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# ent o fEERC DISCLAIMER LEGAL NOTICE This research report was prepared by the Energy & Environmental Research Center (EERC), an agency of the Univ ersity of North Dakota, as an account of work sponsored by the U.S. Department of En ergy (DOE) and the North Dakota Industrial Commission (NDIC). Because of the research na ture of the work performed, neither the EERC nor any of its employees makes any warranty, expr ess 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 othe rwise does not necessarily consti tute or imply its endorsement or recommendation by the EERC.

DOE ACKNOWLEDGMENT This report was prepared with the support of DOE Nati onal Energy Technology Laboratory Cooperative Agreement No. DE -FC26-08NT43291. However, any opinions, findings, conclusions, or recommen dations expressed herein are t hose 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 G overnment, 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 re presents 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 n ecessarily constitute or imply its endorsement, recommendation, or favoring by the United States G overnment 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 pursuan t to an agreement pa rtially funded by the Industrial Commission of North Dakota, and neith er the EERC nor any of its subcontractors nor the NDIC nor any person ac ting on behalf of either:
A. Makes any warranty or represen tation, express or implied, with respect to the accuracy, completeness, or usefulness of the information c ontained in this report or that the use of any information, apparatus, method, or process disclosed in this report may not infringe privately owned rights; orB. Assumes any liabilities with re spect to the use of, or for da mages 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 n ecessarily constitute or imply its endorsement, recommendation, or favoring by NDIC. The views a nd 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 Resear ch 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 rapi d increase in oil production. This final report summarizes EERC assessments of distributed end-use opportunities that were evaluated for their potential to contribute to signif icant 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 .......................................................................................................... xi i
INTRODUCTION .................................................................................................................. ........ 1
BACKGROUND ON BAKKEN AS SOCIATED 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, Transpor t, 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 Sm all-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 ..................................................................................................... 5 9 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 – Reciprocati ng Engine Scenario ......................................................... 66 Grid Support – Gas Turbine Scenario ....................................................................... 67 Local Power – Reciprocati ng 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-Ba sed 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 Rele vance in North Dakota ........................................................... 86 Conceptual Chemical Production in North Dakota ............................................................. 87
OVERALL STUDY CONCLUSIONS ......................................................................................... 90
ACKNOWLEDGMENTS ............................................................................................................ 91
REFERENCES .................................................................................................................... ......... 92
OVERVIEW OF PETROCHEMICAL INDUSTR Y INFRASTRUCTURE ................ Appendix A
DISTRIBUTED-SCALE AMMONIA PLANT PRELIMINARY DESIGN ................ Appendix Biv LIST OF FIGURES
1 Geographic extent of the Bakken Form ation 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 Form ation 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 Bakke n 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 we ll 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 ga s for January and December 2011 .................................... 13 14 Number of Bakken wells flaring a ra nge 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 el ectrical transmission ................................................................... 55 31 Flared NG and electrical distribut ion cooperative serv ice 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 s upport – gas turbin e scenario ................................................. 68 35 Process flow diagram, local power – reciprocating engine scenario .................................. 69 36 Process flow diagram, local pow er – microturbine scenario............................................... 71 37 NG and NGL supply chain .................................................................................................. 7 7 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 ............................................................................................. 8 4 44 North Dakota NGL production ........................................................................................... 85vii LIST OF TABLES
1 December 2011 Monthly Oil and Gas Pr oduction for the Top Four Producing Counties in North Dakota ...................................................................................................... 9 2 Summary of Bakken Wells Flari ng Gas Based on Rates/Month – December 2011 Data ........................................................................................................... 14 3 Summary of Wells Flaring Gas Base d on Rates/Day – December 2011 Data ................... 16 4 Select Associated Gas Quality Data fr om Wellheads in the Bakken Formation in North Dakota ................................................................................................................. ...... 17 5 Assumed Bakken Gas Composition .................................................................................... 17 6 Possible Distributed- Scale Acid Gas (SO 2 and CO 2 ) Removal Technologies .................... 23 7 Possible Distributed-Scale Wa ter 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 Sy stem 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 Ma jor 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 Ma jor 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 Associ ated 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 Ch aracteristics Review ............................................................... 60 31 Summary of Power Ge neration Scenarios .......................................................................... 62 32 Assumed Lean Gas Composition ........................................................................................ 64 33 Summary of Wellhead Gas Flow a nd Product Volume Assumptions ................................ 65 34 Total Cost Summary, Grid Support – Reciprocating Engine Scenario ............................... 67 35 Summary of Product Revenues, Grid Suppor t – 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 Engi ne Scenario ............................... 70 39 Summary of Product Revenues, Local Powe r – Reciprocating E ngine Scenario ............... 70 Continued . . .ix LIST OF TABLES (continued)
40 Flow Diagram, Local Power – Microturbine Scenario ....................................................... 71 41 Total Cost Summary, Local Powe r – Microturbine Scenario ............................................. 72 42 Summary of Product Revenues, Local Power – Microturbine Scenario ............................. 73 43 Summary of Power Ge neration 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 .............................. 90x NOMENCLATURE
AEGS Alberta Ethane-Gathering System ASHRAE American Society of Heating, Refr igeration, 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 ft 3 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 I ndustrial Commission NETL National Energy Technology Laboratoryxi NGL natural gas liquid NGV natural gas vehicle NREL National Renewa ble 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 Intermediatexii 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 En ergy (DOE) National Energy Technology Laboratory (NETL), has conducted a study focused on assessing the technical and economic viability of technologies that could increase ut ilization of associated gas. The impetus for this study is the rapid growth of gas flaring in North Dakota, a function of rapid increas e 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 be gin production and gas-gathering infrastructure gets constructed, thereby creati ng 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-pr ocessing plants, thereby extracting value from a currently uncaptured resource. Ec onomic analysis of these tec hnologies consisted of comparing capital expenses to potential reve nue generation in an effort to frame the potential for more detailed economic study specifi c to individual technology. T echnologies evalua ted included 1) natural gas liquid (NGL) recovery, 2) co mpressed natural gas (CNG) for vehicle fuel, 3) electrical power generati on, and 4) chemical production. Bakken associated gas is typically low in su lfur 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 a llows 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 compress ed gas. Clearly, NGL recovery would be most economical at wells flaring larg er quantities of gas, immediat ely after production begins to capture the greatest volume of gas. Addition ally, technology mobility is critical to enable relocation to new wells as gas-gather ing 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 conve rsion 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 specificati on and compressed before being disp ensed to a vehicle. Further, vehicle fleets utilizing the CNG fuel would need to be adaptable and flexib le to take advantage of this stranded and transient ga s resource. In spite of these drawbacks, U.S. Energy Information Administration (EIA) data indi cate that CNG prices have been significantly lower and experienced less volatility over th e 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 axiii tripling of the electric load in oil-producing ar eas of western North Dakot a and eastern Montana. An initial review of the char acteristics of each distribu ted power generation technology eliminated some options from further consider ation. Based on this revi ew, three technologies were evaluated: reciprocating engine, gas turbine, and microt urbine. When evaluating power generation scenarios, th e projects were characterized into two distinct categ ories 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 generati on 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 pr ofitability. Despite rapid and significant growth of gas production in North Dakota, only a small fr action of total U.S. NG is produced in the state. Pipeline and rail export of gas and NGLs to existing petroche mical infrastructure is likely to continue to be the predominant mode to ma rket these resources. Alth ough NG export is likely to dominate in North Dakota, opportunity does exist for small-scale technol ogies that can convert low-cost gas to higher-value chemicals or fu els that have a strong regional demand. The production processes with the best opportunity for economic success at the well site include novel fertilizer production technolo gies or innovative gas-to-liquid approaches that can be scaled appropriately. All such processe s would benefit by being mobile to periodically relocate to better-producing wells and avoid reduced ut ilization rates. Although none of these approaches appear to be highly compelling from a purely economic perspective, two end- use technologies were identifie d 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 perfor mance. 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 effici ent than at large centralized facilities, may be an enabling technology, allowi ng 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 depl oy at small scale in the Williston Basin, but some chemicals (specifically nitrogen-base d 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 Technol ogies 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 En ergy (DOE) National Energy Technology Laboratory (NETL), has conducted a study to assess the techni cal and economic viability of technologies and processes that could lead to increased utiliza tion of associated gas. The scope of this study included evaluating distributed e nd-use opportunities that may be nefit 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 incr ease in the amount of associated gas that is flared wh ile gas-gathering, processing, and transmission infrastructure are built to accommodate the new pr oduction. In spite of dramatic investment and expansion of gas-processing infrastructure, ar ound 30% of North Dakota’s produced natural gas is flared, nearly 190,000 thousand cubic feet (Mcf)/day or 1,500,000 gasolin e 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 natu ral gas liquids (NGLs). Therefore, although natural gas prices are at a historic low—approximately 10% of the va lue 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 gath er and process gas. Typical Bakken gas may contain as much as 10 gallons of NGLs per 1 Mc f 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, wi th 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 gather ing 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. Nonethel ess, an opportunity exis ts for the next several years to utilize newly pr oduced, otherwise flared associated gas before gathering infrastructure is fully built out. Longer term, opportunity will con tinue 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 applic ability to distributed operation with associated gas containinghigh lev e either w i for distr i chemica l that coul of this s industry and rapi d producti o challeng e impleme n

