life cycle greenhouse gas emissions and freshwater ... · emissions and freshwater consumption...

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Life Cycle Greenhouse Gas Emissions and Freshwater Consumption Associated

with Bakken Tight Oil Supplemental Information

Ian J Laurenzi*, Joule Bergerson†, Kavan Motazedi†

* ExxonMobil Research and Engineering, Corporate Strategic Research

†University of Calgary, Department of Chemical and Petroleum Engineering

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1 Goal and Scope ..................................................................................................................................... 4

1.1 System Definition .......................................................................................................................... 4

1.1.1 Definition of the Base Case Bakken Life Cycle ...................................................................... 6

1.1.2 Alternative Flaring Scenarios ................................................................................................ 6

1.2 Co-product Accounting (Allocation) .............................................................................................. 6

1.2.1 Upstream............................................................................................................................... 6

1.2.2 Downstream .......................................................................................................................... 7

1.3 Impact Assessment ....................................................................................................................... 0

2 Calculations - Electricity and Transportation ........................................................................................ 1

2.1 Impacts associated with the Electricity Grid ................................................................................. 1

2.2 Transportation ............................................................................................................................ 14

2.2.1 Fuels .................................................................................................................................... 14

2.2.2 Truck .................................................................................................................................... 14

2.2.3 Rail ....................................................................................................................................... 15

2.2.4 Pipeline ................................................................................................................................ 15

2.2.5 Waterway ............................................................................................................................ 15

2.2.6 Summary ............................................................................................................................. 16

3 Characteristics of Bakken Hydrocarbons ............................................................................................ 16

3.1 Associated Gas ............................................................................................................................ 17

3.2 Oil ................................................................................................................................................ 17

4 Calculations by Life Cycle Phase ......................................................................................................... 18

4.1 Drilling and Completion .............................................................................................................. 18

4.1.1 Data ..................................................................................................................................... 18

4.1.2 Well Casings ........................................................................................................................ 21

4.1.3 Well Cementing ................................................................................................................... 22

4.1.4 Proppant ............................................................................................................................. 23

4.1.5 Gel Frac Additives ............................................................................................................... 24

4.1.6 Drilling and Hydraulic Fracturing ........................................................................................ 25

4.1.7 Completion Flowback .......................................................................................................... 26

4.2 Production ................................................................................................................................... 27

4.2.1 Pumping Unit ...................................................................................................................... 27

4.2.2 Heater Treater ..................................................................................................................... 30

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4.2.3 Tank Vapor Flaring .............................................................................................................. 31

4.2.4 Produced Water and Salt Water Disposal ........................................................................... 32

4.2.5 Corrosion and Scale Inhibition ............................................................................................ 36

4.2.6 Maintenance ....................................................................................................................... 37

4.2.7 Production flaring before hookup ....................................................................................... 38

4.2.8 Production flaring after hookup.......................................................................................... 38

4.3 Crude Transportation .................................................................................................................. 40

4.3.1 Transport to Transloading ................................................................................................... 41

4.3.2 Pipeline ................................................................................................................................ 41

4.3.3 Rail ....................................................................................................................................... 41

4.4 Refining ....................................................................................................................................... 41

4.4.1 GHG Emissions .................................................................................................................... 41

4.4.2 Freshwater Consumption .................................................................................................... 44

4.5 Transportation of Refined Products............................................................................................ 44

4.5.1 Gasoline Transportation ..................................................................................................... 45

4.5.2 Diesel Transportation .......................................................................................................... 46

4.5.3 Vehicle Refueling................................................................................................................. 46

4.6 Vehicle Operation ....................................................................................................................... 46

5 Supplemental Results.......................................................................................................................... 47

5.1 Upstream .................................................................................................................................... 47

5.1.1 Base Case, GHG and freshwater consumption ................................................................... 47

5.1.2 Effect of Flaring due to Absence of Pipeline Connection .................................................... 49

5.2 Life Cycle ..................................................................................................................................... 51

5.2.1 Gasoline............................................................................................................................... 51

5.2.2 Diesel ................................................................................................................................... 53

5.2.3 Effect of Flaring of Associated Gas due to Absence of Pipeline Connection ...................... 54

5.2.4 Effect of Refinery Configuration ......................................................................................... 56

5.3 Sensitivity Analysis ...................................................................................................................... 58

5.3.1 Upstream GHG Emissions ................................................................................................... 58

5.3.2 Life Cycle GHG Emissions of Bakken-derived Gasoline and Diesel ..................................... 61

5.3.3 Upstream Freshwater Consumption ................................................................................... 64

5.3.4 Life Cycle Freshwater Consumption of Bakken-derived Gasoline and Diesel .................... 64

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5.4 Characterization of ranges of impacts ........................................................................................ 65

5.4.1 Upstream, MC ..................................................................................................................... 65

5.4.2 Gasoline and Diesel, MC ..................................................................................................... 67

5.5 Comparison with other studies ................................................................................................... 70

5.6 Greenhouse gas emissions associated with other tight crudes .................................................. 71

6 Summary of Data, Distributions and Modeling Choices Employed .................................................... 72

7 References .......................................................................................................................................... 74

1 Goal and Scope The purpose of this investigation was to robustly estimate the “cradle to grave” greenhouse gas

emissions and freshwater consumption associated with gasoline and diesel refined from Bakken crude.

The estimates are intended to (1) facilitate comparisons with previously reported estimates of life cycle

GHG emissions for gasoline and diesel (i.e. sourced from other crudes), (2) evaluate the effects of

specific operations (e.g. flaring), and explicitly investigate the effects of modeling choices on the results

(e.g. allocation of impacts at the refinery).

Insofar as gasoline and diesel are not compared with each other, but with gasoline and diesel ostensibly

refined from other crudes, we employed a functional unit of “MJ of fuel combusted” for both gasoline

and diesel. Comparison of the GHG emissions associated with Bakken-sourced diesel and Bakken-

sourced gasoline necessitates consideration of the engine efficiencies and drive cycles associated with

gasoline- and diesel-fueled vehicles, i.e. a functional unit of “miles of transport” (for light duty vehicles)

or “ton-miles of transport” (for heavy duty vehicles). This was considered beyond the scope of this

work.

1.1 System Definition The Tight Oil system boundary is illustrated in Figure S1. We include impacts associated with

Drilling,

Hydraulic fracturing,

Separation of crude, produced water and associated gas at the pad,

Well pad operations including production, storage, and flaring,

Transportation of crude to refineries,

Conversion of crude to refined products at the refinery,

Transportation of refined products, and

Use of refined products (combustion as fuel for vehicles)

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Figure S1 System boundaries for LCA of Tight Oil. The upstream phase includes grid-generated power used for salt water disposal and other operations preceding the crude transportation stage. The life cycle is composed of the “Well to Tank” (WTT) and “Tank to Wheel” (TTW) phases.

We also include the life cycle impacts associated with the generation of electricity used in these

processes, cementing and casing of wells, proppant and gel frac additives employed for hydraulic

fracturing, and scale and corrosion inhibitor employed during the production phase of the well life cycle.

As illustrated in Figure S1, associated gas is employed as a fuel for equipment at the well pad, but is also

sold as a co-product. Therefore, the impacts up to and including production (including flaring) are

allocated to both oil and associated gas.

Likewise, the refinery converts crude into several products. Product slates vary from refinery to refinery,

in accordance with their configurations and accessibility to other infrastructure, including chemical

plants. In this study, we consider only following products:

Gasoline

Jet fuel

Ultra-low sulfur diesel

Heating fuel oil

Bunker fuel

Petcoke

Surplus H2 generated via catalytic reforming of naphtha (if any)

Light ends products are utilized as refinery fuel gas, representing an upper-bound for emissions and a

lower bound for resource utilization (e.g. LPG is not part of the product slate, nor are chemical

feedstocks such as ethylene). Environmental impacts for all operations up to and including the refinery

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are allocated to the aforementioned refined products via energy content (HHV). We have also evaluated

the effect of an alternative allocation approach (mass) in our sensitivity analysis.

1.1.1 Definition of the Base Case Bakken Life Cycle

Each month, the North Dakota Department of Mineral Resources (ND DMR)29 reports the following data

for each in-state oil and gas well:

Oil produced (barrels)

Water Produced (barrels)

Associated Gas Produced (thousands of scf)

Days of the month the well produced

Oil Sold (barrels)

Associated Gas Sold* (thousands of scf)

Associated Gas Flared (thousands of scf)

ND DMR also reports the “Pool” associated with each well. Pools in scope for this LCA were “BAKKEN”,

“BAKKEN/THREE FORKS”, “SANISH”, and “THREE FORKS”. In September 2015, ND DMR reported 10001

wells in these pools, of which 9197 reported gas sold, i.e. 92% of Bakken wells were connected to gas

gathering systems. The production from these pools exceeded 95% of the oil production from North

Dakota.

Since 92% of the wells were connected to gas pipelines, we defined our “base case” Bakken well

configuration to be a well featuring a pipeline connection for gas from the beginning of production, i.e.

gas is flared only during completion and as a consequence of upsets associated with infrastructural

constraints. In this case, impacts including those associated with flowback flaring and flaring due to

infrastructural constraints (e.g. pipeline capacity) were allocated to gas and oil sold to their respective

customers, e.g. gas gathering system operators and midstream companies that sell oil to refiners.

1.1.2 Alternative Flaring Scenarios

We also evaluated the sensitivity of our results to flaring by considering scenarios in which associated

gas is flared due to lack of pipeline connection for the first three, six, and twelve months of production.

In these scenarios, flaring of associated gas due to lack of pipeline connection was allocated entirely to

oil. However, flaring of flowback gas and flaring due to infrastructural constraints (e.g. pipeline capacity)

were allocated to gas and oil sold to their respective customers, as in our base case.

1.2 Co-product Accounting (Allocation) We employ allocation in lieu of system expansion in this study, for both upstream co-products (crude

and associated gas) and downstream products (refined fuels).

1.2.1 Upstream

As discussed, GHG emissions and freshwater consumption for all operations up to and including drilling,

completion and the production of crude are allocated to oil and associated gas that is delivered to a

* via pipeline

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gathering pipeline. However, GHG emissions associated with the flaring of associated gas due to the

absence of a pipeline connection are completely allocated to crude – in this situation, there is no co-

product. However, GHG emissions associated with flaring caused by capacity constraints are allocated

to both associated gas and oil.

GHG emissions for crude were calculated using the following formula

𝐺𝑈,𝑗 = 𝑔𝑈,𝑗𝜑

𝐶

where GU,j is the GHG emission allocated to crude for the jth upstream operation (kg CO2eq/bbl crude),

gU,j is the corresponding absolute upstream operation emission (in kg CO2eq/well), C is the life cycle

volume of crude sold to refiners (378,071 bbl/well, on average), and is the ratio of the energy (or

mass) associated with crude relative to the total oil and gas sold from the pad. In the absence of a

pipeline connection, =0. For an average well (Section 3: Characteristics of Bakken Hydrocarbons), the

impacts are allocated to gas and oil as follows:

Scenario: Flaring due to lack of pipeline connection None 3 mos 6 mos 12 mos

Gas Sold (MMscf) 392 360 337 304

Crude Sold (kbbl) 378 378 378 378

Allocation (HHV basis) 0.784 0.798 0.808 0.824 Table S1 Effect of flaring due to absence of a gathering pipeline connection upon allocation of upstream impacts

1.2.2 Downstream

As noted by Wang and coworkers1, the method of allocating impacts to refined products may result in

significant shifts of the impacts among those products. In addition to the practitioner’s choice between

energy-based and mass-based allocation of co-products, one may also allocate at a plant level or a

process-unit level.

Plant-level allocation is conducted as follows: Refinery impacts are allocated to refined products in

proportion to their fraction of energy content (HHV) or mass among products sold by the refinery.

Process-level allocation, by contrast, requires explicit accounting of material through each unit of the

refinery. The PRELIM model used for the estimation of refinery impacts (Section 4.4 Refining) accounts

for the flows of hydrocarbons through individual refinery process units23. Therefore, we were able to

investigate the effect of both allocation methods.

In Table S2, we report the fractions of refinery GHGs emissions attributable to diesel and gasoline

manufactured from Bakken, subject to the refinery configuration as well as the allocation method.

Other refined products included fuel oil, jet fuel, bunker fuel (or asphalt) and coke, subject to the

refinery configuration. Process-level allocation generally results in higher allocation of GHG emissions to

both gasoline and diesel.

GHG emissions for the refining of refined products (GiR, in kg CO2eq/bbl refined product i) were

calculated using the following formula

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𝐺𝑖𝑅 = 𝑅𝜙𝑖

𝐶

𝑃𝑖

where R is the refinery GHG emission (kg CO2eq/barrel of crude), i is the fraction of the refinery GHG

allocated to refinery product i (e.g. gasoline), C is the life cycle volume of crude entering the refinery,

and Pi is the life cycle volume of refined product i.

Upstream and crude transportation impacts associated with refined products were calculated similarly,

using plant-based allocation only, i.e.

𝐺𝐷,𝑖,𝑗 = 𝐺𝑈,𝑗𝜙𝑖𝑃𝑙𝑎𝑛𝑡 𝐶

𝑃𝑖

where GiD,i,j is the GHG emission from the jth upstream or midstream operation associated with refined

product i (kg CO2eq/bbl refined product i), and GU,j is the GHG emission associated with the jth upstream

operation (kg CO2eq/bbl crude).

Plant-level allocation was employed exclusively in our LCA of freshwater consumption, due to the fact

that PRELIM does not account for freshwater consumption associated with specific refinery process

units (Section 4.4 Refining).

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Refinery Type Hydroskimmer Medium Conversion Deep Conversion

Conversion Technologies

FCC GO-HC FCC + GO-HC FCC + Delayed Coking

GO-HC + Delayed Coking

FCC + GO-HC + Delayed Coking

Refinery allocation method

Plant Process Plant Process Plant Process Plant Process Plant Process Plant Process Plant Process

Fraction of refinery GHG allocated to diesel

10% 7% 16% 19% 25% 27% 21% 21% 17% 20% 29% 32% 23% 27%

Fraction of refinery GHG allocated to gasoline

32% 68% 49% 64% 45% 62% 47% 64% 54% 64% 47% 60% 50% 61%

Crude produced over well lifetime (bbl/well)

378,071 378,071 378,071 378,071 378,071 378,071 378,071 378,071 378,071 378,071 378,071 378,071 378,071 378,071

Gasoline manufactured over well lifetime (bbl/well)

133,841 133,841 196,120 196,120 184,928 184,928 190,524 190,524 212,883 212,883 195,623 195,623 204,253 204,253

Diesel manufactured over well lifetime (bbl/well)

38,139 38,139 60,349 60,349 94,215 94,215 77,574 77,574 65,277 65,277 108,810 108,810 87,319 87,319

Table S2 Effect of refinery configuration (type, conversion equipment) and allocation method (plant basis, process basis) upon the allocation of GHG emissions to gasoline and diesel. In addition to gasoline and diesel, GHG emissions are allocated to jet fuel, bunker fuel (or asphalt), fuel oil and coke, subject to the refinery configuration. Crude and midstream impacts are allocated to refined products on a plant-wide basis, i.e. if a Medium conversion refinery with an FCC is used to refine Bakken crude, then 16% of the crude impacts will be allocated to diesel and 49% the crude impacts will be allocated to gasoline, with the remainder allocated to jet fuel, fuel oil, bunker fuel (or asphalt), and petcoke.

To illustrate the allocation procedures thus described, consider the results presented for our base case

LCA (no flaring due to lack of pipeline connection, Medium conversion refinery with FCC) in Table S3. For

drilling and completion, we allocate absolute emissions (first column) to crude-allocated emissions

(second column) as follows:

2,493,160 kg CO2eq

well

0.784

378,071 bbl crude

well

= 5.17 kg CO2eq

bbl crude

where the fraction of GHG emissions allocated to crude (78.4%) comes from Table S1. These GHG

emissions are allocated to gasoline as follows:

5.17 kg CO2eq

bbl crude× 49% ×

378,071 bbl crude

well

196,120 bbl gasoline

well

= 4.84 kg CO2eq

bbl gasoline

where, as mentioned previously, we have allocated the upstream and midstream impacts on a plant-

wide basis of the refinery. Allocation of impacts associated with production and crude transportation

follows an identical procedure, except for associated flaring due to lack of a pipeline connection. Results

of these calculations are provided in detail in Table S25 (Section 5: Supplemental Results).

