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EERC DISCLAIMER

LEGAL NOTICE This research report was prepared by the Energy & Environmental 

Research Center (EERC), an agency of the University of North Dakota, as an account of work 

sponsored by the U.S. Department of Energy (DOE) and the North Dakota Industrial 

Commission (NDIC). Because of the research nature of the work performed, neither the EERC 

nor any of its employees makes any warranty, express or implied, or assumes any legal liability 

or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, 

product, or process disclosed or represents that its use would not infringe privately owned rights. 

Reference herein to any specific commercial product, process, or service by trade name, 

trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement 

or recommendation by the EERC. 

DOE ACKNOWLEDGMENT 

This report was prepared with the support of DOE National Energy Technology 

Laboratory Cooperative Agreement No. DE-FC26-08NT43291. However, any opinions, 

findings, conclusions, or recommendations expressed herein are those of the author(s) and do not 

necessarily reflect the views of DOE. 

DOE DISCLAIMER

This report was prepared as an account of work sponsored by an agency of the United 

States Government. Neither the United States Government, nor any agency thereof, nor any of 

their employees, makes any warranty, express or implied, or assumes any legal liability or 

responsibility for the accuracy, completeness, or usefulness of any information, apparatus, 

product, or process disclosed, or represents that its use would not infringe privately owned rights. 

Reference herein to any specific commercial product, process, or service by trade name, 

trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, 

recommendation, or favoring by the United States Government or any agency thereof. The views 

and opinions of authors expressed herein do not necessarily state or reflect those of the United 

States Government or any agency thereof. 

NDIC DISCLAIMER 

This report was prepared by the EERC pursuant to an agreement partially funded by the 

Industrial Commission of North Dakota, and neither the EERC nor any of its subcontractors nor 

the NDIC nor any person acting on behalf of either: 

A. Makes any warranty or representation, express or implied, with respect to the accuracy, 

completeness, or usefulness of the information contained in this report or that the use of 

any information, apparatus, method, or process disclosed in this report may not infringe 

privately owned rights; or 
B. Assumes any liabilities with respect to the use of, or for damages resulting from the use 

of, any information, apparatus, method, or process disclosed in this report. 

Reference herein to any specific commercial product, process, or service by trade name, 

trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, 

recommendation, or favoring by NDIC. The views and opinions of authors expressed herein do 

not necessarily state or reflect those of NDIC. 
END-USE TECHNOLOGY STUDY – AN ASSESSMENT OF 

ALTERNATIVE USES FOR ASSOCIATED GAS 

ABSTRACT 

The Energy & Environmental Research Center (EERC) in partnership with the North 

Dakota Industrial Commission Oil and Gas Research Council, Continental Resources, and the 

U.S. Department of Energy National Energy Technology Laboratory conducted a study focused 

on assessing the technical and economic viability of technologies and processes that could lead 

to increased utilization of associated gas. The impetus for this study was derived from the rapid 

growth of gas flaring in North Dakota, itself a function of rapid increase in oil production. This 

final report summarizes EERC assessments of distributed end-use opportunities that were 

evaluated for their potential to contribute to significant reductions of gas flaring in liquids-rich 

shale formations like the Bakken Formation in North Dakota. 
i 

TABLE OF CONTENTS 

LIST OF FIGURES ....................................................................................................................... iv 

LIST OF TABLES ........................................................................................................................ vii 

NOMENCLATURE ....................................................................................................................... x 

EXECUTIVE SUMMARY .......................................................................................................... xii

INTRODUCTION .......................................................................................................................... 1

BACKGROUND ON BAKKEN ASSOCIATED GAS ................................................................. 2

Geographic Discussion .......................................................................................................... 2

Geologic Discussion .............................................................................................................. 3

Current Oil and Gas Production ............................................................................................ 5

Exploration and Production Technology ..................................................................... 5

Oil and Gas Production ......................................................................................................... 7

Quantity ..................................................................................................................... 12

Quality/Physical Characteristics ................................................................................ 16

Production, Processing, Transport, and Distribution ................................................. 17

Summary of Bakken Associated Gas .................................................................................. 21

ALTERNATIVE APPROACH FOR SMALL-SCALE GAS PROCESSING AND NGL 

RECOVERY ................................................................................................................................. 22

Background ......................................................................................................................... 22

Summary of Alternative Gas-Processing Technologies ...................................................... 22

Acid Gas Removal ..................................................................................................... 23

Dehydration ............................................................................................................... 24

Nitrogen Rejection ..................................................................................................... 26

NGL Recovery ........................................................................................................... 26

Small-Scale NGL Recovery for Stranded Gas .................................................................... 29

Fee for Service ........................................................................................................... 31

Monetization of Products by Third Party .................................................................. 31

Monetization of Products by Operator ...................................................................... 31

Conclusions ................................................................................................................ 31

APPLICATION I – CNG/LNG FOR VEHICLES ....................................................................... 32

Introduction ......................................................................................................................... 32

CNG and LNG Fundamentals ............................................................................................. 32

CNG Feedstock Availability and Quality .................................................................. 34

Continued . . . 
ii 

TABLE OF CONTENTS (continued) 

Existing CNG Fuel Quality Standards ................................................................................ 36

Recent Movement Toward NGVs ............................................................................. 38

A Distributed Model Suitable for Small-Scale Bakken Associated Gas 

Opportunities ............................................................................................................. 41

NGL Removal and Storage ........................................................................................ 41

A Notional Mobile CNG Fuel-Processing/Compressing/Dispensing Station ..................... 42

Land Acquisition ................................................................................................................. 44 

Economics of the Use of Associated Gas to Fuel NGVs .................................................... 44

Previous Economic Models ....................................................................................... 44

A Model for Use of Bakken Gas in NGVs ................................................................ 46

Evaluation Summary ........................................................................................................... 53

APPLICATION II – ELECTRIC POWER GENERATION ........................................................ 53

Background ......................................................................................................................... 53

Current Electrical Generation .................................................................................... 53

NG Resource ....................................................................................................................... 54

Power Demand/Market ....................................................................................................... 54

Applicable Technologies ..................................................................................................... 59

Reciprocating Engine ................................................................................................. 59

Gas Turbine ............................................................................................................... 60

Steam Turbine ............................................................................................................ 61

Microturbine .............................................................................................................. 61

Fuel Cell ..................................................................................................................... 61

Initial Evaluation ................................................................................................................. 61

Grid Support .............................................................................................................. 62

Local Power ............................................................................................................... 63

Detailed Evaluation ............................................................................................................. 63

Land Acquisition ....................................................................................................... 64

NGL Removal and Storage ........................................................................................ 64

Grid Support – Reciprocating Engine Scenario ......................................................... 66

Grid Support – Gas Turbine Scenario ....................................................................... 67

Local Power – Reciprocating Engine Scenario ......................................................... 69

Local Power – Microturbine Scenario ....................................................................... 70

Drilling Rig Power .............................................................................................................. 72 

Evaluation Summary ........................................................................................................... 74

APPLICATION III – CHEMICALS DERIVED FROM BAKKEN ASSOCIATED GAS ......... 75

Overview of NG and NGL-Based Chemical Industry ........................................................ 75

NG-Processing Infrastructure .................................................................................... 78

NG Distribution Infrastructure .................................................................................. 80

Continued . . . 
iii 

TABLE OF CONTENTS (continued) 

Current NGL Distribution Infrastructure ................................................................... 82

Alternate Rich Gas Distribution System .................................................................... 85

Petrochemical Industry Relevance in North Dakota ........................................................... 86

Conceptual Chemical Production in North Dakota ............................................................. 87

OVERALL STUDY CONCLUSIONS ......................................................................................... 90

ACKNOWLEDGMENTS ............................................................................................................ 91

REFERENCES ............................................................................................................................. 92

OVERVIEW OF PETROCHEMICAL INDUSTRY INFRASTRUCTURE ................ Appendix A 

DISTRIBUTED-SCALE AMMONIA PLANT PRELIMINARY DESIGN ................ Appendix B 
iv 

LIST OF FIGURES 

1 Geographic extent of the Bakken Formation within the Williston Basin ............................. 2

2 Historical estimates of Bakken oil resources ........................................................................ 3

3 Stratigraphic column for rocks of the Williston Basin in North Dakota and generalized 

stratigraphy of the Bakken Formation in North Dakota ........................................................ 4

4 Generalized depiction of an open-hole completion in the middle Bakken, based on 

well completion diagrams in NDDMR–OGD well files ....................................................... 5

5 Generalized depiction of a Middle Bakken uncemented liner completion, based on 

well completion diagrams in NDDMR–OGD well files ....................................................... 6

6 Generalized depiction of a cemented liner completion in the middle Bakken, based on 

well completion diagrams in NDDMR–OGD well files ....................................................... 6

7 Generalized wellbore schematic showing the placement of swell packers for a 

multistage fracture treatment, based on well completion diagrams in NDDMR–OGD 

well files ................................................................................................................................ 7

8 Annual oil production and number of wells producing in North Dakota from 1951 

through 2011 .......................................................................................................................... 8

9 Annual oil and gas production in the Bakken Formation ...................................................... 9

10 Graphical depiction of total gas produced and total gas flared for December 2011 ........... 10

11 Annual gas produced, sold, and unsold ............................................................................... 11

12 Percentage of gas sold and unsold ....................................................................................... 12

13 Graphical depiction of flared gas for January and December 2011 .................................... 13

14 Number of Bakken wells flaring a range of quantities per month for 2011 ........................ 14

15 Flaring rates as a percentage of total flared gas for December 2011 .................................. 15

16 Number of wells flaring a range of quantities per day for 2011 ......................................... 15

17 Generalized NG-processing schematic ............................................................................... 18 

Continued . . . 
v 

LIST OF FIGURES (continued) 

18 Dehydration technology selection guide ............................................................................. 24

19 CryoStar turboexpander and demethanizer ......................................................................... 27

20 Small JT NGL recovery skid as provided by dew point control ......................................... 28

21 Twister supersonic separator ............................................................................................... 29

22 Block flow diagram of NGL removal system ..................................................................... 30

23 NGV use by country ............................................................................................................ 34

24 Historical CNG price comparison ....................................................................................... 39

25 EIA projections for crude oil vs. NG pricing ...................................................................... 40

26 NGL removal system block flow diagram .......................................................................... 42

27 IMW mobile CNG refueling system ................................................................................... 43

28 General Electric’s CNG-in-a-box compressing/dispensing package .................................. 44

29 Largest factors affecting the profitability of marginal and resilient fleets .......................... 45

30 Flared NG and existing electrical transmission ................................................................... 55

31 Flared NG and electrical distribution cooperative service territory .................................... 56

32 NGL removal system block flow diagram .......................................................................... 65

33 Process flow diagram, grid support – reciprocating engine scenario .................................. 66

34 Process flow diagram, grid support – gas turbine scenario ................................................. 68

35 Process flow diagram, local power – reciprocating engine scenario .................................. 69

36 Process flow diagram, local power – microturbine scenario............................................... 71

37 NG and NGL supply chain .................................................................................................. 77

38 Lower 48 states’ shale plays ................................................................................................ 78 

Continued . . . 
vi 

LIST OF FIGURES (continued) 

39 U.S. NG-processing plants .................................................................................................. 79

40 Capacities and number of U.S. NG-processing plants ........................................................ 79

41 North Dakota gas-processing and transportation ................................................................ 81

42 Interstate NG pipelines in North Dakota ............................................................................. 82

43 Alliance Pipeline system map ............................................................................................. 84

44 North Dakota NGL production ........................................................................................... 85
vii 

LIST OF TABLES 

1 December 2011 Monthly Oil and Gas Production for the Top Four Producing 

Counties in North Dakota ...................................................................................................... 9

2 Summary of Bakken Wells Flaring Gas Based on Rates/Month – 

December 2011 Data ........................................................................................................... 14

3 Summary of Wells Flaring Gas Based on Rates/Day – December 2011 Data ................... 16

4 Select Associated Gas Quality Data from Wellheads in the Bakken Formation in 

 North Dakota ....................................................................................................................... 17

5 Assumed Bakken Gas Composition .................................................................................... 17

6 Possible Distributed-Scale Acid Gas (SO2 and CO2) Removal Technologies .................... 23

7 Possible Distributed-Scale Water Removal Technologies .................................................. 24

8 Possible Distributed-Scale NGL Recovery Technologies .................................................. 26

9 Assumptions for Evaluation of a NGL Removal System ................................................... 30

10 Summary of NGL Removal System Costs and Revenue .................................................... 31

11 Select Gas Quality Data from North Dakota Pipeline Stations ........................................... 35 

12 3-month Variability in Gas Quality Data at North Dakota Pipeline Stations ..................... 35 

13 Select National Statistics for NG in 26 Major Urban Areas of the United States ............... 35 

14 Methane Base Fuel Specification ........................................................................................ 37

15 SAE J1616 CNG Specifications .......................................................................................... 37

16 CARB Specifications for CNG ........................................................................................... 38

17 A Sampling of Recent and Ongoing Major Fleet Conversions to CNG ............................. 39

18 Million-Mile Fleet Fuel Savings ......................................................................................... 40

19 Best Vehicles for CNG ........................................................................................................ 45

Continued . . . 
viii 

LIST OF TABLES (continued) 

20 Assumed NGL Revenues Associated with CNG Production .............................................. 48

21 Estimated Mobile Refueling Station Costs ......................................................................... 48

22 Yearly Costs vs. Fuel Savings ............................................................................................. 49

23 Taxes on CNG in North Dakota .......................................................................................... 51

24 Up-Front CNG Fleet Implementation Costs ....................................................................... 51

25 Amortization Costs .............................................................................................................. 52

26 Other Economic Scenarios that Make Fuel Savings Equal to Net Yearly Costs ................ 52

27 Nameplate Electrical Generation Capacity as a Percentage of Total for North 

 Dakota and Neighboring States ........................................................................................... 54

28 Pace Report Highlights and EERC Comments ................................................................... 57

29 Summary of Technologies Analyzed in the NREL–GRI Report ........................................ 59

30 Summary of Technology Characteristics Review ............................................................... 60

31 Summary of Power Generation Scenarios .......................................................................... 62

32 Assumed Lean Gas Composition ........................................................................................ 64

33 Summary of Wellhead Gas Flow and Product Volume Assumptions ................................ 65

34 Total Cost Summary, Grid Support – Reciprocating Engine Scenario ............................... 67

35 Summary of Product Revenues, Grid Support – Reciprocating Engine Scenario .............. 67

36 Total Cost Summary, Grid Support – Gas Turbine Scenario .............................................. 68

37 Summary of Product Revenues, Grid Support – Gas Turbine Scenario ............................. 69

38 Total Cost Summary, Local Power – Reciprocating Engine Scenario ............................... 70

39 Summary of Product Revenues, Local Power – Reciprocating Engine Scenario ............... 70

Continued . . . 
ix 

LIST OF TABLES (continued) 

40 Flow Diagram, Local Power – Microturbine Scenario ....................................................... 71

41 Total Cost Summary, Local Power – Microturbine Scenario ............................................. 72

42 Summary of Product Revenues, Local Power – Microturbine Scenario ............................. 73

43 Summary of Power Generation Scenarios .......................................................................... 74

44 NG Component Boiling Points ........................................................................................... 76

45 North Dakota NG-Processing Capacity .............................................................................. 82

46 NG-Processing Capacity in North Dakota .......................................................................... 83

47 Ammonia Production Cost Estimate at Different Scales and Rates .................................... 88

48 Summary of Evaluated Technologies with Qualitative Characteristics .............................. 90
x 

NOMENCLATURE 

AEGS Alberta Ethane-Gathering System 

ASHRAE American Society of Heating, Refrigeration, and Air Conditioning Engineers 

bbl barrel 

bcf billion cubic feet 

BEPC Basic Electric Power Cooperative 

bpd barrels per day 

Btu British thermal unit 

CARB California Air Resources Board 

CFR Code of Federal Regulations 

CHP combined heat and power 

CNG compressed natural gas 

DEG diethylene glycol 

DOE U.S. Department of Energy 

ECBC Edgewood Chemical Biological Center 

EERC Energy & Environmental Research Center 

EIA U.S. Energy Information Administration 

EOR enhanced oil recovery 

EPA U.S. Environmental Protection Agency 

FERC Federal Energy Regulatory Commission 

FPP factory protection plan 

ft3

 cubic foot 

GGE gasoline gallon equivalent 

GOR gas-to-oil ratio 

GRI Gas Research Institute 

HHV higher heating value 

JT Joule–Thompson 

kWh kilowatt-hour 

LNG liquefied natural gas 

LPG liquefied petroleum gas 

LTS low-temperature separation 

Mbpd thousand barrels per day 

Mcf thousand cubic feet (standard conditions) 

Mcfd thousand cubic feet per day 

MDU Montana–Dakota Utilities Co. 

MMbpd million barrels per day 

MMcf million cubic feet 

MOF metal organic framework 

MTBE methyl tertiary butyl ether 

MW megawatt 

NBIP Northern Border Interstate Pipeline 

NDDMR North Dakota Department of Mineral Resources 

NDIC North Dakota Industrial Commission 

NETL National Energy Technology Laboratory 
xi 

NGL natural gas liquid 

NGV natural gas vehicle 

NREL National Renewable Energy Laboratory 

O&M operating and maintenance 

OEM original equipment manufacturer 

OGD Oil and Gas Division 

OGRC Oil and Gas Research Council 

PA propane–air 

RLOS refrigerated lean oil separation 

SAE Society of Automotive Engineers 

scf standard cubic foot 

TEG triethylene glycol 

ton short ton (2000 pounds) 

USGC U.S. Gulf Coast 

VMT vehicle miles traveled 

WBIP Williston Basin Interstate Pipeline 

WTI West Texas Intermediate 
xii 

END-USE TECHNOLOGY STUDY – AN ASSESSMENT OF 

ALTERNATIVE USES FOR ASSOCIATED GAS 

EXECUTIVE SUMMARY 

The Energy & Environmental Research Center (EERC), in partnership with the North 

Dakota Industrial Commission (NDIC) Oil and Gas Research Council (OGRC), Continental 

Resources, and the U.S. Department of Energy (DOE) National Energy Technology Laboratory 

(NETL), has conducted a study focused on assessing the technical and economic viability of 

technologies that could increase utilization of associated gas. The impetus for this study is the 

rapid growth of gas flaring in North Dakota, a function of rapid increase in oil production. The 

stranded gas resource is a transient resource, permitted by the state to be flared for up to 1 year, 

changing in quantity and location as oil wells begin production and gas-gathering infrastructure 

gets constructed, thereby creating a challenge to mating an end-use technology to the resource. 

The intent of this study is to examine technologies that can utilize the associated gas at 

locations upstream of traditional natural gas-processing plants, thereby extracting value from a 

currently uncaptured resource. Economic analysis of these technologies consisted of comparing 

capital expenses to potential revenue generation in an effort to frame the potential for more 

detailed economic study specific to individual technology. Technologies evaluated included 

1) natural gas liquid (NGL) recovery, 2) compressed natural gas (CNG) for vehicle fuel, 

3) electrical power generation, and 4) chemical production. 

Bakken associated gas is typically low in sulfur and high in NGLs, creating both unique 

challenges to utilization and economic opportunity since NGLs are currently more valuable than 

the dry NG. Deploying small-scale NGL recovery systems as an interim practice while gathering 

lines are built allows the highest value and most easily transported hydrocarbons to be marketed. 

Further, the leaner gas generated from these systems can be more easily utilized for power, 

transportation fuel, or transported as a compressed gas. Clearly, NGL recovery would be most 

economical at wells flaring larger quantities of gas, immediately after production begins to 

capture the greatest volume of gas. Additionally, technology mobility is critical to enable 

relocation to new wells as gas-gathering infrastructure is constructed. 

While there may be several other drivers to warrant the use of CNG in the Bakken region, 

economics alone will most likely not justify conversion of medium-sized fleets of vehicles to 

CNG if a distributed CNG refueling approach is taken. Bakken associated gas is too rich with 

NGLs and too variable in composition to be used “as-is” in NG vehicles (NGVs). It must be 

purified to a strict specification and compressed before being dispensed to a vehicle. Further, 

vehicle fleets utilizing the CNG fuel would need to be adaptable and flexible to take advantage 

of this stranded and transient gas resource. In spite of these drawbacks, U.S. Energy Information 

Administration (EIA) data indicate that CNG prices have been significantly lower and 

experienced less volatility over the past decade when compared to gasoline and diesel fuels, and 

the price gap is expected to continue through 2015. 

The demand for power in the Williston Basin has grown rapidly. In addition to meeting 

this growing demand, utilities are also faced with ensuring grid reliability. Forecasts suggest a 
xiii 

tripling of the electric load in oil-producing areas of western North Dakota and eastern Montana. 

An initial review of the characteristics of each distributed power generation technology 

eliminated some options from further consideration. Based on this review, three technologies 

were evaluated: reciprocating engine, gas turbine, and microturbine. When evaluating power 

generation scenarios, the projects were characterized into two distinct categories based on the 

primary use of the electricity, grid support and local power. In general, power production using 

rich associated gas is a viable option. A wide variety of power generation technologies exist that 

can, without much difficulty, utilize rich gas of varying quality to produce electricity and are 

scaled to wellhead flow rates. 

The petrochemical industry is dominated by large processing plants where economy of 

scale and access to large gas fields maximize profitability. Despite rapid and significant growth 

of gas production in North Dakota, only a small fraction of total U.S. NG is produced in the 

state. Pipeline and rail export of gas and NGLs to existing petrochemical infrastructure is likely 

to continue to be the predominant mode to market these resources. Although NG export is likely 

to dominate in North Dakota, opportunity does exist for small-scale technologies that can convert 

low-cost gas to higher-value chemicals or fuels that have a strong regional demand. The 

production processes with the best opportunity for economic success at the well site include 

novel fertilizer production technologies or innovative gas-to-liquid approaches that can be scaled 

appropriately. All such processes would benefit by being mobile to periodically relocate to 

better-producing wells and avoid reduced utilization rates. 

Although none of these approaches appear to be highly compelling from a purely 

economic perspective, two end-use technologies were identified that represent technically 

feasible applications: CNG and power production. The high price of transportation fuel relative 

to CNG creates some advantages; however, rich gas cannot be used in standard NGVs because of 

concerns over emissions and engine performance. In the case of power production, these 

technologies match nicely the scale and temporal nature of the associated gas resource. In either 

case, small-scale NGL recovery, although less efficient than at large centralized facilities, may 

be an enabling technology, allowing value to be extracted from the associated gas while 

improving economical utilization of leaner gas for transportation and power. Chemicals 

production would be the most challenging to deploy at small scale in the Williston Basin, but 

some chemicals (specifically nitrogen-based fertilizers) may hold some promise. 

Table ES-1 is a summary of the end-use technologies evaluated and their respective 

characteristics as they relate to deployment in the Williston Basin. 

Table ES-1. Summary of Evaluated Technologies with Qualitative Characteristics 

Technology 

Gas Use 

Range, Mcfd 

NGL Removal 

Requirement 

 

Scalability to 

Resource 

Ease of 

Mobility 

Likelihood of 

Deployment at 

Small Scale 

Power – Grid Support 1000–1800 Minimal Very scalable Very easy Very likely 

Power – Local Load 300–600 Minimal Very scalable Very easy Very likely 

CNG 50+ Yes Scalable Very easy Possible 

Chemicals 1,000,000* No Not scalable Not mobile Very unlikely 

Fertilizer 300–2000 No Scalable Not easy Possible 

Gas-to-Liquids 1,000,000* No Scalable Easy Possible 

* Typical commercial-scale plant. 
1 

END-USE TECHNOLOGY STUDY – AN ASSESSMENT OF 

ALTERNATIVE USES FOR ASSOCIATED GAS 

INTRODUCTION 

The Energy & Environmental Research Center (EERC), in partnership with the North 

Dakota Industrial Commission (NDIC) Oil and Gas Research Council (OGRC), Continental 

Resources, and the U.S. Department of Energy (DOE) National Energy Technology Laboratory 

(NETL), has conducted a study to assess the technical and economic viability of technologies 

and processes that could lead to increased utilization of associated gas. The scope of this study 

included evaluating distributed end-use opportunities that may benefit from the rapid expansion 

of oil and gas production in shale formations like the Bakken Formation in North Dakota. 

In North Dakota, oil production increased to 534,000 barrels per day (bpd) by the end of 

2011, up twofold in only 2 years. This rapid growth in oil production has led to an increase in the 

amount of associated gas that is flared while gas-gathering, processing, and transmission 

infrastructure are built to accommodate the new production. In spite of dramatic investment and 

expansion of gas-processing infrastructure, around 30% of North Dakota’s produced natural gas 

is flared, nearly 190,000 thousand cubic feet (Mcf)/day or 1,500,000 gasoline gallon equivalent 

(GGE)/day. 

This gas resource, although underutilized, is not a low-value by-product of oil production. 

Bakken shale gas is rich in natural gas liquids (NGLs). Therefore, although natural gas prices are 

at a historic low—approximately 10% of the value of crude oil on an energy-equivalent basis—

the high concentration of NGLs, ethane, propane, butane, and higher-carbon-number 

hydrocarbons, supports the economic push to gather and process gas. Typical Bakken gas may 

contain as much as 10 gallons of NGLs per 1 Mcf of wellhead gas. These NGLs, when recovered 

from the gas during gas processing, provide economic incentive to build the necessary 

infrastructure to prevent flaring. 

North Dakota, a rural state, possessed limited NG infrastructure prior to the recent increase 

in oil and gas production activity. Construction of gas-gathering pipeline, gas-processing plants, 

and interstate pipeline is proceeding rapidly, with industry planning to invest $3 billion between 

2011 and 2014. For a period of time, gas flaring is likely to continue; however, it is widely 

expected that as production activities mature in the Bakken play, gas gathering and infrastructure 

will meet the demand. Currently the North Dakota Century Code allows gas to be flared for up to 

12 months after initial production. After that, gathering piping is expected to be connected to 

new well sites, and gas must be marketed. Nonetheless, an opportunity exists for the next several 

years to utilize newly produced, otherwise flared associated gas before gathering infrastructure is 

fully built out. Longer term, opportunity will continue because of the existence of a small 

fraction of wells that, because of geography or economics, may not be connected to gasgathering systems. 