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lower me m sandstone. t es of total o s (bbl) (Fig u s, the Bak k v ery low po r

2 008).

a had beco m k lahoma, wi t o duced mor e m ent of M i n , North D n g Californi a i c feet (MM c k en Format i m any of the

s most of w e m erous rese r l iston m

bers, Total o il in u re 2). k en is r osity

m e the

t h the e than i neral akota a and c f) of i on is other

e stern r voirsthrough o and Sani
Th since the as oil re c structura many st u W i Willisto n (Figure 3 b y shale Bakken. and san d in the N o

Figure 3 o ut Montana

s h Fields in e Bakken F o 1950s, wit h c overy strat e l characteri s u dies.
i th respect t n Basin ty p 3 ). Lithologi s rich in o r The litholo g d stones) to c a o rth Dakota p

3 . Stratigrap h and North D No r th Dako

o rmation ha h each deca d e gies and te c s tics of the

o stratigrap h p ically com p c ally, the u p r ganic carb o g y of the m i a rbonates (p r p ortion of t h

h ic column f

stratigraph y D akota, wit h ta b eing the s been kno w d e since the c hnologies e Bakken Fo r

h y, the Dev p rises three p per and lo w o n that act a i ddle Bakke n r imarily dol o h e Williston

f or rocks of t y of the Bak k

4 h the Elm C most prolif i

w n to be hy d

1970s seein g e volved. As r mation in N

onian–Miss i

members: w er member s

a s the sour c n varies wi d o mites), wit h Basin.

t he Willisto n k en Formati o C oulee Field

i c examples d rocarbon- be g periods o f

such, the s t N orth Dak o

i ssippian-ag the upper, s of the Bak k c e rock for d ely from cl a h five distin c

n Basin in N o n in North in Montan a of Bakken s

e aring in th e f interest am o t ratigraphic, o ta have be e

ed Bakken middle, an k en Formati o

oil reservo i a stics (inclu d ct lithofacie

N orth Dakot a

Dakota. a and the Pa r s uccess.