By contrast, the refinery GHG emissions are allocated to gasoline as follows:

27.3 kg CO2eq

bbl crude× 64% ×

378,071 bbl crude

well

196,120 bbl gasoline

well

= 33.5 kg CO2eq

bbl gasoline

GHG Emissions (kg CO2eq/well)

GHG Emissions (kg CO2eq/bbl crude)

GHG Emissions (kg CO2eq/bbl gasoline)

GHG Emissions (kg CO2eq/bbl diesel)

Plant Level Process level Plant Level Process level

Drilling and Completion 2,493,160 5.17 4.84 4.84 5.17 5.17

Production 18,614,138 38.59 36.12 36.12 38.59 38.59

Crude Transportation 2,229,447 5.90 5.52 5.52 5.90 5.90

Refining 10,307,718 27.26 25.52 33.45 27.26 33.11

Table S3 Allocation of Crude and Refining GHG to refined products for base case LCA (gas hookup throughout production). Results shown are for base case LCA with a Medium conversion refinery with an FCC and no gas oil hydrocracker. GHG emissions estimates are reported using IPCC AR5 GWPs (Section 1.3: Impact Assessment)

1.3 Impact Assessment We assess freshwater consumption and greenhouse gas (GHG) emissions in this study. GHG emissions

are quantified by multiplying the emissions of GHGs (kg CO2, CH4 and N2O) by their respective global

warming potentials (GWPs) and summing the resulting emissions (in kg CO2eq) in accordance with

standard practice. We utilize GWPs from the 5th Assessment Report of the IPCC (AR5) for our analyses,

selecting a 100-year time horizon in accordance with the guidelines of the Kyoto protocol4. The GWPs

are summarized in Table S4.

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GWP (kg CO2eq/kg) AR4 AR5

20-year 100-year 20-year 100-year

CO2 1 1 1 1 CH4 72 25 85 30 N2O 289 298 264 265 Table S4 Global Warming Potentials (GWPs) employed in this study are highlighted in red

2 Calculations - Electricity and Transportation Transportation and use of electricity are common to many operations spanning the life cycle of Bakken

crude. For instance (Figure S1),

Pipelines, rail and trucks are used to transport both crude and refined products;

Electricity is consumed by refineries, pipeline pumping stations, and service stations;

Trucks deliver materials and fuel to the pad.

In this LCA, we do not assume that the fuels used for rail, truck and barge transportation are derived

from Bakken crude. Instead, we utilize the results of other LCAs to estimate the impacts of petroleum

fuels, which ostensibly represent a “typical” impact associated with the carbon and water footprints of

fuels refined in the United States. Likewise, we use a common “grid mix” to account for the impacts of

electricity generation.

2.1 Impacts associated with the Electricity Grid The impacts associated with grid electricity were estimated using

1. The grid mix of 2013 as reported by the EIA 923 Electricity Data File5

2. The NETL LCA Data Tool6, for baseline freshwater consumption and GHG emissions associated

with electricity generated from coal, gas, nuclear and wind.

3. The 2013 Argonne National Labs GREET model7 for baseline GHG emissions associated with

electricity generated from geothermal sources and hydropower.

4. The NREL study “Consumptive Water Use for U.S. Power Production”8 for baseline freshwater

consumption associated with electricity generated from hydropower.

In Table 5 we report the life cycle GHG and water consumption figures reported by ANL, NREL and NETL.

GHG emissions are expressed using GWPs from the two most recent assessment reports of the IPCC9,10

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Life Cycle GHG Emissions (kg CO2eq/MWh consumed)

Freshwater Consumption (kg/MWh consumed)

AR4 AR5

20 year 100 year 20 year 100 year

NG CCGT† 643 499 683 514 947 NG GT‡ 989 766 1,051 790 223 Existing Nuclear 41 39 42 39 2,670 Conventional Wind 22 21 23 22 26 Advanced Wind 16 16 17 16 22 Existing Coal 1,245 1,099 1,291 1,115 1,830 Hydro, Eastern Interconnect§ 5 5 5 5 208,554 Hydro, Western Interconnect** 5 5 5 5 46,934 Hydro, Texas Interconnect 5 5 5 5 0 Geothermal 63 63 63 63 1,087 Table 5 Life Cycle Impacts reported for U.S. power generation technologies

6,7,8.

We calculated the carbon and water footprints for each NERC region (Figure 2), and then weighted

these footprints by the power generated in each region to obtain the footprint of the U.S. grid (“lower

48”). By doing so, we were able to construct “distributions” of the grid water and carbon footprints with

expectation values of the U.S. grid footprints.

† Combined Cycle Gas Turbine, i.e. a gas turbine connected to a heat recovery steam generator (HRSG)

‡ Gas Turbine

§ The Eastern Interconnect comprises the MRO, SPP, SERC, FRCC, RFC and NPCC NERC Regions (Figure 2). The TRE

NERC region is the Texas Interconnect, and is independent of both the Eastern and Western Interconnects. **

The Western Interconnect is comprised of the WECC NERC region. The TRE NERC region is the Texas Interconnect, and is independent of both the Eastern and Western Interconnects.

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Figure 2 NERC Regions in 20135

To calculate the footprints of each region, we modified the impacts reported in Table 5 as follows: First,

we adjusted the NETL life cycle impacts – replacing the efficiencies used by NETL with the average power

plant efficiencies for each region (as calculated from the EIA Electricity Data File5). Both 2013 regional

averaged power plant efficiencies and NETL model efficiencies are reported in Table S6.

Efficiency††

TRE WECC FRCC MRO RFC NPCC SERC SPP NETL Coal 32% 33% 33% 32% 33% 32% 33% 32% 37% NG CCGT 46% 46% 47% 45% 46% 46% 47% 46% 50% NG GT 45% 42% 30% 28% 30% 33% 35% 31% 33% Nuclear 33% 32% 32% 33% 33% 33% 33% 33% 33% NG ST

‡‡ 30% 29% 29% 25% 29% 31% 30% 30% N/A§§

Table S6 Efficiencies of power generation in U.S. NERC Regions in 2013. Efficiencies used by NETL in their LCA Tool are reported for comparison. Efficiencies are calculated from heat input to the plant and net electrical output from the plant as reported in the EIA 923 Electricity Data File for 2013

5.

Next, we calculated carbon and water footprints of power generated by gas-fired steam turbine power

plants. We approximated these for each NERC region by multiplying the NETL life cycle results for

natural-gas fired combined cycle power plants by the ratio of the NETL NG CCGT efficiency and the

regional NG ST efficiency.

††

HHV basis ‡‡

Natural Gas Steam Turbine §§

NETL had not conducted an LCA of electricity generated via gas-fired steam turbines at the time this work was completed

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Generation in 2013 (millions of MWh)

TRE WECC FRCC MRO RFC NPCC SERC SPP

Nuclear 38.3 57.8 26.5 24.6 270.3 81.9 282.4 7.2

Coal, Steam Turbine 122.0 206.8 41.3 131.1 466.9 10.7 440.1 126.7

NG, CCGT 137.5 173.8 119.7 8.2 118.6 81.4 222.6 43.3

NG, GT 8.7 10.8 2.5 1.1 7.6 4.9 18.6 2.6

NG, Steam Turbine 6.4 10.7 5.7 0.5 4.4 11.3 23.6 15.8

Hydropower 0.0 137.0 - 6.0 5.2 23.2 32.2 3.4

Wind 32.3 44.0 - 33.7 18.4 5.1 3.4 23.7

Geothermal - 10.2 - - - - - -

Table S7 NERC Region Grid Mixes in 2013. Greater than 96% of all U.S. electricity is generated via these sources – other sources include cogeneration from refineries, power generation via combustion of petcoke (~1% in WECC and SPP, negligible in other regions), IGCC (~0.6% in FRCC, and negligible in other regions) and solar photovoltaics (0.6% in WECC, less than 0.03% in other regions). Electricity from Canadian and Mexican generators is not included. Generation for each region and power source was calculated from data in the EIA 923 Electricity Data File for 2013

5.

Integrating the information in Table S6 and Table S7, we obtained the carbon and freshwater footprints

of grid electricity in 2013 illustrated in Figure S3 through Figure S10, which employ 100-year GWPs for

CH4 and N2O from the 5th assessment report of the IPCC (AR5)10. We note that the freshwater

consumption associated with each grid mix is dominated by hydropower, even if the contribution of

hydropower is relatively small.

The distribution of the carbon footprint of the “lower 48” grid mix is illustrated in Figure S11, using 100-

year GWPs for CH4 and N2O from the 5th assessment report of the IPCC (AR5)10. Carbon footprints using

other GWPs are reported in Table S8.

Life Cycle GHG Emissions (kg CO2eq/MWh consumed)

AR4 AR5

20-year 100-year 20-year 100-year

TRE 832 701 871 715 WECC 670 568 700 579 FRCC 770 630 810 645 MRO 956 841 992 853 RFC 852 741 886 753 NPCC 425 340 450 349 SERC 804 690 838 702 SPP 1,044 897 1,087 913 “Lower 48” 793 679 828 691 Table S8 Carbon Footprints of NERC Regions in the “lower 48” U.S. states in 2013, expressed with alternative GWPs. Our base case LCA was conducted with GWPs from the IPCC AR5, with a 100-year time horizon (red). Results with 100-year GWPs from the AR5 are illustrated in Figure S11.

5

Figure S3 Impacts associated with electricity generated in the TRE NERC Region in 2013. GHG expressed in terms of 100-year GWPs from the IPCC AR510

.

6

Figure S4 Impacts associated with electricity generated in the WECC NERC Region in 2013. GHG expressed in terms of 100-year GWPs from the IPCC AR510

. If hydropower water consumption is included, the life cycle water consumption of WECC is 2,931 gal/MWh consumed.

7

Figure S5 Impacts associated with electricity generated in the FRCC NERC Region in 2013. GHG expressed in terms of 100-year GWPs from the IPCC AR510

. If hydropower water consumption is included, the life cycle water consumption of FRCC is 390 gal/MWh consumed.

8

Figure S6 Impacts associated with electricity generated in the MRO NERC Region in 2013. GHG expressed in terms of 100-year GWPs from the IPCC AR510

. If hydropower water consumption is included, the life cycle water consumption of MRO is 2,051 gal/MWh consumed.

9

Figure S7 Impacts associated with electricity generated in the RFC NERC Region in 2013. GHG expressed in terms of 100-year GWPs from the IPCC AR510

. If hydropower water consumption is included, the life cycle water consumption of RFC is 861 gal/MWh consumed.

10

Figure S8 Impacts associated with electricity generated in the NPCC NERC Region in 2013. GHG expressed in terms of 100-year GWPs from the IPCC AR510

. If hydropower water consumption is included, the life cycle water consumption of NPCC is 6,262 gal/MWh consumed.

11

Figure S9 Impacts associated with electricity generated in the SERC NERC Region in 2013. GHG expressed in terms of 100-year GWPs from the IPCC AR510

. If hydropower water consumption is included, the life cycle water consumption of SERC is 2,236 gal/MWh consumed.

12

Figure S10 Impacts associated with electricity generated in the SPP NERC Region in 2013. GHG expressed in terms of 100-year GWPs from the IPCC AR510

. If hydropower water consumption is included, the life cycle water consumption of SPP is 1,266 gal/MWh consumed.

13

Figure S11 Impacts associated with electricity generated in the “lower 48” U.S. in 2013. GHG expressed in terms of 100-year GWPs from the IPCC AR510

.

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2.2 Transportation

2.2.1 Fuels

In the life cycle of Bakken crude, gasoline and diesel are used for transportation of materials to and from

the pad as well as for powering equipment at the pad. The CO2, CH4 and N2O emissions associated with

diesel (“Well to use”) were adopted from the NETL Petroleum Baseline study11 We adopted high and

low heating values of these fuels from GREET 2013. We report these figures explicitly in Table S9.

Life Cycle GHG Emissions (kg/gal) Gasoline Diesel

CO2 10.69 12.12 CH4 0.01324 0.01295 N2O 0.0006232 0.00006392 CO2eq (AR5, 100 year) 11.25 12.52 HHV (Btu/gal) 124,340 138,490 LHV (Btu/gal) 116,090 129,488 Table S9 GHG emissions associated with fuel used in the life cycle of Bakken crude for transportation or as a power source for equipment at the pad. GHG emissions adopted from 11. HHV and LHV were adopted from GREET 2013

7.

The GHG emissions associated with the combustion of fuels refined from Bakken crude are adopted

from GREET 20137 (Table S10).

Combustion GHG Emissions (g/mile) Gasoline Diesel

CO2 367.8 315.9 CH4 0.0139 0.0006 N2O 0.0068 0.0007 Fuel economy (Btu LHV/mile) 4,795 3,995 Table S10 GHG emissions associated with the combustion of fuels. Adopted from GREET 2013

7.

The freshwater consumption associated with gasoline and diesel strongly depends on the source of the

crude from which they are manufactured, as well as the specific configurations of the refineries from

which they are manufactured. In this LCA, we adopt a freshwater consumption of 2.15 gal/gal gasoline

or diesel from King and Webber12, implicitly assuming that diesel and gasoline used for Bakken wells is

not sourced from Bakken itself. In our MC simulations and sensitivity analysis, we permit the freshwater

consumption to vary over the entire range proposed by King and Webber: between 1.4 and 2.9 gal/gal

gasoline or diesel.

2.2.2 Truck

In our base case LCA, we adopt a fuel economy for heavy duty truck transport of 134 ton-miles/gal,

which is the average of the two Class 8 fuel economies reported in the 2013 Vehicle Technologies

Market Report13. In MC simulations, we model the truck fuel economy as a uniform random variable

ranging from 115 to 154 ton-miles/gal (diesel) – the two limits of class 8 fuel economy reported by

ORNL. These two limits are for different modes of transport – the latter being more representative of

long haul transportation, and the former representing transportation for shorter distances.

15

2.2.3 Rail

In our base case LCA, we adopt a fuel efficiency for rail transport of 289 Btu/ton-mile (HHV basis), which

is reported in the ORNL Transportation Energy Data Book (Edition 31)14. Employing the HHV for diesel in

Table S9, this corresponds to a fuel economy of 479 ton-mile/gal (diesel) – about 3.5 times greater than

that for Class 8 trucks (Truck).

2.2.4 Pipeline

Pipelines for both crude oil and refined products are driven by electrical pumps. There is considerable

variation in reported energy usage for pipelines in the literature. In their 2009 baseline analysis of

petroleum fuels, NETL11 adopted an electricity intensity of 260 Btu/ton-mile (0.0762 kWh/ton-mile),

relying upon a figure from an early version of Argonne National Lab’s GREET model. The newest version

of GREET7 reports an “energy intensity” of 404 Btu/ton-mile, whose relationship to electricity intensity is

unclear in the GREET documentation. GHGenius15 utilizes a value of 250 kJ/tonne-km (0.101 kWh/ton-

mile) for finished products and 150 kJ/tonne-km (0.061 kWh/ton-mile) for crude.

In this LCA, we employ the data reported by Hooker16 (Table S11) for seven pipeline operators in 1981.

Although pipeline efficiency may have increased over the past 30 years, we utilize these figures as a

conservative lower bound for electricity usage. In our base case, we employ the average electricity

intensities for crude and products pipelines: 0.051242 kWh/ton-mile and 0.047670 kWh/ton-mile

respectively.

Material Movements (106 m3-km)

Specific Gravity

Actual Electrical Consumption (1012 J)

Electricity Intensity (kWh/ton-mile)

Crude 2292 0.85 282.1 0.04993 Crude 4593 0.85 287.6 0.02540 Crude 2763 0.85 350.8 0.05151 Crude 9197 0.85 1194.6 0.05269 Crude 3820 0.85 722 0.07668

Refined Products 5012 0.752 440.9 0.03569 Refined Products 2977 0.54 225.2 0.03069 Refined Products 1448 0.736 310.8 0.08707 Refined Products 17742 0.76 1628.3 0.03723

Table S11 Electricity Intensity of pipeline transportation. “Movements”, “Specific Gravity” and “Actual Electrical Consumption” are from Hooker 16. Electricity intensities (rightmost column, red) were calculated from these figures. The average electricity intensity for crude pipeline transport is 0.051242 kWh/ton-mile, and the average electricity intensity for products pipeline transport is 0.047670 kWh/ton-mile.

2.2.5 Waterway

Refined products are transported by pipeline, rail, truck and waterway. We estimated the GHG

emissions and freshwater consumption associated with waterway transport as follows:

First, we adopted a waterway fuel efficiency of 217 Btu/ton-mile from the ORNL Transportation Energy

Data Book14. The same source (Table A-10, page A-16) reports that the 2009 consumption of distillate

fuel oil for “Vessel Bunkering” was 1,485,134 thousand gallons (2.06×1014 Btu HHV), whereas the 2009

consumption of residual fuel oil for “Vessel Bunkering” was 5,464,313 thousand gallons (8.20×1014 Btu

16

HHV). Using these figures, we partitioned the overall waterway fuel efficiency into two components for

diesel (43.50 Btu HHV diesel/ton-mile) and fuel oil (173.50 Btu HHV/ton-mile)

We then adopted the following emissions for diesel and fuel oil combustion from the NETL Petroleum

Baseline Study11, which in turn were adopted from the U.S. EIA17 (Table S12):

Greenhouse Gas Emissions for Combustion (g/gallon) CO2 CH4 N2O

Diesel Fuel, Waterways 10,147 0.74 0.26 Residual Fuel Oil, Waterways 11,793 0.86 0.30 Table S12 Combustion emissions for waterway fuels (Source: 17)

We approximated the life cycle emissions for diesel and residual fuel oil used as waterway fuel by

multiplying the combustion GHG emissions by 1.25. Expressed in terms of 100-year IPCC AR5 GWPs (),

the GHG emissions for waterway diesel and residual fuel oil are 4.02×10-3 kg CO2eq/ton-mile and

1.72×10-2 kg CO2eq/ton-mile, respectively. The combined GHG emission for waterway transport is thus

2.12×10-2 kg CO2eq/ton-mile.

