling rigs and fracking
spreads currently operating across each region (Figure 1). By contrast the natural
gas basins, predominantly located in the eastern half of the country, have seen a
decline in activity to just ~18% of 2014 wells due to the lower commodity price.
1.1 Shale Oil Production
A typical shale oil production well is drilled up to 3,000ft horizontally through
the pay zone, and fracked in multiple “stages” to maximize contact between
wellbore and the surrounding low-permeability reservoir. The injected fracking
fluid is usually water plus additives such as biocide, viscosity modifiers and drag
reducing agents to optimize the pumping process. Proppant, resin-coated sand or
high-strength ceramic pellets, is added to keep the fractures open once the fluid
injection has stopped. Multiple horizontal wells are usually drilled from a single
surface location or pad, each having its own drainage area. A typical Bakken
development well drainage areas is 20 - 30 acres per well (Figure 2), with up to 32
wells drilled per pad.
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Initial shale oil well production rates average 500 b/, although this rate
undergoes a very steep decline (Figure 3). Cumulative Bakken or Niabara oil
production averages 0.4 MMbbl per well after 5 years.
1.2 Water Management Issues
Industrial scale shale oil development has raised concerns about water
management. The total water volume required to frac a well may exceed 300,000
bbl (48,000 tonnes). Depending on the well spacing (20 – 30 acres), aggregate water
consumption may reach 0.6m3 per m2 of reservoir under development, equivalent to
23 inches – or about one year’s - annual North Dakota rainfall.
Approximately 50% of the water injected during fracture stimulation is retained
in the subsurface formation, never returning for re-use or disposal. In areas where
freshwater resources are scarce this water for fracturing may need to be
transported over long distances, adding to operational intensity, transportation
safety risks, and carbon footprint. Storage facilities are required to create buffer
capacity between water supply and water demand locations.
Seismicity is a concern in some areas where fracking operations are underway,
and is usually associated with disposal of fracking waste water after it has been
flowed back to surface with first oil production. If a single injection well is
repeatedly used to dispose of hundreds of fracked well flowbacks, the resulting
accumulated water pressure will gradually alter the subsurface stress regime,
increasing the risk of reactivating shallow geological faults.
In summary, hydraulic fracking of shale reservoirs places an intense burden on
regional water supply and disposal infrastructure, even if flowback water is
recycled, which a substitute stimulation technique may alleviate.
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2. CO2 AS A FRACKING FLUID
The ability to substitute frac water with “energized” fluids (usually in the form of
a foam) is already recognized. Today a variety of gases, including LPG (propane),
CO2, and N2 are deployed in the field, particularly if water restrictions apply to
drought regions, subject to the substitute gas’s availability. The use of large
quantities of gas requires specific storage and pumping equipment.
Energized fluids achieve higher oil production rates than brine in the same
geology (Figure 4), while achieving superior proppant placement, and eliminating
treatment of flow-back water, and the gas may be recovered at surface for re-use.
CO2 may be transported to the wellsite as a dense phase supercritical fluid, with
favorable properties at operating pressure and temperature (Figure 5).
2.1 CO2 for EOR
CO2 is widely used in onshore US conventional oil plays for Enhanced Oil
Recovery (EOR), as shown in Figure 6. When CO2 is added, oil’s viscosity and its
attraction to the reservoir rock are both reduced. With sustained CO2 injection, an
additional 5 to 15% of the original oil in place may be recovered, depending upon
the in-situ oil and formation properties. The world’s largest CO2 production,
transportation, and injection network supplies depleted conventional oilfields in the
Permian Basin, representing half the nation’s 318 Mb/d production attributable to
EOR supplied by 3.4 Bcf/d (67 MMt/year) of CO2.
Since shale oil developments only recover < 10% of the original oil in place,
versus 20 – 50% recovery from conventional oilfields, operators have recognized
the opportunity to trial CO2 as a fracking fluid in an attempt to replicate the success
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of conventional EOR. US shale oil reserves would thus be transformed if
unconventional CO2 EOR were proven to be technically viable.
2.2 Fluid flow through hydrocarbon-saturated shales
The influence of a fracking fluid on shale reservoir productivity is dependent
upon the fluid-rock interactions at the pore scale (Figure 7). Shale permeability (a
measure of how easily fluid flows through the pore space) often reduces when
matrix grains are hydrated by water, although this effect may be masked by the
highly permeable propped fracture connecting the wellbore to the shale formation.
