gsbgen332_allenaoki_co2fraccing

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


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


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.


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.


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


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.


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/


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


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


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.


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


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


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$


Table 4.1) LCOE – gas fired CCS

Table 4.2) LCOE – Coal Fired CCS


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


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.


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)


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


Figure 5) CO2 phase diagram, density and viscosity


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


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/


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).

gsbgen332_allenaoki_co2fraccing

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