We model the freshwater consumption associated with residual fuel oil to be the same as diesel and

gasoline, i.e. 2.15 gal freshwater consumed/gal fuel (Section 2.2.1). Combining the diesel and fuel oil

contributions, we estimate the freshwater consumption associated with waterway transportation to be

7.52×10-5 bbl/ton-mile.

2.2.6 Summary

In Table S13 we summarize the GHG emissions associated with transportation modes in this LCA:

Transport Mode GHG Emissions (kg CO2eq/ton-mile) Freshwater Consumption (bbl/ton-mile)

Truck 0.09319 0.00038 Rail 0.02614 0.00011 Pipeline (crude) 0.03543 0.00055 Pipeline (product) 0.03296 0.00051 Waterway 0.02121 0.00008 Table S13 Summary of impacts of transport modes. GHG emissions reported using IPCC AR5 GWPs with a 100-year time horizon

3 Characteristics of Bakken Hydrocarbons Bakken wells produce crude, associated gas, and water. The three-phase mixture proceeds from the

well head to a heater treater, where they are separated***. The produced water goes to one or more

tanks, and oil goes to a separate set of tanks. The associated “raw” gas is routed to a gathering pipeline

leading to a processing plant. There, impurities and high value molecules are removed before the gas is

sent to a transmission pipeline for sale to industrial and other consumers. Gas sold to the operator of

the gathering system is outside the boundary of this LCA.

***

In some cases, some of the water is separated from the oil and gas via a “two phase separator” between the well and the heater treater.

17

Some of the associated gas exiting the heater treater is used by equipment at the pad. For instance,

some of the gas is combusted to provide heat for the heater treater. Associated gas may also be used as

fuel for gas engines that power the pumping unit (pump jack).

There is a flare at each Bakken pad, serving as a safety device in the event of an upset. In the event of

an impediment to the flow of gas to the gathering system (e.g. due to a transient capacity limitation),

the associated gas will flow to the flare. A separate pipe from the oil tank battery will go to the flare,

providing a safe disposition of organic vapors that evolve from the oil during storage.

3.1 Associated Gas The physical properties of the associated gas sent to the gathering system are summarized in Table S14.

Component mol%

N2 4.4 CO2 0.5 Methane 52.8 Ethane 22.4 Propane 13.4 Butanes 4.6 Pentanes 1.1 Hexanes+ 0.7 Table S14 Composition of Bakken associated gas.

The high heating value (HHV) of this gas is 1510 Btu/scf – typical for Bakken wells. The low heating value

(LHV) is 1378 Btu/scf. The heat content of this gas is substantially higher than that of most gas wells, due

to the increased presence of ethane and larger hydrocarbons. This corresponds to a relative decrease in

methane content: only 52.8% of the gas (by amount/mole or volume) is methane. Employing a 100-year

GWP from the IPCC AR5, 0.306 kg CO2eq will be emitted per scf of vented associated gas. By contrast,

for every scf of associated gas completely burned, 0.089 kg CO2 will be emitted.

3.2 Oil Bakken crude is both light (API > 38) and sweet (sulfur content < 0.5%), thereby requiring less energy

and chemical processing to convert it to finished fuels. Bakken has a low heating value of 18.7×103

Btu/lb, and a high heaving value of 19.9×103 Btu/lb. Additional properties of pertinence to refining are

provided in Table S15.

18

Full crude LSR Naphtha Kerosene Diesel AGO LVGO HVGO VR AR

Cut volume, % 100.0 15.0 23.5 21.9 9.3 9.4 7.5 6.8 6.5 20.9 Sulphur , wt% 0.097 0.000 0.005 0.027 0.113 0.172 0.211 0.238 0.326 0.257 Nitrogen , mass ppm 445 - - 20 191 384 744 1,062 3,093 1,610 API gravity 42.4 88.7 57.3 40.4 31.9 26.8 24.0 20.8 11.1 18.7 Hydrogen, wt% 13.6 16.4 14.6 13.5 12.9 12.5 12.5 12.3 11.9 12.2 MCR, wt% 0.7 - - - - - 0.0 0.4 9.0 3.1 Kw (Approximate) 11.8 12.7 12.0 11.8 11.8 11.7 11.9 11.9 11.7 11.9 Tb50, [°C] 259.0 46.0 130.0 233.0 317.0 370.0 425.0 485.0 588.0 482.0

Table S15 Bakken crude assay data used in refinery GHG estimation using PRELIM. The temperature ranges corresponding to each cut (LSR, Naphtha, ... AR) are reported in the PRELIM documentation

3. Tb50 is the temperature that represents 50% of

the mass yield of each fraction on mass basis. MCR is the “micro carbon residuum”, also known as the Conradson Carbon Residue (CCR). Kw is the Watson (UOP) characterization factor.

4 Calculations by Life Cycle Phase We divide the life cycle of Bakken crude into the following phases: Drilling and Completion, Production,

Crude Transportation, Refining, Transportation of Refined Products, and Vehicle Operation.

4.1 Drilling and Completion Bakken crude is primarily extracted from the sandstone/siltstone Middle Bakken formation, which is

sandwiched between two shale formations (Upper and Lower Bakken). The Three Forks formation sits

below the Bakken formation. Crude Production in the Williston Basin comes from both the Bakken and

Three Forks, with some multi-well pads producing from both formations.

4.1.1 Data

4.1.1.1 Production and EUR

In our previous LCA of Marcellus shale gas, we revealed that the estimated ultimate recovery (EUR) of

the well is a key factor in the environmental characterization of the resource18. In this study, we

calculated EURs for 3513 hydraulically fractured Bakken wells (horizontally) drilled since 2010, using

production data from the IHS Enerdeq service. The wells were drilled and completed by all Bakken

operators. As in our previous work, we used the method of Ilk to calculate EURs, defining the end of life

by a critical minimum flowrate or a maximum lifetime of 40 years19.

We then restricted this dataset to exclude wells for which water production and oil production data

were incomplete. Production figures (kbbl crude vs time, kbbl produced water vs time, EUR, and well

lifetime) for the resulting 2264 wells were then employed in the LCA.

In our base case, we utilize the average EUR, average 3 month production, average 6 month production,

average 12 month production, and well lifetime. These figures, along with other key statistics of the

datasets are reported in Table S16.

19

p10 p50 p90 Mean

3 month production (kbbl) 9 26 52 29 6 month production (kbbl) 19 46 85 50 12 month production (kbbl) 35 75 133 81 EUR (kbbl) 134 320 651 372 Well lifetime (months) 231 404 459 370 Table S16 Characteristics of Bakken Wells drilled since 2010. EURs calculated using the method of Ilk. Well lifetimes were defined by a critical level of production or a maximum of 40 years.

We note that the EURs calculated via this approach (and reported in Table S16) do not include oil

collected during flowback. Our approach for calculating this additional quantity is discussed in Section

4.1.7.

We also employed Monte Carlo (MC) simulations to assess the range of carbon footprints possible for

Bakken crudes. In our MC simulations, randomly selected well EURs and then selected the

corresponding 3, 6, and 12 month production (kbbl) and well lifetime (months) to accurately correlate

these figures. The correlations among these variables are illustrated in Figure S12.

20

Figure S12 Correlated Production Data for 2264 wells (XTO and other producers) utilized in the LCA of Tight Oil. Production volumes at 3, 6 and 12 months were obtained from the IHS Enerdeq service. The EUR for each well was calculated using monthly timeseries for each well (IHS Enerdeq) using the method of Ilk (19)

4.1.1.2 GOR

The gas-oil ratio (GOR) defines the amount of gas that is produced along with every barrel of oil. The

GOR for Bakken wells varies throughout the play. We estimated the GOR for Bakken wells using the

21

results of production tests for 57 wells drilled and completed by XTO Energy (an ExxonMobil affiliate) in

2013. Key statistics are reported in Table S17.

In our base case LCA, we employed the average GOR. In MC simulations, we randomly selected one of

the 57 GORs per trial. GOR was not correlated with any other variable reported in Table S17.

Figure S13 Gas-oil ratios from 57 Bakken wells. GORs were estimated during production tests, during which the gas and oil flows were measured. The blue box contains the 25

th and 75

th percentiles, the red line denotes the median, the gray “x”

denotes the mean (1357 scf/bbl), and the whiskers denote the minimum and a distance of 1.5×IQD beyond the 75th

percentile (IQD = p75 – p25). Outliers (data exceeding the right-hand whisker) are represented by red “+” symbols.

p10 p50 p90 Mean

GOR (scf/bbl) 603 1,327 2,186 1,357 Length of Surface Casing (ft) 1,368 2,025 2,274 1,916 Length of Intermediate Casing (ft) 10,266 10,749 11,509 10,884 Length of Liner (ft) 9,821 10,304 11,095 9,984 Length of Tubing (ft) 9,181 9,824 10,592 9,852 Total cement (sack/well) 1,312 1,430 1,663 1,488 Total water pumped (bbl/well) 58,419 76,145 85,790 72,975 Total proppant (lb/well) 2,520,590 2,766,877 3,387,325 2,818,647 Diesel fuel for hydraulic fracturing (gal/well) 13,293 23,402 36,469 24,413 Diesel fuel for drilling (gal/well) 31,794 53,730 89,979 58,706 Table S17 Properties of 57 wells drilled and completed by XTO Energy in 2014.

4.1.1.3 Other Data

Statistics from several other key data sets from these 57 wells are also included in Table S17, including

features of the well design (casing, cement), inventory data for hydraulic fracturing (freshwater

pumped, proppant, and diesel fuel for frac pumps), and diesel fuel usage for drill operation.

4.1.2 Well Casings

4.1.2.1 Raw material extraction through manufacture

Bakken wells consist of several layers of steel casing with intermediate cementing to assure well

integrity. Summary statistics for the well properties for 57 wells drilled and completed by XTO in 2013

are reported in Table S17.

In our base case LCA, we employed the average well features (conductor depth, tubing, etc.). In MC

simulations, we randomly selected one of the 57 well features per trial.

22

The total mass of steel was calculated by multiplying the length of tubings by their linear weight:

Surface Casing Weight: 36 lb/ft

Intermediate Casing Weight: 29 lb/ft

Liner Casing Weight: 13.5lb/ft

Tubing Weight: 13.5 lb/ft

The corresponding life cycle carbon emissions of the steel casings were calculated using the model

"Reinforcing steel, at plant/RER WITH US ELECTRICITY U" in the US-EI 2.2 database, available in Simapro

820. This process was modified to use the grid mix previously discussed (Impacts associated with the

Electricity Grid). Expressed in terms of 100-year GWPs from the IPCC AR5, 3.69×105 kg CO2eq/well are

emitted in association with the part of the life cycle of the casings extending from raw mineral

extraction to manufacture.

We estimated the freshwater consumption associated with the manufacture of casings by multiplying

the total mass of steel by a life cycle water consumption of 2.90 kg H2O/kg steel, adopted from Norgate

et al.21 From this, we estimate freshwater consumption associated with the casings to be 4307 bbl/well.

4.1.2.2 Transportation to the well pad

We also estimated the GHG emissions and water consumption associated with the transport of casings

to the Williston basin. If the steel casings are manufactured in Youngstown, OH, then the rail transport

distance will be 1432 - 1532 miles, with an average value of 1482 miles. We assumed a subsequent truck

transport distance of 20 miles. The fuel for both modes of transport was diesel, and we utilized the fuel

usage (per ton-mile) discussed previously (Truck, Rail). Expressed in terms of 100-year GWPs from the

IPCC AR5, 10,567 kg CO2eq are emitted per well in association with the transportation of casings.

Further employing the freshwater intensity of diesel previously discussed (Truck), we estimate that 43.2

bbl of freshwater are consumed per Bakken well as a consequence of truck and rail transportation of

casings.

4.1.3 Well Cementing


As previously mentioned, cement is injected between well casings to assure well integrity. Summary

statistics for the cement usage for 57 wells drilled and completed by XTO Energy (an ExxonMobil

affiliate) in 2013 are reported in Table S17. One sack is equivalent to 94 lbs. Thus, on average, 63.5

tonne of concrete are used per well.

Figure S14 Total cement used for 57 Bakken wells drilled in 2013. The blue box contains the 25th

and 75th

percentiles, the red line denotes the median, the gray “x” denotes the mean (70 tons), and the whiskers denote the minimum and a distance of

23

1.5×IQD beyond the 75th


The corresponding life cycle carbon emissions associated with the extraction through manufacture of

cement were calculated using the model "Portland cement, at plant NREL/US"" in the US-EI 2.2

database, available in Simapro 8. Like the life cycle model for steel casings, this process was modified to

use the grid mix previously discussed (Impacts associated with the Electricity Grid). Expressed in terms

of 100-year GWPs from the IPCC AR5, 8.69×104 kg CO2eq/well are emitted in association with the part of

the life cycle of the cement extending from raw mineral extraction to manufacture.

In this analysis, we assume 5.2 gallons of freshwater are added to each sack of cement. Mixing is done

at the drilling site. Thus, on average, 184 bbl of fresh water are consumed for cementing per well.


We assume that cement is manufactured at a facility between 25 and 100 miles from the drilling site,

with an average of 63 miles. Transport over this distance was assumed to be entirely via heavy duty

trucking, using the impacts previously discussed (Truck). Expressed in terms of 100-year GWPs from the

IPCC AR5, 407 kg CO2eq/well are emitted in association with the transport of cement to the drilling site.

Further employing the freshwater intensity of diesel previously discussed (Fuels), we estimate that 1.67

bbl of freshwater are consumed per Bakken well as a consequence of truck and rail transportation of

(unmixed) cement to the pad.

4.1.4 Proppant


The hydraulic fracturing process facilitates the flow of oil and gas from a reservoir by creating fissures,

which are “propped” open by sand or ceramic particles commonly referred to as “proppant”. The

fissures are created by explosives (“perforation”), expanded by water injected at high pressure, and

“propped” by proppant suspended in the water. During the flowback phase of the HF process, the

water returns to the surface, leaving behind the proppant that keeps the fissures open. Proppant used

for Bakken wells consists of a mix of sand and ceramic beads22. As we report in Table S17, 2,818,647

lb/well are used on average.

Figure S15 Total proppant used in 57 Bakken wells drilled in 2013. The blue box contains the 25th

and 75th

percentiles, the red line denotes the median, the gray “x” denotes the mean (1.41×10

3 tons), and the whiskers denote the maximum and a

distance of 1.5×IQD preceding the 25th

percentile (IQD = p75 – p25). Outliers (data exceeding the left-hand whisker) are represented by red “+” symbols.

24

In this LCA, we model the extraction through manufacturing phases of proppant using the model "Sand,

at mine/CH WITH US ELECTRICITY U" in the US-EI 2.2 database, available in Simapro 8. This process was

modified to use the grid mix previously discussed (Electricity Mix). Expressed in terms of 100-year GWPs

from the IPCC AR5, 5.14×103 kg CO2eq/well are emitted in association with the part of the life cycle of

the casings extending from raw mineral extraction to manufacture.

In this LCA, we did not model freshwater consumption directly associated with the mining of sand.

However, we did account for freshwater consumption associated with the electricity utilized in process

(2.92 Watt-hours/kg sand). Employing the freshwater consumption of the U.S. grid (452 gal/MWh,

Figure S11), this amounts to 2.13×102 kg H2O/kg sand. The corresponding amount of freshwater

consumption per Bakken well is 40 bbl/well.


Like well casings, we model the transportation of proppant as a combination of rail and heavy duty

trucking – both fueled by diesel. We employ a rail transport distance of 1000 – 1100 (average, 1050)

miles, suggestive of the distance between Lasalle County, IL and the Bakken play. We also employ a 20

mile truck transport distance from the transloading site. Following the method previously discussed for

steel casings, and expressing our findings in terms of 100-year GWPs from the IPCC AR5, we obtain an

estimate of 41,303 kg CO2eq/well for the emissions associated with transportation of proppant to the

well pad. The corresponding freshwater consumption is estimated to be 169 bbl/well.