The expectation of the study when proposed was to evaluate a number of known 

technologies and assess their applicability to distributed operation with associated gas containing 
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Figure 2. 

e Associated

rgest produc

e being Texa

on bbl (510

es Oil and 

the No. 2 pr

In addition to

produced in

hough a shale

mations in th

e Bakken Fo

akota and n

ussion 

ormation is 

on typically

nd the midd

C) within th

re Bakken F

bon resource

nventional oi

Historical es

d Press anno

cer of oil in 

as, Alaska, a

0,000 bpd) 

Gas Divisio

oducer of oi

o the 15 mil

n November

e formation,

he United St

ormation in t

northeastern 

known to b

y consists o

dle member, 

he shales ma

ormation ran

e within the

il play becau

stimates of B

ounced on O

the United 

and Californ

in Novemb

on, 2012). B

il in the Uni

llion bbl of o

r 2011. An 

 it is an oil p

tates, which 

the U.S. port

Montana. T

3 

be an import

f three mem

comprising 

ay be as hig

nging from 

e Bakken F

use it is typi

Bakken oil re

October 28, 2

States, ahea

nia, respectiv

ber 2011 (N

Based on th

ited States in

oil, approxim

important p

play (with a

tend to be p

tion of the W

The formatio

rtant source 

mbers: the 

dolomitic s

gh as 40%, w

10 to 500 bi

ormation is

ically charac

esources (Bo

2009, that N

ad of Louisi

vely. North 

North Dako

he increased

n March 201

mately 15.6 m

oint regardi

associated N

primarily NG

Williston Bas

on is produc

rock for oil

upper and 

siltstone and 

with estimat

illion barrels

 tremendou

cterized by v

ohrer et al., 2

North Dakota

iana and Ok

Dakota pro

ota Departm

d production

12, surpassin

million cubi

ing the Bakk

NG), unlike m

G plays. 

sin underlies

ctive in num

l in the Will

lower mem

sandstone. 

tes of total o

s (bbl) (Figu

s, the Bakk

very low por

2008). 

a had becom

klahoma, wit

oduced more

ment of Mi

n, North D

ng California

ic feet (MMc

ken Formati

many of the 

s most of we

merous reser

liston 

mbers, 

Total 

oil in 

ure 2). 

ken is 

rosity 

me the 

th the 

e than 

ineral 

akota 

a and 

cf) of 

ion is 

other 

estern 

rvoirs 
througho

and Sani

Th

since the

as oil rec

structura

many stu

Wi

Williston

(Figure 3

by shale

Bakken. 

and sand

in the No

Figure 3

out Montana 

sh Fields in 

e Bakken Fo

 1950s, with

covery strate

l characteris

udies. 

ith respect t

n Basin typ

3). Lithologi

s rich in or

The litholog

dstones) to ca

orth Dakota p

3. Stratigraph

and North D

North Dako

ormation ha

h each decad

egies and tec

stics of the 

o stratigraph

pically comp

cally, the up

rganic carbo

gy of the mi

arbonates (pr

portion of th

hic column f

stratigraphy

Dakota, with

ta being the 

s been know

de since the 

chnologies e

Bakken For

hy, the Dev

prises three 

pper and low

on that act a

iddle Bakken

rimarily dolo

he Williston 

for rocks of t

y of the Bakk

4 

h the Elm C

most prolifi

wn to be hyd

1970s seeing

evolved. As 

rmation in N

onian–Missi

members: 

wer members

as the sourc

n varies wid

omites), with

Basin. 

the Williston

ken Formatio

Coulee Field 

ic examples 

drocarbon-be

g periods of

such, the st

North Dako

issippian-ag

the upper, 

s of the Bakk

ce rock for 

dely from cla

h five distinc

n Basin in N

on in North 

in Montana

of Bakken s

earing in the

f interest amo

tratigraphic, 

ota have bee

ed Bakken 

middle, an

ken Formatio

oil reservoi

astics (includ

ct lithofacie

North Dakota

Dakota. 

a and the Par

success. 

e Williston B

ong oil prod

 lithological

en the subje

Formation i

d lower Ba

on are domin

irs in the m

ding shales, 

s being iden

a and general

rshall 

Basin 

ducers 

l, and 

ect of 

in the 

akken 

nated 

middle 

silts, 

ntified 

lized 
Alt

activity, 

Lodgepo

Cu

In 

technolog

have be

geomech

several y

be most 

wells, the

We

lateral len

uncemen

Resource

F

though the B

the petroleu

le, Three Fo

urrent Oil an

Explorat

general, ap

gies and too

en largely 

hanical prope

years have be

favorable (e

e use of hydr

ell completio

ngths of 500

nted liners, s

es – Oil and 

igure 4. Gen

base

Bakken Form

um industry

orks, and Bir

nd Gas Pro

tion and Pro

pproaches to

ols for the dr

dictated by

erties within

een drilled h

e.g., areas of

raulic fractu

ons consist 

00–10,000 ft

shown in gen

Gas Divisio

neralized dep

d on well co

mation is the

y is also op

rdbeard Form

duction 

oduction Tec

o the selec

rilling, comp

y knowledg

n a localized

horizontally i

f relatively h

uring is critic

of horizonta

t. Completio

neralized de

n (NDDMR

piction of an

ompletion dia

5 

e target of th

ptimistic abo

mations. 

chnology

tion of exp

pletion, and 

ge (or lack

d area. A va

into the mid

higher poros

cal to establis

ally drilled w

ons include o

epictions from

R–OGD) well

n open-hole c

agrams in N

he majority 

out several 

ploitation st

stimulation 

k thereof) o

ast majority 

ddle member

sity and perm

shing long-t

wells at dep

openhole and

m North Da

l files in Fig

completion i

NDDMR–OG

of the curre

others, incl

trategies and

 of wells in 

of lithology

of Bakken 

r where geol

meability). F

term product

pths greater 

d variations 

akota Depart

gures 4–6. 

in the middle

GD well files

ent oil produ

luding the T

d applicatio

the Bakken

y, structure,

wells in the

logy is thoug

For most Ba

tivity. 

than 8000 f

of cemented

tment of Mi

e Bakken, 

s. 

uction 

Tyler, 

on of 

n play 

 and 

e last 

ght to 

akken 

ft and 

d and 

ineral 
Figure 5

Figure 6

. Generalize

. Generalize

d depiction o

completio

ed depiction 

well comple

of a Middle 

on diagrams 

of a cement

etion diagram

6 

Bakken unc

in NDDMR

ted liner com

ms in NDDM

cemented lin

R–OGD well

mpletion in th

MR–OGD w

ner completio

l files. 

he middle B

well files. 

on, based on

Bakken, base

 well 

d on 
Fra

treatment

completi

operators

Fig

swell pac

to fractur

between 

transvers

and prop

Figu

multista

Oil

Sin

a relative

in the lat

in the m

unconven

productio

acture treatm

ts in open

ons; howeve

s. 

gure 7 show

ckers to isol

re the well a

the fractur

se to the wel

pant placem

ure 7. Gener

age fracture t

l and Gas P

nce 1951, wh

ely slow pac

te 1980s) an

mid 2000s), 

ntional form

on in North D

ments can be

nhole comp

er, multistag

s a generaliz

ate the vario

along the len

re and the 

lbore and, u

ment to ensur

alized wellb

treatment, ba

Production 

hen oil was f

e. With the 

nd hydraulic 

the efficien

mations such

Dakota from

e divided int

pletions hav

ge completio

zed wellbor

ous fracture 

ngth of the 

wellbore. M

unlike longitu

e good flow 

bore schemat

ased on well

first produce

advent of ho

fracturing o

ncy of oil re

h as the Ba

m 1951 throu

7 

to two categ

ve lower c

ns appear to

e schematic 

zones. The 

wellbore in 

Multistage c

udinal fractu

communica

tic showing t

l completion

ed from the W

orizontal dril

or “fracking”

ecovery imp

akken econo

ugh 2011. 

gories: singl

capital cost

o be increasi

 of a multis

objective of

order to cre

completions 

ure completi

ation to the w

the placeme

n diagrams in

Williston Ba

lling (first u

” (first utiliz

proved and 

omical. Figu

e stage or m

s than mu

ng in popula

stage treatme

f a single-sta

eate the grea

attempt to 

ions, require

wellbore. 

ent of swell p

n NDDMR–

asin, oil has 

utilized in the

zed in the B

made recov

ure 8 show

multistage. S

ultistage fra

arity among 

ent scheme u

age completi

atest contact

create frac

e quality prop

packers for a

–OGD well f

been produc

e Williston B

akken Form

very of oil 

ws the annua

Single 

acture 

most 

using 

ion is 

t area 

ctures 

ppant 

a

files. 

ced at 

Basin 

mation 

from 

al oil 
Figur

through 

 Da

high of 5

increase 

surpassed

Novembe

The

associate

productio

540,000 t

record, w

1951 and

Inte

historical

(and gas

capacity.

gas being

gathering

NG, the 

goal is t

“stranded

is upstrea

re 8. Annual 

2011. Data s

aily oil produ

534,000 bpd 

is uncertai

d significan

er 2011. 

e Bakken F

ed NG, and 

on. Daily g

thousand cu

with 155,803

d 1990, respe

erestingly, t

lly to 1:1 mo

s) production

 The shortag

g flared at th

g and proces

economics a

o see indust

d” gas is bei

am of the ga

oil productio

sourced from

uction has in

in Decembe

n. The num

nt mileston

Formation, a

the quantiti

gas producti

ubic feet (M

3 MMcf pro

ectively. Gas

the basinwi

ost recently. 

n has result

ge of gas-pr

he well site. 

ssing infrast

are challengi

try get flari

ing called no

as-processing

on and numb

m the North D

ncreased sig

er 2011) and

mber of pro

nes in 201

although an

ies of NG p

ion reached

Mcf) per day

oduced. Figu

s records pri

ide gas-to-o

Despite the 

ted in a sub

ocessing cap

Therefore, 

tructure to c

ing. State of

ng down to

ontraditional

g facility. 

8 

ber of wells p

Dakota Indus

gnificantly, e

d is projecte

oducing wel

11, exceedi

n oil play, 

produced ha

d an all-tim

y. The annua

ure 9 shows

ior to 1990 a

oil ratio (G

change in th

bstantial sho

pacity, in tur

the industry

capture this 

fficials have

o at least 10

l NG, a term

producing in

strial Comm

exceeding 50

d to continu

lls and acti

ing 6300 

also produc

ave also inc

me high in 

al productio

the annual 

are incomple

GOR) produ

his ratio, the

ortage of g

rn, has resul

y is investing

gas resource

e released sta

0%. For the 

m that is inte

n North Dako

mission, Oil an

00,000 bpd 

ue rising, alth

ive drilling 

and 200, 

ces significa

reased with

December 

on for 2011 

oil and gas 

ete. 

uction has 

e quantity an

gas-gathering

lted in a dra

g considerab

e, but at the

atements ind

purposes o

ended to des

ota from 195

nd Gas Divis

(recording a

hough the ra

rig counts 

respectively

ant quantitie

h the growin

2011, excee

was also a

production 

gone from

nd pace of ne

g and proce

amatic increa

ble capital in

e current pri

dicating that

of this study

scribe all NG

51 

sion. 

a new 

ate of 

also 

y, in 

es of 

ng oil 

eding 

a new 

since 

m 2:1 

ew oil 

essing 

ase in 

n gasice of 

t their 

y, this 

G that 
Figure 9

Da

of the NG

70% com

18% (non

North Da

and Will

productio

To 

to show t

the Dece

5000-me

9. Annual oi

ata through t

G resource a

mes from the

ne more than

akota only, t

liams (in al

on from thes

Table 1. D

Four Pro

County 

Dunn 

McKenzi

Mountrai

Williams

better under

the geograph

ember 2011 

ter grid was

il and gas pro

Dakota Ind

the end of 20

and are cons

e Bakken Fo

n 3%) from 

he top four o

lphabetical 

se four count

December 2

oducing Cou

ie 

il 

rstand the lo

hic location 

data from N

s applied, an

oduction in t

dustrial Com

011 were co

sidered prim

ormation, 12

several othe

oil- and gasorder). Tab

ties. 

2011 Month

unties in No

Monthly Oi

b

2,33

3,07

4,49

2,05

ocation of th

of gas prod

NDDMR–OG

nd gas volum

9 

the Bakken F

mmission, Oil

ompiled from

marily from t

2% from the

er formation

-producing c

le 1 summa

hly Oil and G

orth Dakota

il Production

bbl 

37,900 

79,265 

97,997 

53,172 

his gas produ

duction as we

GD (Figure 1

mes (total an

Formation. D

l and Gas Di

m NDDMR–

the Bakken 

e Madison F

ns. Focusing 

counties are 

arizes the D

Gas Produc

n, M

Pro

uction, a gra

ell as the loc

10). For eac

nd flared) we

Data sourced

ivision. 

–OGD regar

Formation. 

Formation, an

on the Bakk

Dunn, McK

December 2

ction for the

Monthly Gas 

oduction, Mc

1,620,249 

4,343,047 

3,256,932 

3,273,668 

aphical depic

cation of fla

ch of these fi

ere summed 

d from the N

rding the qua

More accur

nd the rema

ken Formati

Kenzie, Moun

2011 oil and

e Top 

cf 

ction was cr

ared gas base

figures, a 500

within each

North 

antity 

ately, 

aining 

ion in 

ntrail, 

d gas 

reated 

ed on 

00- × 

h grid
Figure 10. Graphical depictio

flared for

10 

n of total ga

 December 2

s produced 

011. 

and total gas 
for Dece

color cor

about the





A 

significan

percentag

35% of 

percentag

Formatio

processin

the gas b

been con

attempt t

Although

flared ro

2012). 

Figure 1

 

1

 Wyoming

ember 2011 

rresponding 

e issue of NG

Flaring is w

Higher leve

chart of the

nt increase 

ge of gas un

the total g

ges of gas 

on. Prior to 

ng infrastruc

being sold to

nverging. Th

to keep pac

h this rate a

oughly 40% 

1. Annual ga

 

g flaring total i

in Mcf. The

to a volum

G flaring at t

widespread th

ls of flaring 

e annual ga

in gas prod

nsold (and as

gas produce

sold and u

developme

cture was suf

o market. Sin

his issue ha

e with the r

appears very

less than T

as produced,

C

 

includes CO2-v

e aggregate 

me range. Th

the well site:

hroughout th

exist where 

as produced

duction as w

ssumed flare

ed. Figure 

unsold have

ent of the B

fficient to ha

nce 2007, th

as not gone 

rapid increa

y high on a p

Texas or Wy

, sold, and u

Commission, 

venting volume

11 

for each gri

hese two fig

:

he Williston B

gas gatherin

d, gas sold, 

well as the i

d) at the end

12 provides

e changed 

Bakken Form

andle the gas

he two numb

unnoticed,

se in gas pr

percentage b

yoming1 (U

unsold. Data 

Oil and Gas

es. 

id was then 

gures make 

Basin. 

ng has not ye

and gas un

increase in u

d of 2011 re

s a graphic

with the d

mation, the

s production

bers (% gas 

and infrast

roduction an

basis, on a 

U.S. Energy 

sourced from

s Division. 

n represented

clear some 

et been built

nsold since 

unsold gas 

eached a new

cal perspecti

development 

 existing g

n, resulting i

sold and %

tructure is b

nd to captur

volume bas

Information

m the North D

d in each gr

important p

t out. 

1990 show

(Figure 11).

w high, excee

ive on how

of the Ba

as-gathering

in 85% to 90

% gas flared) 

being built i

re the flared

is, North D

n Administra

Dakota Indu

rid by 

points 

ws the 

. The 

eding 

w the 

akken 

g and 

0% of 

have 

in an 

d gas. 

akota 

ation, 

ustrial 
Figure

Ano

phenome

change in

previousl

should b

significan

matching

As 

productio

distinct in

productio

being fla

In 2

and 57,9

summariz

2011 dat

the Dece

day. Figu

Decembe

that Tabl

 12. Percent

other impor

enon. To bet

n flare gas 

ly, Figure 1

be noted tha

ntly), and th

g distributed 

Quantity

presented 

on is substan

ncrease in g

on has outpa

red at the we

2011, a total

976 MMcf w

zes the num

a. Figure 14

mber 2011 d

ure 15 displa

er. Figure 16

le 2, Table 3

age of gas so

Co

rtant point 

tter highlight

location and

13 shows th

at in any gi

his change 

end-use tech

y

in previous

ntially great

as productio

aced the ga

ell site (repr

l of 155,803

was unsold.

mber of wells

 shows the s

data are prov

ays the Dece

6 shows the 

, Figure 14, 

old and unso

ommission, 

about the 

t the tempor

d quantity d

he flared ga

iven area, t

in volume, 

hnology to t

s sections, 

ter than oil p

on beginning

s-processing

esented as g

3 MMcf of N

 To further

s flaring gas

same breakd

vided in Tab

ember flaring

same break

and Figure 1

12 

old. Data sou

Oil and Gas

flared gas

ral nature of

during 2011.

as in Januar

the volume 

and opport

the source pr

the quantity

production f

g around 200

g capacity, r

gas unsold in

NG was pro

r define the 

s at varying 

down of well

ble 3 as the n

g rates as a p

down for th

15 summariz

urced from th

s Division. 

s is that it

f the flare ga

. Using the 

ry and Dece

of gas flar

tunity, pose

roduct (flare

y of NG fr

from other f

07 (Figure 1

resulting in 

n Figure 11).

duced, of w

quantity of

rates per mo

ls flaring thr

number of w

percentage o

he 2011 calen

ze Bakken w

the North Da

t is a temp

as issue, Fig

same grid s

ember 2011

red changed

es a signific

ed gas). 

from Bakke

formations, 

1). This rapi

an increase

which 97,827

f NG being

onth based o

roughout 201

wells flaring b

of the total f

ndar year. It

wells only. 

akota Industr

porally sen

ure 13 show

system desc

, respective

d (in some 

cant challeng

n Formatio

as shown b

id increase i

ed volume o

7 MMcf was

g flared, Tab

on the Dece

11. Alternati

based on Mc

flared amoun

t should be n

rial 

sitive 

ws the 

cribed 

ely. It 

cases 

ge to 

n oil 

by the 

in gas 

of gas 

s sold 

ble 2 

ember 

ively, 

cf per 

nt for 

noted 
Figure 13. Graphical depiction of f

13 

lared gas for January and December 2011. 
Fig

ND

per year 

productio

annually 

productio

from the 

Table 2.

Month –

Flaring R

0–499 

500–999

1000–49

5000–99

10,000–1

>20,000 

Total 

* Does not

gure 14. Num

DDMR–OGD

for the next

on of 100,00

by approx

on and only 

Williston B

 Summary

– December

Rate, Mcf/mo

99 

99 

19,999 

t equal 100% b

mber of Bak

D has indicat

t several yea

00 Mcf/well 

imately 200

10% is flare

asin. 

of Bakken W

r 2011 Data

onth 

because of roun

kken wells fla

ted in presen

ars. Using 2

(300 Mcf/d

0,000,000 M

ed, the flared

14 

Wells Flarin

Number of

2228

170

522

156

72

27

3175

nding. 

aring a range

ntations that

000 new we

ay) it is anti

Mcf. If gas 

d volume wo

ng Gas Base

f Wells P

e of quantiti

t it expects, 

ells per year

icipated that

gathering a

ould still am

ed on Rates

Percent of To

70 

5 

16 

5 

2 

1 

99 

ies per month

2000 new w

r and an ass

t gas product

and process

mount to 20,0

s/ 

otal* 

h for 2011.

wells to be d

umed annua

tion will inc

sing catch u

000,000 Mcf

drilled 

al gas 

crease 

up to 

f/year 
F

Figure 15. F

Figure 16. Nu

laring rates

mber of Ba

 as a percen

kken wells f

15 

ntage of total

flaring a ran

l flared gas f

ge of quanti

or Decembe

ties per day 

r 2011. 

for 2011. 
16 

Table 3. Summary of Bakken Wells Flaring Gas Based on Rates/Day – 

December 2011 Data 

Flaring Rate, 

Mcf/day 

Number 

of Wells 

Percent of Total, 

No.-of-wells basis* 

Total Gas Flared 

December, Mcf 

Percent of Total, 

flared-volume basis 

<1 1695 53.4 2331 0.1 

1–299 1325 41.7 2,178,842 49.9 

300–599 103 3.2 1,017,536 23.3 

600–899 26 0.8 463,634 10.6 

900–1199 17 0.5 457,220 10.5 

1200–1499 4 0.1 87,378 2.0 

1500–1999 3 0.1 70,974 1.6 

>2000 2 0.1 89,621 2.1 

Total 3175 99.9 4,367,536 100.1 

* Does not equal 100% because of rounding. 

This study focused on the opportunity for utilization of associated gas from initial wells 

drilled on a lease. Associated gas will be available in greater quantities as infill wells are 

installed, and thus may impact the applicability of certain technologies investigated in this study. 

It was reasoned that by the time multiple wells are in production, gas-gathering infrastructure 

will be in place. For this reason and others stated in the report, the authors view the window of 

opportunity for application of these technologies to be during the initial few months when gas 

production is at its highest and not as a long-term installation. In most scenarios considered, once 

gas production has declined sufficiently, the equipment would be mobilized to a new well to 

capture initial production. 

Quality/Physical Characteristics 

NG at the wellhead commonly exists as a mixture of methane (C1) with other 

hydrocarbons, including ethane (C2), propane (C3), butane (C4), pentane (C5), hexane, and 

higher (C6+). These higher-carbon-number hydrocarbons are often referred to as NGLs. 

Wellhead NG also contains other compounds such as water vapor, hydrogen sulfide, carbon 

dioxide, oxygen, and nitrogen. A random sample of Bakken region wellhead gas quality data is 

presented in Table 4. 

Bakken associated gas is typically low in sulfur and high in NGLs. This high NGL content 

typically corresponds with higher energy content (1300–2000 Btu/ft3

) when compared to 

residential pipeline gas (~1000 Btu/ ft3

). These NGLs pose unique challenges to utilization, both 

economically and practically. 

Although gas composition can vary within Bakken wells, a gas composition was assumed 

for the purposes of this study and is presented in Table 5. In addition to the composition in 

Table 5, the energy content was assumed to be 1400 Btu/ ft3

. 
17 

Table 4. Select Associated Gas Quality Data from Wellheads in the Bakken Formation in 

North Dakota1

Wellhead: A B C D E F G 

C1, mol% 70.23 48.07 73.93 50.79 68.05 52.9 66.17 

C2, mol% 13.94 18.78 13.25 15.73 14.2 11.32 13.15 

C3, mol% 6.7 14.87 5.55 11.61 8.05 8.52 7.01 

C4+, mol% 5.5 16.38 4.32 14.42 6.22 6.46 9.37 

CO2 + N2, 

mol% 

3.44 1.72 2.87 7.29 3.43 19.8 4.18 

H2S 0.19 0.18 0.08 0.16 0.05 1.00 0.12 

Wobbe Index, 

 Btu/scf 

1470 1712 1454 1563 1491 1207 1519 

Methane No. 

 (MN) 

53.2 43.5 56.1 44.9 51.6 49.2 48.7 

1

 Data from a randomly selected set of wellhead gas analysis provided to the EERC by a number of North Dakota 

operators. 

Table 5. Assumed Bakken Gas Composition

Component mol% 

H2O (water) 0.02 

N2 (nitrogen) 5.21 

CO2 (carbon dioxide) 0.57 

H2S (hydrogen sulfide) 0.01 

C1 (methane) 57.67 

C2 (ethane) 19.94 

C3 (propane) 11.33 

I-C4 (isobutane) 0.97 

N-C4 (n-butane) 2.83 

I-C5 (isopentane) 0.38 

N-C5 (n-pentane) 0.55 

C6 (hexane) 0.22 

C7 0.09 

C8 0.04 

C9 0.01 

C10–C11 0.00 

C12–C15 0.00 

Production, Processing, Transport, and Distribution 

NG processing acts to separate heavier hydrocarbons (ethane, propane, butane, etc.) and 

other contaminants (sulfur, nitrogen, oxygen, water, etc.) from the pure natural gas, to produce 

what is known as “residue gas” or “pipeline-quality” dry NG. Independent transportation 

pipelines impose varying restrictions on the makeup of the gas that can be injected into the 

pipeline. 
Th

Here, liq

trucked t

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elevate th

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plant thro

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

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e first proce

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Water remo

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ese processe

Figure 17

esses involv

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of NGLs 

carbon dioxi

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18 

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G is then tra

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typically occ

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ansported to 

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cur at or ne

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17. 

mation 

head. 

es are 

some 

eaters 

essing 

plant, 
19 

Water Removal 

In addition to separating oil and some condensate from the wet gas stream at the wellhead, 

water vapor that exists in solution in NG is removed via dehydrating processes – either 

absorption or adsorption. Absorption occurs when the water vapor is taken out by a dehydrating 

agent. Adsorption occurs when the water vapor is condensed and collected on the surface. These 

processes are generally conducted at a centralized gas-processing plant. 

Glycol dehydration is a frequently employed absorption process that uses a liquid 

desiccant to absorb water vapor from the gas stream. Glycol dehydration uses either diethylene 

glycol (DEG) or triethylene glycol (TEG) in contact with the wet gas stream to absorb water 

from the wet gas. After absorbing water, the glycol particles sink to the bottom of the contactor, 

where they are removed. The now-dry NG is then carried out of the dehydrator. The glycol 

solution is heated in a boiler to vaporize the water out of the solution. 

Solid desiccant dehydration is a frequently employed adsorption method that usually 

consists of two or more adsorption towers filled with solid desiccants, such as silica gel. Wet NG 

is passed through the towers. Water vapor in the wet NG is sequestered on the surface of the 

desiccant. Dry NG exits the tower to the NGL separation process. 

Separation of NGLs 

Removal of NGLs is generally accomplished at centralized gas-processing facilities in two 

steps. First, the NGLs must be extracted from the NG. Second, these NGLs must be fractionated 

into their base components. 

NGL Extraction 

Two techniques account for approximately 90% of all NGL removal from NG streams in 

gas-processing plants – the absorption method and the cryogenic expander process (Ghosh and 

Prelas, 2009). 

The absorption method of NGL extraction is very similar to using absorption for 

dehydration. The main difference is that in NGL absorption, absorbing oil is used instead of 

glycol. This absorbing oil absorbs NGLs in much the same manner as glycol absorbs water. The 

NG is passed through an absorption tower and is brought into contact with the absorption oil, 

which absorbs much of the NGLs. The “rich” absorption oil then exits the tower and is fed into 

lean oil stills, where the mixture is heated to a temperature above the boiling point of the NGLs 

but below that of the oil. This process recovers approximately 75% of butanes and 85%–90% of 

pentanes and heavier molecules. 

Cryogenic processes are used to extract lighter hydrocarbons such as ethane from NG. 

These processes use extreme cooling of the gas stream to condense out the lighter NGLs. An 

effective method of chilling the gas stream is the turbo expander process. In this process, 

external refrigerants are used to cool the NG stream. Then, an expansion turbine is used to 

rapidly expand the chilled gases, which causes the temperature to drop significantly (Joule–
20 

Thompson [JT] effect). This process can recover up to 95% of the ethane originally in the gas 

stream. 

NGL Fractionation 

NGLs removed from the NG stream must next be broken down into their base 

components to be marketable. Fractionation is used to accomplish this step. Fractionation uses 

controlled heating and the boiling points of the different hydrocarbons in the NGL stream to 

separate gas components. The fractionation process is conducted in discrete steps, starting with 

the removal of the lighter NGLs from the stream. Fractionators are used in the following order: 

 Deethanizer 

 Depropanizer 

 Debutanizer 

 Butane splitter or deisobutanizer – this step separates the iso- and normal butanes 

Sulfur and Carbon Dioxide Removal 

NG can contain significant amounts of sulfur and carbon dioxide, which must be removed 

prior to use of the NG as fuel. The process for removing hydrogen sulfide from NG is similar to 

the processes of glycol dehydration and NGL absorption described earlier. This process is used 

in approximately 95% of U.S. gas-processing plants. The NG is bubbled through a tower that 

contains an amine solution having an affinity for sulfur. The effluent gas is typically free of 

sulfur compounds. Like the process for NGL extraction and glycol dehydration, the amine 

solution is typically regenerated. Although most NG desulfurization involves the amine 

absorption process, it is also possible to use solid desiccants such as iron sponges to remove the 

sulfide and carbon dioxide. 

Straddle Extraction Plants 

In addition to processing done at the wellhead and at centralized processing plants, final 

polishing is sometimes accomplished at straddle extraction plants. These plants are located on 

major pipeline systems. Although the NG that arrives at these straddle extraction plants is 

already of pipeline quality, there may exist small quantities of NGLs that are extracted at the 

straddle plants. 

Interstate Pipeline Transport 

Interstate NG pipelines have gas quality requirements that vary from pipeline to pipeline 

but are established for each pipeline under its Federal Energy Regulatory Commission (FERC) 

gas tariff. Tariff terms and conditions typically limit such gas characteristics as the following: 

 Presence on nongaseous constituents (such as particulates, gums, and oil) 

 Heating value 

 Liquid hydrocarbon content (expressed as dew point) 

 Hydrogen sulfide, total sulfur, and mercaptan sulfur 
21 

 Hydrocarbon components 

 Water 

 Undesirable constituents like carbon dioxide, oxygen, nitrogen, and mercury 

 Specific gravity 

 Hydrogen 

 Helium 

 Deleterious (toxic or hazardous) substances 

 Microbial agents 

 Temperature 

Summary of Bakken Associated Gas 

Based on the information presented in the previous sections, several key points have been 

provided to summarize the current state of oil and gas development as well as the opportunities 

as hypothesized by the authors: 

 North Dakota is experiencing unprecedented oil and gas production from the Williston 

Basin in the western part of the state. Assuming continued strong prices for oil and 

continued completion technology evolution, the development of the Williston Basin is 

expected to continue at a rapid pace. 

 The primary formation targeted for production is the Bakken Formation, a tight shale 

formation requiring horizontal drilling and hydraulic fracturing stimulation to produce 

economical quantities of oil. 

 The Bakken Formation is an oil play but contains significant quantities of associated 

NG, which is high in NGLs. 