e Williston B o ng oil pro d lithologica l e n the subj e

Formation i d lower B a o n are domi n i rs in the m ding shales, s being ide n

a and genera l r shall

B asin d

ucers l , and e ct of

i n the a kken n ated m iddle silts, n tified

l izedAl t activity, Lodgepo C u

In technolo g have be geomec h several y b e most wells, th e W e lateral le n unceme n Resourc e

F

t hough the B the petrole u le, Three F o

u rrent Oil a n E

xplora t general, a p g ies and to o en largely h anical prop e y ears have b e

favorable ( e e use of hyd r

e ll completi o n gths of 50 0 n ted liners, s e s – Oil and

igure 4. Ge n b ase B akken For m u m industr y o rks, and Bi r

n d Gas Pro
t ion and Pr o
p proaches t o o ls for the d r

dictated b y e rties withi n e en drilled h e .g., areas o f r aulic fract u

o ns consist 0 0–10,000 f t s hown in ge n

Gas Divisio

n eralized de p d

on well c o m ation is th e y is also o p r dbeard For m duction

o duction Te c

o the selec r illing, com p y knowled g n a localize d h orizontally i f relatively h u ring is criti c

of horizont a t . Completi o n eralized d e n (NDDM R

p iction of a n o mpletion di a

5 e target of t h p timistic ab o m ations.

c hnolo gy tion of ex p p letion, and g e (or lac k d

area. A v a i nto the mi d h igher poro s c al to establi s

a lly drilled w o ns include o e pictions fro m R

–OGD) wel l

n open-hole c

a grams in N h e majority o ut several

p loitation s t

stimulation k

thereof) o a st majority d dle membe r s ity and per m shing long- t

w ells at de p o penhole an d m

North D a l files in Fi g

c ompletion i N DDMR–O G of the curr e others, inc l

t rategies an d of wells in o f litholog y

of Bakken r where geo l m eability). F t erm produc t
p ths greater

d variations a kota Depar t g ures 4–6.

i n the middl e G D well file s e nt oil prod u l uding the T

d applicati o the Bakke n y , structure,

wells in th e l ogy is thou g F or most B a t ivity. than 8000 f of cemente d t ment of M i

e Bakken, s
. u ction T yler,

o n of n play

and e last g ht to a kken

f t and d

and i neralFigure 5

Figure 6 . Generalize

. Generaliz e d d epiction o completi o

e d depiction well compl e o f a Middle o n diagrams

of a cemen t e tion diagra m

6 Bakken un c in NDDM R

t ed liner co m m s in NDD M c emented li n R

–OGD wel l

m

pletion in t h M R–OGD w n er completi o l files.

h e middle B w ell files. o n, based o n

B akken, base well

d onFr a treatmen t completi operator s Fi g swell pa c to fractu r b etween transver s and prop

Fig u multist a

Oi l Si n a relativ e in the la t in the m unconve n producti o a cture treat m t s in ope n ons; howev e s
. g ure 7 show c kers to isol r e the well a

the fractu r s e to the we l p ant place m

u re 7. Gene r a ge fracture t

l and Gas P

n ce 1951, w h e ly slow pa c t e 1980s) a n m id 2000s),

n tional for m o n in North D m ents can b e n hole com p e r, multista g
s a generali z ate the vari o a long the le n r e and the

lbore and, u m ent to ensur

alized well b t reatment, b a

P roduction
h en oil was f

e. With the n d hydraulic

the efficie n m ations suc h

D akota fro m e divided in t p letions ha v g e completio

z ed wellbor o us fracture n gth of the wellbore. M u nlike longit u

e good flow

b ore schema t

a sed on wel l

f irst produc e advent of h o fracturing o n cy of oil r e h as the B a m

1951 thro u

7 t o two cate g v e lower c

ns appear t o

e schematic zones. The wellbore in M ultistage c u dinal fract u communic a

t ic showing t l completio n

e d from the W o rizontal dri l o r “fracking ” e covery im p a kken econ o u gh 2011. g ories: singl c apital cost o be increasi

of a multis objective o f order to cr e c ompletions u re complet i a tion to the w

t he placeme n diagrams i n

W illiston B a lling (first u
” (first utili z p roved and o mical. Fig u e stage or m s than m u ng in popul a

s tage treatm e f a single-st a e ate the gre a

attempt to i ons, requir e w ellbore.

e nt of swell p n NDDMR

–

a sin, oil has u tilized in th e z ed in the B

made reco v u re 8 sho w m

ultistage. S u ltistage fr a ar ity among

e nt scheme u a ge complet i a test contac t

create fra c e quality pro p

p ackers for a

– OGD well f

been produ c e Williston B akken For m v ery of oil w s the annu a S ingle a cture

most

u sing i on is t area c tures p pant

a f iles.

c ed at B asin m ation from a l oilFigu r through

D a high of 5 increase surpasse d Novemb e Th e associat e producti o 540,000 t record, w 1951 an d
Int e historica l (and ga s capacity. gas bein g gatherin g NG, the goal is t “strande d is upstre a r e 8. Annual 2011. Data s

a ily oil prod u 5 34,000 bpd

is uncertai d

significa n er

2011.

e Bakken F e d NG, and o n. Daily g t housand c u w ith 155,80 3 d

1990, resp e

e restingly, t l ly to 1:1 m o s ) productio n The shorta g g flared at t h g and proce s economics a o see indus t d ” gas is be i a m of the g a oil producti o s ourced fro m

u ction has i n

in Decemb e n. The nu m n t milesto n

F ormation, a

the quantit i g as product i u bic feet ( M 3 MMcf pr o e ctively. Ga s
t he basinw i o st recently. n has resul t g e of gas-pr h e well site. s sing infras t a re challeng i t ry get flari i ng called n o a s-processin g o n and num b m

the North D

n creased si g e r 2011) an d m

ber of pr o n es in 20 1

a lthough a n i es of NG p i on reache d M cf) per da y o duced. Fig u

s recor d s pr i
i de gas-to- o Despite the t ed in a su b ocessing ca p Therefore, t ructure to c i ng. State o f ng down t o o ntraditiona l g facility.