4.1.5 Gel Frac Additives


Various chemicals are typically added to the mixture of water and proppant, including scale inhibitor,

corrosion inhibitor, and biocide. Specific formulations are reported at the FracFocus website22. From a

review of Bakken wells at FracFocus, we estimated that 0.54% – 0.67% (by mass) of the material injected

during fracturing was composed of additives. Thus, we modeled the mass fraction of additives in gel

formulations as a uniform random variable on this range (average 0.61 wt%).

Additives include guar gum (a gelling agent), ethanol (a surfactant), potassium formate (a gel

crosslinker), ethylene glycol (a scale inhibitor), and sodium chloride (a breaker), among other

proprietary and non-proprietary components. A survey of these or related molecules in the US-EI

database revealed that the carbon footprints of these molecules range from 1 – 4 kg CO2eq/kg additives.

Therefore, we modeled the life cycle GHG emissions of frac additives as a uniform distribution on this

range (mean: 2.5 kg CO2eq/kg additives). We investigated the impact of gel additives on the carbon

footprint of tight oil in our sensitivity analysis.

In our base case LCA, 72,975 bbl (11.6 million kg) of freshwater are injected during the fracturing

process, along with 2,818,647 lb (1.28 million kg) of proppant, for a total of 12,879 tonne/well of water

and proppant. Thus, we estimate that 12879 0.0061

1−0.0061 = 78.65 tonne/well of additives are injected along

with proppant and fresh water. The corresponding GHG emissions for the additives amount to 196,613

kg CO2eq/well.

25

Lacking information regarding the specific manufacturing processes for many of the frac additives, we

approximated the freshwater consumption for their life cycles to be the same as diesel (Fuels). Our

estimate of the corresponding freshwater consumption for a Bakken well is thus 1,216 bbl H2O/well.

This is 1.6% of the amount of freshwater pumped directly for hydraulic fracturing (Table S17).


In this analysis, we assume that additives are manufactured in Houston and are transported by rail to

the Williston basin. We model the transportation distance as a uniform random variable ranging from

1600 – 1700 miles (average 1650 miles). Thus, in our base case (1650 miles), 143,000 ton-miles of

transport of additives are required per well. Again, employing the findings previously discussed (Fuels,

Truck) 3,737 kg CO2eq/well are estimated to be emitted due to transportation of frac additives. The

corresponding freshwater consumption (by way of the diesel life cycle) is 15.3 bbl/well.

4.1.6 Drilling and Hydraulic Fracturing

Diesel is used as a fuel for the drilling rig as well as pumps employed in the hydraulic fracturing process.

Summary statistics for the diesel fuel usage for 57 wells drilled and completed by XTO Energy (an

ExxonMobil affiliate) in 2013 are reported in Table S17.

Figure S16 Diesel used as fuel for the drilling rig and hydraulic fracturing pumps for 57 wells completed in 2013. The blue box contains the 25

th and 75

th percentiles, the red line denotes the median, the gray “x” denotes the means (59,000 and 24,000

gallons respectively), and the whiskers denote the minima and distances of 1.5×IQD beyond the 75th

percentiles (IQD = p75 – p25). Outliers (data exceeding the right-hand whiskers) are represented by red “+” symbols.

In our base case LCA, we employed the average diesel usages for drilling and hydraulic fracturing.

Combining the results in Table S17 and Table S9, we estimate base case GHG emissions for HF of

3.06×105 kg CO2eq/well (AR5, 100 year), and base case GHG emissions for drilling of 7.35×105 kg

CO2eq/well (AR5, 100 year).

In MC simulations, we randomly selected diesel volumes for drilling and fracturing among the 57

aforementioned wells. There was no correlation between the fuel consumption for fracturing and

drilling.

26

There are two aspects of freshwater consumption associated with drilling and hydraulic fracturing: First,

there is direct freshwater consumption for both activities, using freshwater at the pad. There is also

freshwater consumption associated with the diesel employed as a power source for the drill and the frac

pumps. The average direct freshwater consumption at the pad, as reported in Table S17, is 72,975

bbl/well. By contrast, freshwater consumption associated with diesel used to power the frac pumps is

1.25×103 bbl/well. Freshwater consumption associated with diesel used to power the drill is 3,005

bbl/well.

Figure S17 Total volumes of water injected during the hydraulic fracturing process for 57 Bakken wells completed in 2013. The blue box contains the 25

th and 75

th percentiles, the red line denotes the median, the gray “x” denotes the mean (3.1×10

6

gallons), and the whiskers denote the minimum and a distance of 1.5×IQD beyond the 75th


4.1.7 Completion Flowback

Following drilling and hydraulic fracturing, the well must be completed. A part of this process is

flowback, whereby gas, oil and water – primarily frac fluid – are recovered and separated at the surface

using a temporary separator. XTO Energy, like many operators in the Bakken, flares the associated gas

separated from the liquids during flowback. A video representative of Bakken flowbacks has been

prepared by researchers at the University of Texas at Austin23.

Figure S18 Flowback gas flared during Bakken completions. Flowback gas volumes from 32 wells completed in 2013 are reported. The blue box contains the 25

th and 75

th percentiles, the red line denotes the median, the gray “x” denotes the

mean (7.9×106), and the whiskers denote the minimum and a distance of 1.5×IQD beyond the 75

th percentile (IQD = p75 –

p25). Outliers (data exceeding the right-hand whisker) are represented by red “+” symbols.

In Figure S18 we report a representative sample of flowback gas volumes from Bakken well completions.

The GHG emissions associated with flowback flaring depend upon the flare efficiency, i.e. the fraction of

gas that is combusted. In this analysis, we employ a flare efficiency of 98%, following the convention of

the U.S. EPA24. That is, we divide the flowback gas into two portions, applying the emission factor of

0.089 kg CO2/scf to the 98% of the flowback gas that is burned, and 0.306 kg CO2eq/scf to the 2% of the

remaining unburned flowback gas (100-year GWP, IPCC AR5). For our base case, in which 7.9 MMscf of

27

gas is flared during flowback (Figure S18), this amounts to 48,685 kg CO2eq/well for the unburned

flowback gas, and 689,938 kg CO2eq/well for the combusted flowback gas.

In our sensitivity analysis, we varied the flare destruction efficiency from 90% to 100% to investigate its

effect upon the upstream and life cycle GHG emissions.

During flowback, a quantity of oil is collected. This oil is correlated with the amount of gas flared during

flowback. On average, 5970 bbl of oil is collected during flowback. We add this quantity to the

forecasted EUR (Section 4.1.1.1 Production and EUR), such that a typical quantity of oil produced over

the well life cycle is 378 kbbl/well.

4.2 Production Production of oil (and gas) from Bakken wells involves a variety of equipment and processes. The

production phase of the Bakken life cycle includes artificial lift, separation of produced fluids (water, gas,

and oil), storage and transport of crude and water, and the transport and flaring of gas, among other

activities.

For about three months after well completion, oil, gas and water will be produced as a result of natural

flow. Subsequently, a pumping unit (pump jack) will be employed for “artificial lift”. The produced

fluids flow to a three-phase separator known as a “heater treater”, where they are separated into oil,

water, and associated gas. Some of the gas is used as fuel for the pumping unit and heater treater - the

rest is sold or flared. Water and oil flow from the heater treater to their own tanks. Hydrocarbon vapors

entrained in the crude and water evolve from solution and flow through piping to the flare. In this LCA,

we have not considered vapor recovery from the tanks (i.e. repressurization and injection of tank vapors

into the gathering system).

In our base case LCA, the heater treater is hooked up to a gathering pipeline before post-flowback

production is initiated. However, some of this gas may be flared due to pipeline capacity limitations. In

some cases, operators produce oil from Bakken wells without a hookup. In this case, associated gas that

is not used as lease fuel is sent to the flare until a gathering pipeline can be installed. We have

considered three such scenarios to evaluate the sensitivity of the life cycle GHG emissions to flaring due

to the lack of a gas hookup:

1. Flaring without a hookup for three months, followed by collection of gas with intermittent

flaring due to capacity limitations

2. Flaring without a hookup for six months, followed by collection of gas with intermittent flaring

due to capacity limitations

3. Flaring without a hookup for twelve months, followed by collection of gas with intermittent

flaring due to capacity limitations

4.2.1 Pumping Unit

Initially, the well produces fluids due to reservoir pressure alone. After about three months, a pumping

unit is employed for artificial lift. The prime mover for the pumping unit will be either a 60 hp electric

28

motor or gas engine. If the prime mover is a gas engine, it will typically be fueled with associated gas

from the well. In our base case, we consider the pumping unit to be powered by an electrical motor.

Production is a transient process. Initially, many wells produce continuously. However, as the wells age,

the pumping units will be configured to produce intermittently, which gives the formation time to

produce into the well bore and maximize the amount of oil withdrawn per stroke of the pumping unit.

Hence, the prime movers (e.g. gas engines) will also operate intermittently.

To estimate the fraction of time that the wells are producing (and thus, the fraction of time that prime

movers are operating), we analyzed the down times of all wells both operated by XTO Energy and

employing artificial lift in 2014. From our assessment of these wells, which were largely drilled and

completed over the past ten years, we determined that wells on artificial lift operate 82% of the time on

average (Figure S19). We also found that the utilization was independent of the completion date, that is,

the fraction of time that the pumping unit is operating is independent of the well age.

Figure S19 Fractional utilization of pumping units associated with Bakken wells operating throughout 2014.

As wells age, the amount of gas and oil produced by them will decrease. In response, the prime mover

may be replaced with another of lesser rating. In this LCA, we assume the 60 hp prime mover is

replaced with a 30 hp machine after 10 – 15 years. In the base case, the prime mover is replaced at 12.5

years. In MC simulations, the time of replacement is modeled as a uniform random number on the

aforementioned interval.

29

In our sensitivity analysis, we also consider a scenario in which the pumping unit is driven by a gas

engine. Engines for Bakken pumping units (60 hp) in the Bakken typically consume 11 – 13 Mcf††† of

associated gas per day. In our base case, we use a fuel consumption rate of 12 Mcf/day. In our MC

simulations and sensitivity analysis, we treat the fuel consumption as a uniform random variable on the

aforementioned range. Fuel consumption is halved when the 60 hp engine is replaced by a 30 hp engine

later in the well’s life.

4.2.1.1 Electricity Usage - Motor

We assume that the efficiency of the motors (the 60 hp motor in the first phase of the well life and the

30 hp motor in the second phase of the well life) is 90%, i.e. 0.9 J work/J electrical input. Hence, the

electrical input for the first phase of the well life is

60 hp × (12.5 yr − 0.25 yr) ×

365 dayyr

×24 hrday

×7.457 × 10−4 MW

hp

0.9 × 0.82 = 4355 MWh

The electricity usage over the remaining years (using a 30 hp motor) is 3,266 MWh. Employing the

electricity impacts previously discussed (2.1 Impacts associated with the Electricity Grid), the

corresponding GHG emission is 5,268,916 kg CO2eq/well (AR5, 100-year) and the corresponding

freshwater consumption is 81,877 bbl/well.

4.2.1.2 Fuel Use – Natural Gas Engine

In our sensitivity analysis, we consider a scenario in which the pumping unit is driven by a natural gas

engine throughout the life of the well. As mentioned previously, internal data show that gas engines

consume 12,000 scf/day on average when a well is producing continuously. Reducing this by 18% (1 –

82%) to account for intermittency, and multiplying by the duration of the first phase of the well life on

artificial lift (12.25 years), we estimate the associated gas consumption for the pumping unit prime

mover to be 43.8 million scf per well for the first phase of the well life (3 months – 12.5 years, on

average).

We assume that the gas consumption in the second phase of the well life is 6,000 scf/day: 50% less than

that in the first phase of the well life, suggestive of replacement of a 60 hp engine with a 30 hp engine.

Reducing this by 18% (1 – 82%) to account for intermittency, and multiplying by the duration of the

second phase of the well life on artificial lift (18.4 years on average), we estimate the associated gas

consumption for the pumping unit prime mover to be 32.8 million scf/well for the second phase of the

well life.

Employing the emission factor for combusted gas (2.2.1 Fuels), the corresponding GHG emissions are

6,792,705 kg CO2eq/well (AR5, 100 year).

†††

1 Mcf = 1000 scf

30

4.2.2 Heater Treater

4.2.2.1 Fuel Use

Heater treaters heat the fluid produced by the well to break emulsions or promote the separation of

phases (gas, oil and water). Internal data from 2014 show that treaters consumed 6.16 - 9.33 thousand

scf/day, with the variation due to seasonal variation in temperature.

Treater fuel use is proportional to liquid throughput. In 2014, on average, XTO Bakken wells in North

Dakota produced 90.1 barrels of oil per day, and 56.5 barrels of water per day. Therefore, a

representative fuel use metric for Bakken heater treaters is 52.84 scf gas/bbl throughput (oil and water).

We estimated the average life cycle fuel consumption for the heater treater as follows:

(372.10 kbbl

well− 28.77

kbbl

well) × (1 + WOR) × 52.84

scf gas

bbl oil and water= 2.8 × 104 scf/well

where the average life cycle “water oil ratio” (WOR) was 0.544 bbl produced water/bbl oil (4.2.4

Produced Water and Salt Water Disposal). The fuel gas consumption is about 5.5% of gross gas

production. Employing the emission factor for combusted associated gas (3.1 Associated Gas), we

estimate the life cycle GHG emissions associated with heater treater fuel to be 2,481,381 kg CO2eq/well.

4.2.2.2 Fugitive Emissions

In shale gas operations, some of the most noteworthy sources of fugitive methane emissions are

pneumatic controllers, e.g. level controllers for vertical gas-water separators. By contrast, the “dump

valves” for the heater treaters employed in tight oil operations are typically mechanically controlled.

Nevertheless, we do account for other possible fugitive emissions from the heater treater, utilizing the

method of the EPA discussed in the Annexes of the “Inventory of U.S. Greenhouse Gas Emissions and

Sinks: 1990 – 2012”25 (EPA’s Annex 3, Table A-147). EPA reports a methane emission factor of 19 scf

CH4/heater-treater/day. Thus, we estimate the life cycle fugitive emissions from the heater treater as

follows

19 scf CH4

heater-treater∙day×

scf associated gas

0.528 scf CH4×

1 heater-treater

well× 30.87 years = 4.05 × 105

scf gas emitted

well

We multiply this quantity by 0.306 kg CO2eq/scf vented or leaked gas (3.1 Associated Gas) to obtain a

life cycle emission of 1.64×105 kg CO2eq/well.

In our Monte Carlo simulations and sensitivity analysis, we sought to assess the sensitivity of the

upstream and life cycle GHG emissions of Bakken crude upon the EPA emission factor for heater

treaters. EPA does not report any measure of precision of this factor. Therefore, we adopted a

normalized confidence interval of 27% reported by EPA for two phase separators for water and gas26,

and modeled the emission factor for heater treater fugitive emissions as a lognormal distribution with a

mean of 19 scf CH4/ day and a standard deviation of

𝜎 = 19√exp ((ln(1 + 0.27))2

1.64485) − 1

scf CH4

heater-treater∙day= 3.57

scf CH4

heater-treater∙day

31

4.2.2.3 Recirculation Pump

To avoid the buildup of residual material in the bottom of the heater treater, oil from the storage tanks

is regularly recirculated to the heater treater. Recirculation occurs for about 1.5 hours per week, using a

pump driven by a 10 hp gasoline-fired engine, for a total of about 24,000 hphr over the well’s lifetime.

We estimate the GHG emissions for this small stationary combustion source using EPA’s AP-4227, which

reports emissions for uncontrolled gasoline engines of 1.08 lb CO2/hphr, or 154 lb CO2/MMBtu (Table

3.3-1). From the latter, we estimate total gasoline consumption for the recirculation pump of 1459

gallons/well. Using the information in Table S9, one obtains a life cycle emission of 16,413 kg CO2/well

for the operation of the recirculation pump.

The life cycle water consumption associated with the gasoline used for operating the recirculation pump

was estimated by multiplying the gasoline consumption by the estimate of King and Webber for life

cycle water consumption for fossil fuels (2.2.1 Fuels). This estimate is 75 bbl freshwater/well.

4.2.3 Tank Vapor Flaring

A heater treater provides only a single “stage” of separation. Thus, some of the molecules typically

found in the associated gas will accompany the crude to its tank, where they may separate at the tank

pressure. The composition of those vapors will depend upon the composition of the hydrocarbons

produced from the well and the effectiveness of separation at the heater treater, among other factors.

Key properties of tank vapors from 36 Bakken wells in 7 counties of North Dakota are reported in Figure

S20. The proportion of tanks vapors to crude is defined by the flash factor. In our analysis, we employ a

flash factor defined by the key statistics of a study conducted by the North Dakota Department of

Health28, modeling this parameter as a lognormal distribution with a mean of 55.26 scf vapors/bbl crude

and a 90th percentile of 97.91 scf vapors/bbl crude.