 Currently, the value of the NGLs is substantially higher than the value of the “residue” 

gas, and separation of the NGLs, if economical, makes sense and can enable the 

economic viability of other NG uses. 

 The combination of prolific oil production from Bakken wells, the currently high crude 

oil price, and the significant quantity of associated gas has resulted in a volume of NG 

production that exceeds the current gas-gathering and processing infrastructure. The 

excess of gas has forced producers to flare large quantities of NG at some “stranded” 

well sites. 

 Given that industry, regulators, and the general public wish to minimize this flaring, the 

amount of flared NG is likely to decrease significantly in the future. 

 The best opportunity for capturing and utilizing the flared gas in a nontraditional 

manner (i.e., a use other than delivery and processing at a NG plant) is likely to be timesensitive. That is, infrastructure will eventually be built out and gas will be captured. 

The opportunity to capture the gas exists after the well is put into production and before 
22 

gas gathering occurs. Modularity and mobility will also be vital in any feasible 

distributed opportunity. 

ALTERNATIVE APPROACH FOR SMALL-SCALE GAS PROCESSING AND NGL 

RECOVERY 

Background 

The overarching purpose of this study was to identify alternative uses of stranded rich 

associated gas that could provide an economical alternative to flaring while efforts continue to 

build gas-gathering and processing infrastructure needed to accommodate the rapid expansion of 

oil and gas production in the Bakken Formation. Emphasis was placed on uses that derived 

economic and environmental benefit while allowing a minimum amount of gas cleanup. Within 

the study, the authors recognized that to be competitive, small-scale gas utilization approaches 

would need to be mobile, moving to where stranded gas is available or competitive with 

centralized gas processing, thereby allowing the technology to remain in place even after gasgathering pipelines are installed. 

Two obvious gas uses were identified that have large NG demand and match the 

geographically distributed gas resource: transportation fuel and power. The high price of 

transportation fuel relative to NG creates some advantages; however, rich gas cannot be used in 

standard NG vehicles (NGVs) because of concerns over emissions and engine performance. In 

the case of power production, NGLs contained in the rich gas are more valuable in the chemical 

market than as a combustion fuel or associated electricity. Further, they do not necessarily 

improve engine performance. As such, small-scale NGL recovery, although less efficient than at 

large centralized facilities, may be an enabling technology, allowing value to be extracted from 

the associated gas while improving economical utilization of leaner gas for transportation and 

power. Further, at some locations, where geography and economics prevent gas gathering, even 

low-efficiency NGL recovery approaches may provide an attractive alternative with no flaring. 

Summary of Alternative Gas-Processing Technologies 

The goal of this study is not to define a specific distributed-scale gas-processing system 

but, rather, to identify opportunities to work outside the typical centralized gas plant model and 

identify conditions that could allow technical and economic feasibility. The approach taken by 

this study is to examine the broad unit functions employed in traditional gas processing, then 

identify new alternatives that may offer potential paths for further research focused on 

applicability to smaller-scale implementation. The unit functions can be broken down as follows: 

 Acid gas removal 

 Dehydration 

 Nitrogen rejection 

 NGL recovery 
23 

Acid Gas Removal 

In most cases, because of low content, acid gas removal is not required on Bakken 

associated gas. In general, potential acid gases to be removed from NG streams are CO2 and H2S. 

CO2 is essentially a neutral compound and, in most cases, is removed via the formation of 

carbonic acid. This is a kinetically slow process that may require catalysis. H2S is much more 

reactive and is easier to remove. Several conventional and alternative technologies can be 

applied to acid gas removal. A summary of these technologies is presented in Table 6. 

Table 6. Possible Distributed-Scale Acid Gas (SO2 and CO2) Removal Technologies 

Absorbents (solvents) 

 Physical 

 Chemical (organic, inorganic) 

 Physical/Chemical 

Adsorbents (pressure swing adsorption, online or off-line regeneration) 

 Molecular Sieves 

 MOFs 

 PURASPEC (ZnO for H2S removal) 

Membranes 

 Polymer 

 Zeolites 

Several alternate acid gas removal technologies are currently under development. Some of 

these technologies are being investigated already within the EERC’s gasification and syngas 

purification programs. Some of these technologies hold near-term promise for small-scale NGprocessing applications. 

New semipermeable membrane technologies enable separation of acid gases and water 

from the NG stream. However, with current technology, it is difficult to adjust the relative rates 

of diffusion of CO2 and H2S. Therefore, a distributed gas-processing system utilizing this 

technology must be designed to meet the CO2 specification. A fixed-bed adsorbent may then be 

used to remove H2S subsequently to meet the sulfur specification. 

Metal organic frameworks (MOFs) have been investigated by many (including DOE 

NETL, UOP, Sandia National Laboratories, U.S. Army Edgewood Chemical Biological Center 

[ECBC] and others) as highly efficient, easily regenerable acid gas absorbers (Willis, 2010; 

Peterson and Rossin, 2008). MOFs are novel crystalline compounds consisting of metal ions 

structured within organic molecules to form multidimensional porous structures. Chemisorption 

occurs because the framework has a strong affinity for the acid gases possessing high adsorption 

enthalpies. The framework chemistry is also conducive to easy release of the guest molecules 

(acid gas) when regeneration is desired. It may be possible to advance MOF state of the art to 

suit a distributed gas-processing application. 
Co

temperatu

transport

gas be r

temperatu

wellhead

processin

among th

T

D

A

 

 

M

A

 

 

 

Dehydra

mpounds kn

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removed to 

ure plus a m

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ng plant. Sev

hese alternat

Table 7. Pos

Direct Cooli

Absorption 

Glycol 

Alcohols 

Membranes

Adsorbents 

Activated A

Alkali Meta

Molecular S

Figure 1

ation 

nown as gas 

ssure conditi

valves. There

levels low

margin of sa

separation 

veral dehydr

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(pressure sw

Alumina, Sili

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Sieves (zeoli

18. Dehydrat

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afety. The d

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ibuted-Scale

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(KCl, LiCl)

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tion technolo

24 

n form when

orable. These

ne operators

e saturation 

dehydration 

rbon liquids

ss alternativ

he chart show

e Water Re

ption, on-lin

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n liquid wat

e hydrates c

s typically re

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wn in Figure

moval Tech

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marized in T

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hnologies 

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Table 7. Sele

tion) 

CaCl2) 

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s and 

g NG 

in the 

peline 

at the 

gasection 
25 

Liquid Desiccants 

Dehydration with liquid desiccants typically involves the use of a glycol solution in an 

absorber column. It can also be combined with cooling. It is the most widely applied process, 

used extensively in production operations and in many refinery and chemical plant operations. 

DEG or TEG are typically used in field gas or gas-processing plant residue gas streams. For 

chilled contacting, ethylene glycol is used. 

Methanol has also been employed in dehydration processes. Methanol is used either in 

direct injection or contactor absorber processes. Because methanol has a high vapor pressure, 

losses to the vapor and liquid hydrocarbon phases are considerably higher than with glycols. 

Methanol recovery methods such as IFPEXOL must be employed. 

Cooling Below Initial Dew Point 

Low-temperature separation (LTS) can be employed to dehydrate a gas stream. This 

method generally requires additional steps to prevent hydrate formation. For example, ethylene 

glycol can be used in conjunction with LTS for hydrate prevention and simultaneous dehydration 

of the gas. New rapid expansion technologies such as Twister® have also been combined with 

LTS to achieve dehydration. 

Solid Desiccants 

Dehydration of NG with solid desiccants is usually limited to those cases where complete 

water removal is desired, for example, in cryogenic plants operating in the region of −100° to 

−150°F or where a relatively small volume of gas is being processed. 

Molecular sieves are also being employed in the gas-processing industry for cryogenic 

plant feed-conditioning applications and some sour gas applications with special acid-resistant 

binder formulations. Dehydration of NG to a typical pipeline requirement of 7 lbwater/MMscf is 

normally least costly utilizing a liquid desiccant such as glycol, rather than using solid 

desiccants. 

Solid desiccants such as activated alumina and silica gel have been successfully used for 

many years in production and processing applications that require lower dew point than achieved 

by conventional glycol. With silica gel, it is possible to simultaneously remove hydrocarbons and 

water. However, with solid desiccants, regeneration becomes a significant design factor. 

Multiple-bed systems are used on gases with relatively low water content. Typically, one or more 

beds are in service drying gas and one or more beds are in regeneration mode. 

Deliquescent Desiccants 

Deliquescent systems can be economical for smaller gas volumes typical of wellhead rates 

up to 1 MMcf. Deliquescent desiccants generally comprise naturally hygroscopic alkaline-earth 

metal halide salts, e.g., calcium chloride. Water vapor is removed from NG as it flows through a 

bed of desiccant in a pressure vessel. Moisture is attracted to the deliquescent desiccant and coats 
26 

it with hygroscopic brine. This brine continues to attract water, forms a droplet, and then 

migrates with gravity to a liquid sump. Since the desiccants dissolve upon attracting and 

absorbing water vapor, relatively inexpensive new desiccant is simply added to the vessel when 

needed. 

Nitrogen Rejection 

Nitrogen rejection unit operations will not always be required. The necessity of this 

operation will depend heavily upon the characteristics of the gas field to which the distributed 

operation is being applied. When nitrogen rejection is required, one of two technologies is 

typically employed – cryogenic technology or selective gas-permeable membrane technology. 

Cryogenics are generally assumed to be power-intensive and, therefore, not adaptable for use at a 

distributed scale. Selectively permeable membrane technology may be scalable to this size. 

NGL Recovery 

Because of the relatively high value of products produced, NGL recovery technology 

options exist for larger and smaller gas-processing applications. The general approaches 

employed by these technology options are summarized in Table 8. In general, these approaches 

fall into one of three categories of processes: 

 Control of temperature and pressure to achieve condensation of NGLs 

 Separation of heavier NGLs from lighter gas with pressurized membrane separation 

systems 

 Physical/chemical adsorption/absorption 

Table 8. Possible Distributed-Scale NGL Recovery Technologies 

Turboexpander + Demethanizer 

JT Low-Temperature Separation 

Membranes 

Absorption 

 Refrigerated Lean Oil Separation (RLOS) 

Adsorption 

 Activated carbon 

 Molecular Sieve 

Twister Supersonic Gas Low-Temperature Separation Dew-Pointing Process 

Turboexpansion 

A commonly employed approach to NGL recovery at industrial gas-processing plants is to 

use a turboexpander in conjunction with a demethanizer. One manufacturer’s hardware is shown 
in Figure

mixture 

knockout

results in

demethan

turboexp

temperatu

Liq

where it 

the lowe

required 

the heat r

Th

pipeline. 

injection 

in the he

to marke

e 19. In this

results from

t pot. The li

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nizer (distill

ander wher

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repeatedly a

er section o

to vaporize 

required to p

e demethani

A gas com

into the dis

at exchange

t. 

s approach, 

m condensati

iquid stream

the tempera

ling column

re it under

t enters the d

Figure 19. 

various level

absorbs heat

f the demet

the liquid fr

provide distil

izer produce

mpressor dri

stribution pip

r as it cools 

a heat exch

ion of NGL

m from the k

ature of the

). In paralle

goes a rap

demethanizer

CryoStar tur

ls of the de

t from the in

thanizer. In 

rom the botto

llation reflux

es gas that i

ven by the 

peline. The N

the inlet ga

27 

hanger first 

Ls. The gas–

knockout po

e stream sig

el, the gas s

pid expansio

r to serve as 

rboexpander

emethanizer 

nlet gas bein

effect, the 

om of the de

x to the top o

is suitable fo

turboexpan

NGL produc

s. The NGL

chills the i

–liquid mixtu

ot flows thro

gnificantly b

tream from 

on that aga

 distillation 

r and demeth

is drained t

ng cooled. W

inlet gas p

emethanizer.

of the demet

for distributi

nder compre

ct from the d

Ls are then se

inlet gas wh

ure is separ

ough a throt

before the s

the knocko

ain lowers 

reflux. 

hanizer. 

through the

Warmed liqu

provides the

. The turboe

thanizer. 

on to end-u

esses the pro

demethanize

ent to storag

here a gas–l

rated in a si

ttling valve.

stream enter

out pot enter

the gas st

 heat excha

uid is return

e low-grade 

expander rem

use consume

oduct gas b

er is also wa

ge for distrib

liquid

imple 

 This 

rs the 

rs the 

tream 

anger, 

ned to 

 heat 

moves 

ers by 

before 

armed 

bution 
Sev

condense

consists 

respect, i

to accom

Th

pressure 

reduction

require u

Th

turboexp







JT Separ

veral compa

e NGLs. An

of a gas-toit is similar t

mplish the exp

Figure 20

e process of

is availabl

n across the 

up to 1000 ps

Twister S

e Twister su

ander, comb

Expansion 

Cyclonic ga

Recompress

ration 

anies offer sk

n example o

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to the turboe

pansion, and

0. Small JT N

f expanding g

e. However

JT valve m

si differentia

Supersonic S

upersonic se

bining the fo

as–liquid sep

sion 

kid-mounted

of such a sy

ger, a JT (th

expansion pr

d does not re

NGL recove

gas to produ

r, JT units 

must be provi

al pressure to

Separation 

eparator (sho

llowing proc

paration 

28 

d systems th

ystem is sh

hrottling) va

rocess, exce

ely on a dem

ry skid as pr

uce cooling c

become ex

ided by fron

o operate eff

own in Figu

cess steps in

hat employ t

hown in Fig

alve, and a 

ept that it em

methanizer. 

rovided by d

can be cost-e

xpensive to 

nt-end gas co

ficiently. 

ure 21) has t

n a compact, 

the JT effect

gure 20. A J

gas–liquid s

mploys no ro

dew point co

effective wh

operate wh

ompression. 

thermodynam

tubular devi

t to chill ga

JT unit typi

separator. In

otating mach

ontrol. 

hen excess su

hen the pre

A JT unit m

mics similar

ice: 

s and 

ically 

n this 

hinery 

upply 

essure 

might 

r to a 
Wh

temperatu

following















Sm

Sm

that cann

hereas a turb

ure drop by

g gas–liquid

Multiple inl

A nozzle is 

in a low tem

The rapid ex

The high-vo

The liquids 

The separate

The liquid 

vessel and r

mall-Scale N

mall-scale NG

not yet be ga

Figu

boexpander 

y transformin

d separation s

let guide van

used to exp

mperature an

xpansion res

orticity swirl

are separate

ed streams a

stream conta

recombined w

NGL Recove

GL recovery 

athered and 

ure 21. Twist

transforms 

ng pressure 

steps: 

nes generate 

pand the satu

d pressure. 

sults in the fo

l drives the d

ed from the g

are slowed do

ains slip ga

with the dry 

ery for Stran

has the pote

marketed is

29 

ter superson

pressure to

to kinetic e

a high-vorti

urated feed g

ormation of 

droplets to th

gas using a c

own and rep

s, which is

gas stream.

nded Gas 

ential to prov

s typically fl

nic separator

shaft power

energy. Twi

icity, concen

gas to super

a mist of hy

he wall with 

cyclonic sepa

pressurized in

removed in

vide several

flared, result

. 

r, Twister ac

ster technol

ntric swirl. 

rsonic veloci

ydrocarbon c

centrifugal 

arator. 

n separate d

n a compact 

l benefits to 

ting in unuti

chieves a si

logy employ

ity, which re

condensate.

force. 

diffusers. 

liquid dega

the industry

ilized energy

imilar 

ys the 

esults 

assing 

y. Gas 

y, the 
loss of re

as an int

transport

these sys

compress

Figure 22

Ind

present i

(from 10

4000 gall

rich gas, 

and an en

scale NG

NGL rem

P

R

R

R

R

R

V

N

L

L

L

Cap

and chill

of −20°F

NGLs w

56,000 g

evenue, and 

terim practic

ted hydrocar

stems can be

sed gas. As 

2, generating

F

dustry exper

n many prod

000 Mcf/day

lons of NGL

removal of 

nvironmenta

GL recovery

moval system

Table 9. As

Parameter

Rich Gas Flo

Rich Gas Flo

Rich Gas Flo

Rich Gas He

Rich Gas Pri

Volume of N

NGL Price, v

Lean Gas Flo

Lean Gas He

Lean Gas Pri

pital costs fo

ing and stor

F and 1000 p

was based 

allons (1300

emissions fr

ce while gat

rbons to be 

e more easil

an alternati

g a lower em

Figure 22. B

ience indica

ducing Bakk

y of rich g

Ls per day. S

at least a po

al benefit to 

y, a simplifie

m evaluation 

ssumptions 

ow Rate from

ow Rate Proc

ow Rate, des

eat Content 

ice (cost) at t

NGLs Existin

value 

ow Rate from

eat Content 

ice, value 

or the NGL 

rage. The com

psi (from an 

on a desire

0 bbl), or fou

rom the flare

hering lines

captured an

ly utilized fo

ive, the lean

mission profil

Block flow di

ates that 10

ken wells. A

gas), the da

Since the NG

ortion of the 

the flare em

ed model w

assumes the

for Evaluat

m the Wellhe

cessed, econ

sign flow 

the Wellhea

ng in Rich G

m NGL Rem

removal sy

mpression-a

assumed pre

e to have 

ur 400-bbl ta

30 

ed gas. Deplo

 are built al

nd marketed.

or power an

n gas can st

le than rich g

iagram of N

 to 12 gall

At an estima

aily producti

GLs make up

NGLs from 

missions. To 

as develope

e parameters

tion of a NG

ead, average

nomic cutoff

d

Gas 

moval System

ystem compr

and-chilling 

essure of 35

2 weeks o

anks. The est

oying smallllows the gr

. Further, th

nd transporta

till be flared

gas. 

NGL removal

ons of NGL

ated NGL re

ion of NGL

p a majority 

the rich gas

evaluate the

ed based on 

s shown in T

GL Remova

A

e

f

10

m 85% o

12

rise two mai

system is ba

5 psi at the h

of storage 

timated capi

-scale NGL r

reatest value

he leaner gas

ation fuel or

d, as shown

l system. 

Ls/Mcf of a

emoval rate 

Ls would b

of the econo

s has both ec

e potential v

a JT-based 

Table 9. 

al System 

Assumed Va

300 Mcf/da

600 Mcf/da

1000 Mcf/d

1400 Btu/ft

$0.00/Mcf

0–12 gallons/

$1.00/gallo

of rich gas fl

210–1250 Bt

$2.00/Mcf

in compone

ased on a de

heater/treater

capacity, o

ital cost for t

recovery sys

e and most e

s generated 

r transported

n conceptual

associated g

of 4 gallons

be approxim

omic value o

conomic pote

viability of s

technology

alue 

ay 

ay 

day 

ft

3

f

/Mcf 

on 

flow rate 

tu/ft3

f

ents: compre

esign require

r). The stora

or approxim

the NGL rem

stems 

easily 

from 

d as a 

lly in 

gas is 

s/Mcf 

mately 

of the 

ential 

small-

. The 

ession 

ement 

age of 

mately 

moval 
31 

system of $2,500,000 is based on vendor quotes and industry discussion. Operating and 

maintenance (O&M) costs were assumed to be 10% of the total capital cost, or 

$250,000 (Table10). Revenue calculations are based on NGL sales only at $1.00/gallon and a 

recovery rate of 4 gal/mcf. In this scenario, it has been assumed that residue gas is flared. 

Table 10. Summary of NGL Removal System Costs and Revenue 

Description Capital Cost 

Annual O&M 

Cost 

Annual 

Revenue1

NGL Removal System, 

 300 Mcfd rich gas 

$2,500,000 $250,000 $350,400 

NGL Removal System, 

 600 Mcfd rich gas 

$2,500,000 $250,000 $700,800 

NGL Removal System, 

 1000 Mcfd rich gas 

$2,500,000 $250,000 $1,168,000 

1

 Assumes 80% annual system availability and no cost for rich gas. 

Although the technical aspects of NGL removal are fairly straightforward, the business and 

contractual aspects do not share that simplicity. Several business models could be employed 

which are summarized in the following sections. 

Fee for Service 

The simplest business model for all parties involved is to provide the service of separating 

NGLs from the rich gas for a fee (most likely on a dollar-per-gallon basis). In this scenario, the 

operator pays a third party to separate the liquids, and the operator sells the liquids and either 

continues to flare the lean gas, sells it, or sends it on to gas processing via gas-gathering 

infrastructure. 

Monetization of Products by Third Party 

More complicated but still plausible would be a scenario where the entity separating the 

NGLs from the rich gas buys the rich gas, removes the NGLs, and sells the NGLs (and likely the 

lean gas as well). If the entity separating the NGLs is a third party and not the current operator, 

the contractual and financial aspects are likely quite complicated. 

Monetization of Products by Operator 

If the current operator chooses to perform the well site NGL separation, contractual and 

financial issues would likely be managed similar to existing contracts with royalty owners 

consistent with existing contractual relationships. 

Conclusions 

Although the economic viability of NGL removal systems is highly dependent on how the 

business entity is positioned in the supply chain and contractual considerations, sufficient value 
32 

is contained within the recovered NGL to suggest an economical business plan could be 

developed. 

Clearly, NGL recovery would be most economical at wells flaring larger quantities of gas 

immediately after production begins in order to capture the greatest volume of gas. Additionally, 

such a technology would benefit from being mobile and easily mobilized and commissioned 

every several months. The value achievable from trucked delivery of NGL is also a critical factor 

in determining economic viability. Businesses with their own gas-processing facilities would 

likely gain the greatest value. Those relying on third-party truck unloading may experience 

smaller profit margins. 

APPLICATION I – CNG/LNG FOR VEHICLES 

Introduction 

A possible utilization of flared gas is to purify and compress it for use in NGVs. The gas 

vented or captured at the wellhead is too rich and variable in composition to be used effectively 

in NGV engines; therefore, extensive small-scale gas processing would be required to implement 

this utilization strategy upstream of typical large-scale gas plants. CNG for vehicles is a 

commercial off-the-shelf product with original equipment manufacturer (OEM) and aftermarket 

engine options as well as fueling stations available from vendors. Provided NG is available with 

sufficient quality and quantity, CNG can provide a cost-effective and low-emission alternative to 

gasoline and diesel, and the economics are well understood. The purpose of this study was to 

evaluate adaptation of CNG upstream of the gas plant to positively impact flaring. For these 

applications to be feasible, a significant amount of small-scale gas processing will be necessary, 

including purification, compression, and dispensing of CNG fuel. Further, the vehicle fleets 

utilizing the CNG fuel would need to be adaptable and flexible in order to take advantage of 

stranded gas resource that changes in quality, quantity, and location with time. 

It is generally assumed that a new wellhead in North Dakota can flare gas for up to a year 

before North Dakota oil and gas regulators demand that the associated gas be captured for use at 

the well site or gathered and transported to centralized gas-processing plants. The CNG fueling 

system and accompanying fleet would need to be capable of following this transient resource or 

models would need to be adapted to enable fueling infrastructure to remain in place as gasgathering pipelines fill in around the CNG infrastructure. 

CNG and LNG Fundamentals 

NG has been used as an engine fuel since 1860, long before gasoline engines were 

commercialized. The first U.S. vehicles to use NG as a fuel were put on the road in the 1960s. In 

2009, the U.S. CNG vehicle fleet numbered 114,270. At the same time, the LNG vehicle fleet 

numbered 3176. Worldwide, approximately 13.2 million NGVs are in use. In the past two 

decades, the number of NGVs on U.S. roads has increased nearly 500%. Transit buses account 

for approximately 62% of all CNG motor fuel use (U.S. Energy Information Administration, 

2012a). 
Th

countries











e United Sta

s surpass the

Lack of dem

Lack of dem

Limited ran

volume per 

of about 200

Safety: Som

CNG indust

Lack of fill

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FuelMaker 

tanks at hom

several thou

installation 

Additional 

incremental

the largest c

Environmen

regulations. 

and kits mu

ates does no

 United Stat

mand: Many

mand has, to 

nge: CNG ta

unit energy 

0–250 miles

me U.S. con

try’s justifiab

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usand dollar

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cost of eng

 cost of pur

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ntal Protectio

Conversion

st be installe

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tes in NGV u

y major ma

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anks designe

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: There are 

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e fueling sy

er, the home 

rs to purch

ine: One of

rchasing an 

of the cost

on Agency (

n kit makers

ed by certifie

33 

world in use 

utilization. T

anufacturers 

t, prohibited

ed to operat

asoline or di

f the gasoline

ress concern

hat it is safer

more than 1

are open to

stem, called

device take

ase and ins

f the largest

OEM NGV 

t of CNG co

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s must go th

ed technician

of NGVs. A

The reasons f

sell CNG c

d their entran

te at 3500 p

iesel cousins

e model. 

ns about the

r than gasoli

1000 CNG 

o the public

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 or converti

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California A

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As shown in 

frequently ci

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filling statio

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o wider use 

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omplex certi

Figure 23, m

ited include:

ere in the w

U.S. market.

more on-ve

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CNG, despit

ons in the U

n company c

es and fills N

he tank and 

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of NGVs i

vehicles. O

e with strict 

es Board (CA

ification pro

many 

:

world. 

.

ehicle 

range 

te the 

United 

called 

NGV 

costs 

mit its 

is the 

ne of 

 U.S. 

ARB) 

ocess, 
34 

Figure 23. NGV use by country (NVG Journal, 2012). 

Having established some of the barriers to NGV use in the United States, strong factors are 

also playing into a reinvigorated impetus to consider NGVs. Strongest among these market 

forces is the price gap between CNG and gasoline. This gap is currently at record levels because 

of supply and demand factors stemming from a wealth of new NG source discoveries in the 

United States. As a result of this increased supply, CNG prices are ranging from $1.00–$3.00 

lower than gasoline, on a GGE basis. Continued low CNG prices could further encourage more 

widespread use of CNG for fleet vehicles. 

CNG must be stored in tanks at pressures up to 3600 psi to offer the vehicle adequate 

driving range. Alternatively, LNG, which is 2–3 times more dense than CNG (3500 psi), can also 

be stored in vacuum-insulated pressure vessels. LNG is typically used only with heavy-duty 

vehicles, where a greater fuel quantity demand exists. 

LNG contains a significantly higher ratio of methane to heavier hydrocarbons. This is 

because of the processing required to liquefy the NG. As the NG is compressed and significantly 

cooled to −260°F, heavier hydrocarbons (NGLs) condense and are separated from the methane. 

This precipitation and separation occurs to a much lesser degree with CNG because CNG is not 

significantly cooled, except to compensate for the rise in temperature due to compression. 

Because LNG fuel is much closer to pure methane than most CNG fuels, LNG does not present 

the same challenges in emissions or fuel quality variation that CNG does. 

CNG-powered vehicles attain roughly similar fuel economy when compared to 

conventional gasoline vehicles, on a GGE or energy content basis. A GGE is a quantity of CNG 

or LNG that contains the same amount of energy (measured in Btus or joules) as a gallon of 

gasoline. One GGE is roughly 5.7 lb of CNG or roughly 1.5 gallons of LNG. 

CNG Feedstock Availability and Quality 

Gas processing of Bakken associated gas is generally accomplished at centralized gasprocessing plants in North Dakota. The residue gas produced at these gas-processing plants is 

injected into pipelines that traverse North Dakota. Table 11 presents select samples of pipeline 

gas quality data from various locations in these pipelines. 

The gas quality varies quite dramatically between pipeline operators and geographic 

locations. What cannot be seen in this summary is the gas quality variation over time. A 

summary of the variability in gas quality at these same pipeline stations over the 3-month period 

of October–December 2011 is presented in Table 12. 

Liss and Thrasher (1992) produced the most frequently referenced survey of variation 

(both temporal and geographic) in natural gas composition in the United States. This survey 

documented wide variations in NG quality across the United States. A brief summary of this 

extensive data set is captured in Table 13. This study also concluded that gas quality variations 

over time across the nation are highly variable. 
35 

Table 11. Select Gas Quality Data from North Dakota Pipeline Stations, 4th Quarter 20113

 

WBIP1

Williston–

Ray 

WBIP N. 