Research currently underway at Stanford University’s Department of Energy
Resource Engineering includes testing the effect of injecting different fluids into a
methane-saturated shale samples. These experiments have demonstrated that
shale’s effective permeability to water is broadly similar to that of CO2 (depending
upon the original permeability of the shale sample). An important phenomenon
observed was that when CO2 is injected into the methane-saturated shale sample,
some of the CO2 gas is adsorbed onto the shale, displacing water. The implication,
requiring further research, is that shale oil and gas formations may be suitable for
long term CO2 geological sequestration.
No research has been conducted to date at Stanford University to measure the
effective permeability of injecting CO2 in oil-saturated shale, although research into
this topic is underway at other institutions, such as the University of North Dakota.
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2.3 Project Inquiry Phase
In order to establish whether CO2 could be considered as a viable fracking fluid,
our research pursued three lines of inquiry:
a) A literature search on the topic of CO2 fracking
b) Interviewed three Stanford University domain experts to obtain their
opinions on the viability of CO2 as a fracking fluid for shale oil reservoirs
c) Query posted on an oil industry social media website (www.oilpro.com)
Literature Search
Oil industry thought leaders such as S.D.Joshi1 recognize that “the world’s top
EOR specialists are now focusing on the next stage: how to maximize tertiary oil
recovery from unconventional reservoirs”. A handful of oil industry research papers
have reported that organic shale has the ability to permanently store significant
amounts of CO2 due to gas adsorption by dispersed organic matter, and several have
quantified the benefits of CO2 fracking.
Interviews at Stanford School of Earth Sciences
Interviews were held with Dr Anshul Agarwal, Program Director at Stanford
Centre for Carbon Capture and Storage (SCCS); Prof Lynn Orr, Professor in Energy
Resources Engineering; and Dr Mark Zoback, Professor in Earth Sciences. Dr
Agarwal and Prof Orr both acknowledged that more work needed to be done on CO2
flooding of shale oil formations, since to date SCCS research had only investigated
methane-saturated shale samples. However they both judged that a reasonable
1 http://www.spe.org/jpt/article/6435-guest-editorial-eor-next-frontier-for-unconventional-oil/
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proportion of CO2 (assumed +/- 50% of the injected volume) could be sequestered
by injecting into an oil shale well under the right conditions.
By contrast, Prof Zoback judged that all CO2 injected when fracking a shale oil
production well would simply flow back to surface when the well was placed on
production, rendering the procedure ineffective as a CO2 sequestration technique.
Oilfield Social Media response
A query about the successes or lessons learned from CO2 fraccing was posted on
OilPro2. A Halliburton engineer confirmed that he had performed a multi-stage frac
job in the Permian (where CO2 supplies are readily available), though gave no
information on productivity. Another respondent commented that while
supercritical CO2 was not ideally suited for conveying proppant due to the challenge
of controlling fluid viscosity, CO2 foams were effective. A third respondent advised
that the advantage of Halliburton’s CO2 foam frac was that production starts quickly
when the well is back-flowed. We conclude therefore that CO2 fracs are practical.
3. POTENTIAL CO2 MARKET, SOURCING AND EMISSIONS IMPACT
3.1 CO2 Shale Market Potential Value
Oilfield CO2 is predominantly sourced from naturally occurring accumulations;
however their exploitation is becoming increasingly expensive while demand from
conventional EOR projects is predicted to increase. The current market for Permian
CO2 delivery is ~ 2 to 2.25% of WTI crude benchmark per Mcf ($25-30/tonne at
$70/bbl3). Typical oil yields from EOR are ~1bbl per 6,000mcf (0.32 tonnes).
2 http://oilpro.com/q/1515/co2-fraccing-fluid
3 Personal communication, Andy Wood, VP Operations Summit Energy
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Assuming that 0.3MMbbl water could be substituted with the equivalent volume
of CO2 for a frac job (38.2Mt CO2), the supply cost at $27/tonne would be $1.03MM
per well (before cost savings from using less water), as summarized in Table 3.1.
Assuming the typical recovery per well of 0.4 MMstb is boosted 10% by EOR
effects, CO2 fracking could potentially be commercially attractive to the operator,
the incremental oil yielding 172% undiscounted profit, as shown in Table 3.2.