Figure S20 Properties of tank vapors from 36 Bakken wells. The blue box illustrates the 25th

and 75th

percentiles of the data. The red line denotes the median, and the gray “x” denotes the mean. The whiskers extend to the minima and maxima of the data sets.

Combination of the information reported in Figure S20 yields an emission factor for flared tank vapors of

0.132 kg CO2/scf, and an emission factor for vented tank vapors of 0.114 CO2eq/scf (AR5, 100-year). By

32

contrast, as previously discussed, the emission factor for vented associated gas is 0.306 kg CO2eq/scf,

and the emission factor for combusted associated gas is 0.089 kg CO2/scf. The emission factor for

combusted tank vapors is higher than that of associated gas due to the enrichment of larger

hydrocarbons in the former, resulting in the emission of more carbon per scf of gas burned. The

emission factor for vented tank vapors is lower than that of associated gas due to the reduced methane

content of the former.

As discussed previously (4.1.7 Completion Flowback), we employ a flare efficiency of 98%, following the

convention of the U.S. EPA. That is, we divide the tank vapors into two portions, applying the emission

factor of 0.132 kg CO2/scf to the 98% of the tank vapors that are successfully combusted at the flare,

and 0.114 CO2eq/scf to the 2% of the tanked vapors that are not. Combining this with the

aforementioned flash factor, we obtain a tank vapor emission factor of 7.28 kg CO2eq/bbl oil delivered

to the tank. Multiplying this by the oil EUR, we obtain a life cycle estimate of GHG emissions associated

with tank vapor flaring of 2.7×106 kg CO2eq/well.

4.2.4 Produced Water and Salt Water Disposal

Tight oil wells produce gas, oil and water. The water produced is largely from the hydraulic fracturing

process, but water in the formation may also be produced. Separation of oil, water, and gas occurs at

the heater-treater. Produced water drains to water tanks located at the pad, and is regularly collected

via truck and transported to Class II salt water disposal (SWD) facilities.

The amount of water produced over the life cycle of a well has implications for the energy required for

its transport and disposal, as well as the amounts of scale and corrosion inhibitors required to keep the

oil flowing from the well (See Corrosion and Scale Inhibition).

To estimate the amount of water produced by Bakken wells over their lifetimes, we employed the

aforementioned IHS/Cera data set, which reports produced water volumes as well as crude production

volumes. We conducted analyses of produced water volumes (water cuts) for the aforementioned 2264

wells drilled since 2010 at 3, 6 and 12 months of production. We illustrate the time evolution of the

cumulative water cut (total produced water/total produced crude) in Figure S21.

33

Figure S21 Water cut for Bakken wells - data and forecast. Boxes heights are defined by p25 and p75; red lines indicate medians.

34

At 3, 6, and 12 months, the distributions of the cumulative water cuts were found to be roughly

lognormal (Figure S22).

Figure S22 Distributions of cumulative water cuts (cumulative produced water/cumulative oil) at 3 (A), 6 (B), and 12 (C) months of production. Data from 2264 drilled since 2010 (Source: IHS/Cera Enerdeq browser). At each time, the distribution is approximately lognormal (fit: red line).

Moreover, the time evolutions of the p75 and p25 of each distribution were well-fit by a power law (Table

S18).

Equation b1 b0 R2

log10(Water Cut p75, bbl/bbl crude) = b1*log10(Time, months) + b0 -0.146 0.207 96%

log10(Water Cut p25, bbl/bbl crude) = b1*log10(Time, months) + b0 -0.083 -0.376 94% Table S18 Parametrization of the time evolution of the p25 and p75 for the cumulative water cut for Bakken crude

Using these results, we estimated the life cycle volume of produced water as follows:

35

1. We estimated the well lifetime from our EUR calculations as previously discussed (Figure S12,

370 months for the base case; selected along with the EUR in MC runs).

2. We then estimated the p75 and p25 for the cumulative water cut at the end of the well life using

the equations in Table S18. For a well lifetime of 370 months (Figure S12), these yield p25 =

0.257 bbl produced water/bbl crude and p75 = 0.682 bbl produced water/bbl crude.

3. We then modeled the cumulative water cut at the end of well life as a lognormal distribution,

parametrizing it with this p75 and p25. For a well lifetime of 370 months, the average amount of

produced water is 0.54 bbl produced water/bbl crude.

4. We then estimate the life cycle produced water by multiplying this number by the oil EUR (base

case 372 kbbl/well, otherwise selected by MC as discussed previously). In our base case

202,251 bbl of water is produced/well over its lifetime.

We calculate the impacts associated with transport and disposal of the produced water as follows: The

distance between a Bakken well and a class II disposal well is often less than 15 miles. In our LCA, we

model this distance as a uniform distribution ranging from 10 – 15 miles (average 12.5 mi). Water trucks

are fueled by diesel, and typically carry as much as 7800 gallons of produced water. In our base case

LCA, this yields 443,000 ton-miles of transport of produced water.

Utilizing the fuel economy for trucks previously discussed (Truck), we obtain a life cycle diesel fuel usage

for wastewater transport of 3300 gal/well. Applying the life cycle emission factors reported in Table S9,

we obtain an estimate of GHG emissions for transportation of wastewater of 41,274 kg CO2eq/well (100

year, AR5).

Freshwater is consumed in association with wastewater transport by way of the fuel used in that

transport. Multiplying the aforementioned 3300 gal/well by the freshwater consumption factor

reported by King and Webber (2.2.1 Fuels), we estimate that 169 bbl of freshwater is consumed in

association with wastewater transport over the life cycle of a Bakken well.

Once produced water arrives at a SWD site, it is pumped through one or more tanks to allow particles to

settle, and finally injected into a saline aquifer using an electricity-driven pump. We estimate the

electricity usage using the following formula:

𝑊 =1

𝜀𝑉Δ𝑃

1

For SWD in the Williston basin, we estimate the pressure change (P) to be 1535 psi. V is the volume of

wastewater injected (202,251 bbl), and we adopt a pump efficiency of 90% (work energy/electrical

energy). From Eq. 1, we obtain a total electrical load for SWD over the well lifetime of 105 MWh. Using

the aforementioned electrical grid carbon footprint (Table S8), we obtain a carbon footprint for SWD

from Bakken wells of 72,633 kg CO2eq/well.

The freshwater consumption associated with injection is primarily driven by the freshwater

consumption associated with the electricity used. Multiplying the aforementioned 105 MWh by the

freshwater consumption associated with grid electricity (Figure S11), we estimate 1,129 bbl of

36

freshwater will be consumed in associated with injection of wastewater into SWD over the life cycle of a

Bakken well.

4.2.5 Corrosion and Scale Inhibition

To prevent corrosion of the casings and production equipment and formation of scale within the well

(which in turn affects the rate of flow of oil), inhibitors of these processes are routinely injected into the

well.

4.2.5.1 Inhibitors

Corrosion inhibitors vary in composition, but are largely composed of water and methanol. We modeled

corrosion inhibitor as a mixture of 36% (wt) methanol in water, with a specific gravity of 0.95. We

utilized the US-EI database in SimaPro 8 to estimate the carbon footprint of Methanol (NREL/USLCI

process), explicitly accounting for differences between the electrical grid mix in that process and the

aforementioned grid mix. We estimated the water footprint of Methanol from the electricity use

associated with its life cycle. From this, we estimate the freshwater consumption for corrosion inhibitor

to be 0.21 gal/kg inhibitor. Moreover, we estimate that the life cycle GHG emissions associated with

corrosion inhibitor are 0.23 kg CO2eq/kg inhibitor for a 100-year AR5 GWP.

Scale inhibitors are largely composed of ethylene glycol, ammonium chloride, and water; We model it as

a mixture of 20% (wt) ethylene glycol, 10% (wt) ammonium chloride, and 5% (wt) methanol in water

(65%, wt), with a specific gravity of 1.19. We utilized the US-EI database in SimaPro 8 to estimate the

carbon footprint of Methanol (NREL/USLCI process), as previously discussed. Ammonium chloride and

ethylene glycol were modeled likewise, using information in the US-EI 2.2 processes "Ammonium

Chloride, at plant/GLO WITH US ELECTRICITY U" and "Ethylene Glycol, at plant/RER WITH US

ELECTRICITY U". From this, we estimate the freshwater consumption for corrosion inhibitor to be 0.71

gal/kg inhibitor. Moreover, we estimate that the life cycle GHG emissions associated with corrosion

inhibitor are 0.51 kg CO2eq/kg inhibitor for a 100-year AR5 GWP.

4.2.5.2 Treatment

There are two types of treatment: batch treatment and continuous treatment. In batch treatment,

additives are mixed with fresh water and then delivered to a well by truck. The mixture is then injected

down the casing of the well. The procedure may be conducted daily or weekly depending on the

requirements for the well, the effectiveness of a given additive, etc.

The amount of freshwater mixed with inhibitors for batch treatment depends on the geochemical

features of a well. A survey of batch treatments of XTO wells in the summer of 2014 revealed a broad

range, from a p10 of 152 bbl freshwater/bbl inhibitors to a p90 of 1430 bbl freshwater/bbl inhibitors. The

average freshwater was 860 bbl freshwater/bbl inhibitors (20.5 bbl freshwater/gal inhibitors).

By contrast, wells treated continuously typically have a tank of inhibitors in the vicinity of the well pad,

which are replenished periodically as needed. Continuous treatment does not typically require addition

of extra fresh water.

37

The decision to treat a well continuously or with batch treatments is dictated by the specific geological

and geochemical conditions for a given well, and is typically assessed on the basis of the flow rate of

produced water. In Table S19, we report the findings of a survey of batch and continuous treatments of

XTO wells in the summer of 2014

gal inhibitor/gal produced water bbl inhibitor/well (base case)

Average Min Max Corrosion Inhibitor batch 1.20×10

-4 1.12×10

-4 1.28×10

-4 24

continuous 6.13×10-5

5.36×10-5

6.90×10-5

12 Scale Inhibitor batch 6.24×10

-5 6.00×10

-5 6.47×10

-5 13

continuous 1.39×10-5

8.68×10-6

1.91×10-5

3 Table S19 Treatment volumes for scale and corrosion inhibition. Barrels of inhibitor reported in the final column correspond to the base case LCA, in which 202,251 bbl of water are produced per Bakken well over its lifetime (See Produced Water and Salt Water Disposal).

Using these figures, we estimated the total volumes of inhibitors as well as the total amount of

freshwater consumption associated with batch treatments. We report these figures in the rightmost

column of Table S19. Utilizing the emission factors for these inhibitors previously discussed (Inhibitors),

the life cycles of these volumes yield 2,758 kg CO2eq/well (100 year, AR5).

Freshwater consumed in association with corrosion and scale inhibition is a sum of three quantities:

1. direct freshwater consumption associated with batch treatments,

2. freshwater consumption associated with manufacture of the corrosion inhibitors, and

3. freshwater consumption associated with the manufacture of scale inhibitors.

We estimate the first of these by summation of the batch treatment volumes (24 + 13 = 37 bbl/well) and

multiplying this quantity by the freshwater required for batch treatments (860 bbl/bbl inhibitors).

Freshwater consumption associated with manufacture of corrosion and scale inhibitors was estimated

by multiplying the volumes in Table S19 by their specific gravities and their respective life cycle

freshwater consumptions (4.2.5.1 Inhibitors). Collectively, these quantities sum to 31,722 bbl/well.

4.2.6 Maintenance

Wells must be maintained over their life cycles. We assess the carbon and water footprints associated

with maintenance by way of the impacts associated with the fleet of vehicles used. In 2013, XTO Energy

operated just less than 700 wells in North Dakota, and its operators drove 2.1 million miles to maintain

them. Combining this information with the information reported for gasoline reported in Table S9 and

Table S10, we estimate that 84 bbl of gasoline are consumed over the life of a well in association with

maintenance. Combining this estimate with the the life cycle freshwater consumption and GHG

emissions for this gasoline reported in Section 2.2.1 (Fuels), we estimate that 44,068 kg CO2eq/well

(AR5, 100-year) are emitted, and 180 bbl of freshwater/well are consumed, in association with well

maintenance over the well life cycle.

38

4.2.7 Production flaring before hookup

Some Bakken wells produce oil without a gas hookup, flaring the associated gas that is not used as fuel

for a pumping unit or heater treater. In North Dakota, operators must apply for permits to flare

associated gas from Bakken wells for up to a year. Flaring for greater lengths of time may be permitted

if an operator can demonstrate a sufficient economic burden associated with the collection of

associated gas.

In our base case LCA, Bakken wells are shut in between flowback and the connection of the well to the

gathering system. We also considered three additional scenarios:

Flaring of associated gas (no gas hookup) for three months

Flaring of associated gas (no gas hookup) for six months

Flaring of associated gas (no gas hookup) for twelve months

LCAs were conducted for each scenario.

We estimated the GHG emissions associated with the flaring of associated gas as follows:

1. We estimate gross gas production over the first three, six, and twelve months of well operation

(scf/well) without a hookup by multiplying the average oil volumes for three, six, and twelve

months (Table S16) by the GOR (Figure S13).

2. We then calculate gas volumes associated with operation of pumping units (Section 4.2.1.2) and

heater treaters (Section 4.2.2.1) over three, six and twelve months.

3. We subtract fuel usage from gross production to obtain estimates of flared gas volumes

4. Modeling the flare efficiency as previously discussed (Section 4.1.7), we apply an emission factor

of 0.089 kg CO2/scf to 98% of the flared gas volume, and 0.306 kg CO2eq/scf to the remaining 2%

(Section 3.1, AR5, 100-year).

The results of this analysis are summarized in Table S20:

Months without pipeline connection Zero (Base Case) Three Six Twelve

Production Flaring Before Hookup (slip) 0 239,120 407,344 651,446 Production Flaring Before Hookup (combusted) 0 3,388,680 5,772,655 9,231,927 Table S20 GHG emissions associated with production flaring (no gas hookup) in kg CO2eq/well (AR5, 100 year).

4.2.8 Production flaring after hookup

Even if the heater treater is connected to a gas pipeline, some gas may still be flared due to

infrastructural constraints, i.e. challenges or constraints on the gathering system(s) to which the well is

connected. A gathering pipeline can only accommodate a certain flow rate of gas. If that flow rate is

exceeded – for instance, due to the connection of a new well to the system, then gas may flow to the

flare instead of the gathering pipeline.

We used monthly production data reported by the North Dakota Industrial Commission29 to estimate

the fraction of gas that is flared due to infrastructural constraints. The data reported include gross oil

39

and gas volumes, and volumes of gas sold and flared. Data are reported for all wells in North Dakota,

including those plugged and abandoned, salt water disposal wells, etc.

For each month, estimates were calculated as follows:

1. First, each well was characterized as having a gas hookup based on the reported “gas sold”: If no

gas was sold, then we treated the well as if it lacked a pipeline connection. Otherwise, reported

flaring was attributed to infrastructural constraints on the gathering system to which the well

was connected.

2. Total gross production of gas, total flaring due to infrastructural constraints, and total flaring

due to lack of pipeline connection were then summed over all wells.

3. The fraction of gas flared due to infrastructural constraints was then calculated as a ratio of the

total gas flared due to infrastructural constraints and the total gross production.

In Figure S23 we report the fractions of gross gas flared due to infrastructural constraints from June

2013 through December 2014. On average, 16.7% of gross gas produced with a pipeline connection is

flared.

Figure S23 Fraction of gas produced from Bakken wells flared due to capacity constraints (i.e. when the well is connected to a gathering system). The blue box contains the 25

th and 75

th percentiles, the red line denotes the median, the gray “x” denotes

the mean (16.7%), and the whiskers denote the minimum and maximum.

GHG Emissions from infrastructure-related flaring were calculated as follows: First, the amount of gas

that would be produced after hookup was calculated as the difference between the gas EUR and the

amount of gas flared prior to hookup (Section 4.2.7 Production flaring before hookup). In our base case,

this amounted to 505 MMscf/well. From this, the amounts of gas used for fuel (heater treater, pumping

unit) were subtracted. In our base case, the net gas after fuel use was 402 MMscf/well. Next, we

multiplied this figure by 16.7% to obtain the volume of gas flared (67 MMscf/well). Finally, modeling the

flare efficiency as previously discussed (Section 4.1.7), we applied an emission factor of 0.089 kg CO2/scf

to 98% of the flared gas volume, and 0.306 kg CO2eq/scf to the remaining 2% (Section 3.1, AR5, 100-

year).

The results of this procedure are reported in Table S21. Note that the amount of gas flared due to

infrastructural constraints is dependent upon the length of time between the beginning of production

and the connection to the pipeline. This is simply a result of the fact that gas cannot be flared due to

infrastructural constraints if it is already being flared due to a lack of pipeline hookup.