Tioga 

Transfer–

Ray 

WBIP 

Baker–

Little 

Beaver 

WBIP 

Dickinson–

Glen Ullin 

WBIP 

Bismarck–

Glen Ullin 

NBIP2

Guardian

NBPC 

Glen 

Ullin 

C1, mol% 69.25 71.29 91.92 82.98 82.98 95.44 95.49 

C2, mol% 23.06 21.15 3.10 12.07 12.13 2.14 1.95 

C3, mol% 3.13 3.29 0.46 1.00 1.00 0.21 0.14 

C4+, mol% 0.30 0.29 0.09 0.07 0.08 0.03 0.01 

CO2 + N2, mol% 4.27 3.98 4.43 3.88 3.81 1.97 2.21 

H2S, mol% 0.00 0.00 0.00 0.00 0.00 0.00 0.00 

Wobbe Index, 

 Btu/scf 

1414 1411 1298 1353 1355 1331 1324 

MN 62.0 63.2 96.9 78.4 78.3 101.2 102.2 

1

 Williston Basin Interstate Pipeline. 

2

 Northern Border Interstate Pipeline. 

3

 Sources: transmission.wbienergy.com and www.northernborder.com. 

Table 12. 3-month Variability in Gas Quality Data at North Dakota Pipeline Stations, 

4th Quarter 20111 

 

WBIP 

Williston–

Ray 

WBIP 

N. Tioga 

Transfer–

Ray 

WBIP 

Baker–Little 

Beaver 

WBIP 

Dickinson–

Glen Ullin 

WBIP 

Bismarck–

Glen Ullin 

NBPC Glen 

Ullin 

NBPC 

Guardian 

Calculated Dry 

 Gross Btu/ft3 

1193–1237 1186–1620 971–1144 1011–1179 1006–1176 1003–1019 1006–1019 

C1, mol% 67.85–72.51 34.08–73.85 51.14–95.41 73.74–95.98 71.46–91.21 94.12–95.79 95.04–96.11 

C2, mol% 19.44–23.31 10.05–22.24 0.30–23.67 1.93–23.03 4.20–21.58 1.62–2.97 1.58–2.48 

C3, mol% 3.01–4.96 3.11–33.28 0.03–6.98 0.14–1.56 0.21–2.70 0.11–0.33 0.10–0.29 

i-C4, mol% 0.08–0.26 0.04–0.25 0–0.21 0–0.05 0.01–0.09 0–0.03 0–0.03 

n-C4, mol% 0.15–0.63 0.07–0.55 0–0.55 0–0.11 0.01–0.20 0–0.03 0–0.03 

i-C5, mol% 0.01–0.05 0–0.05 0–0.01 0 0–0.02 0–0.01 0–0.01 

n-C5, mol% 0.01–0.06 0–0.05 0–0.03 0 0–0.02 0 0 

C6+, mol% 0–0.02 0–0.02 0–0.01 0 0–0.03 0 0–0.01 

CO2 + N2, mol% 3.4–5.3 2.53–4.67 3.92–17.40 1.93–4.28 3.0–4.86 2.04–2.40 1.76–2.16 1

 Sources: transmission.wbienergy.com and www.northernborder.com. 

Table 13. Select National Statistics for NG in 26 Major Urban Areas of the United States (Liss 

and Thrasher, 1992)

 National Mean 

National 

Minimum with 

PA1

National 

Minimum 

Without PA 

10th Percentile 

Nationwide 

90th Percentile 

Nationwide 

C1, mol% 93.9 55.8–98.1 74.5–98.1 89.6 96.5 

C2, mol% 3.2 0.5–13.3 0.5–13.3 1.5 4.8 

C3, mol% 0.7 0.0–23.7 0.0–2.6 0.2 1.2 

C4+, mol% 0.4 0.0–2.1 0.0–2.1 0.1 0.6 

CO2 + N2, mol% 2.6 0.0–15.1 0.0–10.0 1.0 4.3 

Wobbe Index, Btu/scf 1336 1201–1418 1201–1418 1331 1357 

MN 90.0 34.1–96.2 73.1–96.2 84.9 93.5 

1

 PA refers to propane–air peak shaving during peak demand periods.
36 

Existing CNG Fuel Quality Standards

In general, pipeline gas quality standards do not match fuel specifications set forth by 

either engine manufacturers or regulatory bodies such as CARB. In fact, there is no nationwide 

pipeline gas specification. CARB is the only U.S. regulatory entity that has established a 

commercial fuel quality specification for NG. 

The lack of clear and reasonable gas quality standards is, by many accounts, impeding the 

proliferation of CNG and NGVs. Engine manufacturers have greatly improved engine designs in 

the past decade to accommodate a wider range of fuel compositions, but without a nationwide 

pipeline standard and without a robust CNG market, CNG suppliers have been unable to 

consistently deliver the fuel quality required to support a developing CNG market. 

Anecdotally, other fuels markets have had to wrestle with the problem of chasms between 

manufacturer fuel specifications and available fuels. This has happened largely behind the scenes 

in the world of gasoline and diesel engines. There has always been a tension between the OEMs 

and the fuel providers. The OEM’s ideal is to have a very tight fuel specification to preclude 

effects of variable fuel composition on their engines. The fuel suppliers cannot generally provide 

that high level of quality without charging an objectionable premium cost. In the case of mature 

gasoline and diesel markets, this balance of power results in the two factions agreeing to a 

compromise. 

In the case of CNG, there is not yet a host of major fuel suppliers in the market to push 

back against the demands of the OEMs. This leads to an unbalanced approach to fuel 

specifications. The authors of this report spoke with these OEMs and upfitters, including 

Cummins Westport, Westport HD, Landi Renzo, and BAF. These companies told the authors 

that strict fuel specifications are required for engine warranty purposes because CNG fuels have 

the potential to vary so greatly. It is the OEM’s position that no engine design could adequately 

accommodate such widely ranging fuel compositions without inducing damage to the engine or 

accelerating the replacement schedule of various consumables. 

Following is a summary of the major relevant CNG fuel specifications in use in the United 

States today. 

40 Code of Federal Regulations (CFR) 79.55 Base Fuel Specifications (EPA) 

EPA prescribes a set of base fuel specifications for each major type of fuel used in 

transportation in the United States. This base fuel specification is not meant to declare a required 

specification for fuel sold but, rather, sets a standard fuel upon which tailpipe emissions should 

be measured. Methane base fuel is defined as a gaseous motor vehicle fuel marketed 

commercially as CNG, whose primary constituent is methane. According to CFR 79.55, methane 

base fuel must meet the specifications listed in Table 14. 
37 

Table 14. Methane Base Fuel Specification, 40 CFR 79.55 

Component Value 

Methane, mol%, min. 89.0 

Ethane, mol%, max. 4.5 

Propane and Higher HC, mol%, max. 2.3 

C6 and Higher HC, mol%, max. 0.2 

Oxygen, mol%, max. 0.6 

Sulfur (including odorant additive) ppmv, max. 16 

Sum of CO2 and N2, mol%, max. 4.0 

Society of Automotive Engineers (SAE) J1616 – Recommended Practice for CNG 

Vehicle Fuel 

SAE has published a recommended CNG specification, summarized in Table 15, which 

presents important physical and chemical characteristics of CNG vehicle fuel and describes test 

methods for evaluating these characteristics. It does not, however, take the CARB approach to 

fuel specification by hydrocarbon species. Instead, it leans heavily on the Wobbe index as a 

measure of fuel quality and provides recommendations on nonfuel contaminant content. 

Table 15. SAE J1616 CNG Specifications 

Component Value 

Water Content Note1 

CO2 3.0%, max. 

S and Sulfur Compounds 8–30 ppm, max. 

O2 Note 2 

Particulate Matter Minimized 

Pressure Hydrocarbon Dewpoint Temperature Note 3 

Wobbe Index 48.5–52.9 MJ/m3 

1

 The local dew point temperature of the fuel should be defined as 5.6°C below the 

 monthly lowest dry-bulb temperature at the maximum operating cylinder pressure. 

2

 The oxygen level must not produce a mixture within the flammability limits of NG. 

3

 The composition of NG should be such that the original gaseous storage volume 

 will form less than 1% of a liquid condensate at the lowest ambient temperatures 

 and gas storage pressure between 5.5 and 8.3 MPa at which maximum condensation 

 occurs, depending on gas composition.

California Specifications for CNG (California Code of Regulations, 2012) 

The CARB CNG fuel specification takes a conservative approach and prescribes fuel 

content by hydrocarbon species as well as by maximum levels of nonfuel contaminants. It does 

not address fuel heating value directly but, rather, prescribes a fuel mixture that could be used to 

derive a methane number or Wobbe index. 
38 

CNG cannot be sold or supplied in California unless it meets the specifications in the 

Table 16. Industry sources indicate that the commercially available CNG fuel in California may 

not meet the California specification, and the issue may have to be reviewed in the future (U.S. 

Energy Information Administration, 2012a). In fact, since 2010, CARB has been considering a 

major redefinition of these CNG specifications to instead rely almost solely on methane number 

as the key specification. This change is being advocated by major CNG engine manufacturers 

and their trade associations. 

Table 16. CARB Specifications for CNG 

Component Value, mol%, unless otherwise noted 

Methane 88.0%, min. 

Ethane 6.0%, max. 

C3 and Higher HC 3.0%, max. 

C6 and Higher HC 0.2%, max. 

Hydrogen 0.1%, max. 

Carbon Monoxide 0.1%, max. 

Oxygen 1.0%, max. 

Sum of CO2 and N2 1.5–4.5%, range 

Water 1

Particulate Matter 2

Odorant 3

Sulfur 16 ppm by vol., max. 

a The dew point at vehicle fuel storage container pressure must be at least 

 10°F below the 99.0% winter design temperature listed in Chapter 24, 

 Table 1, Climatic Conditions for the United States, in the American 

 Society of Heating, Refrigerating and Air Conditioning Engineers 

 (ASHRAE) Handbook, 1989 fundamentals volume. 

b

 The CNG must not contain dust, sand, dirt, gums, oils, or other 

 substances in an amount sufficient to be injurious to the fueling 

 station equipment or the vehicle being fueled. 

c

 The NG at ambient conditions must have a distinctive odor potent 

 enough for its presence to be detected down to a concentration in air of 

 not over 1/5 (one-fifth) of the lower limit of flammability.

Recent Movement Toward NGVs 

Corporate Push for NGV Fleet Conversion 

A small but significant number of American corporate entities have committed to 

converting substantial portions of vehicle fleets to CNG and LNG. The reasons for this push vary 

by case, but in general can be attributed to corporate “green” strategy, fuel cost savings, 

government incentives, and regulatory pressure in certain states. A small sampling of recent and 

ongoing fleet conversions to CNG and LNG is presented in Table 17. This list is not 

comprehensive but, rather, is intended to convey that many major U.S. corporations are acting on 

motivations to adopt NGV technology into their fleets and business strategies. 
Table 17.

National F

AT&T – C

Verizon – 

Federal Ex

UPS – Ope

Waste Man

Av

decade w

same per

summariz

regionall

presented

Th

However

productio

differenti

Informat

 A Samplin

Fleets 

Committed to

Recently Co

xpress

erates 1100+

nagement – 

The Impe

vailable data

when compa

riod, CNG h

zes nationw

ly, larger or 

d, but a simi

Figure 24. H

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ials shown 

ion Adminis

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onverted 501

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etus of High 

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smaller sep

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Historical CN

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in Figure 2

stration (EIA

t and Ongoi

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Gasoline Pr

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n significantl

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parations bet

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NG price co

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39 

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Data Center, 

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all of these

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million miles

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41 

A Distributed Model Suitable for Small-Scale Bakken Associated Gas 

Opportunities 

Opportunities to use wellhead gas to produce CNG fuel in the Bakken development may 

be plentiful because of the rapid and prolonged pace of development, but each opportunity exists 

for only a limited time. In general, a maximum of 1 year passes between the time a new well is 

completed and the time at which gas-gathering pipeline is brought to the first well on the new 

location. During this time, associated gas is typically flared. After this time, the assumption is 

that it would be difficult to compete with the economics of gathering and centralized gas 

processing, especially given that “pipeline quality” does not always equate to CNG quality. 

Additional polishing is often required to convert pipeline gas to CNG gas, given the wide 

variations in pipeline gas composition. 

Prior to injection into pipelines, Bakken associated gas is treated in centralized gasprocessing facilities connected to wellheads by vast networks of gathering pipelines. 

Accomplishing the same (or higher) level of gas processing at the wellhead would require 

1) miniaturization of gas purification technologies, 2) great reduction in price of each 

purification function for the smaller scale, and 3) mobile purification/compression/dispensing 

systems capable of being quickly set up at one location then mobilized and moved to new 

locations on a regular basis and at intervals of less than 1 year. 

A natural economy of scale exists at larger, centralized gas-processing plants. Desiccant 

towers, desulfurizer units, NGL extraction, and fractionation towers are traditionally made most 

economical when they are built to process large amounts of gas. The inherent nature of scale 

works against cost-effective size reduction. It is, indeed, a challenge to miniaturize these systems 

for the purpose of achieving the same level of processing at the wellhead. There are, however, 

enabling techniques to be investigated to work around this phenomenon of scale. 

NGL Removal and Storage 

The removal of NGLs from the rich gas greatly increases the economic feasibility of a 

CNG project and reduces the loss of resource when flaring is necessary. Based on modeling done 

as part of this study, the EERC concluded that removing the NGLs (specifically butane and 

heavier constituents and a portion of propane) can be accomplished with chilling and JT cooling 

operated at −20°F and 200–1000 psi. Once the NGLs have been separated and stabilized, they 

are pumped to on-site storage tanks. 

At an estimated NGL removal rate of 4 gallons/Mcf (from 1000 Mcf/day of rich gas) the 

daily production of NGLs would be approximately 4000 gallons of NGLs per day. Based on this 

NGL production number and a desire to have 2 weeks worth of storage capacity, the required 

storage capacity would be approximately 56,000 gallons (1300 bbl). NGLs would need to be 

stored on-site at a minimum pressure of 200 psi to maintain NGLs in the liquid phase. 

Based upon discussions with industry representatives, the capital cost for the NGL removal 

and storage system is estimated to be $2,500,000. This capital cost includes the necessary 
compress

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46 

Key NREL Report Conclusions 

In summary, the NREL report concluded the following: 

 Decisions made on equipment purchases, capital upgrades, and fuel contracts have 

long-term impacts on the operational success of the fleet. 

 Larger transit and refuse fleets (75+ vehicles) tend to be profitable and resilient to 

variations in project parameters. 

 School fleets and small transit/refuse fleets tend to be marginal. 

 Diesel prices are a powerful indicator of profitability given that NG prices are relatively 

consistent. A school bus project appears to only make economic sense once diesel 

prices approach $4/gallon for 100-bus fleets and $5/gallon for 50-bus fleets. 

 Project success is very sensitive to vehicle maintenance costs. 

 Tax issues have a strong influence on profitability. 

 The cost of the station has a significant influence on the profitability of marginal 

projects. 

 Factors that do not have much effect on project profitability over the range tested are: 

 Efficiency difference between CNG and diesel engines (−25% to +10%). 

 Change in vehicle/project life (10 years to 20 years). 

 Electricity prices (50% and 150% baseline). 

 Maintenance costs for the CNG station (50% and 150% baseline). 

 Garage upgrade (for minimal-upgrade scenario). 

 Number of new attendants/hostlers (fewer than two to more than four personnel). 

A Model for Use of Bakken Gas in NGVs 

Many of the cost factors that must be analyzed to produce a valid economic assessment of 

the Bakken region’s CNG/LNG opportunities are well understood. However, this study lacks 

sufficient data to determine costs associated with a foundational component of a valid economic 

assessment – costs related to the technology required to purify the rich, wet associated gas into 

engine manufacturer-approved CNG/LNG fuel. Few, if any, microscale distributed systems exist 

that are capable of separating NGLs, sulfur, and water from the rich Bakken associated gas 

economically to polish the resource to CNG-quality fuel. None were identified by this study. 

That is not to say that larger systems could not be adapted, but to date, this has not been a market 

opportunity, so no commercially available systems exist. 
47 

Liquefaction of natural gas to produce LNG fuel is even more challenging in terms of cost, 

especially at the small scales being investigated within the context of this study. After a brief 

examination, LNG did not surface as an area of emphasis. Reasons for not including LNG as an 

area of emphasis for this study included: 

1. Significantly increased capital costs of liquefaction equipment over CNG equipment. 

2. Difficulties in miniaturizing and mobilizing liquefaction systems for use at the wellhead. 

3. Additional precompression removal of natural gas liquids required to provide suitable 

feedstocks to liquefaction process. 

One of the objectives of the study was to determine a palette of potentially viable 

technologies that could be scaled down to address distributed-scale gas purification for CNG 

production. The technologies outlined in a previous report section are all candidates for this 

scaling effort. The cost analysis for fuel preparation costs will, therefore, only outline a boundary 

condition for costs that create an economically feasible scenario. 

Scale of Potential CNG Consumption Relative to Bakken Associated Gas 

A fleet traveling 1 million miles annually would consume approximately 

15,000 Mcf/year, or 23,000 scf of CNG per day (assuming 15 miles/GGE). Comparing this 

against the gas production rates shown in Table 3, it is evident that even large NGV fleets would 

not consume significant quantities of Bakken associated gas relative to the amount of gas 

available. The CNG economic assessment will necessarily start from an assumed, reasonably 

sized fleets, and project where the economic breakeven point will be, given a set of assumptions. 

It will then present sensitivity analyses based on various fleet gas usage factors. 

Fuel Preparation Costs 

Perhaps the largest unknown in this economic analysis is the cost of fuel purification and 

preparation for compression and dispensing operations. Because the North Dakota Bakken 

Formation associated gas is a rich gas, commercial, off-the-shelf, distributed-scale technology is 

not readily available. Costs were estimated based upon EERC experience in gas-processing 

technologies from other technology sectors. $2.5 million was assumed for a small-scale gasprocessing system that can be made mobile to work at sites of opportunity in the Bakken region. 

This cost would naturally decrease as additional units are manufactured, but development costs 

would necessarily need to be captured in the first sale. 

A by-product of fuel purification is the NGL stream produced. This NGL stream has value 

and must be factored into the CNG economic analysis. Throughout the various applications 

discussed in this report, the authors use the assumptions listed in Table 20 to represent revenue 

generated from an NGL removal system and subsequent sale of NGLs. This represents additional 

revenue in the CNG economic model. 
48 

Table 20. Assumed NGL Revenues Associated with CNG 

Production 

Product Quantity 

Assumed 

Value 

Daily 

Revenue 

Annual 

Revenue1

NGLs 2400 gpd $1.00/gal $2400 $700,800 

1

 Assumes 80% annual system availability.

For the purposes of this study, the cost of associated gas has been set at zero. The actual 

cost of this resource will be highly dependent upon the business arrangement. 

Station Costs 

This report assumes, based upon findings in the NREL report (Johnson, 2010), that high 

throughput, rapid fueling stations will serve the most economically feasible vehicle fleet 

scenario – that of a high-mileage fleet with significant fuel consumption. This assumption drives 

a baseline including a fast-fill station capable of significant fueling throughput and rapid 

turnaround of vehicles upon fueling. 

This fueling station must also be mobile to move to where uncaptured associated gas 

exists. Even if it is assumed that the gas converted to CNG can be obtained from gathering lines 

(thus alleviating the requirement to move as frequently as would be necessitated by stationing at 

wellheads that are eventually connected to gas-gathering systems within a year), it could be 

argued that the station would need to remain mobile to serve the moving fleets of vehicles 

following the expansion of the Bakken play. This would apply equally to field service vehicles, 

transit buses, and personal vehicles. Given this set of assumptions, a fueling station configuration 

can be defined. The mobile CNG fueling trailer offered by IMW Industries serves as an effective 

example. IMW Industries has provided the costing information in Table 21 (Damiani, 2012). 

Table 21. Estimated Mobile Refueling Station Costs (Damiani, 2012) 

Mobile Fueling Station Cost Component Lease Purchase 

Refueling Trailer $13,000 per month $500,000

Siting Costs $10,000 per site 

Electrical Costs1 $0.10/GGE2

Maintenance Costs 5% of equipment costs per annum

1

 North Dakota low electrical rates considered. 

2

 Ybarra, 2007. 

Thus IMW Industries and the EERC estimate that in a lease situation, a project would 

expend approximately $15,000 per month to lease, site, operate, and maintain the IMW mobile 

fueling station, assuming one site a year and a fleet refueling with 72,000 GGE (developed in 

Table 22). Over a 10-year project lifespan, a lease would cost approximately $1.8 million. A 

purchase situation would alternately cost approximately $750,000 (not including financing 

costs), using the same assumptions. Given the anticipated long-term refueling needs, the 

remainder of the economic evaluation was performed based on the purchase of a refueling 

system. 
49 

Table 22. Yearly Costs vs. Fuel Savings 

Yearly Financing Payments $908,325

Additional Yearly Fueling Trailer-Siting Costs $10,000

Yearly Fueling Trailer Maintenance Costs $50,000

Yearly Electricity Costs $7,200

Yearly Gas Resource Payments $0

Less Yearly Revenue from NGL Recovery and Sale (Table 20) ($700,800)

Net Yearly Costs $274,725

Yearly Cost Savings in Fuel, assuming comparable fuel mileage 

 Number of Vehicles 60

 Vehicle Miles Traveled (VMT) per Vehicle 18,000

 VMT Total 1,080,000

 Mileage, miles/GGE 15

 GGE Consumed 72,000

 Gasoline Cost, $/gal $3.70

 CNG Cost, $/GGE $2.45*

 Net Cost Savings on an Energy Basis, $/GGE $1.25

Net Yearly Cost Savings for Total Fleet VMT $90,000

* $2.45 CNG price is a high quote of national pump price samples from www.cngprices.com on 

 April 19, 2012. 

Vehicle Costs 

For the sake of this model, it is assumed that the fleet of vehicles would consist of 

60 converted Ford F-250 pickups used as field service vehicles. The costs for these conversions 

are readily available from each manufacturer. As an example, BAF Technologies provides this 

conversion package at a cost of $12,800/vehicle. This includes upfit costs for a bifuel CNG–

gasoline engine or a dedicated CNG engine plus transportation to a local Ford dealer. It does not 

include state and local taxes on vehicle purchases. For 60 conversions, vehicle costs would 

amount to $768,000. 

O&M Costs 

NGVs are often assumed to have lower maintenance costs compared to diesel and gasoline 

engine vehicles. NG burns cleaner (fewer carbonaceous deposits), so its combustion results in 

less wear on mechanical components of the engine and extends the time between tuneups and oil 

changes. Anecdotally, some fleet operators have reduced maintenance costs by as much as 40% 

by converting their vehicles to CNG. Oil changes are recommended every 10,000–25,000 miles, 

depending upon the vehicle make and how the vehicle is used. This is compared to every 3000–

5000 miles for the gasoline engine. 

Despite this anecdotal indication, little evidence is found in the literature to support this 

assumption. In fact, Watt (2012) and World Bank (2001) state that maintenance may actually be 

more expensive, compared to diesel maintenance, for the following reasons: 

 NGV parts are generally more expensive because of lower volumes. 
50 

 NGV engine users have reported reduced reliability of NGV engines, although it should 

be noted that this may be a function of engine vintage. Manufacturers are sure to state 

that 1990s engines were in the early stage of their product development cycle and will 

continue to improve. 

Therefore, this study will assume that maintenance costs do not vary significantly from gasoline 

or diesel engines in similar use situations. This approach is validated by the approach taken 

independently in the NREL report discussed previously (Johnson, 2010). 

Fuel Price 

The value of stranded associated gas is difficult to assess. The focus of this report was to 

identify economical utilization of fuel resources that are otherwise being flared (unmonetized). 

The report scope was expanded to include not only wellhead associated gas that is currently 

flared, but also gathered associated gas, if there is potential to use that gas locally and in an 

economically efficient manner. 

This report takes the tack of proposing a reasonable bounding fuel cost for the model (topdown, in many respects). This fuel price must be a value that is supported by market demand, is 

comparable to prices regionally and nationwide, and does not artificially push the economic 

analysis out of bounds. 

A fuel price of $2.45/GGE represents a reasonable marker for the following reasons: 

 Although higher prices are reported at fueling stations elsewhere in the nation, this 

value still allows for a cost premium that can be applied toward higher gas-processing 

costs assumed to be relevant to smaller, distributed fuel processing. 

 Although lower prices are reported at fueling stations elsewhere, this value still reflects 

the fact that no distribution costs are incurred. 

 Although this price is higher than reported at fueling stations elsewhere, this price point 

potentially still represents a large fuel cost savings for medium-sized fleets. 

Taxes and Incentives 

A myriad of state incentives for NGVs exists, but they vary greatly by state. Currently, 

there are no North Dakota State incentives for NGVs or NG fueling stations. 

The Energy Policy Act of 2005 (§1341, Publication L, No. 109-58) provided income tax 

credit when NGVs were purchased. However, this tax credit was allowed to expire in December 

2010. Similarly, a fuel excise tax credit to sellers of CNG or LNG fuel expired in 2009, although 

the credit was then extended until August 2011 as part of the Tax Relief, Unemployment 

Insurance Reauthorization, and Job Creation Act of 2010 (PL 111-312). No federal incentives for 

NGVs or NG fueling stations currently exist. Finally, income tax credits for installation of NGV 

fueling infrastructure expired in December 2010 and were extended for 1 year as part of the Tax 
51 

Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (PL 111-312). 

No federal incentives currently exist to promote NGV purchase and use, but in January of 2012, 

President Barack Obama renewed a conceptual push for increased use of NGVs, sketching out 

plans for additional federal tax credits and other incentives (Sanati, 2012). Details of this plan 

were developing at the time of this report. 

Fuel taxes are examined as follows and summarized in Table 23 only to verify that they are 

not excessive to the point that they necessarily inflate the previously described assumed fuel 

cost. A fuel cost of $2.45/GGE less $0.413/GGE leaves $2.037/GGE for nontax fuel costs, 

including O&M of the fueling station, siting costs, amortization costs, and fuel-processing costs. 

This is still a moderate price point when compared with other tax-inclusive price points across 

the nation and is thus deemed a conservative but reasonable price point. 

Table 23. Taxes on CNG in North Dakota 

Tax Component 

Addition to 

Fuel Price 

Federal CNG Excise Tax (reference IRS Form 720) $0.183/GGE 

North Dakota State Sales Tax on CNG Exempt 

North Dakota Special Fuels Excise Tax $0.23/GGE 

Total Tax Add to CNG $0.413/GGE 

Costs of Financing 

Using cost estimates described previously, a simple bounding analysis can be completed to 

determine a net annual fuel cost savings that is required to economically justify implementation 

of CNG fleet conversion, including installation of support infrastructure. There are many 

sensitivity studies that could be performed, but only basic data with many cost assumptions are 

provided here. Insurance and permitting costs are not included because of the difficulty in 

obtaining estimates on such an insufficiently defined, hypothetical case. These costs would likely 

be small relative to other implementation costs. 

The analysis first approximates the up-front implementation costs anticipated for such a 

project. The up-front costs are summarized in Table 24. This analysis shows that approximately 

$6.8 million must be rolled up into the first-year expenses of a fleet conversion project. These 

costs also represent additional costs that would not be incurred without the conversion project. 

Table 24. Up-Front CNG Fleet Implementation Costs 

Upfront Cost Component Cost, US$ 

Mobile Refueling Trailer Purchase (two trailers) $1,000,000 

First Year Siting Costs (four sites) $40,000 

Vehicle Upfit Cost (60 vehicles) $768,000 

Gas Processing Unit (two units) $5,000,000 

Total Up-Front Implementation Costs $6,808,000 
52 

Next, a simple look at amortization costs is summarized in Table 25, assuming a 6% 

interest rate. No time value of money is accounted for in this simple analysis. This calculation 

shows that $6.8 million in up-front costs could be financed for approximately $2.3 million in 

interest, totaling approximately $9.1 million in principal and interest. 

Table 25. Amortization Costs 

Equipment and First-Year Costs $6,808,000 

Finance Processing Costs $10,000 

Total Amount Financed $6,818,000 

Interest Rate 6% 

Finance Period 10 years 

Estimated Monthly Payment $75,693.78 

Total Interest Paid $2,265,253 

Total Principal + Interest $9,083,253 

These values provide input for the real goal of this analysis, which is to illustrate the yearly 

savings in fuel costs required to justify the CNG conversion project on strictly economic value. 