8 b er of wells p D akota Indu s

g nificantly, e d

is projecte o ducing we l 1 1, exceed i

n oil play, p roduced h a d

an all-ti m y . The annu a u re 9 shows i or to 1990 a

o il ratio ( G

change in t h b stantial sh o p acity, in tu r the industr y c apture this f ficials hav e o at least 1 0 l NG, a ter m p roducing i n s trial Com m

e xceeding 5 0 d to contin u l ls and act i i ng 6300
also produ c a ve also inc m e high in

al producti o the annual a re incompl e G OR) prod u h is ratio, th e ortage of g r n, has resu l y is investin g

gas resourc e e released st a 0 %. For the m

that is int e n

North Dak o m ission, Oil a n

0 0,000 bpd u e rising, alt h i ve drilling and 200,

c es signific a reased wit h December o n for 2011

oil and gas e te.

u ction has e quantity a n g as-gatherin g

l ted in a dr a g considera b e , b ut at th e a tements in d

purposes o e nded to de s o ta from 19 5 n d Gas Divi s
(recording a h ough the r a

rig counts respectivel y

a nt quantiti e h the growi n

2011, exce e

was also a production
gone fro m n d pace of n e g and proc e a matic incre a b le capital i n e current pr i d icating tha t o f this stud y s cribe all N G 5 1 s ion.

a new a te of

also y , in

e s of n g oil e ding a

new since

m

2:1 e w oil e ssing a se in n gasi ce of t their y , this G thatFigure 9

D a of the N G 70% co m 18% (no n North D a and Wil l producti o

To to show t the Dec e 5000-me 9 . Annual o i

a ta through t G resource a m es from th e

n e more tha n a kota only, t l iams (in a l o n from the s

Table 1. D Four Pr o County Dunn McKenz i Mountra i Williams

better unde r t he geograp h e mber 2011

ter grid wa s i l and gas pr o Dakota In d

t he end of 2 0 a nd are con s e Bakken F o n 3%) from he top four o l phabetical s e four coun t

D ecember 2 o ducin g Co u

i e i l

r stand the l o h ic location d ata from N s applie d , a n o duction in t d

ustrial Co m

0 11 were c o s idered pri m o rmation, 1 2

several oth e o il- and gas

order). Tab t ies.

2 011 Mont h u nties in N o

Monthly O i b 2,3 3 3,0 7 4,4 9 2,0 5

o cation of t h

of gas pro d N DDMR–O G n d gas volu m

9 t he Bakken F m mission, Oi l

o mpiled fro m m arily from t 2 % from th e er

formatio n

- producing c l e 1 summ a

h l y Oil and G o rth Dakota

i l Productio n b bl 3 7,900 7 9,265 9 7,997 5 3,172

h is gas prod u d

uction as w e G D (Figure 1 m es (total a n F ormation. D l and Gas D i

m

NDDMR

– t he Bakken e Madison F n s. Focusing c ounties are a rizes the D

G as Produ c

n , M Pr o

u ction, a gr a e ll as the lo c 1 0). For ea c n d flared) w e D ata source d i vision.

– OGD rega r

Formation. F ormation, a n

on the Bak k Dunn, Mc K D ecember 2

c tion for th e M onthly Gas o duction, M c

1,620,249 4,343,047 3,256,932 3,273,668

a phical depi c c ation of fl a c h of these fi e re summed d

from the N

r ding the qu a

More accur n d the rem a k en Format i K enzie, Mou n 2 011 oil an d

e Top

c f

c tion was c r a red gas bas e fi gures, a 50 0

within eac h N orth

a ntity ately, a ining i on in n trail, d

gas

r eated e d on 0 0- × h gri dFigu r e 10. Grap h ical depicti o flared fo r

10 n of total g a December 2 s produced 011. and total g a sfor Dec e color co r about th e



 A significa n percenta g 35% of percenta g Formati o processi n the gas b b een co n attempt t Althoug h flared r o 2012).

Figure 1

1 Wyomin g e mber 2011 r responding e issue of N G Flaring is w Higher leve chart of th e n t increase g e of gas u n

the total g g es of gas o n. Prior to n g infrastru c b eing sold t o n verging. T h t o keep pac h this rate a o ughly 40%

1. Annual g a

g flaring total i in Mcf. Th e to a volu m G flaring at t

w idespread t h

ls of flaring

e annual g a in gas pro d n sold (and a s g as produc e

sold and u developm e c ture was su f o market. Si n h is issue h a e with the r a ppears ver y

less than T

a s produced , C

i ncludes CO 2 - v e aggregate m e range. T h

t he well site : h roughout t h

exist where

a s produce d d

uction as w s sumed flar e e d. Figure u nsold hav e e nt of the B f

ficient to h a n ce 2007, t h a s not gone r apid increa y high on a p T exas or W y

, sold, and u C ommission,

v enting volum e 11 for each gr i h ese two fi g : h e Williston B

gas gatheri n d , gas sold, w ell as the i

d) at the en d 12 provide s e changed B akken For m a ndle the ga s h e two num b unnotice d , se in gas p r p ercentage b y oming 1 ( U

u nsol d . Data

Oil and Ga s

e s. i d was then g ures make

B asin.

n g has not y e

and gas u n i ncrease in u d

of 2011 re s a graphi c with the d m ation, the s productio n b ers (% gas

and infras t r oduction a n b asis, on a U .S. Energy

sourced fro m s Division. n represente d clear some

e t been buil t

n sold since u nsold gas e ached a ne w c al perspect i d evelopment

existing g n , resulting i

sold and % t ructure is b n d to captu r volume bas Informatio n

m

the North D d

in each g r important p

t out.