40

Months without pipeline connection Zero (Base Case) Three Six Twelve

Production Flaring After Hookup (slip) 482,081 442,186 414,119 373,393 Production Flaring After Hookup (combusted) 6,831,788 6,266,413 5,868,666 5,291,514 Table S21 GHG emissions from the flaring of associated gas due to infrastructural constraints in kg CO2eq/well (AR5, 100 year).

4.3 Crude Transportation Bakken crude is typically transported from tanks at well pads to transloading facilities, where they are

transferred to crude pipelines or rail cars. The crude is then transported to refineries. On average, 378

thousand bbl/well (48.9×106 kg/well) are transported and delivered to refineries (Section 4.1.7

Completion Flowback).

The North Dakota Pipeline Authority reports the monthly breakdown of crude volumes transported via

different modes30. We summarize their reports in Figure S24. Note that the distribution of transport

modes appears to have stabilized by December 2014. In this analysis, we use the distribution of modes

at that time, excluding the exports to Canada (1%), i.e. 60% of crude is transported by rail, 35% is

transported to non-North-Dakota refineries by pipeline, and 5% is transported to the Tesoro refinery in

Mandan North Dakota by pipeline.

Figure S24 Volumes of crude oil transported from the Williston Basin (Source: 30)

The distances between the Williston Basin and the refineries at which crude is refined vary considerably.

In 2013, Philadelphia Energy Solutions announced that 160,000 bpd of Bakken was being delivered by

rail31. Valero’s refinery in Memphis received as much as 100,000 bpd in 2013, which was largely

transported via rail to Louisiana, and then to the refinery via the Capline pipeline32. Phillips 66 has

reported that they are refining 75,000 bpd at the Bayway refinery in Linden, NJ33.

Lacking information about the volumes transported to each refinery, we modeled the distance between

transloading sites and refineries as a random number with a minimum of 320 miles, a maximum of 1850

miles, and an average of 1400 miles. This distance was used for both rail and pipeline transport, with

41

the exception of pipeline transport to the Tesoro refinery in Mandan, ND (about 230 miles from

Williston, ND). The impact of distance was explicitly considered in our sensitivity analysis.

4.3.1 Transport to Transloading

In some cases, crude is transported from the pad to transloading facilities via pipeline. In this LCA, we

assume the crude is transported from the pad to the transloading site via truck.

We model a typical distance between a pad and a transloading site (rail or pipeline) of 20 miles.

Combining this with the total volume of crude produced (EUR + flowback crude), we estimate the total

amount of crude transportation between the pad and transloading site to be 1.08×106 ton-miles/well.

Employing the truck fuel economy reported in Section 2.2.2 (Truck), we estimate an average of 8026 gal

diesel consumed per well as fuel for transportation of crude from the pad to the transloading site over

the life cycle of a well. Using the information reported in Section 2.2.1 (Fuels), the corresponding GHG

emissions and freshwater consumption are 100,526 kg CO2eq/well and 411 bbl/well, respectively.

In our sensitivity analysis and MC simulations, we model the distance between the pad and transloading

site as a uniform random number between 10 and 30 miles.

4.3.2 Pipeline

35% of the oil produced from a Bakken well amounts to 17,298.26 tonne/well. If this is transported over

a distance of 1400 miles, then the total pipeline transport is 38.9×106 tonne-km/well. As previously

discussed, the electricity requirements for crude transportation via pipeline amount to 0.051242

kWh/ton-mile of crude (Table S11). Therefore, 1,367.08 MWh of electricity will be consumed per well in

association with pipeline transportation to refineries. The GHG emissions and freshwater consumption

associated with this electricity (Figure S11) are 945,183 kg CO2eq/well and 14,688 bbl/well, respectively.

A similar analysis of the oil transported to Tesoro’s refinery in Mandan, ND yields GHG emissions and

freshwater consumption of 8,311 kg CO2eq/well and 129 bbl/well, respectively.

4.3.3 Rail

60% of the oil produced from a Bakken well amounts to 29,160 tonne/well. If this is transported over a

distance of 1400 miles, then the total rail transport is 65.7×106 tonne-km/well. Utilizing the rail fuel

efficiency previously discussed (479 ton-mile/gal diesel, Section 2.2.3), we estimate 93.8 thousand

gallons of diesel are consumed per well in association with rail transportation. The GHG emissions and

freshwater consumption associated with this diesel are 1,175,427 kg CO2eq/well and 4,804 bbl/well.

4.4 Refining

4.4.1 GHG Emissions

We employed the Petroleum Refinery Life Cycle Inventory Model (PRELIM) to estimate the GHG

emissions and product slates associated with the refining of Bakken 2,3. PRELIM is a mass and energy

based process unit-level tool that permits estimation of energy use and greenhouse gas (GHG) emissions

associated with processing of specific crude oils within a range of configurations in a refinery. In PRELIM

a material balance connects the different process units along with flow splitters that together simulate

42

different refinery configurations, while flows are split using ratios that have been obtained from

discussions with refinery experts (Figure S25).

Two Bakken crude oil assays were analyzed, to investigate the sensitivity of the results to the particular

assay. The model was run for both assays in all seven refinery configurations:

Hydroskimming

Medium conversion

o with FCC

o with gas-oil hydrocracking

o with FCC and gas oil hydrocracking

Deep conversion

o with FCC

o with gas-oil hydrocracking

o with FCC and gas oil hydrocracking

These sets of runs were conducted with both mass- and energy-based allocation to refined products to

investigate the allocation method upon the results, as well all sets of GWPs reported in Table S4. For

each set of GWPs, we employed the corresponding electricity grid mix impacts (Table 5, “lower 48”) to

ensure consistency in GHG estimation.

Mass or energy allocation methods were used to allocate the GHG emissions to all final products (i.e.

gasoline, jet fuel, diesel, fuel oil, bunker C, coke, sulfur, and naphtha catalytic reformer (NCR) hydrogen,

if a surplus of hydrogen existed), subject to the refinery configuration. For instance, if a surplus of

hydrogen was produced for a particular run, then emissions would be allocated to it.

In all PRELIM runs, results were reported based on the higher heating values (HHV) of final products, and

we considered only straight run naphtha to be fed to the naphtha catalytic reformer (NCR).

43

Figure S25 Configurations of the PRELIM refinery. The hydroskimming configuration (green units) includes the desalter, atmospheric pipestill (APS), naphtha, diesel and kerosene hydrotreaters, isomerization unit, and merox unit. “Medium conversion” refinery configurations (green and orange units) include all of the hydroskimming units as well as a vacuum distillation unit (VDU), a gas oil hydrocracker (GO-HC), a fluid catalytic converter (FCC), a feed hydrotreater for the FCC, and an alkylation unit. “Deep conversion” refineries (green, orange and blue units) will also include a delayed coker and a hydrotreater for naphtha generated from it. “Medium” and “deep” conversion refineries may exclude the GO-HC or FCC (and associated units), but not both.

44

4.4.2 Freshwater Consumption

Some refinery process units use water as a heat transfer medium for cooling or heating, whereas others

employ water directly in refinery processes. Although refineries typically reuse steam, process water

and cooling water, some water is lost to evaporation (e.g. in cooling water towers), blowdown, or other

processes. This water is consumptively lost, and is replenished with fresh water.

PRELIM does not currently account for freshwater consumption. Therefore, we modeled freshwater

consumption for refining using data from 32 ExxonMobil refineries in 2013 (Figure S26). The variability

in refinery freshwater consumption is partly a consequence of the availability of seawater for once-

through cooling – which consumes less water than closed-loop cooling – as well as the variability of

process units within those refineries. The average freshwater associated with refinery operations has

decreased in recent decades as process engineers have identified ways to use water discharged from

certain processes as feed to other processes with less stringent water purity demands. The average

refinery freshwater consumption is about 0.7 bbl/bbl crude refined; the median is about 0.5 bbl/bbl

crude refined.

Figure S26 Freshwater consumption associated with ExxonMobil refineries in 2013

Lacking information regarding the particular water demands of individual process units, we allocated

freshwater to refined products at a plant-wide level.

4.5 Transportation of Refined Products We adopted the modeling approach employed by NETL11, using updated data sources. The two primary

data sources were the reported movements of refined products reported by Association of Oil Pipe Lines

(AOPL)34 (Table S22), and the total petroleum consumption as reported by the U.S. EIA (18,771 thousand

bbl/day)35. Both sets of figures employed were from 2009, as the most recent data from AOPL were

from that year.

Mode of Transportation Fraction of total products ton-miles (in 2009)

Pipelines, 63.30% Rail 4.20% Truck 6.80% Waterway 25.70% Table S22 Reported movements of refined products (Source: 34). Total ton-miles of petroleum products in 2009 amounted to 474 billion ton-miles

To estimate the amount of transport of refined products, we divided the total transport of refined

products in the U.S. in 2009 by the total consumption of those products in the U.S., for an average

45

amount of transport of 69.2 ton-miles of transport per barrel of refined products. We then multiplied

this quantity by the volumes of gasoline and diesel manufactured from Bakken over the life cycle of a

well (196,120 bbl and 60,349 bbl respectively, in our base case with a Medium Conversion refinery with

an FCC and no gas-oil hydrocracking capacity) to get total ton-miles of transport for each refined

product. We then distributed the transport among the modes in accordance with the figures reported

in Table S22, and accounted for the GHG emissions and freshwater consumption associated with each

mode.

4.5.1 Gasoline Transportation

In our base case LCA, 196,120 bbl of gasoline will be manufactured from Bakken crude over the life cycle

of the well. Multiplying this by the transport factor of 69.2 ton-miles of transport per barrel of refined

products, one obtains an estimate of life cycle gasoline transport of 13.5×106 ton-miles/well.

Distributing the transport in accordance with the figures reported in Table S22, and employing the GHG

emissions and freshwater consumption reported in Table S13, one obtains the estimates reported in

Table S23:

46

Transportation Mode Total Gasoline Transport (ton-miles)


Freshwater Consumption (bbl/well)

Pipeline 8,590,262 283,125.42 4,399 Rail 569,970 14,896.83 60.89 Truck 922,809 85,998.92 351.50 Waterway 3,487,673 73,974 262

Total 457,995 5,075

Table S23 GHG and freshwater consumption associated with transportation of gasoline manufactured from Bakken crude

4.5.2 Diesel Transportation

In our base case LCA, 60,349 bbl of diesel will be manufactured from Bakken crude over the life cycle of

the well. Multiplying this by the transport factor of 69.2 ton-miles of transport per barrel of refined

products, one obtains an estimate of life cycle gasoline transport of 4.17×106 ton-miles/well.

Distributing the transport in accordance with the figures reported in Table S22, and employing the GHG

emissions and freshwater consumption reported in Table S13, one obtains the estimates reported in

Table S24:

Transportation Mode Total Diesel Transport (ton-miles)


Freshwater Consumption (bbl/well)

Pipeline 2,643,365 87,122.36 1,353 Rail 175,389 4,584.00 18.74 Truck 283,963 26,463.29 30.33 Waterway 1,073,215 22,763 81

Total 140,933 1,484 Table S24 GHG and freshwater consumption associated with transportation of diesel manufactured from Bakken crude

4.5.3 Vehicle Refueling

We adopt the approach employed by NETL for estimation of GHG emissions associated with vehicle

refueling. NETL estimates that 0.00125 kWh of electricity are consumed per gallon of fuel added to the

tank of a vehicle. In our base case LCA, 196,120 bbl of gasoline and 60,349 bbl of diesel are

manufactured from Bakken crude over the life cycle of the well. Therefore, we estimate 13.46 MWh of

electricity will be consumed in association with vehicle refueling over the life cycle of a well. Applying

the impacts for grid electricity reported in Figure S11, this amounts to GHG emissions of 9,309 kg

CO2eq/well and freshwater consumption of 145 bbl/well.

4.6 Vehicle Operation In our base case LCA, 196,120 bbl of gasoline and 60,349 bbl of diesel are manufactured from Bakken

crude over the life cycle of the well. GHG emissions associated with combustion of diesel and gasoline

were estimated using the information reported in Table S10. Over the life cycle of a Bakken well,

73,789,470 kg CO2eq/well are emitted in due to the combustion of Bakken-derived gasoline, and

25,968,854 kg CO2eq/well are emitted in due to the combustion of Bakken-derived diesel.

47

5 Supplemental Results Utilizing material balances and allocation, the impacts previously discussed were attributed to crude,

associated gas, and refined products. In our base case, a pipeline connection for the sale of gas is

available throughout production of crude (with the exception of the flowback phase of the well), the

crude is refined in a “medium conversion” refinery with an FCC (no gas-oil hydrocracking or resid

conversion), and energy based allocation is employed to partition upstream impacts to crude and

associated gas, as well as partitioning of “well to refinery” impacts among refined products.

We also conducted sensitivity analyses to assess the effect of the lack of a pipeline connection for the

gathering of associated gas, the use of mass allocation, the effect of plant-based allocation at the

refinery (vs. the default process-based allocation), and perturbations of other key parameters about

their mean values.

We also conducted Monte Carlo simulations, randomly selecting parameters from their distributions

and data from their datasets, to obtain distributions of the carbon and water footprints of Bakken.

These Monte Carlo simulations accounted for the correlations among variables as previously discussed

(Figure S12).

5.1 Upstream

5.1.1 Base Case, GHG and freshwater consumption

Our estimates for the base case upstream GHG emissions are illustrated on the right hand axes in Figure

S27 (a detailed breakdown is provided in Table S25). We include the GHG emissions associated with

refining and crude transportation on the axes to the left, for context.

Figure S27 Upstream GHG emissions expressed in IPCC AR5 GWPs (100-year).

As our results show, the impact associated with capacity-driven flaring is 15.2 kg CO2eq/bbl (see also

Table S25), whereas the refining of Bakken in a medium-conversion refinery with an FCC results in the

emission of 28 kg CO2eq/bbl, of which 24.7 kg CO2eq/bbl are direct emissions, and 2.5 kg CO2eq/bbl are

48

associated with purchased electricity. Our estimate of refinery emissions is consistent with the reported

GHG emissions from the Tesoro Mandan refinery (649,000 tonne CO2eq in 201336), which processed

about 60,000 barrels per day of Bakken crude in 2013.

The GHG emissions associated with crude alone are not scientifically meaningful per se, as crude has no

function other than as a feedstock for other finished products, i.e. “bbl of crude” isn’t a meaningful

functional unit. That said, the upstream emissions associated with Bakken crude are approximately the

same as those reported for the U.S. crude slate in 2005 on a “per barrel” basis (Ref 11, Table 2-6).

In Figure S28, we illustrate our estimates for the upstream freshwater consumption. Hydraulic fracturing

consumes as much freshwater as grid electricity (consumed by the pumping unit) over the life cycle of a

well. However, the freshwater consumption associated with batch treatments of corrosion and scale

inhibitors constitutes almost 16% of the upstream water footprint.

Figure S28 Upstream, midstream and refinery freshwater consumption, excluding hydropower freshwater consumption

The upstream phases of the Bakken life cycle account for 40% of the freshwater consumption from the

well to the refinery - about a third of the freshwater consumption associated with the refinery.

These estimates include the freshwater consumption associated with grid electricity, excluding

freshwater consumption associated with hydropower (Figure S3 - Figure S11). If hydropower freshwater

consumption is included, one obtains the results reported in Figure S29. In this case, the freshwater

consumption associated with the pumping unit increases from 0.17 to 0.73 bbl/bbl crude; freshwater

consumption associated with refinery electricity increases from 0.04 to 0.17 bbl/bbl crude; freshwater

consumption associated with crude transportation increases from 0.05 to 0.18 bbl/bbl crude – largely

due to pipeline pump electricity.

49

Figure S29 Upstream, midstream and refinery freshwater consumption, including freshwater consumption associated with hydropower.

5.1.2 Effect of Flaring due to Absence of Pipeline Connection

We summarize the details of GHG emissions reported in Sections 4.1 and 4.2 for each flaring scenario in

Table S25. If associated gas is flared for the first twelve months of production before a pipeline is

connected, we estimate the life cycle emissions associated with the crude to be 68.5 kg CO2eq/bbl crude

– 57% higher than our base case. The dependency of the upstream carbon footprint upon the duration

of flaring is non-linear as a consequence of the nonlinear decline of production (Figure S30): The effect

of the first six months of flaring is an increase in GHG emissions of 15.5 kg CO2eq/bbl, whereas the

increase associated with an additional six months of flaring is 9.1 kg CO2eq/bbl.

Our method of allocation of flared gas (no pipeline connection) increases the absolute GHG emissions

attributable to oil as well as the allocation of pad GHGs. This is a consequence of decreasing relative

amounts of co-product when gas is flared due to an absence of a pipeline connection for the sale of

associated gas. For instance, the GHG emissions associated with heater treater fuel use rise from 5.14 to

5.41 kg CO2eq/bbl crude as one goes from “no flaring due to absence of a pipeline connection” to “12

months of flaring due to absence of pipeline connection”, simply because there is less gas sold to which

GHGs might otherwise have been allocated.