The amortization summarized in Table 25 results in a $75,893 monthly payment toward principal 

and interest. Over the course of a year, this amounts to $910,723 in payments. An estimate of 

financing costs is included in Table 22 along with costs incurred during subsequent years of the 

project to arrive at a net yearly project cost. This is then compared against the yearly savings 

from reduced fuel prices. 

It is apparent from the calculations summarized in Table 22 that a 60-vehicle fleet will not 

pay for itself in fuel savings alone, even if rich gas resource purchase costs are ignored. Other 

noneconomic factors would have to be included to justify this conversion project. If the analysis 

is pursued further to investigate sensitivities to the primary input parameters of vehicles, VMT, 

mileage, and relative fuel costs, the situations summarized in Table 26 can provide the economic 

justification required. In this table, inputs are found in bold cells, calculations in nonbold cells. 

The variables changed from the baseline presented in Table 22 to drive the net cost savings for 

total fleet VMT to be equal to net yearly costs presented in Table 22 are highlighted in bold italic 

text in Table 26. This sensitivity analysis shows that a significantly larger fleet than that 

presented in the baseline case in Table 22 needs to be considered to make such a project 

economically feasible. 

Table 26. Other Economic Scenarios that Make Fuel Savings Equal to Net Yearly Costs

Number of Vehicles 164 120 120 120 

VMT per Vehicle 18,000 24,600 18,000 18,000 

Total VMT 2,952,000 2,952,000 2,160,000 2,160,000 

Mileage, miles/GGE 15 15 10.98 15 

GGE Consumed 196,800 196,800 196,721 144,000 

Gasoline Cost, $/gal $3.70 $3.70 $3.70 $3.71 

CNG Cost, $/GGE $2.45 $2.45 $2.45 $2.00 

Net Cost Savings on an Energy Basis, $/GGE $1.25 $1.25 $1.25 $1.71 

Net Cost Savings for Total Fleet VMT $246,000 $246,000 $245,902 $246,240 
53 

A large driver in this simple model (and a large unknown) is the cost of the gas-processing 

unit. With no commercial off-the-shelf packages available for this type of rich gas processing to 

CNG-quality fuel gas, a reasonable estimate of $2.5 million was used. If this analysis is 

completed with a $500,000 price for the gas-processing unit instead, the numbers change 

dramatically. Total up-front implementation costs become $2,808,000. Total principal and 

interest become $3,754,269, including $936,269 of interest. Net yearly costs instead become net 

yearly revenue if NGL sales are accounted for (again, ignoring rich gas resource purchase costs). 

The net yearly revenue becomes $258,173. Thus it can be determined that: 

 The CNG purification system cost will be a major driver of the economic justification 

for CNG use. 

 The business agreement to purchase the rich gas resource will, of course, be critical to 

the economic justification. 

Evaluation Summary 

While there may be several other drivers to warrant the use of CNG in the Bakken region, 

economics alone will most likely not justify conversion of medium-sized fleets of vehicles to 

CNG if a distributed CNG refueling approach is taken. The economics of small-scale, distributed 

gas processing seem to be the major driver pushing costs per VMT to high levels. Several other 

studies in the literature have concluded that economic justifications can be made for CNG if 

stationary fueling systems are used in conjunction with large fleets of vehicles. The economies of 

scale involved in centralized processing and gas distribution are difficult to improve upon. 

If noneconomic justifications for CNG fleet conversion can be made on a case-by-case 

basis, technology exists that could be adapted to suit the needs of any particular refueling 

scenario. This study, however, reveals that some additional gas processing would likely be 

necessary even if the gas resource is obtained from existing pipeline infrastructure in North 

Dakota. A few exceptions exist, depending upon the location of the draw from the pipeline and 

the pipeline from which the gas is drawn. However, much of the pipeline gas in North Dakota 

does not meet minimum specifications for NGV use. 

APPLICATION II – ELECTRIC POWER GENERATION 

Background 

Current Electrical Generation 

North Dakota possesses many abundant energy resources—coal, oil, natural gas, wind, 

hydroelectric, and biomass. Of these, the electrical generation profile of North Dakota currently 

comprises three primary sources: coal, wind, and hydroelectric; in 2010, these represented 64%, 

25%, and 9%, respectively, based on nameplate capacity (U.S. Energy Information 

Administration, 2011). Because of sparse population and low in-state electrical consumption, 
54 

between 60% and 70% of the electricity generated in North Dakota is exported. Table 27 

provides a comparison of North Dakota’s electrical generation to its neighboring states. 

Table 27. Nameplate Electrical Generation Capacity as a Percentage of Total for 

North Dakota and Neighboring States (U.S. Energy Information Administration, 

2011) 

 North Dakota, % Montana, % South Dakota, % Minnesota, % 

Coal 64 44 13 32 

Hydroelectric 25 43 42 1 

Wind 9 6 17 12 

NG <1 5 21 35 

Petroleum 1 1 8 6 

Nuclear 0 0 0 11 

As discussed in the Oil and Gas Production Section, the rapid development of the Bakken 

Formation in the Williston Basin for oil has produced an excess of NG which currently exceeds 

the processing capacity in the area. Flaring the excess NG has become an issue until collection 

infrastructure and processing capacity are built out. For the purposes of this study, this 

“stranded” gas is being called nontraditional NG, a term that is intended to describe all NG that 

is upstream of the gas-processing facility. 

When evaluating the use of nontraditional NG as a fuel for distributed power generation, 

the following considerations are foremost: 

 Scale (0.5 to 10 MW) 

 Fuel flexibility (rich gas with minimal processing) 

 Maturity (commercially available product) 

 Economic feasibility 

NG Resource 

The nontraditional NG resource of the Williston Basin is located in northwestern North 

Dakota, west of large coal-based electrical generation. Figure 30 shows the flared NG in relation 

to existing coal-fired generation as well as electrical transmission infrastructure. Figure 31 shows 

the same flared NG in relation to electrical distribution cooperative service territory. 

Power Demand/Market 

The demand for power in the Williston Basin since the onset of the current oil “boom” has 

grown rapidly. Two electric utilities serve the Williston Basin area: Montana–Dakota Utilities 

Co. (MDU) generates electricity for the major municipalities and Basin Electric Power 

Cooperative (BEPC) provides power, through its member cooperatives, for the rural areas. Based 

on information provided by MDU and BEPC, electricity consumption is increasing significantly. 
As 

1900 MW

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57 

Table 28. Pace Report Highlights and EERC Comments Oil and Gas Development in the Williston Basin Pace Findings (based on 2006 information) EERC Comments (based on 2011 iRapid large-scale development of the Williston Basin will be constrained by the availability of rigs, labor, and service. 

This statement was valid in 2011, although deto 2011 was quite rapid as defined by the Pace with constrained availability of rigs, labor, and 

Lack of availability of electric power will not affect drilling plans, as all wells produce sufficient quantities of NG to be self-sustaining. 

The EERC does not have sufficient informatiorefute this point. 

Pump jacks can be driven by electric motor or a gas-fired engine, but industry strongly prefers electric. 

This statement still holds true. 

A typical Bakken well has a life of 25–30 years and will produce 300,000 bbl over that life (although oil production forecasts do not drive power load forecast). 

Although the life of a typical Bakken well malifetime production is very likely higher than 3

Standard spacing for a Bakken well is 1280 acres. This statement still holds true, although other 

defined (both smaller and larger). 

Power Load Forecast Pace Findings (based on 2006 information) EERC Comments (based on 2011 iPower load is derived from the following primary uses: 

 Electric motors driving pump jacks  Electrically driven field gas gathering  Compressor stations and gas-processing plants  Enhanced oil recovery (EOR)-related pumping loads  Booster pump stations on crude pipelines 

The EERC concurs with this assumption and wits calculations. 

Power load requirements in the Williston Basin are expected to increase over the next 20 years (2027). 

This statement still holds true. 

Power requirements in the Williston Basin will be long term as wells typically produce for 25 to 30 years. 

This statement still holds true. 

Pace used a conversion factor of 0.746 to convert horsepower to electrical demand (kW) 

The EERC concurs with this assumption and wits calculations. 
58 

Table 28. Pace Report Highlights and EERC Comments (continued) Power Load Forecast Pace Findings (based on 2006 information) EERC Comments (based on 2011 iDemand requirements assume a load factor of 80%–100% depending on scenario. 

The EERC concurs with this assumption and wits calculations. 

Future unplanned EOR and gas-gathering, compression, and processing loads represent a huge potential power requirement that was not accounted for in the Pace load forecast. 

This statement may explain why even the Pacunderestimated the load growth from 2007 to 

Enhance Oil Recovery Pace Findings (based on 2006 information) EERC Comments (based on 2011 informationOil produced from EOR activity accounts for approximately 60% of the oil produced in North Dakota. 

Although our data do not address EOR specifihas certainly changed drastically. In 2006, oil Bakken Formation accounted for roughly 6% from 300 wells. By 2010, that number was up than 2100 wells. 

Gas Gathering and Processing Pace Findings (based on 2006 information) EERC Comments (based on 2011 iGeneral consensus amongst industry is that additional gas gathering and processing are required in the Williston Basin. 

Although additional gas-gathering and procesbeen built, this statement still holds true. 

Oil Price Forecast Pace Findings (based on 2006 information) EERC Comments (based on 2011 iIndustry currently believes $40–$45/bbl WBS is the minimum price required for Williston Basin wells to be economical. 

The EERC does not have sufficient informatiorefute this point. 

Over the next 20 years, the West Texas Intermediate (WTI) forecast price averages $56/bbl and never drops below $50/bbl, thus supporting continued development of the Williston Basin assuming operational costs do not increase. 

This statement has held true, although the actutracked more closely with the Pace “High 95%scenario from 2007 to 2011. 
59 

Applicable Technologies 

In 2003, NREL and Gas Research Institute (GRI) prepared a very thorough technical report 

summarizing the gas-fired technologies suitable for distributed electrical generation (Goldstein et 

al., 2003). A review of that document verifies that several platforms are suitable for distributed 

power generation using some form of gas. The technologies discussed in the NREL–GRI report 

are summarized in Table 29. 

Table 29. Summary of Technologies Analyzed in the NREL–GRI Report 

 Reciprocating 

Engine Gas Turbine 

Steam 

Turbine Microturbine Fuel Cell 

Technology Maturity Mature Mature Mature Immature Immature 

Size – Single Unit, MW 0.01–5 0.5–50 0.05–50 0.03–0.25 0.005–2 

Electric Efficiency, HHV1 30%–37% 22%–37% 5%–15% 23%–26% 30%–46% 

Total CHP2 Efficiency, 

 HHV 

69%–78% 65%–72% 80% 61%–67% 65%–72% 

Power-Only Installed 

 Cost, $/kW 

700–1000 600–1400 300–900 1500–2300 2800–4700 

CHP Installed Cost, 

 $/kW 

900–1400 700–1900 300–900 1700–2600 3200–5500 

O&M Cost, $/kWh 0.008–0.018 0.004–0.01 <0.004 0.013–0.02 0.02–0.04 

Availability >96% >98% Near 100% 95% 90% 

Equipment Life, years 20 20 >25 10 10 

Fuel Pressure, psi 1–65 100–500 NA 55–90 0.5–45 

NOx Emissions, lb/MWh 0.2–6.0 0.8–2.4 0.5–1.25 <0.1 1

 Higher heating value. 

2

 Combined heat and power. 

An initial review of the characteristics of each technology (presented in Table 30) 

eliminated some options from further discussion. Borne out of this review, three technologies 

warranted further consideration: reciprocating engine, gas turbine, and microturbine. 

Reciprocating Engine 

The reciprocating, or internal combustion, engine is categorized as either spark-ignited or 

compression-ignited. Spark-ignited engines are typically fueled with lean NG but can also be 

fueled by gasoline, NG, hydrogen, or syngas. Compression-ignited engines are typically fueled 

by diesel fuel or other heavy oils. The output shaft of the engine is connected to an electrical 

generator to produce electricity. Compression–ignition engines can also be set up to operate on a 

bifuel configuration utilizing both diesel and NG. 
60 

Table 30. Summary of Technology Characteristics Review

Technology Reasons for Further Consideration Reasons Against Further Consideration 

Reciprocating Engine  Technology maturity 

 Scale 

 Electric efficiency 

 Cost 

 Equipment life 

 Fuel pressure 

 Fuel flexibility 

(requires specific engine setup) 

 NOx emissions (rich gas may pose 

challenge) 

Gas Turbine  Technology maturity 

 Scale 

 Electric efficiency 

 Cost 

 Equipment life 

 Fuel flexibility (rich gas may pose 

challenge) 

 NOx emissions (rich gas may pose 

challenge) 

Steam Turbine  Technology maturity 

 Scale 

 Cost 

 Equipment life 

 Fuel flexibility 

 NOx emissions (combustion method 

dependant) 

 Electric efficiency 

Microturbine  Electric efficiency 

 Fuel pressure 

 Fuel flexibility 

 NOx emissions 

Fuel Cell  Electric efficiency 

 Fuel pressure 

 NOx emissions 

 Technology maturity 

 Scale 

 Cost 

 Equipment life 

 Fuel flexibility (hydrogen fuel only) 

Gas Turbine 

Gas turbines can be used to generate electricity from a variety of gas feedstocks, including 

gasification syngas, NG, and others. Gas turbines can be configured as simple cycle or 

combined-cycle systems. Simple cycle systems involve the use of a turbine fueled by gas to 

compress air. As the compressed air enters an expansion turbine, it turns an electrical generator. 

Combined-cycle systems also incorporate subsystems that recover exhaust heat and convert it to 

electricity. 
61 

Steam Turbine 

Steam turbines, as the name implies, use a fuel to create steam in a boiler. The steam is 

delivered to a steam generator producing electricity. Steam turbines are unique in that the fuelburning/steam-generating process is separate from the electrical generating process allowing 

unmatched fuel flexibility. 

Microturbine 

Microturbines are basically smaller versions of gas turbines consisting of the following 

main components: 

• Compressor 

• Combustor 

• Turbine 

• Generator 

• Recuperator 

• Waste heat recovery system 

Microturbines are typically classified by their physical component configuration—singleshaft or two-shaft, simple-cycle or recuperated, intercooled, and reheat—typically operate on 

traditional gases such as NG. The microturbine can also be operated on other gases including 

gasifier syngas. EERC research has demonstrated that microturbines can successfully be 

operated on off-spec, high-Btu, and/or low-Btu gases such as oil field sour gas. 

Fuel Cell 

There are several types of fuel cells, each of which creates direct current electricity from 

electrochemical reactions. Although each type of fuel cell functions basically the same, they 

convert hydrogen to electricity in much different ways and are best suited for different 

applications. Simply put, hydrogen fuel, air or oxygen, and sometimes carbon dioxide 

(depending on the fuel cell) are delivered to the fuel cell, producing electricity and other byproducts such as water, waste heat, and excess gas (again, depending on the fuel cell). 

Initial Evaluation 

Given the focus on nontraditional NG (i.e., rich gas with little processing) and a desired 

scale of 0.5 to 10 MW, three technology platforms were considered to be most technically and 

economically viable and are discussed further, reciprocating engines, gas turbines (including 

microturbines), and steam turbines. Each of these technologies has specific advantages, and 

depending on the application, a single technology may be best suited to meet the needs of the 

application. A summary of power generation scenarios is presented in Table 31. 

When evaluating power generation scenarios, the projects were characterized into two 

distinct categories based on the primary use of the electricity: 
62 

Table 31. Summary of Power Generation Scenarios 

Description Example 

Power on 

Required 

Applicable 

Technology General Logistics 

Grid Support: generator 

running on flare gas, producing 

electricity put on the grid. 

 1–10 MW  Reciprocating 

 Gas turbine 

 Steam turbine 

 Flare gas to system 

 Electrical to grid 

Local Power – Small: 

generator running on flare gas, 

producing electricity for local 

consumption. 

 Pump jack 

 Cellular 

tower 

0.2–0.5 MW  Reciprocating 

 Gas turbine 

 Steam turbine 

 Microturbine 

 Fuel cell 

 Flare gas to system 

 Electrical to local 

load 

 Excess electricity to 

grid 

Local Power – Midsize: 

generator running on flare gas, 

producing electricity for local 

consumption. 

 Mancamp 

 Clustered 

wells 

 Drilling rig 

0.5–1 MW  Reciprocating 

 Gas turbine 

 Steam turbine 

 Microturbine 

 Flare gas to system 

 Electrical to local 

load 

 Excess electricity to 

grid 

Local Power – Large: 

generator running on flare gas, 

producing electricity for local 

consumption. 

 Industrial 

plant 

1–10 MW  Reciprocating 

 Gas turbine 

 Steam turbine 

 Flare gas to system 

 Electrical to local 

load 

 Excess electricity to 

grid 

1) Grid support – power generation for direct delivery onto the electrical grid. 

2) Local power – power generation for local use with excess generation (if any) sent to the 

electrical grid. 

A grid support project, although not without logistical issues, is straightforward in design, 

whereas a local power project tends to be more complex because of the introduction of 

significantly more design variables. The evaluation of power generation scenarios assumes that 

adequate electrical infrastructure exists to accommodate the additional electricity these systems 

generate (if delivered to the electrical grid). 

Grid Support 

A grid support project is fairly simple by description. Wellhead gas (with limited cleanup) 

is piped to the electrical generator. The generator burns the gas and produces electricity, which is 

put on the electrical grid for distribution by the local utility to its customers. 

The scale of these projects tends to be driven by capital costs (and cost recovery), and often 

there is an economy of scale that typically results in larger generators being more economically 

feasible. This larger scale, in turn, usually favors reciprocating engines, gas turbines, and steam 

turbines and precludes technologies such as microturbines and fuel cells. 
63 

Local Power 

A local power project is similarly described as wellhead gas (with limited cleanup) which 

is piped to the electrical generator, and the generator burns the gas and produces electricity. But 

in this case, the electricity is first used to power local consumption, with any excess electricity 

put on the electrical grid for distribution by the local utility to its customers. 

Although capital costs are still vitally important, the scale of the local power project is 

equally driven by matching the local electrical load with generation. These projects can range 

widely in scale, depending on the goal of the project (i.e., satisfy only local load, satisfy local 

load with minimal excess generation, or satisfy local load with significant excess generation). 

For this reason, most power generation technologies may be appropriate, depending on the 

project. 

Detailed Evaluation 

As indicated in earlier sections, Bakken associated gas is high in NGLs, resulting in a gas 

with very high Btu values (approximately 1400 Btu/cf). Since the NGLs make up a majority of 

the economic value of the rich gas, removal of at least a portion of the NGLs from the rich gas is 

beneficial to the economics of the project and may be advantageous to (or required by) the 

operation of the electrical generator. All scenarios were evaluated with the following 

assumptions: 

 Rich gas flow rate from the wellhead (average of all Bakken wells): 300 Mcf/day 

 Rich gas flow rate from the wellhead (local power scenarios): 600 Mcf/day 

 Rich gas flow rate from the wellhead (grid support scenarios): 1000–1800 Mcf/day 

 Rich gas Btu content: 1400 Btu/cf 

 NGL removal system used 

 Volume of NGLs existing in rich gas: 10–12 gallons/Mcf 

 Volume of NGLs removed from rich gas: 3–5 gallons/Mcf (1000 Mcf/day would result 

in 3000–5000 gallons of NGLs/day) 

 NGLs stored in 200-psi vessels at the location and periodically trucked to an offloading facility 

 NGL price (value) at the off-loading facility: $1.00/gallon 

 Lean gas flow rate from NGL removal system: 850 Mcf/day 

 Lean gas Btu content: 1210–1250 Btu/cf 
64 

 Lean gas price (value) consumed by electrical generator: $2.00/Mcf 

 Price (value) of electricity generated and delivered to the grid: $0.05/kWh 

 Price (value) of electricity generated and consumed on-site: $0.09/kWh 

In addition to the assumptions listed above, the gas composition of the lean gas 

(1210–1250 Btu/cf) was assumed to be as represented in Table 32. 

Table 32. Assumed Lean Gas Composition

Component mol% 

H2O 0.01 

N2 6.10 

CO2 0.62 

H2S 0.00 

C1 66.33 

C2 19.42 

C3 6.62 

C4 0.84 

C5 0.06 

C6 0.00 

C7 0.00 

C8 0.00 

C9 0.00 

C10–C11 0.00 

C12–C15 0.00 

Two power generation scenarios were evaluated for each category. In the grid support 

category, a reciprocating engine and a gas turbine scenario were evaluated, and in the local 

power category, the authors evaluated both a reciprocating engine and a microturbine. 

For each of the scenarios, capital expenditures for land acquisition and the NGL removal 

and storage system were deemed common for all scenarios and, therefore, described separately. 

Land Acquisition 

Analysis of the power generation scenarios assumed that the placement of the power 

generation system and its related components would not require the purchase or rental of 

additional land area. 

NGL Removal and Storage 

The removal of NGLs from the rich gas, although not necessarily required, greatly 

increases the economics of a power generation project, improves the performance of the genset, 

and reduces the loss of resource (when flaring is necessary). 
Bas

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can be basic

ricity for bu

NGLs from 

oval system 

ed to the ele

Process flow

he system in 

of project ec

ectrical load 

tem scale fo

nd for this stu

re solicited f

gine genset. 

iprocating e

is estimated

be 10% of t

e 34. 

procating E

ally describe

ulk delivery

the rich gas

are pumped

ectrical grid.

w diagram, gr

this scenari

conomics an

in the area 

or this appli

udy a scale o

from manuf

Based on in

engine gense

d to be appro

the capital co

66 

Engine Scena

ed as a recip

y to the elec

s stream prio

d to on-site 

. A simplifi

rid support –

o is not dict

nd the desire

and the abil

ication and 

of approxim

facturers to e

nformation p

et consisting 

oximately $4

ost, or $400

ario 

procating en

ctrical grid. 

or to the ele

storage vess

ed process f

– reciprocati

tated by any

ed level of g

lity of the g

technology 

mately 5 MW

establish the

provided by

 of three 17

4,000,000 ($

,000. The to

ngine genset 

A NGL re

ectrical gene

sels. All ele

flow diagram

ing engine sc

y particular e

rid support i

grid to handl

would mos

W was chosen

e capital and

y the equipm

00-kW gene

$800 per kW

otal costs for

burning lea

emoval syste

erator. The N

ectricity from

m is provid

cenario. 

electrical loa

in that area 

le delivery o

st typically r

n for analysis

d O&M cost

ment vendors

erators (5100

W). Annual O

r this scenari

an gas 

em is 

NGLs 

m the 

ed as 

ad but 

(both 

of the 

range 

s. 

ts for 

s, the 

0-kW 

O&M 

io are 
67 

Table 34. Total Cost Summary, Grid Support – Reciprocating 

Engine Scenario 

 Cost 

Capital Costs 

NGL Removal and Storage System $2,500,000 

Electrical Generator System $4,000,000 

Balance of Plant $1,000,000 

Total Capital Cost $7,500,000 

 

Annual O&M Costs 

NGL System $250,000 

Electrical Generator System $400,000 

Total O&M Cost $650,000 

Using the assumptions presented at the beginning of the Detailed Evaluation section, the 

process and product description can be described as follows. 1000 Mcf/day of associated 

wellhead gas from the heater/treater would be processed by the NGL removal system into 

850 Mcf/day of lean gas and 4000 gallons of NGLs. The NGLs are pumped to on-site storage 

and delivered to market via truck. The lean gas is supplied to the electrical generation system 

which would consume all 850 Mcf/day and produce 114,000 kWh of electricity per day that 

would be transmitted to the electrical grid. The revenue streams for these products are 

summarized in Table 35. 

Table 35. Summary of Product Revenues, Grid Support – Reciprocating 

Engine Scenario

Product Quantity 

Assumed 

Value 

Daily 

Revenue 

Annual 

Revenue1

NGLs 4000 gpd $1.00/gal $4000 $1,168,000 

Electricity 114,000 kWh/day $0.05/kWh $5700 $1,664,400 

Total $9700 $2,832,400 

1

 Assumes 80% annual system availability. 

Grid Support – Gas Turbine Scenario 

As in the previous scenario, the grid support – gas turbine scenario involves supplying rich 

gas from the wellhead to a NGL separation system. NGLs are stored on-site, and lean gas is fed 

to a gas turbine. Electricity produced from the gas turbine is delivered to the electrical grid. As 

shown in Figure 34, the process flow diagram is the same as the reciprocating engine scenario. 

Again targeting a scale of approximately 5 MW for this scenario, quotations were solicited 

from vendors. A budgetary cost estimate for a gas turbine genset comprising three 2000-kW 

generators was $6,400,000 ($1067/kW). Again, the O&M cost was assumed to be 10% of the 

capital cost, or $640,000 annually. The total costs for this scenario are summarized in Table 36. 
Usi

process 

wellhead

1530 Mc

and deliv

which wo

that wou

summariz

Figure

ing the assu

and produc

d gas from 

cf/day of lea

vered to mar

ould consum

uld be transm

zed in Table

34. Process

Table 36. T

Turbine Sc

Capital Co

NGL Rem

Electrical 

Balance o

Total Capi

Annual O&

NGL Syst

Electrical 

Total O&M

umptions pre

t descriptio

the heater/tr

n gas and 72

rket via truc

me the entire

mitted to th

e 37. 

 flow diagra

Total Cost S

cenario 

osts 

moval and St

Generator S

of Plant 

tal Cost 

&M Costs 

tem 

Generator S

M Cost 

esented at th

n can be d

reater woul

200 gallons 

ck. The lean

e 1530 Mcf/d

he electrical

68 

am, grid supp

Summary, G

torage System

System 

System 

he beginning

described as

d be proces

of NGLs. T

n gas is supp

day and prod

grid. The 

port – gas tu

Grid Suppor

Co

m $2,500

$6,400

$1,000

$9,900

$250

$640

$890

g of the Det

s follows. 1

ssed by the

The NGLs ar

plied to the 

duce 140,40

revenue stre

urbine scenar

rt – Gas 

ost 

0,000 

0,000 

0,000 

0,000 

0,000 

0,000 

0,000 

tailed Evalua

1800 Mcf/da

e NGL remo

re pumped t

electrical g

00 kWh of e

eams for th

rio. 

ation section

ay of assoc

oval system

to on-site sto

generation sy

electricity pe

hese product

n, the 

ciated 

m into 

orage 

ystem 

er day 

ts are 
Ta

Pr

NG

El

To

1 A

The

prior to i

on-site d

power – 

depicts th

A q

provided

genset is

capital co

able 37. Sum

oduct 

GLs 

ectricity 

otal 

Assumes 80% 

Local Po

e local powe

introduction 

demand, wit

reciprocatin

he process fl

Figure 35. P

quote was so

d a quote for

s approxima

ost. The cost

mmary of Pr

Qua

7200

140,400 

annual system

ower – Recip

er – reciproc

of the rich 

h the exces

ng engine s

low diagram

Process flow

olicited for a

r a single 25

tely $200,00

ts for this sce

roduct Reve

ntity 

0 gpd

kWh/day 

m availability. 

procating En

cating engin

gas to the ge

s electricity

cenario was

m for the loca

w diagram, lo

a NG-fired g

50-kW NG r

00, and the 

enario are su

69 

enues, Grid

Assumed 

Value 

$1.00/gal

$0.05/kWh

ngine Scena

ne scenario e

enerator. Ele

y fed to the 

s targeted t

al power – re

ocal power –

genset of app

reciprocating

annual O&

ummarized i

d Support –

Daily

Revenu

$7200

h $7020

$14,220

ario 

employs the

ectricity gen

electrical g

to be approx

eciprocating 

– reciprocati

proximately

g engine gen

&M cost was

in Table 38.