1990 sho w (Figure 11)

. w high, exce e

i ve on ho w

of the B a as-gatherin g i n 85% to 9 0 % gas flared)

b eing built i r e the flare d is, North D n

Administr a

D akota Ind u r id by p oints

w s the

. The e ding w the a kken g and 0 % of

have i n an d

gas. akota a tion,

u strialFigure

An o phenom e change i n previous l should b significa n matchin g

As producti o distinct i n producti o b eing fl a In 2 and 57, 9 summari z 2011 dat the Dece day. Fig u Decemb e that Tab l 12. Percent

o ther impo r e non. To be t n flare gas l y, Figure 1 b e noted th a n tly), and t h g distributed Quantit y presented o n is substa n n crease in g o n has outp a red at the w e 2 011, a tota l 9 76 MMcf w z es the nu m a. Figure 14 mber 2011 d u re 15 displ a e r. Figure 1 6 l e 2, Table 3 age of gas s o C o

r tant point t ter highligh t location an d 1 3 shows t h a t in any g i h is change en d -use tec h
y in previou s

n tially grea t as producti o a ced the ga e ll site (repr
l of 155,80 3 w as unsold. m

ber of well s shows the s d ata are pro v a ys the Dec e 6 shows the , Figure 14, o ld and uns o o mmission,

about the t the tempo r d

quantity d h e flared g a i ven area, t in volume, h nology to t

s sections, t er than oil p o n beginnin g s-processin g esented as g 3 MMcf of N To furthe r s flaring ga s s ame break d v ided in Ta b e mber flarin g

same break and Figure 1
12 o l d . Data so u Oil and Ga s

flared gas r al nature o f d

uring 2011

. a s in Janua r t he volume

and oppor t t he source p r

the quantit y p roduction f g around 20 0 g capacity, r g as unsold i n N G was pro r define the s at varying d own of wel l b le 3 as the n

g rates as a p down for th 1 5 summari z u rced from t h s Division.

s is that i t f the flare g a

. Using the r y and Dec e

of gas fla r t unity, pos e r oduct (flar e

y of NG fr f rom other f 0 7 (Figure 1 r esulting in n Figure 11).

duce d , of w

quantity o f rates per m o l s flaring th r n umber of w percentage o h e 2011 cale n

z e Bakken w t he North D a

t is a tem p a s issue, Fig

same grid s e mber 2011 r ed change d e s a signifi c e d gas).

f rom Bakke f ormations, 1). This rap i an increas e

w hich 97,82 7

f NG b ein g onth based o r oughout 20 1 w ells flaring b

o f the total f n dar year. I t w ells only. a kota Indust r

p orally sen ure 13 sho w s ystem des c , respectiv e d

(in some c ant challen g

n Formatio as shown b i d increase i e d volume o

7 MMcf wa s g flared, Ta b o n the Dec e 1 1. Alternat i b ased on M c f lared amou n t should be n r ial

sitive w s the c ribed e ly. It

cases g e to

n oil b y the i n gas o f gas

s sold b le 2 e mber i vely, c f per n t for n otedFigure 13. Graphical d epiction of f

13 lared gas f o r January a n d Decembe r 2011.Fi g

N D per year producti o annually producti o from the Table 2. Month

– Flaring R 0–499 500–999 1000–49 5000–99 10,000– 1 >20,000 Total * Does no t

g ure 14. Nu m

D DMR–OG D

for the nex t o n of 100,0 0

by approx o n and only Williston B Summar y

– Decembe r R ate, Mcf/m o

99 99 1 9,999

t equal 100% b

m

ber of Ba k

D has indica t t several ye a 0 0 Mcf/well imately 20 0 10% is flar e asin. of Bakken W r 2011 Data

o nth

b ecause of rou n

k ken wells fl a

t ed in prese n a rs. Using 2

(300 Mcf/d 0 ,000,000 M e d, the flare d

14 W ells Flari n

Number o f 2228

170 522 156

72 27 3175
n ding.

a ring a rang e

n tations tha t 000 new w e a y) it is ant i M cf. If gas d

volume w o ng Gas Bas e f Wells P

e of quantit i

t it expects, e lls per yea r i cipated tha t

gathering a o uld still a m e d on Rates
P ercent of T o 70

5 16

5 2 1 99

i es per mont h

2000 new w r and an ass t gas produc t a nd proces s m ount to 20, 0 s /

o tal*

h for 2011.

w ells to be d

umed annu a t ion will in c s ing catch u 0 00,000 Mc f d rilled a l gas c rease u

p to f /yearF Figure 15. F

F igure 16. N u laring rate s

mber of B a as a perce n

kken wells f

15 n tage of tota l

f laring a ra n l flared gas f

ge of quant i or Decemb e

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 utiliz ation of associated gas from initial wells drilled on a lease. Associated gas will be ava ilable in greater quantities as infill wells are installed, and thus may impact th e applicability of certain technologies inve stigated in this study. It was reasoned that by the time multiple well s are in production, gas-gathering infrastructure will be in place. For this reason and others stated in the report, the aut hors view the window of opportunity for application of thes e technologies to be during th e initial few months when gas production is at its highest and not as a long-term installation. In most s cenarios considered, once gas production has declined sufficiently, the equi pment 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 hydro carbons 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 su lfur and high in NGLs. This high NGL content typically corresponds with highe r energy content (1300–2000 Btu/ft 3 ) when compared to residential pipeline gas (~1000 Btu/ ft 3 ). These NGLs pose unique ch allenges 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/ ft 3