50

GHG Emissions (kg CO2eq/well) GHG Emissions (kg CO2eq/bbl crude)

Scenario: Flaring due to lack of gas hookup None 3 mos 6 mos 12 mos None 3 mos 6 mos 12 mos

Operations -Drilling, Completion and Completion Sand mining 5,141 5,141 5,141 5,141 0.011 0.011 0.011 0.011 Transport of proppant (road) 2,627 2,627 2,627 2,627 0.005 0.006 0.006 0.006 Transport of proppant (rail) 38,676 38,676 38,676 38,676 0.080 0.082 0.083 0.084 Steel casing: extraction -> manufacture 368,888 368,888 368,888 368,888 0.765 0.779 0.789 0.804 Rail transportation of casings 10,082 10,082 10,082 10,082 0.021 0.021 0.022 0.022 Truck transportation of casings 485 485 485 485 0.001 0.001 0.001 0.001 Cement: extraction -> manufacture 86,856 86,856 86,856 86,856 0.180 0.183 0.186 0.189 Transport of cement 407 407 407 407 0.001 0.001 0.001 0.001 Rail transport of additives to transloading site 3,737 3,737 3,737 3,737 0.008 0.008 0.008 0.008 Frac additives: manufacture 196,613 196,613 196,613 196,613 0.408 0.415 0.420 0.428 Hydraulic Fracturing, CO2 (XTO) 305,765 305,765 305,765 305,765 0.634 0.645 0.654 0.666 Drilling - Diesel powered, CO2 (XTO) 735,261 735,261 735,261 735,261 1.524 1.552 1.572 1.602 Flowback Flaring, CH4 (XTO) 48,685 48,685 48,685 48,685 0.101 0.103 0.104 0.106 Flowback Flaring, CO2 (XTO) 689,938 689,938 689,938 689,938 1.430 1.456 1.475 1.504 Subtotal 2,493,160 2,493,160 2,493,160 2,493,160 5.169

5.263

5.331

5.433

Operations - Production Field separation equipment losses, CH4 (EPA) 163,724 163,724 163,724 163,724 0.339 0.346 0.350 0.357 Pumping unit - Electric Motor, CO2 (XTO) 5,268,916 5,268,916 5,268,916 5,268,916 10.923 11.122 11.266 11.483 Corrosion and scale inhibition (XTO) 2,758 2,758 2,758 2,758 0.006 0.006 0.006 0.006 Pneumatic devices & chemical injection pumps, CH4 (EPA) - - - - 0.000 0.000 0.000 0.000 Tank vapor flaring, CO2 (ND DMR/XTO) 2,709,809 2,709,809 2,709,809 2,709,809 5.618 5.720 5.794 5.906 Heater treater fuel use, CO2 (XTO) 2,481,381 2,481,381 2,481,381 2,481,381 5.144 5.238 5.306 5.408 Recirculation Pump (gasoline), CO2 (XTO) 16,413 16,413 16,413 16,413 0.034 0.035 0.035 0.036 Road transportation for well maintenance (XTO), CO2 44,068 44,068 44,068 44,068 0.091 0.093 0.094 0.096 Transport of wastewater to class II disposal 41,274 41,274 41,274 41,274 0.086 0.087 0.088 0.090 Wastewater disposal (Class II well) 72,633 72,633 72,633 72,633 0.151 0.153 0.155 0.158 Flare Pilot (XTO) 499,292 499,292 499,292 499,292 1.035 1.054 1.068 1.088 Production flaring before hookup (0 months), CH4 (NDPA) - 239,120 407,344 651,446 0.000 0.632 1.077 1.723 Production flaring before hookup (0 months), CO2 (NDPA) - 3,388,680 5,772,655 9,231,927 0.000 8.963 15.269 24.419 Production flaring after hookup, CH4 (ND DMR) 482,081 442,186 414,119 373,393 0.999 0.933 0.885 0.814 Production flaring after hookup, CO2 (ND DMR) 6,831,788 6,266,413 5,868,666 5,291,514 14.163 13.228 12.549 11.532 Subtotal 18,614,138 21,636,668 23,763,053 26,848,547 38.589 47.610 53.943 63.114 Total 21,107,298

24,129,828

26,256,214

29,341,708

43.757

52.872

59.274

68.548

Table S25 Effect of flaring scenario upon allocation of upstream GHG emissions. Operations in red are associated with drilling and completion. Operations in blue are associated with production

51

Figure S30 Effect of flaring scenario (lack of pipeline connection) on upstream GHG. IPCC AR5 GWPs (100-year).

5.2 Life Cycle We report life cycle GHG emissions for gasoline and diesel, which are the main products of refining

Bakken crude. Although our methodology is easily extended to other refined products (e.g. jet fuel), we

have not conducted those assessments at this time.

5.2.1 Gasoline

A breakdown of the life cycle (“well to wheel”) GHG emissions associated with Bakken-derived gasoline

is illustrated in Figure S31, utilizing a functional unit of “MJ of gasoline” (LHV basis) as previously

discussed (Section 1: Goal and Scope). GHG emissions from “well to tank” constitute 18% of the life

cycle emissions, which is similar to the balance of upstream and downstream for gas-fired power. GHG

emissions from the upstream phases (drilling, completion and production) constitute 9% of the life cycle

emissions, of which 3.1% is due to flaring associated with infrastructural limits and 0.31% is due to

operations associated with hydraulic fracturing and flowback flaring.

52

Figure S31 Life cycle GHG emissions associated with gasoline refined from Bakken crude, base case (pipeline connection throughout production, Medium FCC). GHG reported in terms of IPCC AR5 GWPs (100-year time horizon).

A breakdown of the life cycle (“well to wheel”) freshwater consumption associated with Bakken-derived

gasoline is illustrated in Figure S32. The largest freshwater consumer is the refinery, with other

operations including hydraulic fracturing and grid electricity consumed by the pumping unit contributing

smaller roles.

Figure S32 Life cycle freshwater consumption associated with Bakken-derived gasoline. Freshwater consumption associated with hydropower is excluded.

In Figure S32, freshwater consumption associated with hydropower is not included. If included, one

obtains the results illustrated in Figure S33. In this case, the largest source of freshwater consumption is

the electric-motor-driven pumping unit.

53

Figure S33 Life cycle freshwater consumption associated with Bakken-derived gasoline, including freshwater consumption associated with hydropower.

5.2.2 Diesel

In Figure S34 and Figure S35, we report our results for the life cycle GHG emissions and freshwater

consumption associated with Bakken-derived diesel. The breakdowns of contributions to the carbon

footprint are largely similar to those for gasoline: GHG emissions from “well to tank” constitute 17% of

the life cycle emissions, upstream phases (drilling, completion and production) constitute 8% of the life

cycle emissions, of which 2.9% is due to flaring associated with infrastructural limits and 0.3% is due to

operations associated with hydraulic fracturing and flowback flaring. The effect of hydropower is similar

as well: life cycle freshwater consumption increases from 1.22 to 2.02 bbl/bbl diesel when the

freshwater consumption associated with hydropower is included.

Figure S34 Life cycle GHG emissions associated with Bakken-derived diesel; base case (pipeline connection throughout production, Medium FCC). GHG reported in terms of IPCC AR5 GWPs (100-year time horizon)

54

Figure S35 Life cycle freshwater consumption associated with Bakken-derived diesel. Freshwater consumption associated with hydropower is excluded.

5.2.3 Effect of Flaring of Associated Gas due to Absence of Pipeline Connection

The effect of the flaring of associated gas due to absence of a gathering pipeline connection has a

smaller impact upon the life cycle GHG emissions than the crude, largely as a consequence of the

relative GHG emissions associated with the upstream and downstream phases of the Bakken life cycle.

In Figure S36 we illustrate the dependency of the “well to tank” GHG emissions upon the flaring of

associated gas. If gas is flared for the first six month of production, the increase in GHG emissions will

amount to 2.8 g CO2eq/MJ gasoline; an additional six months of flaring results in an additional 1.7 g

CO2eq/MJ gasoline. A similar trend is observed for diesel. Again, this is a consequence of the nonlinear

55

decline of production of Bakken and other tight oil wells.

Figure S36 Effect of flaring of associated gas upon the “Well to tank” GHG emissions for gasoline refined from Bakken in a medium-conversion refinery with an FCC. GHG emissions reported using IPCC AR5 GWPs (100-year time horizon).

The effect of associated gas flaring upon the life cycle GHG emissions is illustrated in Figure S37. If

associated gas is flared for six months due to lack of a pipeline connection, life cycle GHG emissions will

increase by 3.2%; flaring for an additional six months will increase emissions by an additional 1.8%.

56

Figure S37 Effect of flaring of associated gas upon the life cycle GHG emissions for gasoline refined from Bakken in a medium-conversion refinery with an FCC. GHG emissions reported using IPCC AR5 GWPs (100-year time horizon).

5.2.4 Effect of Refinery Configuration

The effects of the choices of refinery configuration and refinery allocation upon the life cycle GHG

emissions for gasoline and diesel refined from Bakken crude are reported in Table S26 and Table S27.

The effect of refinery configuration is relatively small within each category (Hydroskimmer, “Medium”,

“Deep”) of refinery, but larger variations are observed among the categories (1.2 – 2.9 g CO2eq/MJ

gasoline). What is more notable is the effect of the refinery allocation method: for both diesel and

gasoline, utilization of a process-unit based allocation (our base case) yields a higher refining impact

than allocation of all refinery impacts at the plant-level. This contrasts with the findings of Wang and

coworkers, who observed an increase in GHG emissions allocated to gasoline for a process level

allocation (relative to plant level) and a decrease for diesel1.

57








GHG Emissions (g CO2eq/MJ gasoline)

Drilling and Completion

0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 1.0 1.0 0.9 0.9 0.9 0.9

Production 6.8 6.8 7.0 7.0 6.8 6.8 6.9 6.9 7.1 7.1 6.9 6.9 7.0 7.0

Crude Transportation 1.0 1.0 1.1 1.1 1.0 1.0 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1

Refinery GHG Emissions, Direct

2.4 5.1 4.5 5.9 4.4 6.2 4.2 5.8 5.4 6.5 5.6 7.0 5.5 6.7

Refinery Electricity Imports

0.3 0.5 0.5 0.6 0.5 0.7 0.5 0.6 0.5 0.7 0.6 0.7 0.6 0.7

Transport of Gasoline 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5

Vehicle Refueling 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Vehicle Operation 73.1 73.1 73.1 73.1 73.1 73.1 73.1 73.1 73.1 73.1 73.1 73.1 73.1 73.1

Life Cycle 85.0 88.0 87.6 89.1 87.3 89.3 87.2 88.9 88.7 89.9 88.6 90.2 88.7 90.0

Table S26 Effect of refinery type and refinery-level allocation on refinery and life cycle GHG emissions associated with gasoline refined from Bakken crude. The base case analysis is highlighted in red.








GHG Emissions (g CO2eq/MJ diesel)

Drilling and Completion

0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9

Production 6.7 6.7 6.7 6.7 6.7 6.7 6.7 6.7 6.7 6.7 6.7 6.7 6.7 6.7

Crude Transportation 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0

Refinery GHG Emissions, Direct

2.4 1.7 4.3 5.2 4.4 4.7 4.1 4.2 5.1 6.0 5.4 6.0 5.3 6.2

Refinery Electricity Imports

0.3 0.2 0.4 0.5 0.5 0.5 0.4 0.5 0.5 0.6 0.6 0.6 0.6 0.7

Transport of Diesel 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4

Vehicle Refueling 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Vehicle Operation 75.0 75.0 75.0 75.0 75.0 75.0 75.0 75.0 75.0 75.0 75.0 75.0 75.0 75.0

Life Cycle 86.7 85.9 88.8 89.9 88.9 89.3 88.6 88.8 89.7 90.7 90.1 90.7 89.9 90.9

Table S27 Effect of refinery type and refinery-level allocation on refinery and life cycle GHG emissions associated with diesel refined from Bakken crude. The base case analysis is highlighted in red.

58

5.3 Sensitivity Analysis In the preceding discussion, we evaluated the sensitivity of our results to the allocation method for the

refinery and the amount of time that associated gas from Bakken wells is flared due to the absence of a

pipeline connection. These are choices in the design of the LCA.

We also evaluated the sensitivity of our base case LCA to the ranges of data and parameters employed

in our analysis. Our base case results are calculated using (a) the average values of data sets and (b)

expectation values of distributed variables. One would expect alternative estimates if specific data

points or probabilistically-selected parameters were used in these calculations.

Therefore, we evaluated our estimates using one-dimensional sensitivity analysis and Monte Carlo

simulation. The former identifies variables that have the strongest impact upon the results, whereas the

latter yields estimates of representative ranges of environmental impacts, subject to the

representativeness of the data sets and distributions employed in the LCA.

5.3.1 Upstream GHG Emissions

In Figure S38, we present a Tornado diagram for the GHG emissions associated with the upstream

phases of the Bakken life cycle, as illustrated in Figure S1. As in our investigation of the GHG emissions

associated with Marcellus shale gas18, we found that the results were most sensitive to the EUR of the

well – in this case, the Oil EUR. This is partly a consequence of the breadth of the distribution of the EUR

(Figure S12), but also the fact that the GHG emissions associated with drilling and completion are not

proportional to the EUR.

Unsurprisingly, the upstream GHG emissions are also sensitive to the time that wells are not connected

to a gas pipeline (and thus flared).

The next most impactful parameter is the flash factor for tanks (scf/bbl), which defines the total flaring

of tank vapors over the well lifetime. We have used a relatively broad distribution of the flash factor in

this LCA, as specified by the North Dakota Department of Health (4.2.3 Tank Vapor Flaring). However,

internal measurements suggest that use of a lognormal distribution to model this parameter is

appropriate‡‡‡ The flash factor is defined by the way the heater treater is operated, and may be

expected to decrease for all Bakken wells in the near future as regulations mandate that heater treaters

be operated at 130 F, sending more light hydrocarbons to the gas pipeline.

The results are sensitive to the life cycle GHG emissions associated with grid electricity due to the use of

an electric motor for the pumping unit.

‡‡‡

An analysis of 34 experimental characterization of tank vapors yields an average 27.00 scf/bbl, p90 40.12 scf/bbl, and p = 0.4841 for the KS-test of the hypothesis “H0: The flash factor is lognormally distributed with this mean and p90”

59

The next most impactful parameter is the gas oil ratio, which defines the amount of gas produced by the

well, and thus, the amount of gas flared due to pipeline capacity constraints. The GOR is not defined by

engineering, but by the properties of the hydrocarbon formation.

The next most impactful parameter is the fraction of gas that is flared due to pipeline capacity

constraints. This quantity is expected to decrease as midstream companies continue to contract with

Bakken operators to collect high-value NGLs as well as pipeline quality gas for sale.

We also considered the sensitivity of our results to the destruction efficiency of the pit flare. In our base

case, we adopted a flare efficiency of 98%, following the approach of EPA. A 98% flare efficiency was

modeled as follows: 98% of the gas sent to the flare was considered to be fully combusted, and the

remainder vented. By varying the destruction efficiency between 90% and 100%, we investigated the

emission of methane from the flare. We found that the upstream GHG emissions increase by 5% if the

flare efficiency is 90%, vs our base case. The results are relatively insensitive to the flare efficiency due

in part to the methane content of associated gas (52.8% by volume, Table S14), which is lower than that

of typical gas wells.

60

Figure S38 Sensitivity of Upstream GHG emissions to LCA model data and parameters (Tornado diagram). GHG reported using IPCC AR5 GWPs (100-year).

We also evaluated the sensitivity of the upstream GHG emissions to allocation. If 100% of upstream

GHG emissions are allocated to crude oil (versus 78.4%, corresponding to the allocation of impacts via

energy content of sold gas and crude oil), then the upstream GHG emissions amount to 55.8 kg

CO2eq/bbl. The implication of this modeling approach is that the associated gas produced from Bakken

wells has no upstream GHG emissions associated with it.

61

5.3.2 Life Cycle GHG Emissions of Bakken-derived Gasoline and Diesel

Our sensitivity analysis of the life cycle GHG emissions yielded similar results (Figure S39). Estimates of

the life cycle GHG emissions associated with Bakken are most sensitive to EUR, the amount flaring due

to absence of a pipeline connection, and the flash factor for tank vapors, as discussed previously.

However, the results are also strongly affected by the choice of refinery configuration, as well as the

method by which refinery impacts are allocated to gasoline and other refined products (i.e. plant-level

or process level). As previously discussed, the GHG emissions increase with increasing refinery

complexity, owing to energy usage and carbon rejection for process units such as the FCC, gas oil

hydrocracker (GO-HC), and delayed coker. The effect of pit flare destruction efficiency is far less

pronounced at the life cycle level, largely due to the relative impacts of the “upstream” and “end use”

phases of the life cycle. Results of our sensitivity analysis of diesel indicate similar dependencies upon

these parameters (Figure S40).