Gas Turbin

ue 

An

Rev

0 $2,1

0 $2,0

0 $4,1

e same NGL

nerated is fir

grid. The sc

ximately 1 

engine scen

ing engine sc

y 300 kW in 

nset. The ca

s assumed t

ne Scenario

nnual 

venue1

02,400 

049,840 

52,240 

L removal sy

rst used to sa

cale for the 

MW. Figur

nario. 

cenario. 

size. The ve

apital cost fo

o be 10% o

ystem 

atisfy 

local 

re 35 

endor 

or the 

of the 
70 

Table 38. Total Cost Summary, Local Power – 

Reciprocating Engine Scenario 

 Cost 

Capital Costs 

NGL Removal and Storage System $2,500,000 

Electrical Generator System $200,000 

Balance of Plant $500,000 

Total Capital Cost $3,200,000 

 

Annual O&M Costs 

NGL System $250,000 

Electrical Generator System $20,000 

Total O&M Cost $270,000 

Using the assumptions presented at the beginning of the Detailed Evaluation section, the 

process and product description can be described as follows. 600 Mcf/day of associated wellhead 

gas from the heater/treater would be processed by the NGL removal system into 510 Mcf/day of 

lean gas and 2400 gallons of NGLs. The NGLs are pumped to on-site storage and delivered to 

market via truck. The lean gas is supplied to the electrical generation system which consumes 

101 Mcf/day and produces 6000 kWh of electricity that serves on-site electrical load. The 

remaining lean gas (approximately 499 Mcf/day) is either stored on-site for truck transport to the 

pipeline or pumped directly into a NG-gathering system for delivery to a gas-processing plant. 

For this example, we will assume excess gas is sold. The revenue streams for these products are 

summarized in Table 39. 

Table 39. Summary of Product Revenues, Local Power – 

Reciprocating Engine Scenario 

Product Quantity 

Assumed 

Value 

Daily 

Revenue 

Annual 

Revenue1

NGLs 2400 gpd $1.00/gal $2400 $700,800 

Electricity 6000 kWh/day $0.09/kWh $540 $157,680 

Lean gas 499 Mcf/day $2.00/Mcf $998 $291,416 

Total $3938 $1,149,896 

1

 Assumes 80% annual system availability. 

Local Power – Microturbine Scenario 

This scenario involved the removal of NGLs prior to delivery of gas to the microturbine 

and the use of generated electricity to satisfy local electrical demand, with the excess electricity 

delivered to the grid. The scale of this scenario is smaller than other scenarios to provide a range 

of generation scales. For this reason, two scenarios were examined at a scale close to 200 kW. 

Figure 36 shows the process flow diagram of the local power – microturbine scenario. 
To 

feet-abov

represent

derated o

configure

package 

packages

Table 40

Descript

Four 65-

Two 200

In 

processin

will be m

small-sca

flares ex

examples

In b

and unsc

Figure 

accurately s

ve-sea-level 

t the worstoutput of be

ed as multi

systems tha

s offered by 

0. Flow Diag

tion 

-kW Microtu

0-kW Micro

selecting ei

ng capacity 

most econom

ale microtur

xcess lean g

s that follow

both cases, t

cheduled ma

36. Process 

size a system

elevation a

case scenar

etween 20%

ple microtu

at were app

the vendor. 

gram, Local

urbines 

turbines 

ither packag

than the ele

mical only a

rbines consu

gas or is des

w, it is assum

the vendor o

aintenance o

flow diagram

m, the vendo

and a maxi

io as far as

% and 25%. 

urbines coup

proximately 

l Power – M

Nominal 

Power 

Rating 

260 kW 

400 kW 

ge, the NGL

ectrical gene

at the higher

ume less tha

signed to st

med that the e

offers a fact

f the system

71 

m, local pow

or used EER

mum ambie

s electrical p

The two sy

pled togethe

200 kW in

Microturbine

Actual 

Power 

Rating 

195 kW 

316 kW 

L removal 

eration syste

r-gas-produc

an 100 Mcf/

tore the exc

excess lean g

tory protecti

m as well as

wer – microtu

RC-provided 

ent tempera

production e

ystems offere

er in a sing

n scale. Tab

e Scenario

Derate C

25% 4

20% 6

system is l

em. Generall

cing wells. A

/day. This m

cess gas for 

gas is sold. 

ion plan (FP

s parts, inclu

urbine scena

conditions i

ature of 100

environment

ed by the v

gle package 

ble 40 sum

Gas 

Consumed 

49 Mcf/day 

68 Mcf/day 

likely to be

ly, the NGL

As shown in

means that t

sale to the

PP) that cov

uding an ov

ario. 

including a 2

0°F. This w

t and result

vendor were 

and resulte

mmarizes the

Electrici

Generate

4683 kWh

7595 kWh

e much larg

L removal sy

n Table 40, 

the project e

e pipeline. In

vers all sched

erhaul or tu

2250-

would 

t in a 

both 

ed in 

e two 

ity 

ed

h/day 

h/day 

ger in 

ystem 

both 

either

n the 

duled 

urbine 
72 

replacement at 40,000 hours of operation. The FPP “locks in” the annual O&M cost of the 

system, and in both scenarios presented below, it is assumed that the FPP is purchased. 

For the purposes of this report the authors chose to analyze the smaller package (four 65-

kW microturbines) as it more closely matched the 200-kW scale and provided more flexibility 

should a single turbine need to be taken off line for maintenance or some other reason. 

Four 65-kW Microturbine System 

This system consists of four 65-kW Capstone microturbines combined in a single package 

nominally rated at 260 kW of electrical output. Under the conditions discussed above, the system 

would be derated and provide approximately 195 kW of power (or 25% derate). Table 41 

provides a summary of the capital and O&M costs using the costs discussed in this section and 

costs presented in the NGL Removal and Storage section. 

Table 41. Total Cost Summary, Local Power – Microturbine 

Scenario (Four 65-kW) 

 Cost 

Capital Costs 

NGL Removal and Storage System $2,500,000 

Electrical Generator System $383,200 

Balance of Plant $500,000 

Total Capital Cost $3,383,200 

 

Annual O&M Costs 

NGL System $250,000 

Microturbine FPP $33,640 

Total O&M Cost $283,640 

Using the assumptions presented at the beginning of the Detailed Evaluation section, the 

process and product description can be described as follows. 600 Mcf/day of associated wellhead 

gas from the heater/treater would be processed by the NGL removal system into 510 Mcf/day of 

lean gas and 2400 gallons of NGLs. The NGLs are pumped to on-site storage and delivered to 

market via truck. The lean gas is supplied to the electrical generation system which consumes 

49 Mcf per day and produces 4683 kWh of electricity that serves on-site electrical load. The 

remaining lean gas (approximately 461 Mcf/day) is either stored on-site for truck transport to the 

pipeline or pumped directly into a NG-gathering system for delivery to a gas-processing plant. 

The revenue streams for these products are summarized in Table 42. 

Drilling Rig Power 

 The use of wellhead gas as a fuel for drilling operations derives advantages from both 

CNG and power production scenarios described previously. In reciprocating diesel engines, rich 
73 

Table 42. Summary of Product Revenues, Local Power – Microturbine 

Scenario (Four 65-kW) 

Product Quantity 

Assumed 

Value 

Daily 

Revenue 

Annual 

Revenue1

NGLs 2400 gpd $1.00/gal $2400 $700,800 

Electricity 4683 kWh/day $0.09/kWh $421 $122,932 

Lean gas 461 Mcf/day $2.00/Mcf $922 $269,224 

Total $3743 $1,092,956 

1

 Assumes 80% annual system availability. 

wellhead gas can be combusted with little more than dewatering as pretreatment. Further, since 

the fuel displaced is high-priced diesel fuel, the economics are favorable over other lower-priced 

power production applications like large-scale coal or natural gas-based electrical production. 

 As a separate task under this project, the EERC is working with Continental Resources, 

ECO-AFS, Altronics, and Butler Caterpillar to conduct a detailed study and field demonstration 

of the GTI Bi-Fuel System®. Within that task, the EERC conducted a series of tests at the EERC 

using a simulated Bakken gas designed to test the operational limits of fuel quality and diesel 

fuel replacement while monitoring engine performance and emissions. Additionally, a field 

demonstration of the Bi-Fuel System will be completed in the summer of 2012 during which 

engine performance, emissions, and fuel savings will be monitored for the duration of a two-well 

batch drilling operation. The field demonstration will provide researchers and project partners 

detailed information on how the system performs in real well drilling operations and validate fuel 

savings achievable over extended operation. 

 ECO-AFS has recently installed several Bi-Fuel Systems on rigs in the Williston Basin. 

Early data suggest that diesel fuel savings of approximately $1 to $1.5 million can be achieved 

annually. Under typical conditions, operators can expect to achieve diesel replacement of 

40%–60% at optimal engine loads of 40%–50%. 

 Because the Bi-Fuel System is an aftermarket addition providing natural gas to the air 

intake, engine performance is not altered in diesel-only operation. If the natural gas supply is 

interrupted or unavailable at a location, the engines can continue to operate on diesel fuel without 

requiring any alterations. The control system of the Bi-Fuel System also provides a number of 

safety protocols that simply stop gas flow if any engine performance parameters exceed 

manufacturer-recommended limits. The Bi-Fuel System controls continue to monitor engine 

performance, and when engine operational parameters return to acceptable ranges, gas can again 

be supplied to the engines. 

 Total installed capital cost for the Bi-Fuel System ranges from $200,000 to $300,000. 

Once hardware is installed, additional costs will be incurred to bring wellhead gas to the engine 

building. These costs can vary greatly depending on distance to the nearest gas source and gas 

lease terms. These costs have not been included in this assessment. 
74 

Evaluation Summary 

A wide variety of power generation technologies exist that can utilize rich gas of varying 

quality to produce electricity. Power generation technologies also match the assortment of 

wellhead gas flow rates and can be constructed for mobility if needed. 

 

For these reasons, power generation as an end use technology for NG, whether it be flared 

associated gas, gathered but untreated gas, or processed NG, is a strong candidate technology for 

consideration. 

From an economic perspective, the hypothetical power generation scenarios presented in 

this section and summarized in Table 43 provide a preliminary technical and economic 

evaluation that should afford an initial indication of project feasibility. Many assumptions were 

made and the reader should carefully consider the relevance of these assumptions to their 

specific circumstances. 

Table 43. Summary of Power Generation Scenarios 

Scenario Capital Cost 

Annual 

O&M Cost 

Annual 

Revenue1

Grid Support – Reciprocating Engine $7,500,000 $650,000 $2,832,400 

Grid Support – Gas Turbine $9,900,000 $890,000 $4,152,240 

Local Power – Reciprocating Engine $3,200,000 $270,000 $1,149,896 

Local Power – Microturbine $3,383,200 $283,640 $1,092,956 

1

 Assumes 80% annual system availability. 

Based on cost and revenue assumptions provided in the previous sections, all scenarios 

provided a simple payback of 3 years or less. It should be noted that since the contractual 

arrangements vary widely regarding “ownership” of the rich wellhead gas, no cost was assigned 

to obtaining the wellhead gas in the scenarios presented. Readers should take into account this 

input cost based on their specific situation as it will impact the overall economics significantly in 

certain cases. 

In addition to rig power, discussed in the previous section, there are a number of other 

potential natural gas uses related to oil production and operations that could take advantage of 

rich gas on a well site. Although rig power provides one of the largest demands for gas use, the 

heating of drilling fluids during winter months can be achieved with rich gas replacing diesel or 

propane as the more common fuel. The only technology modification required is a burner 

modification, provided that gas is already available at the drilling site. 

Once drilling is complete, rich gas at the drilling location can be used to provide power for 

hydraulic fracturing operations. Bi-fuel systems or dedicated natural gas engines can be utilized 

to provide power for fracturing operations, thereby decreasing diesel deliveries and reducing the 

fuel costs associated with these operations. Gas availability, in terms of volumetric flow rate, 

will need to be investigated since the flow available may be insufficient to provide all of the fuel 
75 

required for fracturing operations. However, in a bi-fuel type application, any shortage of gas 

would be made up with diesel. 

Once production is under way, gas from the producing well or gas transported to the 

location from nearby wells can continue to be used to provide power for production activities 

when electrical service is not available. Although the gas use is relatively low for these 

operations, some remote locations may benefit from on-site generated power. Lastly, wellhead 

gas could be used to fuel workover rigs used intermittently to maintain producing wells. For 

workover rigs powered by the truck’s CNG or LNG engine, wellhead gas would not provide a 

viable alternative. However, workover rigs with separate generators capable of operating on 

wellhead gas could benefit from the low-cost gas available on location. 

Virtually any platform or application that utilizes diesel fuel as part of its operation may 

warrant the evaluation of using natural gas because of the availability and price of the natural 

gas. However, there are a number of contractual logistical, technical, and economic components 

that need to be vetted to determine whether a project makes sense. 

Due diligence is required on the part of the reader to evaluate the cost impacts of 

regulatory, permitting, and engineering design requirements, which were beyond the scope of 

this report. 

APPLICATION III – CHEMICALS DERIVED FROM BAKKEN ASSOCIATED GAS 

Overview of NG and NGL-Based Chemical Industry 

Raw NG, as produced and flared on well sites, is a mixture of many chemical compounds. 

The relative amounts of these components vary from well to well and over time from a single 

well. The potential uses and value of individual components also varies from component to 

component and over time because of market conditions. What all the components have in 

common, are high vapor pressures that permit them to escape from the liquids with which they 

might have been associated. 

Raw NG constituents can be classified into three categories: methane, NGLs (also termed 

condensates), and impurities. Characteristically, the relative amount of a hydrocarbon component 

is inversely related to its size; thus methane, the smallest hydrocarbon, is predominant, with 

progressively decreasing amounts of ethane, propane, butane, pentane, hexane, and largermolecular-weight hydrocarbons. Numerous inorganic compounds are also present, the most 

common being water, carbon dioxide, hydrogen sulfide, mercury, nitrogen, and helium. By 

category, NGLs have the highest value, methane less, and contaminants, for the most part, are 

nuisance waste products. A comparison of the boiling point of major NG hydrocarbons is 

described in Table 44. 
76 

Table 44. NG Component Boiling Points 

Component Chemical 

Name Chemical Formula

Boiling 

Point 

Range, °F

Methane CH4 −259 

Ethane CH3CH3 −128 

Propane CH3CH2CH3 −44 

i-Butane CH3CH(CH3)2 14 

n-Butane CH3CH2 CH2 CH3 31 

neo-Pentane (CH3)2C(CH3)2 49 

i-Pentane CH3CH(CH3)CH2CH3 82 

n-Pentane CH3CH2CH2CH2CH3 97 

Hexanes C6H14 122–156 

Each hydrocarbon extracted from raw NG has a set of uses or can be further processed into 

products. A summary of these uses and products is provided as follows: 

 Methane’s principal use is as a fuel to produce heat for buildings and chemical and 

other processes as well as for generating electric power. To a much lesser extent, 

methane is a feedstock for nitrogen-based fertilizers such as ammonia, urea, and 

ammonium nitrate; for chemicals such as methanol, acetic acid, formaldehyde, and 

hydrogen; and for fuels such as dimethyl ether (a potential diesel fuel substitute) and 

Fischer–Tropsch (FT)-based transportation fuels. In the United States, roughly equal 

shares of NG deliveries to consumers go to 1) residential and commercial customers, 

primarily for heating; 2) utilities for electric power generation; and 3) industrial 

customers for heat and chemical feedstock. (U.S. Energy Information Administration, 

2012b). 

 Ethane is primarily used as a chemical feedstock for production of ethylene and 

derivatives such as polyethylene, ethylene glycol, and ethylene oxide. When feedstock 

prices are depressed relative to fuel prices, ethane also can be rejected into NG pipelines 

to the extent allowed by pipeline operators. 

 Propane’s primary use is residential and commercial heating with the remainder being 

used by 1) industry for chemical feedstock and other uses, 2) agriculture for heating and 

drying, and 3) commercial entities as a motor fuel for forklifts and other vehicles. Of 

propane consumed in the United States in 2010, about half was used for residential and 

commercial heating and a third for chemical feedstock for chemicals such as propylene 

and polypropylene (Lippe, 2011).

 There are two forms of butane (n-butane, a straight chain hydrocarbon, and i-butane, a 

branched hydrocarbon) that possess slightly different chemical properties and uses. The 

majority of butanes are used for heating when alone or combined with propane to create 

liquefied petroleum gas (LPG) and as petroleum refinery feedstock, eventually 

becoming motor fuel. Regulatory restrictions on motor fuel vapor pressure, however, 


Fig

distributi

because o

Th

which is 

gathering

and pipe

processin

discrete 

limit butane

result, refin

higher-octan

ether) (an ox

refrigerants 

plastic and p

Pentanes, he

gasoline.” T

to higher-o

individual c

processes, a

name a few

transported 

enable it to b

gure 37 desc

ion system. A

of the multip

e NGL supp

represented 

g networks t

line-quality 

ng facilities 

NGLs, can 

e levels, espe

ers convert 

ne compoun

xygenate) be

and as feed

polybutadien

exanes, and 

These compo

octane fuels,

components 

as refrigeran

w. Increasin

to Canada to

be pumped i

ribes the su

As is appare

plicity of com

ply chain sta

in Figure 38

to gas-proce

natural gas 

close to wh

be perform

Fig

ecially durin

butanes to o

nds by route

efore blendin

dstock to pro

ne synthetic 

larger hydro

onents typica

, and event

are used a

nt, and as blo

ngly, natura

o dilute bitu

in pipelines.

upply chains 

ent, the NGL

mponents th

arts with pro

8. Raw natur

ssing faciliti

produced. T

here natural 

med at the ga

gure 37. NG

77 

ng the summ

other compo

e of alkylati

ng into moto

oduce chemi

rubber. 

ocarbons are

ally become 

tually appea

as feedstock

owing agent

al gasoline, 

umen crude o

for natural 

L chain is lo

at comprise 

oduction, th

ral gas is col

ies in which

Typically, th

gas is produ

as-processin

and NGL su

er and in ble

ounds, such 

on and to M

or fuel. Add

icals and ma

e often referr

refinery fee

ar in moto

k and solve

t for produc

with some

oil so as to r

gas and NG

nger and als

NGLs and t

he predicted 

llected at we

h the raw ga

hese activiti

uced. Fracti

ng plant as 

upply chain.

ends contain

as conversi

MTBE (meth

ditionally, bu

aterials such

red to collec

edstock, ofte

r fuel. To 

ents for che

ction of poly

e butane inc

reduce the o

GLs from th

so is much m

the range of 

geographic 

ell sites and 

as is treated, 

ies are acco

onation, or 

a means of

ning ethanol.

on of i-buta

hyl tertiary

utanes are us

h as polybut

ctively as “na

en with upgra

a lesser ex

emical and 

ystyrene foa

cluded, is b

oil’s viscosity

e well site t

more compli

products. 

concentratio

sent through

NGLs extra

mplished in

separation o

f separating 

. As a 

ane to 

butyl 

sed as 

ylene 

atural 

ading 

xtent, 

food 

m, to 

being 

y and 

to the 

icated 

on of 

h gasacted, 

n gasof the 

them 
from met

(KS) or 

(AB). 

On

batched 

turn to tr

transport

farther to

more are

the USGC

In 2

daily cap

facilities

class and

nine plan

on the U

19.7 Bcf/

28% and

thane, or a m

Mt. Belvieu

nce fractiona

in a shared 

ravel), or mo

ted far to re

o go to get to

e being cons

C. 

NG-Proc

2010, the Un

pacity of 77

. Figure 40 c

d the cumula

nts accounte

USGC. In 20

f/day, represe

d 14%, respe

Figure 3

mixed NGL 

u (TX), Cha

ated, pure N

pipeline (w

oved by rail.

each petroch

o the USGC 

structed to m

cessing Infra

nited States 

7 billion cub

classifies the

ative capacit

ed for 31% o

10, Texas ha

enting 26% 

ectively, of 

38. Lower 4

stream can 

nnahon (IL)

NGL compo

which require

 Component

hemical faci

or to cracke

move the inc

astructure 

had 493 op

bic feet (Bcf

e plants by c

ty of plants 

of U.S. gasad the larges

of total U.S.

total U.S. p

78 

8 states’ sha

be transport

), Sarnia (O

onents are m

es substantia

ts on the U.S

ilities and re

ers in Illinois

creasing volu

erational NG

f). Figure 39

capacity, the

within each

-processing c

st number of

. capacity. T

processing in

ale plays (20

rted to remot

ON), Fort Sa

moved separ

al storage as

S. Gulf Coa

efineries. Co

s and Iowa, b

umes of com

G-processing

9 depicts th

en describes 

h class. EIA 

capacity. NG

f plants, 163

Texas and Lo

n 2010. Dur

11). 

te facilities, 

askatchewan 

rately by m

s each comp

ast (USGC) d

omponents 

but pipelines

mponents, es

g plants that

he location a

the number 

data indicat

G processing

3, and proce

ouisiana wer

ring this sam

such as Con

(AB) and J

multiple pipe

ponent awai

do not have 

in Conway 

s are in plac

specially tow

t had a comb

and size of 

of plants in

te that the la

g is concent

essing capaci

re responsib

me period, N

nway 

Joffre 

lines, 

its its 

to be 

have 

e and 

wards 

bined 

these 

n each 

argest 

trated 

ity of 

le for

North 
Figure 4

Figure 

0. Capacitie

39. U.S. NG

s and numb

79 

-processing

er of U.S. N

 plants (200

G-processin

9). 

g plants (2010). 
80 

Dakota processed about 0.6% of the U.S. total. Two other regions performed significant 

processing in 2010: Alaska (17%) and the Rocky Mountain region (Colorado and Wyoming had 

a combined output of 18% of U.S. processing). Texas’s disproportionate processing (26% of 

U.S. capacity, but 28% of output) was due to its operating at 83% of capacity—while the rest of 

the country averaged 66%—which indicates an efficient use of resources and potential upcoming 

need to expand capacity. During the period 2004–2009, average plant capacity increased from 

114 to 139 MMcfd. 

Figure 41 exhibits the locations of processing plants in North Dakota in 2011. The number 

and capacity of plants in the state is forecast to increase substantially between 2006 and 2012 as 

projected in Table 45. 

Because of expansion in gas-gathering and processing infrastructure, flaring of NG is 

declining in North Dakota, having peaked in 2011 with 35% of gas being flared. In April 2012, 

North Dakota Department of Mineral Resources statistics showed NG production was up to 

650,000 Mcfd, with 34% being flared. As new gas-processing plants are built and commissioned 

in 2012, the fraction of gas flared is expected to decrease (Persily, 2012). 

NG Distribution Infrastructure 

As Figure 42 indicates, three interstate NG transmission pipelines pass through and are 

accessible within North Dakota. These include WBIP, which extends through eastern Montana, 

northern Wyoming, western South Dakota, and across North Dakota; NBIP, which connects to 

an Alberta collection system in Montana and extends through the Dakotas, Minnesota, Iowa, and 

Illinois to northwest Indiana; and the Alliance Pipeline, which extends from British Columbia 

through North Dakota, Minnesota, and Iowa to Illinois. The capacity of the three pipelines is 

adequate to absorb North Dakota’s growing NG production—which has expanded by 

24 MMcf/month over the past year—for an extended period of time. Growth will be handled by 

the addition of receipt and delivery points, increased compression, and increased ethane rejection 

without expanding or replacing trunk pipelines. 

In 2008, WBIP added 42 MMcfd (expandable to 60 MMcfd) to its system and has 

proposed adding roughly 20 MMcfd of delivery capacity in northwestern North Dakota to be 

constructed later this year. 

NBIP, with a current capacity of 2.401 Bcfd of which 2.171 Bcfd is contracted firm, will be 

receiving NG from ONEOK’s three new 100-MMcfd processing plants and will commence 

service in 2012–2013. The incremental load of these plants on the NBIP will be attenuated 

somewhat by ONEOK’s construction of a 60,000-bpd NGL pipeline that will connect to 

William’s Overland Pass Pipeline in Colorado. ONEOK’s pipeline will permit capture of 

valuable ethane that otherwise would be rejected into the NG product and result in NG flow 

reduction of up to 20%. 
Figure 41. No

(Nort

rth Dakota 

h Dakota Pi

81 

gas-processi

peline Auth

ing and trans

ority, 2011a

portation 

). 
The

rich gas p

at Bantry

North Da

Tioga pl

pipeline 

than 90 M

If N

by Augu

processin

Cu

Rose Pip

Dakota, r

e Alliance P

pipeline. Cu

y, North Da

akota, will a

ant, which w

by Aux Sab

MMcfd) of e

NG producti

st 2013 and 

ng capacity i

Current 

urrently, Bak

peline. Oper

removes hea

Table 45. N

Capacity (2

2006

227 

Figure 42

Pipeline, wit

urrently the p

akota; howev

add a second

will more th

ble, named th

ethane to cra

on growth c

1100 MMcf

in North Dak

NGL Distrib

kken NGLs a

rated by Au

avier NGL c

North Dako

2006–2012)

2008

380 

. Interstate N

th a FERC-c

pipeline’s on

ver, a new p

d point. This 

han double 

he Vantage 

cking facilit

continues as 

fd by January

kota should b

bution Infra

are transport

ux Sable, th

components 

82 

ota NG-Proc

, in million 

2010

500 

NG pipelines

certified cap

nly U.S. rece

pipeline from

construction

the plant’s 

Pipeline, tha

ties in Albert

it has recent

y 2014. As i

be adequate 

astructure 

ted out of sta

he Palermo C

to provide a

cessing

cubic feet p

2011

670 

s in North D

pacity of 1.5

eipt point is 

m Hess’s Ti

n is in conju

capacity, an

at will trans

ta. 

tly, producti

indicated in 

to handle th

ate by rail an

Conditionin

a 110-Mcfd r

per day 

2012

1100 

Dakota. 

513 Bcfd, is

Prairie Pipe

ioga gas pla

unction with 

nd construct

sport up to 6

ion will exce

Table 46, th

he new produ

nd by pipeli

ng Plant nea

rich gas stre

 a high-pres

line’s conne

ant to Sherw

expansion o

tion of an et

60,000 bpd (

eed 1000 MM

he forecasted

uction. 

ne via the P

ar Stanley, N

eam to the P

ssure, 

ection 

wood, 

of the 

thane 

(more 

Mcfd 

d NGPrairie 

North 

Prairie 
83 

Table 46. NG-Processing Capacity in North Dakota, MMcfd

Owner Company Facility County 2006 2008 2010 2011 2012 North Dakota 6 Bear Paw/ONEOK Lignite Burke 7.5 6 6 6 6 Bear Paw/ONEOK Marmath Slope NA 7.5 7.5 7.5 7.5 Bear Paw/ONEOK Garden Creek McKenzie NA NA NA 100 100 Bear Paw/ONEOK Stateline 1 Williams NA NA NA NA 100 Bear Paw/ONEOK Stateline II Williams 32 NA NA NA 100 Petro Hunt Little Knife Billings 4 32 32 32 32 True Oil Red Wing Creek McKenzie 0.5 4 4 4 4 Sterling Energy Ambrose Divide NA 0.5 0.5 0.5 0.5 EOG Resources Stanley Mountrail NA 20 0 0 0 Whiting Oil and Gas Robinson Lake Mountrail NA 30 45 90 90 Whiting Oil and Gas Ray Williams NA 10 10 10 NA Whiting Oil and Gas Belfield Stark NA NA NA 30 30 XTO–Nesson Ray Williams 63 10 10 10 10 Bear Paw ONEOK Grasslands McKenzie 110 100 100 100 100 Hess Tioga Williams 4 120 120 120 250 Hiland Partners Badlands Bowman NA 40 40 40 40 Hiland Partners Norse Divide NA NA 25 25 25 Hiland Partners Watford City McKenzie NA NA NA 50 50 Summit Resources Knutson Billings NA NA NA NA NA Saddle Butte Watford City McKenzie NA NA NA 45 45 Plains Ross Mountrail NA NA NA NA NA Aux Sable – Chicago, IL Aux Sable Prairie Rose Mountrail NA NA 110 110 110  Total 227 380 510 780 1100 
Rose Pip

Illinois. P

to 10 Mb

Vantage 

gas-proce

from the 

with an i

mid-2013

Pipeline 

(expanda

The

Figure 43

Carringto

however,

that pass

North Da

If N

transport

advantag

transport

the price 

“frac spr

heavier 

peline which

Pipeline cap

bpd) of mix

Pipeline sho

essing plant

Tioga plant

initial capaci

3, ONEOK’

in northern

able to 100 M

e Kinder–Mo

3. It has a 

on, which h

, Alliance P

es through N

akota. 