3.2 CO2 Sourcing and Distribution Vision
The Bakken and Eagle Ford formations both overlie extensive lignite coal
deposits (Figure 8), which could serve as a convenient feedstock for future CCS
projects, given the geographic proximity of coal supplies and oilfield CO2 markets,
minimizing the cost of transportation.
The CO2 distribution system might employ a hub and spoke model, consisting of
several large (~2000 MW) coal-fire plants, connected to a network of distribution
pipelines supplying pressurized storage tank farms located every 30-50 miles
across the shale basin. Fleets of tanker trucks would shuttle the CO2 between the
storage site and frac spreads. If the storage site’s CO2 inventory reached capacity,
surplus CO2 would simply have to be vented by the power station.
An example operating lignite gasification plant is the Great Plains Synfuels Plant
in North Dakota, which has been delivering 150MMcf/d CO2 (2.7 MMt/year) to the
Weyburn EOR project in Canada since 20004. If the coal-fired share of US generation
capacity (presently 39%) is to remain, CCS may be necessary to deliver a viable new
fleet of coal-power stations, as envisaged by the Texas Clean Energy Project.
4 http://www.dakotagas.com/About_Us/index.html
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3.2 Emissions Impact of large scale CO2 fracking and sequestration
The impact on US emissions of fracking with CO2 in both the Bakken shale, and
nationwide is assessed in Table 3.3. Assuming that 50% of the injected CO2 is
permanently sequestered (without loss of generation efficiency), if every second
well was fracked with CO2 this technology could potentially reduce power station
emissions by > 250 MMt/yr, equivalent to 12% of total power emissions, (Figure 9).
4. LCOE CALCULATIONS EVALUATING CCS DEPLOYMENT
The Stanford University GSB Levelized Cost of Electricity (LCOE) calculator has
been applied to evaluate LCOE - with and without CCS - for new-build gas-fired and
coal-fired power stations. The model has been adjusted to account for revenues
from CO2 sales to oilfield operators. The model has been applied to test the impact of
the fiscal regulatory framework by running sensitivity analysis on depreciation
method, investment tax credit (ITC), and CO2 emissions charges.
4.1 Future CO2 Markets and Pricing
The value addition from CO2 sales is considerably higher than the fiscal benefits,
and helps close the LCOE gap between gas-fire CCS and non-CCS from over 30% to
below 16% if CO2 can fetch $36/tonne. Although Section 3.1 discussed how shale oil
operators might achieve high returns on EOR investment at $27/tonne CO2 when oil
price is at $70/bbl, over the long term we judge oil price of $85/bbl (implying
$36/tonne CO2) as a more realistic benchmark.
Localized price variations between isolated CO2 markets are likely to occur,
depending upon supply and demand dynamics. A lower price might be accepted by
CCS plant operators to receive at least some revenue when demand is weak.
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Similarly, higher prices might be offered by shale oil operators competing for CO2
supply, particularly if the oil price rises. More connected CO2 markets such as the
Permian basin provide the stability of a competing conventional CO2 EOR market,
whereas the shale gas provinces such as the Marcellus and Devonian may see wider
CO2 price fluctuation linked to natural gas price. In order to provide predictable
revenue streams to secure CCS project finance, each power station operator will
have to agree long-term CO2 supply contracts with a number of oilfield operators.
4.2 Gas Fire Power Stations
Base case economic analysis by Reichelstein et al5 has demonstrated that for
natural gas power plants to be competitive the system price of CCS must drop by
30%, which may be achievable with “learning curve” effects. The results of this
study’s LCOE calculations, including the impact of CO2 emissions fees avoided and
revenues from CO2 sales, are summarized in Table 4.1. These show that a high CO2
emission charge would be the biggest driver for CCS deployment. If emissions fees
are raised to $40/ton, the LCOE gap between CCS and non-CCS lies within 10%.
The second greatest sensitivity is ITC, which is not currently applied to non-
renewable power plants; the federal government offers a maximum 30% ITC to
renewable installations such as solar. In order to test the impact of ITC on gas-fired
CCS, only the power plant’s capture module was considered eligible, which is
assumed to be half of the plant’s total cost. Setting, the sensitivity analysis maximum
ITC to 15% resulted in CCS power becoming approximately 7% more competitive.