62

Figure S39 Sensitivity of Life Cycle (“Well to Wheel”) GHG emissions of Bakken-derived gasoline to model data and parameters (Tornado diagram). GHG reported using IPCC AR5 GWPs (100-year)

63

Figure S40 Sensitivity of Life Cycle (“Well to Wheel”) GHG emissions of Bakken-derived diesel to model data and parameters (Tornado diagram). GHG reported using IPCC AR5 GWPs (100-year)

As previously mentioned, we also evaluated the sensitivity of the results to allocation. If 100% of

upstream GHG emissions are allocated to crude oil (versus 78.4%, corresponding to the allocation of

impacts via energy content of sold gas and crude oil), then the life cycle GHG emissions associated with

Bakken-derived gasoline amount to 91.3 kg CO2eq/MJ gasoline. The implication of such a modeling

approach is that the associated gas produced from Bakken wells has no upstream GHG emissions

associated with it.

64

5.3.3 Upstream Freshwater Consumption

We report the results of a sensitivity analysis of the upstream freshwater consumption associated with

Bakken crude in Figure S41. In contrast to the upstream GHG emissions, we found that the upstream

freshwater consumption is most sensitive to the power source of the pumping unit. This is a direct

consequence of the freshwater consumption associated with hydropower, which defines the freshwater

consumption associated with grid electricity. The water footprint of grid electricity is also the driver for

the sensitivity of our results to the life cycle WOR, as the WOR defines the amount of produced water

requiring reinjection, and the fact that SWD pumps are electricity driven. Direct sensitivity to the

freshwater consumption associated with the grid mix is a consequence of the electricity required for

SWD pumps.

Our results are also sensitive to the freshwater required for batch treatments of corrosion and scale

inhibitor to the well. As previously discussed, the amounts of inhibitors and method of treatment cannot

be known before drilling is initiated, as they are specific to the geological conditions of each well.

Figure S41 Sensitivity of upstream freshwater consumption associated with Bakken crude to model data and parameters (Tornado diagram).

5.3.4 Life Cycle Freshwater Consumption of Bakken-derived Gasoline and Diesel

The sensitivities of our estimates of life cycle freshwater consumption associated with Bakken-derived

gasoline and diesel are illustrated in Figure S42 and Figure S43. The refinery distinguishes the

sensitivities of our results for refined products from the sensitivity of our result for the crude. As

illustrated in Figure S32 and Figure S33, the refinery is the largest single source of freshwater

consumption in the Bakken life cycle, hence, perturbations in this figure yield the largest perturbations

in the life cycle result. The large variability in the regional freshwater consumption of electricity,

compounded with electricity consuming operations including refining, pipeline operations and SWD

causes the life cycle freshwater consumption to depend more strongly on the water consumption of the

electrical grid mix.

65

Figure S42 Sensitivity of Life Cycle (“Well to Wheel”) freshwater consumption associated with Bakken-derived gasoline to model data and parameters (Tornado diagram).

Figure S43 Sensitivity of Life Cycle (“Well to Wheel”) freshwater consumption associated with Bakken-derived diesel to model data and parameters (Tornado diagram).

5.4 Characterization of ranges of impacts Monte Carlo simulations of the Bakken life cycle may be employed to generate distributions of life cycle

impacts that statistically represent the performance of the resource as a whole. We conducted MC

simulations of our base case process featuring a gas pipeline connection throughout production and a

medium conversion refinery with an FCC and no gas oil hydrocracker.

5.4.1 Upstream, MC

The results of our Monte Carlo simulations of the Bakken upstream are reported in Figure S44. The

results of our base case LCAs, i.e. using data averages and expectation values of random variables are

highlighted with gray lines, and 10th and 90th percentiles are highlighted with blue lines.

66

Figure S44 Distributions of the upstream GHG emissions associated with Bakken crude, calculated via MC simulation for all four associated gas pipeline scenarios. Blue lines indicate 10

th and 90

th percentiles. Gray lines represent results from LCAs

using expectation values of distributed variables (see Table S25). Results are reported in terms of IPCC AR5 GWPs (100 year time horizon).

For all scenarios, the difference between the 90th and 10th percentiles is equal to the “deterministic”

results (Table S25), illustrating the variability in the upstream estimates. This variability is largely driven

by the variability in the EUR (Figure S45), and exceeds the impact of any one factor appearing in the one

way sensitivity analysis (Figure S38). In effect, if upstream GHG emissions could be perfectly measured

relative to gross oil production of a well, one couldn’t statistically distinguish the GHG emissions of

subsets of wells defined by factors noted in Figure S38.

67

Figure S45 Correlation of MC simulation results for upstream GHG emissions with respect to EUR. Results reported using IPCC AR5 GWPs (100-year time horizon). Blue lines signify 10

th and 90

th percentiles, and gray lines represent the average EUR

and the base case

In Figure S46 we report the results of our MC simulations for the upstream freshwater consumption.

The variability of upstream freshwater consumption is driven by a combination of the variability in

freshwater use for hydraulic fracturing, scale and corrosion inhibition, and the ultimate recovery of oil

from the well.

Figure S46 Distributions of the upstream freshwater consumption associated with Bakken crude, calculated via MC simulation. Blue lines indicate 10

th and 90

th percentiles. The gray line (0.26 bbl freshwater consumed/bbl crude produced)

represents the result from an LCA that employs expectation values of distributed variables and averages of data sets (see Figure S28). Impacts of hydropower are included in these results.

5.4.2 Gasoline and Diesel, MC

The results of our Monte Carlo simulations of the Bakken life cycle are reported in Figure S47 and Figure

S48. As with the GHG emissions associated with crude, the variability in the life cycle GHG emissions of

68

Bakken-derived gasoline and diesel is driven by variability in the gross recoveries of oil from the wells.

The variability in life cycle GHG emissions due to EUR is much larger than the effect of flaring of

associated gas due to absence of a pipeline connection.

Figure S47 Distributions of the life cycle GHG emissions from Bakken-derived gasoline, calculated via MC simulation for all four associated gas pipeline scenarios. Blue lines indicate 10

th and 90

th percentiles. Gray lines represent results from LCAs

using expectation values of distributed variables (see Figure S37). Results are reported in terms of IPCC AR5 GWPs (100 year time horizon).

69

Figure S48 Distributions of the life cycle GHG emissions from Bakken-derived diesel, calculated via MC simulation for all four associated gas pipeline scenarios. Blue lines indicate 10

th and 90

th percentiles. Gray lines represent results from LCAs using

expectation values of distributed variables (see Figure S37). Results are reported in terms of IPCC AR5 GWPs (100 year time horizon).

The distributions of the freshwater consumption associated with Bakken-derived gasoline and diesel are

reported in Figure S49. As with the upstream freshwater consumption, there is no single factor that

causes most of the variability: EUR, refinery freshwater consumption, water use for hydraulic fracturing,

and water use for corrosion and scale inhibition all contribute.

70

Figure S49 Distributions of the life cycle freshwater consumption associated with Bakken-derived gasoline and diesel, calculated via MC simulation. Blue lines indicate 10

th and 90

th percentiles. Gray lines represent results from LCAs using

expectation values of distributed variables (see Figure S32 and Figure S35). Impacts of hydropower are included.

5.5 Comparison with other studies In Figure S50 we compare our findings to other published LCAs and “Well to Wheels” models of gasoline

and diesel11,15,7,37,38,39. The publications and models against which we compare our results are not

exhaustive – we have included only those that explicitly report CO2, CH4 and N2O emissions associated

with the life cycles of gasoline, allowing for a common expression of all study results using IPCC AR5

GWPs.

Previous studies have employed different modeling assumptions regarding refining, production of crude

resources, crude and product transportation, as well as the contributions of electricity. Moreover, they

have included different crudes: For instance, the NETL Petroleum Baseline and GHGenius explicitly

include oil sands in the crude mix, and GREET includes vehicular impacts beyond the fuel cycle.

Nevertheless, our findings are consistent with all of these studies, with the exception of the recently

published study of the Joint Research Centre-EUCAR-CONCAWE (JEC) collaboration, which appears to

give the lowest estimate of “well to wheel” GHG emissions among all studies.

71

Figure S50 Comparison of the results of the Bakken LCA with other recent petroleum LCAs and well to wheel studies. All results are expressed using IPCC AR5 GWPs (100-year time horizon). Ranges for Bakken results represent 10

th and 90

th

percentiles from MC simulations. Red lines denote Bakken results for our base case and our scenario wherein associated gas is flared during the first 12 months of production due to absence of a gas pipeline. We report GHGenius results for the fuel cycle only, excluding GHG emissions associated with the construction and maintenance of the vehicle.

5.6 Greenhouse gas emissions associated with other tight crudes Bakken is one of the “tight” crudes that has become available to U.S. and Canadian refiners in recent

years. Another major source of tight crude is the Eagle Ford formation in southern Texas. Hydrocarbons

produced from the Eagle Ford vary by location – some regions primarily produce gas, and others

primarily produce crude, and still others produce “condensate” often defined as a hydrocarbon liquid

with an API gravity greater than 45. Key properties of Eagle Ford crude (distinct from Eagle Ford

condensate) required as inputs for the PRELIM model are reported in Table S28

Full crude LSR Naphtha Kerosene Diesel AGO LVGO HVGO VR AR

Cut volume, % 100 12 25 22 9 9 6 7 10 24 Sulphur , wt% 0.24 0.00 0.00 0.01 0.27 0.49 0.47 0.53 0.79 0.63 Nitrogen , mass ppm 268 0 0 4 52 178 312 520 1,625 938

API gravity

44.6

87.0

55.4

43.3

37.0

32.8

31.1

28.4

23.2

26.9 Hydrogen, wt% 14 17 15 14 14 13 14 13 13 13 MCR, wt% 0.65 0.00 0.00 0.00 0.00 0.00 0.00 0.05 5.75 2.47 Kw (Approximate) 12.4 12.8 11.9 12.0 12.1 12.2 12.4 12.5 12.8 12.6 Tb50, [°C] 262 50 133 232 315 369 424 484 603 505

Table S28 Eagle Ford crude assay data used in refinery GHG estimation using PRELIM. The temperature ranges corresponding to each cut (LSR, Naphtha, ... AR) are reported in the PRELIM documentation

3. Tb50 is the temperature that represents 50% of

the mass yield of each fraction on mass basis. MCR is the “micro carbon residuum”, also known as the Conradson Carbon Residue (CCR). Kw is the Watson (UOP) characterization factor.

Like Bakken crude (Table S15), Eagle Ford crude has a relatively high API and low sulfur. Using PRELIM

v1.0, refinery impacts, we estimate the GHG emissions associated with its refining to be similar to

Bakken crude for all PRELIM refinery configurations (

Refinery Type Hydroskimmer Med Deep

72

Conversion Technologies NA FCC GO-HC FCC +

GO-HC FCC GO-HC

FCC+ GO-HC

GHG Emissions (g CO2eq/bbl crude)

Eagle Ford Refinery Emissions, Direct 13.62 22.87 22.02 19.87 27.76 30.46 25.63

Refinery Electricity Imports 1.45 2.21 2.82 2.47 2.87 3.36 2.91

Total 15.07 25.08 24.84 22.34 30.62 33.82 28.55

Bakken Refinery Emissions, Direct 13.74 24.73 24.96 23.29 29.14 31.19 30.38


Total 15.18 27.26 27.81 25.87 32.11 34.39 33.59

Table S29)

Refinery Type Hydroskimmer Med Deep

Conversion Technologies NA FCC GO-HC FCC +

GO-HC FCC GO-HC

FCC+ GO-HC

GHG Emissions (g CO2eq/bbl crude)

Eagle Ford Refinery Emissions, Direct 13.62 22.87 22.02 19.87 27.76 30.46 25.63


Total 15.07 25.08 24.84 22.34 30.62 33.82 28.55

Bakken Refinery Emissions, Direct 13.74 24.73 24.96 23.29 29.14 31.19 30.38


Total 15.18 27.26 27.81 25.87 32.11 34.39 33.59 Table S29 Comparison of refinery GHG emissions for Bakken and Eagle Ford crudes, as calculated by the PRELIM model (g CO2eq/bbl crude). Life cycle GHG emissions for natural gas used as refinery fuel and purchased electricity are included in these estimates.

6 Summary of Data, Distributions and Modeling Choices Employed The following tables summarize the modeling choices and data sources for major stochastic parameters

for all stages of the life cycle.

Stochastic Variable Distribution Reference

Corrosion inhibitor: batch treatment Data Table S19

73

volume, gal batch inhibitor/gal produced water Corrosion inhibitor: continuous treatment volume, gal continuous inhibitor/gal produced water

Data Table S19

Diesel fuel for drilling, gal/well Data Table S17

Diesel fuel for hydraulic fracturing, gal/well

Data Table S17

Distance from cement plant to well, mi Uniform(25,100) Section 4.1.3.2

Distance from steel plant to well, mi Uniform(1432,1532) Section 4.1.2.2

Distance from well to class II disposal, mi Uniform(10,15) Section 4.2.4

Emission factor: Flared tank vapors (XTO), kg CO2/scf

Calculated from Data Figure S20

Emission factor: Vented tank vapors (XTO), kg CO2eq/scf

Calculated from Data Figure S20

Flash factor for tanks (ND), scf tank vapors/bbl crude

Lognormal Section 4.2.3

Fraction of gas flared due to capacity contraints

Data Figure S23

Gas flared during flowback, Mcf/well Data Figure S18

GHG Emissions for Fluid Additives (cradle to gate), kg CO2eq/kg additives

Uniform(1,4) Section 4.1.5.1

GHG Emissions, U.S. Electricity Mix, kg CO2eq/MWh consumed

Analysis of Data Figure S11

GOR, scf/bbl Data Table S17

Heater treater fuel, scf/day Data, Uniform(6160, 9330) Section 4.2.2.1

Heater-Treater*, scf methane/heater-treater/day

Lognormal Section 4.2.2.2

Hours per week of recycle pump use Data, Uniform(1,2)

Length of first phase of well life, years Uniform(10,15), Engineering judgment

Section 4.2.1

Length of Intermediate Casing, ft Data Table S17

Length of Liner, ft Data Table S17

Length of Surface Casing, ft Data Table S17

Life cycle WOR, bbl produced water/bbl crude

Model fit from Data Figure S21, Table S18

Maximum surface injection pressure, psi Data Section 4.2.4

Meters/Piping*, scf methane/meter/day Lognormal

Oil EUR, kbbl/well Data Figure S12, Table S16

Rail distance from additive manufacture to pad, mi

Uniform(1600, 1700) Section 4.1.5.2

Rail distance from sand mining site to transloading site, mi

Uniform(1000, 1100) Section 4.1.4.2

Scale inhibitor: batch treatment volume, gal batch inhibitor/gal produced water

Data Table S19

Scale inhibitor: continuous treatment volume, gal continuous inhibitor/gal

Data Table S19

74

produced water

Total cement, sack/well Data Table S17

Total mass concentration of additives, kg/kg fluid

Total proppant, lb/well Data Table S17

Total water pumped (hydraulic fracturing), bbl/well

Data Table S17

Truck fuel economy, ton-mile/gal Uniform(115, 154) Section 2.2.2

Truck transport from well pad to transloading (rail or pipeline), mi

Uniform(10, 30) Section 4.3.1

Table 30 "Stochastic" parameters employed in the Bakken LCA. The effects of varying these parameters are illustrated in Figure S38, Figure S39, Figure S40, Figure S41, Figure S42, and Figure S43.

Modeling choice Options Default

Coproduct allocation method Mass, Energy Energy

Pumping unit power source Associated Gas/Engine, Electric Motor

Electric Motor

Months until hookup of pipeline for associated gas sales 0, 3, 6, 12 months

0

Table 31 Modeling choices in Bakken LCA. The effects of varying these parameters are illustrated in Figure S38, Figure S39, Figure S40, Figure S41, Figure S42, and Figure S43.

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http://www.aopl.org/pdf/AOPL_Shift_Report_Press_Release_Feb_7_20121.pdf

http://www.eia.gov/cfapps/ipdbproject/iedindex3.cfm?tid=5&pid=5&aid=2&cid=regions&syid=2004&eyid=2012&unit=TBPD

http://www.eia.gov/cfapps/ipdbproject/iedindex3.cfm?tid=5&pid=5&aid=2&cid=regions&syid=2004&eyid=2012&unit=TBPD

http://www.epa.gov/ghgreporting/ghgdata/reportingdatasets.html

http://www.epa.gov/otaq/renewablefuels/420r10006.pdf%20Accessed%20April%208

http://www.epa.gov/otaq/renewablefuels/420r10006.pdf%20Accessed%20April%208

http://www.arb.ca.gov/fuels/lcfs/ca-greet/ca-greet.htm%20Accessed%20Nov%2014

http://www.jrc.ec.europa.eu/

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