Figure 4

NGL pipelin

ting NGLs 

ge in that on

ting compon

received fo

read” (A sim

components

h connects to

acity is expa

xed NGLs w

ould be in op

t by pipeline

t to Alliance

ity of 120,00

’s 525-mile 

n Colorado 

Mbpd) of mix

organ Cochi

single term

as 21,430 b

Pipeline oper

North Dakot

43. Alliance

ne transporta

by rail or 

ne train can 

nents by pip

r NGL comp

milar term, 

s). This val

o the Allianc

andable. A t

was added t

peration, tra

e to Canada

e’s mainline 

00 Mcfd of 

pipeline fr

should be 

xed NGLs to

in Pipeline, t

minal in the 

bl of storag

rates a rich 

a and transp

e Pipeline sys

ation is not 

fractionatin

ship multip

eline might 

ponents and 

NGL marg

lue varies 

84 

ce Pipeline, 

ruck rack ca

o the Palerm

ansporting 40

a. By mid-2

near Sherwo

rich NG to f

rom western

in service, 

o facilities n

the only NG

state that 

ge on-site. In

NG pipeline

ports light N

stem map (A

available, m

g and shipp

ple NGL com

involve mu

that paid fo

gin, refers to

over time 

carrying ga

apable of rec

mo Plant in

0–60 Mbpd 

013, Allianc

ood, North D

facilities in 

n North Da

with an in

near Conway

GL pipeline i

is a propan

n addition to

e between B

GL compon

Alliance Pipe

midstream co

ping compo

mponents as

ultiple pipeli

or the origina

o the same 

on the bas

as to facilitie

ceiving 5 Mb

n April 2012

of ethane fr

ce Pipeline’

Dakota, shou

Channahon,

akota to the

nitial capac

y, Kansas. 

in North Da

ne delivery 

o Kinder–M

British Colum

nents mixed 

eline LP, 20

ompanies ha

onents by r

s cheaply as

ines. The dif

al mixed NG

difference 

sis of NG, 

es in Channa

bpfd (expan

2. Early in 2

rom Hess’s T

’s 79-mile la

uld be in ser

 Illinois. Al

e Overland 

ity of 60 M

akota, is show

point locat

Morgan’s pipe

mbia and Ill

with NG thr

12). 

ave the optio

rail. Rail ha

s NGLs, wh

fference bet

GLs is terme

for propane

 crude oil,

ahon, 

dable 

2013, 

Tioga 

ateral 

rvice, 

so by 

Pass 

Mbpd 

wn in 

ed at 

eline, 

linois 

rough 

on of 

as an 

hereas 

tween 

ed the 

e and 

, and 
petrochem

in the n

$8/MMB

Mt. Belv

Mt. Belv

USGC m

Giv

fractiona

the incre

productio

fractiona

Figur

Ano

pipelines

mixed w

Columbi

lighter N

occur. 

mical prices

neighborhood

Btu. Frac sp

vieu, which 

vieu move to

market. 

ven their lim

ate and produ

ease in NG

on is comp

ated, but stay

re 44. North 

Alternate

other means

s, which are 

with higher 

a, Canada, t

NGLs with m

s and by loca

d of $1/MM

preads can 

differed by

ogether but 

mited access 

uce NGL co

GL productio

pared to fra

ys with the N

Dakota NG

e Rich Gas D

s of transpo

pipelines th

concentratio

o the Chicag

methane to 

ation and ac

MBtu, but 

also differ 

y 3 cents/MM

with a disco

to NGL pip

omponents, 

on over tim

actionated c

NG. 

L production

Distribution

orting lower

hat permit in

ons of NGL

go area is an

a site wher

85 

ccess to prod

in 2011, th

between lo

MBtu on Ju

ount offset b

pelines, Nort

instead of sh

me and sho

components.

n (bpd) (Nor

n System 

r-molecularntroduction 

Ls). The Al

n example of

re recovery 

duct markets

hey were in

ocations suc

uly 25, 201

because of 

th Dakota ga

hipping mix

ows how sm

. It also in

rth Dakota P

-weight NGL

of higher-Bt

lliance Pipe

f such a pipe

and fractio

s. In 2002, f

n the neigh

h as Conw

11. In gener

Conway’s d

as processor

xed NGLs. F

mall Y-grad

ndicates tha

Pipeline Auth

Ls is by m

tu-value gas

eline that ru

eline: it prov

onation of N

frac spreads 

hborhood of

way, Kansas,

ral, Conway

distance from

rs have tend

Figure 44 de

de (mixed) 

at ethane is

hority, 2011

means of rich

ses (i.e., met

uns from B

vides transpo

NGL compo

were 

f $6–

, and 

y and 

m the 

ded to 

epicts 

NGL 

s not 

). 

h-gas 

thane 

British 

ort of 

nents 
86 

Petrochemical Industry Relevance in North Dakota 

North America has four major petrochemical centers: the Mt. Belvieu (TX) and Conway 

(KS) hubs, Edmonton (AB), and Sarnia (ON). Mt. Belvieu’s capacity far exceeds the other 

regions and is considered the price reference point for North American NGLs. Mt. Belvieu has 

an NGL storage capacity of 200 MMbbl; Williams operates storage in Conway with a 20-MMbbl 

capacity. Alberta’s AEGS (Alberta Ethane-Gathering System) has a 5-MMbbl capacity. BP 

operates 12 salt caverns in Sarnia that hold finished products and possess a capacity of 

5.0 MMbbl (6.8 MMbbl of surface brine pond capacity). EIA reported PADD (Petroleum 

Administration for Defense Districts) III (including the USGC) August 2011 NGL inventory to 

be 74.7 MMbbl, which is only a 37% utilization rate, suggesting additional storage capacity 

exists to support the growing shale gas production. 

Traditionally, the North American petrochemical industry has been located in areas that 

possess large gas reserves and geologic storage features like salt domes and depleted reservoirs 

where gas, NGLs, and intermediate products can be stored in very large quantities. Currently, 

96% of U.S. ethane-cracking capacity is concentrated on the USGC, especially Texas and 

Louisiana. As illustrated in Figure 44, the USGC possesses a large fraction of gas reserves and, 

as mentioned previously, has significant geologic storage capacity to accommodate the industry. 

Based on these factors, significant infrastructure has been built around the USGC. Distribution 

capacity exists to transport gas and gas liquids to the region from across North America. 

Additionally, NGL fractionation, cracking, and downstream processing capacity exist to convert 

these hydrocarbons into products that are shipped around the world. As a result of the large 

volume of gas and NGLs processed in the region, it has become the basis and reference point for 

financial markets. 

As described herein, chemical production capital investment decisions are complex, 

involving a myriad of factors, relationships, and timing that consider complete supply chains. A 

detailed discussion of how market factors impact the petrochemical industry and plans for 

infrastructure expansion is provided in Appendix A. Such factors include the following: 

 Capital efficiency 

 Economy of scale (larger units are cheaper to build/operate per pound of product) 

 High utilization rates (run constantly at full throughput) 

 Long life (operate plant for decades) 

 Use of synergies to reduce required investment, such as restarting shuttered plants, 

converting units from petroleum-based feedstock to NG-based feedstock, relieving 

capacity constraints in existing plants, and sharing facilities 

 Proximity to long-term: 

 Cheap and abundant feedstock and utilities 

 Large customer markets 

 Cheap transportation 

 Cheap storage 

 Government regulatory and business climate, plus grants and tax incentives 
87 

Chemicals in North Dakota can be produced at two different locations, the well site and 

downstream of gas processing, each of which has different advantages and issues. The principal 

advantage of well site chemical production in North Dakota is access to cheap gas that would 

otherwise be flared. This advantage, however, is temporary, existing only until infrastructure 

appears. Agricultural chemical production, such as fertilizer, possesses an additional advantage 

of a local product market. Two significant disadvantages of well site chemical production are 

lack of economy of scale and decreasing utilization because of production decline over the life of 

a well. The production processes with the best opportunity for economic success at the well site 

are simple processes, such as NGL collection or processes that manufacture products for which a 

local market exists and are suited for downsizing to small scales, such as novel fertilizer 

production technologies or innovative gas-to-liquid approaches that can capitalize on the price 

difference between gas and liquid transportation fuels. All such processes would benefit by being 

mobile to periodically relocate to better-producing wells and avoid reduced utilization rates. 

North Dakota’s NGL production is forecast to be adequate to support NGL-based chemical 

manufacturing. Based on the generic raw NG composition that was presented earlier in this 

report and at the 600,000-Mcfd raw NG production level, adequate ethane and propane 

(120,000 bpd) could be produced to support two world-scale crackers. At 900,000 Mscfd, three 

world-scale crackers could potentially be supported. If constructed, it is likely that 

polymerization or chemical plants would also be constructed to convert the output into plastics 

and chemicals. Such construction, however, would be contrary to the petrochemical industry’s 

proclivity to build processing facilities on and transmit feedstock to the USGC. 

A construction decision in North Dakota would benefit from many factors discussed 

previously, including large geologic storage, downstream processing capacity, transportation 

routes for products, and supporting infrastructure. Currently, much of the needed infrastructure 

does not exist, and as such, pipeline and rail export to existing industry hubs has been the 

standard practice. A chemicals industry could develop in North Dakota that could use pipeline 

NG feed to produce chemicals of regional interest or produce niche NGL-based chemicals, but it 

is unlikely that investment for a conventional petrochemicals industry could be attracted unless 

profound improvements were made to resolve critical issues. 

Conceptual Chemical Production in North Dakota 

Chemical production near well sites has distinct benefits and disadvantages. Benefits 

include access to NG that would otherwise be flared, which could provide an economic 

advantage of cheaper NG feedstock and an environmental benefit of avoiding flaring, and 

production of chemicals that can be used locally, such as ammonia and motor fuel, which 

reduces costs and safety risks associated with long-distance transport. A major disadvantage is 

the greater unit cost of producing at smaller scales. The following considers production of 

ammonia and FT motor fuel from NG that would otherwise be flared at Bakken well sites. 

Of the Bakken wells that flared in December 2011, the largest two flared more than 

2000 Mcfd and the median flared about 320 Mcfd. Economy of scale drives toward constructing 

and gathering from the largest producing sites. However, NG production characteristically 

declines over time which would result in underutilization of the equipment if the plant was 
88 

designed to capture at initial production rates. This effect and that of varying NG price are 

depicted in Table 47, which shows estimated capital and operating costs for ammonia production 

based on a design described in Appendix B. The NG feed is assumed to be that of the rich gas 

composition discussed earlier in this report. 

Table 47. Ammonia Production Cost Estimate at Different Scales and Rates

 Large Unit/Large 

Flow 

Large Unit/Small 

Flow 

Small Unit/Small 

Flow 

NG Feed Rate, Mscfd 2000 320 320 

Capacity, ton/day 90.1 90.1 14.4 

Production, ton/year 31,227 4,996 4,996 

Utilization Rate, % 95 15 95 

Existing Technology 

Fixed Capital Investment, $ 52,389,617 52,389,617 17,385,099 

Product Cost ($0 rich gas), 

 $/ton 

305.71 1288.91 517.56 

Product Cost ($4 rich gas), 

 $/ton 

395.71 1378.91 607.56 

Product Cost ($8 rich gas), 

 $/ton 

485.71 1468.91 697.56 

The wellhead prices represent those if flared gas were free, if it were sold at EIA’s forecast 

price for the 2015–2020 period, and if it were sold near the peak price in 2005. 

While the above data were intended to be realistic, it is likely that they are optimistic, 

which is characteristic of early-stage cost estimates. Despite this, several observations may be 

made from the data: 

 Economy of scale is evident as the larger flow achieves lower production cost. 

 No ROI assumed. 

 The deleterious effect of underutilization is evident as the capital cost of an oversized 

unit substantially increases the unit production cost; underutilization, of course, can 

occur even if the unit is not oversized because of downtime or loss of the unit before the 

end of its 20-year depreciated life. 

 NG price can significantly impact production cost. 

 General expenses (sales, administrative, research and engineering) at the 1% of sales 

level have little impact on product cost. 

 While large-scale units are routinely constructed and operated, units at this scale are not 

routinely manufactured or operated so should be considered developmental items. 
89 

When compared to production rates of industrial ammonia plants, which have grown from 

about 200 tons/day in the 1950s to 2200 tons/day in design in 2002, well site units are miniscule 

and disadvantaged. Novel technologies, such as H2Gen’s compact reformer, may provide a way 

to reduce capital cost from smaller-scale systems and reduce this handicap. The size and 

complexity of a plant at even the 14-ton/day scale is too large to be considered portable—

moving such a plant would be possible, but expensive and time consuming. 

The U.S. Department of Agriculture Economic Research Service has reported that average 

U.S. farm prices for anhydrous ammonia have risen from $250/ton 10 years ago to $783/ton in 

March 2012. The above analysis indicates that a 10% before-tax return on investment is possible, 

even at a 320-Mcfd feed rate, with appropriate technology, and low NG feedstock and general 

expenses. It should be noted, however, that in 2008, ammonia prices were at $755/ton but fell to 

$499/ton 2 years later, which likely would result in a negative return on investment for a small 

unit. These economics could be favorably impacted if fines were imposed on flaring and 

producers would pay a charge to dispose of the NG. Ultimately, the economics will have to 

compete with wellhead prices as gas gathering is deployed. 

In addition to ammonia, another product derived from NG that has a local market in the 

Bakken is liquid motor fuel. On an energy basis, NG traditionally is priced less than crude oil, 

recently by as much as one-tenth the price of crude on the spot market. Consequently, the 

opportunity exists for a significant upgrade in value if NG could be converted inexpensively to a 

petroleum product such as diesel fuel. A process discovered in the 1920s—the FT process—is 

the preferred means of accomplishing this conversion and offers the prospect of providing a 

high-quality, low-sulfur diesel fuel into a region that is experiencing tight supplies. 

Unfortunately, the capital cost associated with FT fuels production is high even at very large 

scale. Currently, there are five gas-to-liquids (GTL) plants in the world: 

 Shell’s $1 billion 14,700-bpd Bintulu (Malaysia) facility 

 Sasol’s $250 million 10,000-bpd GTL Mossgas (South Africa) plant (the low capital 

cost of the plant likely is due in part to its location within a larger coal-to-liquids facility 

with which it can share resources.) 

 Sasol’s $1 billion 34,000-bpd Oryx (Qatar) plant 

 ChevronSasol’s $8 billion 33,000-bpd Escravos (Nigeria) facility 

 Shell’s $19 billion 140,000-bpd GTL and 120,000-bpd NGL Pearl (Qatar) plant 

It should be noted that the Escravos plant is about a decade late and costs five times the 

original estimate. Scaling down such technology to a 320-Mcfd unit would produce about 32 bpd 

of FT liquids and likely be exorbitantly expensive when scaled down. A few companies have 

claimed to be developing novel small-scale technologies that might be applicable. 

Velocys is a microchannel equipment developer that has been working on GTL technology 

for more than a decade. The company has three demonstration units under way: 50-bpd and 
90 

25-gallon/day biomass-to-liquids units in Brazil and Austria, respectively, and a 6-bpd GTL unit 

in Brazil. Heatric (a subsidiary of Meggitt), which is well known for its compact heat exchangers 

used on oil platforms, claims to have developed hydrogen reactors and studied GTL. 

CompactGTL, a relatively new microchannel equipment developer, is developing equipment 

especially for associated gas and is currently demonstrating a unit in Brazil. Other possible 

developers include IMM, KarlsrubeFZK, Corning Degussa/Evenik, Alfa Laval, and Chart. Some 

developers claim that their units at small scale can be skid-mounted, so they have some mobility. 

Despite this and the possibility that their technologies might be more economical at small scale 

than conventional technologies, their technologies are untested at this time and their economics 

estimates subject to large errors. 

OVERALL STUDY CONCLUSIONS 

This study concludes that of the four alternatives (NGL removal, CNG, power generation, 

and chemical production) investigated as viable end use technologies for using nontraditional 

NG, only two hold near-term promise – NGL removal and distributed power generation. All of 

the technologies, regardless of likelihood of deployment at small scale, have the potential to 

reduce, but not eliminate, the number of flares and the amount of flared associated gas in North 

Dakota (to varying degrees). A summary of all evaluated technologies with their pertinent 

characteristics is provided in Table 48. 

Table 48. Summary of Evaluated Technologies with Qualitative Characteristics

Technology 

Gas Use Range, 

Mcfd 

NGL 

Removal 

Requirement 

Scalability 

to Resource 

Ease of 

Mobility 

Likelihood 

of 

Deployment 

at Small 

Scale 

Power – Grid 

 Support 

1000–1800 Minimal Very 

scalable 

Mobile Very likely 

Power – Local 

 Load 

300–600 Minimal Very 

scalable 

Mobile Very likely 

CNG 41 Mcfd/million 

mile fleet 

Yes Scalable Mobile Possible 

Chemicals >2000 Mcfd No Not scalable Not 

mobile 

Very 

unlikely 

Fertilizer 300–2000 No Scalable Potentially 

mobile 

Possible 

GTL >2000 Mcfd No Scalable Potentially 

mobile 

Possible 

NGL removal will not single-handedly reduce the number of flares, but it will reduce the 

overall quantity of flared gas and will create a viable secondary revenue stream for wells for 
91 

which gathering pipelines have not yet been installed. In fact, several companies are now 

pursuing this business opportunity within the Bakken region. 

Distributed power generation seems to best match the scale of the flared gas resource 

available, and can utilize the flared gas almost as is, with little cleanup necessary. Distributed 

power has the capability to provide grid support and increase reliability in the rural areas of 

North Dakota currently experiencing the highest levels of activity related to oil exploration. 

However, the evaluation of power generation scenarios assumes that adequate electrical 

infrastructure exists to accommodate the additional electricity these systems generate. 

The CNG application could be pursued, but requires extensive gas cleanup and polishing 

activity to achieve the gas quality levels currently demanded by engine providers. The CNG 

application also requires a fleet with some flexibility to follow the flared gas opportunities where 

they exist. More appropriate for CNG application is implementation at existing downstream gas 

supply for fleets of sufficient size to achieve significant financial benefit. 

Finally, the chemical production application holds the least promise of any applications 

investigated. This has much to do with supply chain logistics, and lack of demand for producible 

products in the upper Midwest. Chemical production tends to be tightly centered in 

petrochemical hubs, where all inputs are readily available, and a nearby pipeline for products is 

readily available. With that said, the production of nitrogen-based fertilizers (a subset of 

chemicals) may hold some promise at small scale. 

ACKNOWLEDGMENTS 

The EERC would like to acknowledge the contributions of the following organizations and 

individuals who provided information, data, and technical support: 

 Altech-Eco Corp. – Cassie Badillo 

 Aux Sable – Jim Asbury 

 BAF/Clean Energy – Brent Pope 

 Bakken Express, LLC – Tim Maloney 

 Basin Electric Power Cooperative – Dave Raatz and Jay Lundstrom 

 CHS, Inc. – Carl Younce 

 Clean Energy – Michael Eaves 

 Cummins NPower – Randy Phelps 

 Cummins Power Generation – Peter Schroeck 

 Dew Point Control, LLC – Myron Goforth 

 Dresser-Rand – Norman Price 

 Enbridge – Kelly Wilkins 

 Energy Engineering, Inc. – Ron Rebenitsch 

 GE Energy – Mike Farina 

 Hess Corporation – Cary Longie and Myles Dittus 

 Horizon Power Systems – Bryan Hensley and Bo Hensley 
92 

 IMW/Clean Energy – Chris Damiani 

 Landi Renzo USA – Marco Genova 

 Linde LLC – Krish Krishnamurthy, Bryan Luftglass, and John Wei 

 Montana–Dakota Utilities Co. – Andrea Stomberg 

 North Dakota Association of Rural Electric Cooperatives – Harlan Fuglesten 

 North Dakota Industrial Commission/Oil & Gas Research Council – Bruce Hicks and 

Jim Lindholm 

 North Dakota Pipeline Authority – Justin Kringstad 

 Saddle Butte Pipeline, LLC – Shawn Rost 

 Westport Innovations, Inc. – Stephen Ptucha, Tahra Jutt, and Jonathan Burke 

REFERENCES 

Alliance Pipeline LP. System map. www.alliance-pipeline.com/contentfiles/ 

27_receiptdeliverymap_DeliveryMap_andersk_20041213_v1.PDF (accessed June 2012). 

Alternative Fuels and Advanced Vehicles Data Center. Natural Gas Fueling Station Locations. 

www.afdc.energy.gov/afdc/fuels/natural_gas_locations.html (accessed June 2012). 

Bohrer, M.; Fried, S.; Helms, L.; Hicks, B.; Juenker, B.; McCusker, D.; Anderson, F.; LeFever, 

J.; Murphy, E.; Nordeng, S. Bakken Formation Resource Study Project; North Dakota 

Department of Mineral Resources Report; 2008; 23 p. 

California Code of Regulations, Title 13 (Motor Vehicles), Division 3 (Air Resources Board), 

Chapter 5 (Standards for Motor Vehicle Fuels), Article 3 (Specifications for Alternative 

Motor Vehicle Fuels). 

Damiani, C. Business Development Manager, IMW Industries, Chilliwak, BC, Canada, personal 

communication. 

Ghosh, T.K.; Prelas, M.A. Energy Resources and Systems, Volume 1: Fundamentals and NonRenewable Resources; Springer Science + Business B.V., 2009; ISBN 978-481-2382-7. 

Goldstein, L.; Hedman, B.; Knowles, D.; Freedman, S.I.; Woods, R.; Schweizer, T. Gas-Fired 

Distributed Energy Resource Technology Characterizations; Report for National Renewable 

Energy Laboratory Contract No. DE-AC36-99-GO10337; NREL/TP-620-34783; National 

Renewable Energy Laboratory: Golden, CO, Nov 2003. 

Huffmaster, M.A. Gas Dehydration Fundamentals. Presented at the Laurance Reid Gas 

Conditioning Conference, 2004. 

Johnson, C. Business Case for Compressed Natural Gas in Municipal Fleets; Report for 

National Renewable Energy Laboratory; NREL/TP-7A2-47919; June 2010. 
93 

Johnson, C., Natural Gas Vehicles, Fueling Infrastructure, and Economics; National Renewable 

Energy Laboratory; March 2011. 

Lippe, D. Trends in Retail Propane Demand and the Impact on Market Balances in North 

America. Presented at the Platts NGL Forum, Houston, TX, Sept 26–27, 2011. 

Liss, W.E.; Thrasher, W.R. Variability of Natural Gas Composition in Select Major 

Metropolitan Areas of the U.S.; Gas Research Institute Report GRI-92/0123, 1992. 

NGV Journal. Gas Vehicle Report, April 2012. www.ngvjournal.dreamhosters. 

com/en/statistics/item/911-worldwide-ngv-statistics. (accessed June 2012). 

North Dakota Department of Mineral Resources Oil and Gas Division. North Dakota Surpasses 

Half a Million Barrels of Oil per Day. Press Release, Jan 10, 2012. 

North Dakota Pipeline Authority. Annual Report; July 1, 2010 – June 30, 2011a; pp. 26. 

North Dakota Pipeline Authority. North Dakota Petroleum Council Annual Meeting, Sept 21, 

2011, pp. 47. 

Pace Global Energy Services. Williston Basin Oil Development Power Load Forecast Study; 

Report for Basin Electric Power Cooperative, July 2007. 

Persily, L. Office of the Federal Coordinator for Alaska Natural Gas Transportation Projects, 

May 7, 2012. www.arcticgas.gov/2012/gas-flaring-increases-worldwide-almost-5-tcf-2011 

(accessed June 2012). 

Peterson, G.W.; Rossin, J.A. Impregnated Metal-Organic Frameworks for the Removal of Toxic 

Industrial Chemicals, ECBC-TR-660, Nov 2008. 

Sanati, C. The Biggest Winners of Obama’s Natural Gas Push, FORTUNE magazine, 

http://finance.fortune.cnn.com/2012/01/27/the-biggest-winners-of-obamas-natural-gas-push/ 

(accessed June 2012). 

U.S. Energy Information Administration. U.S. EIA’s Alternatives to Traditional Transportation 

Fuels, Table V1. www.eia.gov/renewable/ (accessed June 2012a). 

U.S. Energy Information Administration. www.eia.gov/cneaf/electricit/epa/existing_ 

capacity_state.xls (accessed Jan 2011). 

U.S. Energy Information Administration. www.eia.gov/dnav/ng/ng_prod_sum_dcu_NUS_m.htm 

(accessed Jan 2012b). 

U.S. Energy Information Administration. Natural Gas Processing: The Crucial Link Between 

Natural Gas Production and Its Transportation to Market; Special Report; Office of Oil and 
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Gas; Jan 2006; www.eia.gov/pub/oil_gas/natural_gas/feature_articles/2005/ngprocess/ 

ngprocess.pdf (accessed July 2012). 

Watt, G.M. Natural Gas Vehicle Transit Bus Fleets: The Current International Experience, 

International Association for Gas Vehicles Review Paper. www.Jangv.org/ 

htm/sources/reports/iangv_bus-rcport.pdf (accessed June 2012). 

World Bank. International Experience with CNG Vehicles; World Bank Technical Paper No. 

24062, Oct 2001. 

Willis, R. Carbon Dioxide Removal from Flue Gas Using Microporous Metal Organic 

Frameworks; Final Technical Report for U.S. Department of Energy National Energy 

Technology Laboratory, Oct 2010. 

Ybarra, S. The Life-Cycle Cost Advantage of NGVs in Delivery Fleet Applications. U.S. 

Department of Energy Clean Cities Program Webcast, July 2007. 
APPENDIX A 

OVERVIEW OF PETROCHEMICAL INDUSTRY 

INFRASTRUCTURE 
A-1 

OVERVIEW OF PETROCHEMICAL INDUSTRY INFRASTRUCTURE 

ECONOMIC CONDITIONS 

The global economic downturn of 2008–2009 reduced natural gas liquid (NGL) 

consumption during that period, the extent of which varied by region. As Table A-1 depicts, U.S. 

ethylene production peaked in 2007; whereas, Taiwan and China ethylene production fell 

slightly in 2008 but recovered and set records the following two years. In that environment, 

expansion of ethylene production was moving away from the United States toward areas of 

increasing demand such as the Far East and areas possessing feedstock advantages, such as the 

Middle East. 

Underlying the Middle East feedstock advantage was the perception that the United States 

would increasingly import NG. In 2006, North America (excluding Puerto Rico) had five 

operating liquefied NG (LNG) import terminals, with 17 more approved and 25 awaiting 

approval. At that time, there was only one export terminal in Kenai, Alaska, which has since 

been shutdown. Expectation of such importing implied expectations of limited domestic NG 

production increases and associated NGL production increases, as well as higher prices for both. 

Even with increased NG flow into the United States in the form of LNG, since LNG is generally 

more than 92% methane, NGL processing expansion opportunity was limited. 

Table A-2 portrays the difficulties that NG and NGL markets faced in the early to middle 

portion of the 2000s. NG prices were relatively high compared to those of its products and 

competition. Industrial NG prices averaged $4–$6/Mcf in 2002–2003, but increased to $7–

$9/Mcf in 2005–2006, and were headed higher. Additionally, NG price was about two-thirds of 

petroleum on an energy basis and the frac spread (i.e., the price of the fractionated products over 

the cost of the feedstock) was about $1/MMBtu. 

Exemplifying these economic conditions, production capacity was static or declining in the 

United States. In the case of NG-based chemicals, such as ammonia and methanol, production 

decreased by 41% and 89%, respectively, during the period 2000–2007. In the case of NGL 

derivatives, Chemical & Engineering News reported that, during the 2000s, U.S. petrochemical 

executives expected that “. . .investment of capital in domestic petrochemical plants would be 

limited mostly to maintenance.” 