.17 Table 4. Select Associated Gas Quality Data from Wellheads in the Bakken Formation in North Dakota 1 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 CO 2 + N 2 , mol% 3.44 1.72 2.87 7.29 3.43 19.8 4.18
H 2 S 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 anal ysis provided to the EERC by a number of North Dakota operators.
Table 5. Assumed Bakken Gas Composition Component mol% H 2 O (water) 0.02 N 2 (nitrogen) 5.21 CO 2 (carbon dioxide) 0.57 H 2 S (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, Tran sport, and Distribution NG processing acts to separate heavier hydroca rbons (ethane, propane , butane, etc.) and other contaminants (sulfur, nitrogen, oxygen, wate r, etc.) from the pure na tural gas, to produce what is known as “residue gas” or “pipe line-quality” dry NG. Inde pendent transportation pipelines impose varying restrictions on the make up of the gas that can be injected into the pipeline.Th Here, li q trucked t instance s elevate t h
Th plant thr o three ma i



 Th e first proc e

q uid water a n t o a refinery s , heaters a n h e gas temp e e minimall y o ugh a net w i n processe s Water rem o Separation o Sulfur and c
ese process e

Figure 17 e sses invol v n d oil (con d

or gas-pro c n d scrubbers

e rature to a v
y processed w w ork of smal

are normal l

o val o f NGLs c arbon dioxi

e s are summ a

. Generalize v ed in NG p d ensates) ar e c essing plan t

are installe d v oid formati o

w ellhead N G l, low-press u l y employe d

de removal

ar ized in th e

d NG-proce Admin i

18 p rocessing t e separated f t , and the w a d . The scru b o n of icelike
G is then tr a u re-gatheri n d

to remove t

e process di a

ssing sche m i stration, 20 0 t ypically oc c f rom the “w a stewater is b bers remov methane h y

a nsported to n g pipelines. t he various i m

a gram show n

m atic (U.S. E n

0 6). c ur at or n e w et” gas. Th e normally d i e solid part i y drates.

a centraliz e At the gas

mpurities:

n in Figure 1

nergy Infor m e ar the well e condensat e i scarded. In i cles. The h e

e d gas-proc e

- processing p

1 7.

m ation head. e s are some e aters

e ssing p lant,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 employe d absorption process that uses a liquid desiccant to absorb water vapor from the gas st ream. Glycol dehydration uses either diethylene glycol (DEG) or triethylene glycol (TEG) in c ontact with the wet gas stream to absorb water from the wet gas. After absorbing water, the glyc ol 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 wate r out of the solution. Solid desiccant dehydration is a frequently employed adsorption method that usually consists of two or more adsorption towers filled w ith solid desiccants, such as silica gel. Wet NG is passed through the towers. Water vapor in th e 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-processi ng 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 NG L 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” abso rption 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 o il. This process recovers approximately 75% of butanes and 85%–90% of pentanes and heavier molecules. Cryogenic processes are used to extract light er 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 st ream. Then, an expansion turbine is used to rapidly expand the chilled gase s, which causes the temperatur e 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 ne xt be broken down into their base components to be marketable. Fractionation is us ed to accomplish this step. Fractionation uses controlled heating and the boiling points of th e 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 deisobut anizer – this step separate s the iso- and normal butanes Sulfur and Carbon Dioxide Removal NG can contain significant amounts of sulfur and carbon dioxide, wh ich must be removed prior to use of the NG as fuel. The process for removing hydrogen sulfide fr om NG is similar to the processes of glycol dehydrat ion 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 regene rated. Although most NG desulf urization 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 pr ocessing plants, final polishing is sometimes accomplished at straddle extraction plants. These plants are located on major pipeline systems. Although the NG that arri ves 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 requ irements that vary from pipeline to pipeline but are established for each pi peline under its Federal Energy Regulatory Commission (FERC) gas tariff. Tariff terms and conditi ons typically limit such gas char acteristics as the following:

 Presence on nongaseous constituents (suc h as particulates, gums, and oil)
 Heating value
 Liquid hydrocarbon content (e xpressed as dew point)
 Hydrogen sulfide, total sulf ur, and mercaptan sulfur21  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 prev ious 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. A ssuming continued strong prices for oil and continued completion technology evolution, th e development of the Williston Basin is expected to continue at a rapid pace.

 The primary formation targeted for producti on is the Bakken Formation, a tight shale formation requiring horizontal drilling and hydraulic fracturing stim ulation to produce economical quantities of oil.

 The Bakken Formation is an oil play but cont ains significant quantities of associated NG, which is high in NGLs.

 Currently, the value of the NGLs is substantia lly higher than the value of the “residue” gas, and separation of the NGLs, if ec onomical, 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-gath ering and processing infrastructure. The excess of gas has forced producers to flare la rge 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 d ecrease significantly in the future.

 The best opportunity for capturing and u tilizing the flared gas in a nontraditional manner (i.e., a use other than delivery and pr ocessing at a NG plant) is likely to be timesensitive. That is, infrastructure will even tually be built out and gas will be captured. The opportunity to capture the gas exists after the well is put into production and before22 gas gathering occurs. Modularity and mobilit y will also be vital in any feasible distributed opportunity.