5 Class notes, Sustainable Energy, GSBGEN332
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Finally, the impact of the depreciation method was evaluated. If 5-year MACRS
depreciation is applied to the CCS power stations, LCOE reduces by 2%, whereas
MACRS with 50% bonus in 1st year will reduce LCOE by 3%.
4.3 Coal Fire Power Stations
Assuming CO2 emissions from conventional coal-fired power stations of 1,000
kg/MWh6, the CO2 capture rate must exceed 92% for net emissions to fall within the
EPA’s proposed 80 kg/MWh upper limit. Such a high capture rate should be possible
with existing technology, which already achieves 90% efficiency, though we assume
additional system and O&M costs of 20% are incurred over the 80% efficient CCS
operation. At 95% efficiency LCOE was calculated as 9.65 c/KWh, comparable with
the 80% capture rate LCOE of 9.68 c/KWh; both of which being almost equivalent to
the LCOE 9.54 c/KWh of coal-fired power plants without CCS (See Table 4.2).
Since coal-fire plants generate 2.6 times as much CO2 as gas-fired plants, the
LCOE of coal CCS is very sensitive to both CO2 emission cost and market price.
Assuming the CCS plant can sell CO2 at $36/tonne while avoiding $15/tonne
emissions fees, a CCS coal-fired power plant can compete with non-CCS, even though
coal LCOE is much higher than natural gas under these conditions. However, future
technologies may reduce CO2 coal-fire capture costs sufficiently to compete with
natural gas installations, particularly in countries such as China where gas prices are
less competitive than in the US.
6 Stanford University Energy Resource class notes, CEE173
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Table 3.1) Cost of CO2 to frac one shale oil production well
Table 3.2) Economic value from using CO2 to frac one shale oil production well
Table 3.3) Potential impact of CO2 fracking on emissions from US power stations
CO2 pressure 1160 psi
CO2 compression Temperature 20 DegC
CO2 density 0.8 g/cc
to provide 300,000 reservoir barrels 38157 tonnes
CO2 price 27 $/tonne
CO2 cost 1.030 MM$
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Table 4.1) LCOE – gas fired CCS
Table 4.2) LCOE – Coal Fired CCS
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Figure 1a) Primary onshore US shale basins bearing oil (blue) and natural gas (red)
Figure 1b) Rotary rig count in the Bakken play, as at November 2014 (170 rigs)7
7 http://gis.bakerhughesdirect.com/RigCounts/default2.aspx
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Figure 2) How a shale oil well is fracced8
Figure 2) Multiple wells typically share a common surface location to optimize exploitation efficiency
8 Image courtesy of NY Times Magazine, http://www.nytimes.com/news/the-lives-they-lived/2013/12/21/george-mitchell/
1) Drill down to the target shale formation, kick off and drill a 3,000ft long horizontal drain, run a 7” diameter steel production liner.
2) Perforate the liner plus rock with explosive charges, then pump a high pressure mix of water, chemical and sand proppant into the crevices to propagate a set of deep fractures, creating a greater surface area for hydrocarbon to flow back into the wellbore.
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Figure 3a) Average shale oil and gas well production rates by basin. Fracking technology has improved since 2010, as majority of wells are now horizontal.
Figure 3b) Typical Niobara shale oil production type curve (Whiting Petroleum)
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Figure 4) Comparison of frac fluid attributes and modeled well productivity for slickwater vs energized fluid fracs9
9 SPE 163867, Fluid Selection for Energized Fracture Treatments, Ribeiro&Sharma, University of Texas, 2013
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Figure 5) CO2 phase diagram, density and viscosity
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Figure 6a) North American CO2 distribution systems and current throughput
Figure 6b) Permian Basin CO2 Pipeline Infrastructure and capacities. 10
10 http://www.melzerconsulting.com/index.php/maps
http://www.texascleanenergyproject.com/2011/co2-whiting-petroleum-corporation
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Figure 7a) Schematic depiction of reservoir pore space and permeability
Figure 7b) How CO2 might increase oil recovery from shale11
11 http://www.spe.org/jpt/article/5712-carbon-dioxide-may-offer-an-unconventional-eor-option/
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Figure 8) US Coal Resource map
Figure 9) US 2012 CO2 emissions from power generation by fuel type, compared with current CO2 EOR consumption (yellow), and potential future anthropogenic CO2 disposal capacity in shale plays (green).
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