Table A-1. Annual Ethylene Production Rates Compared to 2007 Base Year 

(American Chemical Society, 2011) 

 2007, metric 

tonnes/year 

2008 Rate, 

% 

2009 Rate, 

% 

2010 Rate, 

% 

United States 25,412 −11 −11 −6 

Taiwan 3666 −1 5 7 

China 10,477 −2 2 35 
A-2 

Table A-2. U.S. NG and NGL Market Comparison over Time 

 Early–Mid-2000s 2011 

Industrial NG Prices, direction $7.82/Mcf (up) (2006) $5.02/Mcf (down) 

Relative Value of NG to Crude 60%–65% (2003) 30%–35% 

Frac Spread $1/MMBtu (2002) $6–$8/MMBtu 

Direction of NG Movement Importer Exporter 

Direction of Olefin Production Contracting Expanding 

This situation changed dramatically during the 2000s as advances in drilling horizontal 

well bores and hydraulic fracturing made petroleum trapped in shale formations economically 

accessible. The increased U.S. NG production due to these methods has profoundly reduced the 

price of NG and associated liquids, especially relative to its crude oil-based competition, at a 

time when NGL-derived products have maintained their value. The effect is expanded 

investment in NG and NGL infrastructure in the United States and the potential reversal in 

direction of trade from increasing LNG imports to expanding LNG exports. Thus, while today 

there are 12 operating LNG import terminals in the United States (plus one in Puerto Rico), three 

of those are now approved to export LNG, with at least one additional pursuing approval to 

export. 

Extracting maximum return from a resource such as NG requires an efficient supply chain; 

inadequacies or inefficiencies in distribution or production systems reduce the value of the 

resource. The term “stranded” has been coined to describe extreme cases where valuable 

resources are inaccessible or transportation cost-excessive. Thus the value of resources depends 

upon the efficiency of their supply chains. 

Major determinants of the efficiency of chemical processes are the scalability of the 

process, installing the maximum size and operating near capacity – that is to say, design, install, 

and operate to maximize economy of scale. Major determinants of efficient storage and 

transportation are to use the cheapest storage technologies and locations, to minimize 

transportation distances, to use the cheapest transportation modes, and to operate near capacity. 

Other factors would be to take maximum advantage of synergies with existing facilities and to 

integrate multiple steps. In practice, 60% of U.S. ammonia production capacity is located in 

Louisiana, Oklahoma, and Texas because of proximity to NG feedstock. In the case of 

polyethylene plastic, more than 95% of ethane-cracking (ethylene production) capacity is in 

Louisiana and Texas, again in part because of proximity to petroleum and NGL feedstock. In 

2004, petroleum comprised about 55% of the ethylene feedstock. 

Recently, however, with the cash cost of making ethylene from ethane at 18 cents/pound 

and from light naphtha at 46.5 cents/pound, ethane makes up 70% of ethylene production. The 

appearance of substantial production from the Marcellus and Bakken Formations has had 

relatively little influence on plans for constructing future facilities in those areas as only one of 

five petrochemical companies that have announced plans to construct major new petrochemical 

complexes have decided to locate outside of Louisiana and Texas. Only Shell has announced 

construction outside of the U.S. Gulf Coast (USGC), recently selecting Pennsylvania for a new 

facility. 
A-3 

Shell’s decision came under criticism by participants at a September 2011 Platts-sponsored 

NGL Forum for various reasons, such as disposition of feed when the facility is processing at 

reduced rates. Feed can go to storage at Henry Hub or to the many other nearby petrochemical 

complexes if one USGC complex cannot accept feed – without such infrastructure around it, 

where will Shell send its feed? To take advantage of its proximity to northeastern customers, 

Shell also is considering constructing a polyethylene plant with the cracker; otherwise, it would 

have to transport its ethylene to a polymer plant. 

This would not be necessary on the USGC, since polyethylene plants and infrastructure 

already exist there. The decision could also be considered risky during periods that West Texas 

Intermediate (WTI) petroleum prices fall relative to NGLs: in situations when refinery feedstock 

is cheaper than NGLs, the USGC is advantaged because 1) it has many more refineries than the 

East Coast (45% of which are for sale or shutting down) and 2) recently its WTI feedstock has 

been cheaper than the Brent crude oil processed by East Coast refineries. 

Existing Infrastructure 

There are relatively few NGL pipelines as compared to NG and crude oil pipelines in the 

United States. With the exception of a couple of pipelines extending from Texas to New York 

and Texas to North Carolina, locations of North American component pipelines tend to reside 

within a “V” emanating from Texas northwestward to Alberta and from Texas northeastward to 

eastern Ontario, with the highest concentration lying between Kansas and the Texas Gulf Coast, 

as indicated by the PennWell LPG and NGL and Phillips 66 propane pipeline system maps 

shown in Figures A-1 and A-2. 

Enterprise Products Partners LLP owns or has interest in 15,600 miles of mixed NGL 

pipelines, 160 million barrels of usable storage capacity, and 619 thousand barrels per day of 

fractionation capacity in the central part of the United States, as shown in Figure A-3. The far 

eastern line is a propane pipeline that has not been included in the cumulative pipeline distance. 

Additionally, Enterprise Products operates a number of NGL storage facilities described in 

Table A-3 and NGL fractionation facilities described in Table A-4. 

Phillips 66 conducts its Midstream business primarily through a joint venture, Dakota 

Catalyst Products, Inc., Midstream LLC. DCP Midstream’s assets include 62,000 miles of 

pipelines, 61 gas-processing plants and 12 NGL fractionators. In 2010, DCP Midstream 

extracted 193 thousand barrels per day (Mbpd) of NGLs through fractionators in Mt. Belvieu, 

Texas (50 Mbpd), Conway, Kansas (43 Mbpd), and Gallup, NM (26 Mbpd), as well as other 

assets in Trinidad, the Caribbean, and Central America. Phillips 66 (previously the midstream 

and downstream segments of ConocoPhillips) also owns substantial pipeline assets, as indicated 

in Figure A-4. 

The Cochin (Dome) pipeline system (Figure A-5) is a 1900-mile, 12-inch-diameter 

multiproduct pipeline owned by Kinder–Morgan operating between Fort Saskatchewan, Alberta, 

and Windsor, Ontario, including five terminals. Operating on a batched basis, the system has an 
Figure A-1. Penn

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A-7 

estimated capacity of about 70,000 barrels per day and has five U.S. propane terminals. In 2007, 

the pipeline had filed tariff agreements with Federal Energy Regulatory Commission C for the 

following products between the indicated points: 

 Light hydrocarbon liquids between Fort Saskatchewan, Alberta, and Windsor, Ontario 

 Ethane and ethane–propane mix between points in Iowa and in Michigan 

 NGLs between Maxbass, North Dakota, and Detroit, Michigan 

 Ethylene between Maxbass, North Dakota, and delivery points in Iowa and Michigan 

 Ethane and propane between Cochin East, Iowa, and MAPCO near Iowa City, Iowa 

 NGLs between Maxbass, North Dakota, and Detroit, Michigan 

 Propane between points in North Dakota, Minnesota, and Iowa, and delivery points in 

North Dakota, Minnesota, Iowa, Indiana, and Michigan 

 Ethane between Maxbass, North Dakota, and delivery points in Iowa and Michigan 

 Field-grade butane between Maxbass, North Dakota, and Detroit, Michigan (reference 

to Maxbass and Detroit refers to the international boundary near those locations). 

Currently, pipeline operations only involve propane. In June 2010, Kinder–Morgan 

announced a nonbinding open season to add a lateral segment to Clarington, Ohio, to transport 

Marcellus Shale Y-grade NGLs. Enterprise Products, Phillips 66, the Cochin (Dome) pipelines, 

and the Buckeye NGL pipeline (Figure A-6) comprise the majority of U.S. mixed NGL 

pipelines. 

As shown in Figure A-7, Dow Chemical Company operates 3000 miles of product 

pipelines along the USGC. This system transports both liquid and gas products, with the vast 

majority of products being hydrocarbons that include NG, ethylene, propylene, propane, ethane, 

and ethane–propane mix. 

Future Expansion Infrastructure 

In response to recent market conditions, U.S. petrochemical companies are moving 

forward on expanding ethane-cracking capacity in the United States. The shale boom in North 

America has reversed the course of petrochemical companies which are switching feeds from 

naphtha to NGLs, unshuttering dormant facilities, modifying naphtha crackers to accept NGLs, 

and studying—if not beginning front-end engineering design of—new, multibillion-dollar 

complexes. In November, 2011, Bentek estimated that overall in the United States, the 17 

fractionation addition and expansion projects that have been announced will increase 

fractionation capacity by 27% (835 Mbpd) by the end of 2016. This forecast likely did not 
Figur

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A-9 

include MarkWest Energy Partners’ February 2012 announcement of 140 Mbpd of additional 

fractionation in the Marcellus region. Additionally, Bentek reported that 12 new and expanded 

NGL pipelines will add 1800 Mbpd of capacity through 2014. Two expansions transport NGLs 

to the Conway area, while the remainder move NGLs to Mt. Belvieu. 

During the period 2011–2017, Williams estimates Marcellus production of ethane, 

propane, butanes, and NG will increase more than 185, 70, 30, and 20 Mbpd, respectively. For 

its size, the Marcellus is particularly underdeveloped: lacking processing, pipelines, 

fractionation, and other infrastructure. In response, Caiman Energy has announced projects in 

two locations that will install 720 MMcfd of gas-processing and 42.5 Mbpd of fractionation 

capacity within the next few years, and MarkWest is adding 1100 MMcfd gas-processing and 

115 Mbpd of deethanizing fractionation capacity. 

In North Dakota infrastructure expansion includes the Vantage ethane pipeline to Alberta 

and a rich gas line from the Tioga gas-processing plant to the Alliance Pipeline, which will 

permit some NGLs to travel with NG to fractionators in Illinois. Purvin & Gertz, the North 

Dakota Department of Mineral Resources and Vantage have projected North Dakota ethane 

supply to peak in the 2014–2020 time frame between 40 and 115 Mbpd, so the pipeline was 

designed to transport 40 Mbpd (60 Mbpd with additional pumping) of ethane to Alberta. Toll 

charges for the approximately 430-mile trip from Tioga, North Dakota, to Empress, Alberta, are 

to be 8.68 cpg the first year. OneOK’s 60 Mbpd (110 Mbpd with additional pumping) Bakken 

Extension to the Overland Pass Pipeline that goes south from North Dakota to Bushton (KS), 

near Conway, relies upon the expansion of Kansas fractionators and pipelines to Mt. Belvieu to 

minimize the Kansas and North Dakota discounts. 

In Kansas, ONEOK is increasing fractionation capacity in Bushton to match the additional 

60 Mbpd to be received on the Overland Pass Pipeline. 

Figure A-8 displays existing pipelines and summarizes expansions announced prior to 

September 2011. 

Figure A-9 indicates that Mt. Belvieu, for example, will need to more than double its 2009 

fractionation capacity to be able to fractionate its additional NGL imports. 

Five world-class plants are planned or are being constructed in the United States: 

 ChevronPhillips Chemical Company 1.5-million-tpy cracker outside of Houston and 

polyethylene plant near its Sweeny, Texas, cracker 

 Dow Chemical ethylene and 0.75-million-tpy propylene units in Freeport, Texas 

 Sasol 1.4-million-tpy cracker in Lake Charles, Louisiana 

 Formosa Plastics 0.8-million-tpy ethylene cracker, 0.6-million-tpy propane 

dehydrogenation unit, and a linear low-density polyethylene plant in Point Comfort, 

Texas 
F

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GL supply 

. NGL pipel

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A-10 

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el, 2011). 
A-11 

 Shell ethane cracker, as well as polyethylene and monoethylene glycol chemical 

facilities in near Monaca, Pennsylvania 

In addition to these, other companies are unshuttering or have suggested constructing or 

expanding cracking facilities: 

 Dow is restarting a cracker near Hahnville, Louisiana. 

 Occidental Petroleum in Ingleside, Texas, where it makes vinyl chloride. 

 Either Chemicals is considering building an ethane catalytic cracker near Charleston, 

West Virginia. 

 LyondellBasell is studying expansion equivalent to a half-cracker at an existing facility. 

In reflecting on these announcements, industry and media have commented that not all 

announced facilities will be constructed and not in the announced time frames. The 

petrochemical industry has tended to overconstruct, resulting in excess capacity, and has viewed 

shale skeptically (although developing confidence with time). While most capacity should be 

installed in the 2015–2017 time frame, construction pace might be adjusted with infrastructure 

rollout and feed availability. 

Shell’s Appalachian facility, constructed away from the USGC infrastructure, has drawn 

attention. Factors favoring the plan include: 

 Proximity to the Marcellus supply. 

 Location within 400 miles of almost half of U.S. plastics converters who would benefit 

by having faster delivery and less inventory requirements. 

 Lower ethane feedstock cost because of lack of infrastructure to transport ethane out of 

the region. 

 Potential underground ethane storage (as indicated by the presence of underground NG 

storage in the Appalachian region shown in Figure A-10). 

Factors that could work against Shell’s proposal include: 

 Lack of infrastructure (although Shell representatives have said that there is a solution 

to the lack of infrastructure issue). 

 Lower feedstock price, which will be temporary as infrastructure appears. 


Th

cracker g

suppliers

comment

REFERE

American

Engin

Braziel, E

NGL

ConocoP

2012

Dow Che

Enterpris

Fi

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goes down: 

s will contin

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ENCES 

n Chemical

neering New

E.R. NGL In

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Phillips. http

). 

emical Comp

se Products. 

igure A-10. U

facili

ement to b

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urrent questio

without an

nue to prod

dia is that on

l Society. F

ws 2011, July

nfrastructure

ept 26, 2011.

://ngl.conoc

pany. Dow.C

EnterprisePr

U.S. lower 4

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build local 

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A-12 

48 states’ un

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polyethylen

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rences appea

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Figures of 

Constraints;

m/EN/propa

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ges/index.asp

July (2012) 

July 2012). 

vantage of 

position whe

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d to? A com

ry. Chemica

Surpluses. P

px (accessed

local 

en the 

since 

mmon 

al & 

Platts 

d July 
A-13 

Kinder–Morgan Cochin ULC. Notice of Open Season for the Marcellus Lateral Project, June 14, 

2010. 

Penwell. www.pennwellbooks.com/lppipadnfacm.html (accessed July 2012). 

Rextag Strategies. www.rextagstrategies.com/downloads (accessed June 2012). 

U.S. Energy Information Administration. Annual Underground Gas Storage Report. 
APPENDIX B 

DISTRIBUTED-SCALE AMMONIA PLANT 

PRELIMINARY DESIGN 
B-1 

DISTRIBUTED-SCALE AMMONIA PLANT PRELIMINARY DESIGN 

DESIGN APPROACH 

As part of a project to develop a basic engineering design package for a 20-ton/day 

ammonia production plant based on the use of natural gas feedstock, the Energy & 

Environmental Research Center developed a preliminary plant design comprising the primary 

unit operations (unit ops) of: 

 Feedstock gas cleanup to the extent required to yield a methane-rich gas suitable to 

undergo catalytic steam reforming. 

 Catalytic steam reforming of methane-rich gas to yield a syngas comprising primarily 

hydrogen, carbon monoxide, carbon dioxide, and water, followed by hydrogen 

separation from the syngas to yield a hydrogen stream with a purity level of at least 

99.99%. 

 Separation of nitrogen from air to yield a nitrogen stream with a purity level of at least 

99.99%. 

 Ammonia synthesis via reacting high-purity hydrogen with air-extracted nitrogen in a 

reactor system equipped with capabilities for ammonia recovery, recycle of unreacted 

hydrogen and nitrogen, and purge of inert materials. 

This design was the basis for ammonia production cost estimates presented previously. 

Following is a description of the ammonia process, after which tables containing individual 

equipment costs and tables containing detailed product cost breakdowns appear. 

Figure B-1 illustrates the ammonia production pathway and key process inputs, along with 

optional modules for on-site electricity production and conversion of ammonia to urea. The 

overall natural gas-to-ammonia process was conceptualized and simulated with Aspen Plus 

modeling software. The simulation encompassed separation of raw gas-contained methane from 

impurities such as sulfur compounds and carbon dioxide, reforming methane into hydrogen, 

nitrogen separation from air, and reaction of hydrogen and nitrogen to form ammonia. The basic 

process flow diagram developed from the Aspen Plus model is shown in Figure B-2. The model 

was optimized based on an input of 39,000 standard cubic feet/hour (scfh) of raw gas with a 

composition of 52% methane, 36% carbon dioxide, and the remainder being nitrogen, oxygen, 

and trace amounts of sulfur compounds. About 350 gallons/hour of water is consumed during 

hydrogen production, and 120,000 scfh of air is required for combustion (to provide heat to drive 

the endothermic steam methane reforming [SMR] hydrogen production reaction) and as a source 

of nitrogen. Approximately 1 megawatt (MW) of electricity is required, most of which is used 

for gas compression. 

To enable the quickest path to plant fabrication, the basic engineering plant design effort 

incorporated—to the extent possible—commercially available technologies as primary unit ops. 
Based on

prepared 

purificati

recovery

from qua

purificati

an appro

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vendors 

bids, pre

and deliv

selected. 

Ga

Ga

sulfur co

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carbon d

operation

approxim

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unit oper

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compress

Figure B-1. 

n input and 

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were receiv

eferred vend

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Description

as Cleanup

as cleanup in

ntamination

ected gas cle

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ns, the raw

mately 86% o

to approxim

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sion.

20-ton/day a

output requ

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ogen separat

unreacted hy

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ic engineerin

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w gas is co

of the raw g

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be combus

ammonia pro

uirements for

technologie

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eceived for 

ation units. B

ia synthesis 

ng design p

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nologies/ven

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f sulfur and 

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gas-contained

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hane (along w

sted for heat

B-2 

oduction pla

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es for 1) ga

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nitrogen, an

supplying 

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ackage for t

bid request. A

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zes a pressu

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d methane a

of methane 

with a large 

t. About 20

ant working 

day ammoni

as cleanup, 2

ammonia syn

nd purge of i

gas cleanup

viable quotes

d solicitation

the unit. Tw

After review

oted prices, p

utilized in the

rovided as fo

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maximum-e

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efficiency SM

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SMR (hydro

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diagram. 

ote requests 

n production

cluding amm

als. Viable q

n production

ved for supp

pared and le

ds from qua

eived quotes

e representat

plant design 

to ensure ag

MR perform

PSA) proces

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required fo

were 

n and 

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quotes 

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et for 

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gainst 

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outed 

or gas 
B-3 

Figure B-2. Aspen Plus-developed basic process flow diagram for 20-ton/day ammonia (35-ton/day urea) p
Hy

Th

the meth

the meth

water–ga

used to s

level of 

556 lb/ho

required 

for suppl

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1373 lb/h

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separate the h

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mmonia Syn

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hown in Fig

Approximate 

d Purificati

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from the 77

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B-3 shows a

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m air using a 

rity level of 

and nitroge

monia synth

nce in desig

gure B-4 is 

300-lb/hour

B-4 

ion

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te gas. Abou

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monia plant.

PSA unit. T

99.96%. Ab

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r SMR hydro

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ng designed 

monia produ

he hydrogen

ation unit.

on of 

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ts are 

purity 

About 

air is 

quired 

about 

ed for 

units, 

by a 

uction 

n and 
B-5 

Figure B-4. Aspen Plus model of ammonia synthesis unit operation.
B-6 

nitrogen streams will undergo compression to approximately 100 bar and then will be combined 

in a catalytic ammonia reactor. The produced ammonia will be condensed and separated from the 

unconverted gases, which are recycled back to the reactor. Near 100% conversion of hydrogen 

and nitrogen is achieved and 1710 lb/hour (equating to about 20 tons per day) of ammonia is 

produced. About 304 kW of electricity is required for gas compression. The ammonia product 

can be stored for sale or converted to urea. For urea production, exhaust carbon dioxide from the 

SMR (hydrogen production) unit is purified and reacted with ammonia to produce urea. About 

2089 lb/hour of carbon dioxide is required to react with the 1710 lb/hour of ammonia to yield 

2850 lb/hour (equating to about 35 tons/day) of urea. 

Capital Cost Estimate

Using the quotes received from vendors for selected unit operations and smaller equipment 

pieces and ancillary plant requirements, a cost estimate for fabrication of a 20-ton/day natural 

gas-to-ammonia plant was prepared. As shown in Table B-1, the total estimated capital cost of 

the plant is $16.5 million. Also as shown in the table, the total cost estimate includes a 

$2.5 million used hydrogen production unit. The unit comes with a guarantee, and it is 

worthwhile to note that several small-scale good-condition SMR units are available from 

vegetable oil refiners that are facing reduced demand for hydrogenated vegetable oil and no 

longer need on-site hydrogen production capability. 

Using this 20-ton/day design and cost estimate as the basis, an analysis was performed to 

evaluate the economics of ammonia production for three scenarios: 

Table B-1. 20-tons/day Ammonia Plant Preliminary Capital Cost Estimate 

Cost Item 

Cost 

Estimate, 

$million Notes 

Gas Cleanup 3.61 Includes $500K assembly cost 

Hydrogen Production/Purification 2.52 Used unit; includes $500K assembly cost 

Reverse Osmosis Water Cleanup 0.1 

Nitrogen Generation 1.4 Includes $300K assembly cost 

Ammonia Synthesis Loop 2.5 Preliminary cost estimate 

Hydrogen Compressor 1.5 

Nitrogen Compressor 0.5 

Control System 0.1 

Ammonia Storage3

 and Loadout 1.1 

Detailed Engineering 1.3 

Site Preparation 0.5 Estimate; need site-specific information 

Assembly 0.5 

Shakedown 0.5 

Total Installed Cost 16.5 

1 Less expensive unit may be available. 

2 Cost of new unit, including assembly, is $6 million. 

3 7 days worth (140 tons) of storage. 
B-7 

 2000 Mcfd gas flow and a 2000-Mcfd-capacity reactor (90 tpd ammonia) 

 320 Mcfd gas flow and a 2000-Mcfd-capacity reactor (90 tpd ammonia) 

 320 Mcfg gas flow and a 320-Mcfd-capacity reactor (15 tpd ammonia) 

In the absence of an objective basis by which to estimate siting requirements for a compact 

ammonia production unit, no land acquisition costs were incurred in this cost estimate. 

A total capital equipment cost of $6 million was used for the 20-tpd system. Cost estimates 

for the different-sized systems was accomplished by means of correlations using the exponential 

relationship between equipment size and cost: 

Cost2 = Cost1 *(Size2 / Size1)

n

Standard exponents from the technical literature (Towler and Sinnott, 1991) were adopted, 

and a 0.79 exponent was adopted based on literature values. 

Detailed economic data for each of the three scenarios is provided in Tables B-2–B-4. 
B-8 

Table B-2. 2000 Mcfd and Large Reactor Design Applying Current Technology Reformer 

Ammonia Total Product Cost Estimate 

2000 Mcfd and Large Reactor Design 

 Feed Rate: 2000 Mcfd natural gas 

Location: Bakken (2012) Heating value: 1490 Btu/cf natural gas 

Capital Investment Gas Consumption: 36.5 MMBtu/tonne 

 Fixed $51,889,617 Capacity: 81.7 tonne/d ammonia 

 Working 90.1 ton/d ammonia 

 Start-Up $500,000 On Stream: 95% 

Total $52,389,617 Production: 31,249 ton/year ammonia 

 

 

Quantity/ton Price $/unit 

Cost 

 $/year $/ton 

Raw Materials 

 Natural Gas (Feed + Fuel) 22.2 Mcf 0.00 0 0.00 

Utilities 

 Electricity 1200 kWh 0.09 3,374,889 108.00 

 Water 420 gal 0.02 262,491 8.40 

Total Utilities 3,637,380 116.40 

Labor 

 Operating 0.25 Operator/shift 300,000 75,000 2.40 

 Laboratory 10% Operating labor 7500 0.24 

 Maintenance 1.5% Fixed captial 

 Investment (FCI) 

 778,344 24.91 

 Operating Supplies 10% Operating labor 7500 0.24 

Supplies 

 General 0.6% FCI 311,338 9.96 

 Maintenance 1.5% FCI 778,344 24.91 

 Catalyst and Chem. 31,250 1.00 

Direct Production Cost 180.06 

Plant Overhead 20% Total labor 173,669 5.56 

Fixed Charges 

 Insur. and Taxes 2% FCI 1,037,792 33.21 

 Depreciation 5% FCI + start-up 2,619,481 83.83 

Manufacturing Cost 9,457,598 302.65 

Gen. Expen. (Salary 

 Administration Research and 

 Expenses (SARE) 

1% Sales 95,531 3.06 

Total Product Cost 305.71 

Before Tax Return on 

Investment (ROI) 

0% Total investment 0 0.00 

Product Value 9,553,130 305.71 
B-9 

Table B-3. 320 Mcfd and Large Reactor Design Applying Current Technology Reformer 

Ammonia Total Product Cost Estimate 

320 Mcfd and Large Reactor Design 

 Feed Rate: 2000 Mcfd natural gas 

Location: Bakken (2012) Heating value: 1490 Btu/cf natural gas 

Capital Investment Gas Consumption: 36.5 MMBtu/tonne 

 Fixed $51,889,617 Capacity: 81.7 tonne/d ammonia 

 Working 90.1 ton/d ammonia 

 Start-Up $500,000 On stream: 95% 

Total $52,389,617 Production: 31,249 ton/year ammonia 

 

 

Quantity/ton Price $/unit 

Cost 

 $/year $/ton 

Raw Materials 

 Natural Gas (Feed + Fuel) 22.2 Mcf 0.00 0 0.00 

Utilities 

 Electricity 1200 kWh 0.09 539,613 108.00 

 Water 420 gal 0.02 41,970 8.40 

Total Utilities 581,583 116.40 

Labor 

 Operating 0.25 Operator/shift 300,000 75,000 15.01 

 Laboratory 10% Operating labor 7500 1.50 

 Maintenance 1.5% FCI 778,344 155.78 

 Operating Supplies 10% Operating labor 7500 1.50 

Supplies 

 General 0.6% FCI 311,338 62.31 

 Maintenance 1.5% FCI 778,344 155.78 

 Catalyst and Chem. 5000 1.00 

Direct Production Cost 509.29 

Plant Overhead 20% Total labor 173,669 34.76 

Fixed Charges 

 Insur. and Taxes 2% FCI 1,037,792 207.71 

 Depreciation 5% FCI + start-up 2,619,481 524.27 

Manufacturing Cost 6,375,551 1,276.03 

Gen. Expen. (SARE) 1% Sales 64,400 12.89 

Total Product Cost 1288.91 

Before Tax ROI 0% Total investment 0 0.00 

Product Value 6,439,950 1288.91 
B-10 

Table B-4. 2000 Mcfd and Small Reactor Design Applying Current Technology Reformer

Ammonia Total Product Cost Estimate 

320 Mcfd and Small Reactor Design 

 Feed Rate: 320 Mcfd natural gas 

Location: Bakken (2012) Heating value: 1490 Btu/cf natural gas 

Capital Investment Gas Consumption: 36.5 MMBtu/tonne 

 Fixed $16,885,099 Capacity: 13.1 tonne/d ammonia 

 Working 14.4 ton/d ammonia 

 Start Up $500,000 On stream: 95% 

Total $17,385,099 Production: 4996 ton/year ammonia 

 

 

Quantity/ton Price $/unit 

Cost 

 $/year $/ton 

Raw Materials 

 Natural Gas (Feed + Fuel) 22.2 Mcf 0.00 0 0.00 

Utilities 

 Electricity 1200 kWh 0.09 539,611 108.00 

 Water 420 gal 0.02 41,970 8.40 

Total Utilities 581,581 116.40 

Labor 

 Operating 0.25 Operator/shift 300,000 75,000 15.01 

 Laboratory 10% Operating labor 7500 1.50 

 Maintenance 1.5% FCI 223,276 50.69 

 Operating Supplies 10% Operating labor 7500 1.50 

Supplies 

 General 0.6% FCI 101,311 20.28 

 Maintenance 1.5% FCI 253,276 50.69 

 Catalyst and Chem. 5000 1.00 

Direct Production Cost 257.07 

Plant Overhead 20% Total labor 68,655 13.74 

Fixed Charges 

 Insur. and Taxes 2% FCI 337,702 67.59 

 Depreciation 5% FCI + start-up 869,255 173.98 

Manufacturing Cost 2,560,056 512.38 

Gen. Expen. (SARE) 1% Sales 25,859 5.18 

Total Product Cost 517.56 

Before Tax ROI 0% Total investment 0 0.00 

Product Value 2,585,916 517.56 

REFERENCES 

Towler, G.; Sinnott, R. Chemical Engineering Design: Principles, Practice and Economics of 

Plant and Process Design second edition; Elsevier Ltd. 

Peters, M.; and Timmerhaus, K. Plant Design and Economics for Chemical Engineers; fourth 

edition, McGraw-Hill, Inc., 1991.