ALTERNATIVE APPROACH FOR SMAL L-SCALE GAS PROCESSING AND NGL RECOVERY Background The overarching purpose of this study was to identify alternat ive uses of st randed rich associated gas that could provide an economical al ternative 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 Formati on. Emphasis was placed on uses that derived economic and environmental benefit while allo wing a minimum amount of gas cleanup. Within the study, the authors recognized that to be comp etitive, small-scale gas utilization approaches would need to be mobile, moving to where st randed 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 th at 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 concer ns 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-scal e NGL recovery, although less efficient than at large centralized facilities, ma y be an enabling technology, allowing value to be extracted from the associated gas while improving economical util ization of leaner gas for transportation and power. Further, at some locations, where geogr aphy and economics prevent gas gathering, even low-efficiency NGL recovery approaches may provi de an attractive altern ative with no flaring. Summary of Alternative Gas-Processing Technologies The goal of this study is not to define a sp ecific distributed-scale gas-processing system but, rather, to identify opportunitie s 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 functi ons employed in traditional gas processing, then identify new alternatives that may offer pote ntial paths for further research focused on applicability to smalle r-scale implementation. The unit functi ons can be broken down as follows:

 Acid gas removal
 Dehydration
 Nitrogen rejection
 NGL recovery23 Acid Gas Removal In most cases, because of low content, ac id gas removal is not required on Bakken associated gas. In general, potential acid gases to be removed from NG streams are CO 2 and H 2 S. CO 2 is essentially a neutral co mpound and, in most cases, is removed via the formation of carbonic acid. This is a kinetically slow process that may require catalysis. H 2 S is much more reactive and is easier to rem ove. Several conventional and al ternative 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 (SO 2 and CO 2 ) 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 H 2 S removal) Membranes Polymer Zeolites

Several alternate acid gas removal technologies are currently under development. Some of these technologies are being investigated al ready within the EERC’s gasification and syngas purification programs. Some of these technolog ies hold near-term promise for small-scale NGprocessing applications. New semipermeable membrane technologies en able separation of acid gases and water from the NG stream. However, with current technology, it is difficult to adju st the relative rates of diffusion of CO 2 and H 2 S. Therefore, a distributed gas-pr ocessing system utilizing this technology must be designed to meet the CO 2 specification. A fixed-bed adsorbent may then be used to remove H 2 S subsequently to meet the sulfur specification. Metal organic frameworks (MOFs) have be en investigated by many (including DOE NETL, UOP, Sandia National Laboratories, U.S. Army Edgewood Chemical Biological Center [ECBC] and others) as highly efficient, easil y regenerable acid gas absorbers (Willis, 2010; Peterson and Rossin, 2008). MOFs are novel crysta lline compounds consisting of metal ions structured within organic molecules to form multidimensional porous structures. Chemisorption occurs because the framework ha s a strong affinity for the acid gases possessing high adsorption enthalpies. The framework chemistry is also c onducive to easy release of the guest molecules (acid gas) when regeneration is desired. It may be possible to advance MO F state of the art to suit a distributed gas-processing application.C o temperat u transpor t gas be r temperat u wellhea d processi n among t h

T D A

M A D eh y dr a mpounds k n u re and pre s t pipes and v r emoved to u re plus a m d

and after n g plant. Se v h ese alternat

T able 7. Po s D irect Cool i A bsorption

Glycol Alcohols M embrane s A dsorbents

Activated A Alkali Met a Molecular S

Figure 1 a tion

n own as gas s sure condit i v alves. Ther e

levels lo w m argin of s a separation v eral dehyd r i ves can be g

s sible Distr i i n g

(pressure s w A lumina, Sil i a l Chlorides S ieves (zeol i

1 8. Dehydra t hydrates c a i ons are fav o e fore, pipeli n w er than th e

a fety. The d of hydroca r r ation proce g uided by t h

i buted-Scal e

w in g adsor p i ca Gel (KCl, LiCl) i tes)

t ion technol o

24 n form whe n o rable. Thes e n e operator s e saturation d ehydration r bon liquid s ss alternati v h e chart sho w

e Water Re

p tion, on-li n , Alkaline- E

o gy selectio n n liquid wa t e hydrates c s typically r e

point at t h step is typ i s and remo v v es are sum m w n in Figur e

moval Tec h

n e or off-li n E arth Metal C

n guide (H u t er is presen t c an agglome r e quire that w h e lowest e i cally comp v al of acid m arized in T e 18.

h nolo g ies

n e re g enera t C hlorides ( C

u ffmaster, 2 0 t in NG line r ate and plu g w ater vapor i e xpected pi p

leted both a

gases at a T able 7. Sel e

t ion)
C aCl 2 )

0 04). s and g NG i n the p eline a t the

gase ction25 Liquid Desiccants Dehydration with liquid desiccants typically invol ves 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 re sidue gas streams. For chilled contacting, ethylene glycol is used. Methanol has also been employed in dehydrati on processes. Methanol is used either in direct injection or contactor absorber processe s. Because methanol has a high vapor pressure, losses to the vapor and liquid hydr ocarbon 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 fo r 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 cr yogenic plants operati ng in the region of

− 100° to

− 150°F or where a relatively small vol ume 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 lb water /MMscf is normally least costly utilizing a liquid desiccan t 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 applicati ons that require lower dew point than achieved by conventional glycol. With silic a gel, it is possible to simulta neously remove hydrocarbons and water. However, with solid desiccants, rege neration becomes a sign ificant 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 sm aller 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 va por is removed from NG as it flows through a bed of desiccant in a pressure ve ssel. Moisture is attracted to th e deliquescent desiccant and coats26 it with hygroscopic brine. This brine continues to attract wate r, forms a droplet, and then migrates with gravity to a liquid sump. Si nce the desiccants dissolve upon attracting and absorbing water vapor, relatively inexpensive ne w desiccant is simply added to the vessel when needed. Nitrogen Rejection Nitrogen rejection unit operations will not al ways 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-intensi ve and, therefore, not adaptable for use at a distributed scale. Selectively permeable membra ne technology may be s calable to this size. NGL Recovery Because of the relatively high value of products produced, NGL recovery technology options exist for larger and smaller gas-pro cessing applications. The general approaches employed by these technology options are summarized in Table 8. In general, these approaches fall into one of three ca tegories of processes:

 Control of temperature and pressure to achieve condensation of NGLs

 Separation of heavier NGLs fr om 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 demethan izer. One manufacturer’s hardware is shownin Figur e mixture knockou t results i n demetha n turboex p temperat u

Li q where it the low e required the heat r Th pipeline. injection in the he to marke e 19. In thi s results fro m t pot. The l i n lowering n izer (distil l ander whe r u re before i t

q uid from v

repeatedly a e r section o

to vaporize r equired to p e demethan i

A gas co m into the di s at exchange t. s approach, m

condensat i i quid strea m the temper a l ing column r e it under t enters the d

Figure 19.

v arious leve l a bsorbs hea t f the deme t the liquid f r p rovide disti l
i zer produc e m

pressor dr i s tribution pi p r as it cools a heat exc h i on of NG L m

from the k a ture of th e ) . In parall e goes a ra p d emethanize r

CryoStar tu r

l s of the d e t from the i n t hanizer. In r om the bott o l lation reflu x

e s gas that i ven by the p eline. The N

the inlet ga

27 h anger first L s. The gas

–

k nockout p o e stream si g e l, the gas s p id expansi o

r to serve as

r boexpande r

e methanizer n let gas bei n

effect, the o m of the d e x to the top o i s suitable fo

turboexpa n N GL produ c s . The NGL chills the i

– liquid mixt u o t flows thr o g nificantly b

tream from o n that ag a distillation

r and demet h

is drained t n g cooled. W

inlet gas p e methanizer

. o f the deme t fo r distributi n der compr e c t from the d L s are then s e i nlet gas w h ure is sepa r o ugh a thro t b efore the s

the knock o a in lowers reflux.

h anize r
. through the W armed liq u p rovides th e

. The turboe t hanizer.
on to en d

- u e sses the pr o d emethaniz e e nt to stora g h ere a gas– l r ated in a s i t tling valve. s tream ente r o ut pot ente r

the gas s t

heat exch a u id is retur n e low-grade e xpander re m

u se consum e

o duct gas b e r is also w a g e for distri b l iqui d i mple This r s the r s the t ream

a nger, n ed to

heat m oves

e rs by b efore a rmed b utionSe v condens e consists respect, i to acco m

Th pressure reductio n require u

Th turboex p



 JT Sepa r

v eral comp a e NGLs. A n of a gas-to

i t is similar t m

plish the ex p

Figure 2 0

e process o f

is availabl n across the u

p to 1000 p s Twister S e Twister s u ander, com b Expansion Cyclonic g a Recompres s r

ation

a nies offer s k n example o

- gas exchan g t o the turbo e p ansion, an d

0 . Small JT N

f expanding g e. Howeve r JT valve m s i differenti a S upersonic S

u

personic s e b ining the f o

a s–liquid se p s ion k i d -mounte d o f such a s y g er, a JT (t h e xpansion p r d

does not r e

N GL recove

g as to prod u r , JT units m

ust be prov i a l pressure t o S eparation

e parator (sh o llowing pro c

p aration

28 d

systems t h y stem is s h h rottling) v a r ocess, exc e e ly on a de m

ry skid as p r

u ce cooling c

become e x i ded by fro n o operate ef f

o wn in Fig u c ess steps i n h at employ t h own in Fi g

a lve, and a e pt that it e m m ethanizer.

r ovided by d

c an be cost- e x pensive to n t-end gas c o f iciently.

u re 21) has t n a compact, t he JT effec t g ure 20. A J

gas–liquid s m

ploys no r o

d ew point c o

e ffective w h

operate w h o mpression.

t hermodyna m tubular dev i t to chill ga J T unit typ i s eparator. I n o tating mac h

o ntrol.

h en excess s u h en the pr e

A JT unit m

m ics simila r i ce: s and i cally n this h inery

u

pply e ssure m ight

r to aW h temperat u followin g















S m S m that can n h ereas a tur b u re drop b y g gas–liqui d Multiple in l
A nozzle is in a low te m The rapid e x The high-v o The liquids The separat e The liquid vessel and r

m all-Scale N

m all-scale N G

n ot yet be g a Fig u

b oexpander y transformi n d

separation s l et guide va n

used to ex p m

perature an

x pansion re s

o rticity swir l

are separat e

e d streams a
stream cont a r ecombined w N GL Recov e G L recovery a thered and u re 21. Twis t

transforms n g pressure s teps:

n es generate
p and the sat u

d pressure.

s ults in the f o l drives the d

e d from the g

a re slowed d o

a ins slip ga w ith the dry

e r y for Stra n

has the pot e marketed i s
29 t er superso n

pressure to to kinetic e
a high-vort i

u rated feed g

o rmation of
d roplets to t h
g as using a c

o wn and re p s, which is gas strea m
.

n ded Gas

e ntial to pro v s typically fl n ic separator

shaft powe r e nergy. Twi

i city, conce n
g as to supe r

a mist of h y h e wall with

c yclonic sep a
p ressurized i n

removed i n

v ide severa l f lare d , resul t .

r , Twister a c ster technol

n tric swirl.

r sonic veloc i

y drocarbon c

centrifugal

a rato r
.

n separate d

n a compact

l benefits to t ing in unut i c hieves a s i l ogy emplo y

i ty, which r e

c ondensate.

force.

d iffusers.

liquid deg a

the industr y i lized energ y i milar y s the

e sults

a ssing

y . Gas y , theloss of r e as an in t transpor t these sy s compres s Figure 2 2

In d present i (from 1 0 4000 gal l rich gas, and an e n scale N G NGL re m

P R R R R R V N L L L

Ca p and chill of

− 20° F NGLs w 56,000 g e venue, and t erim practi c t ed hydroca r s tems can b e s ed gas. As 2 , generatin g

F

d

ustry exper n

many pro d 0 00 Mcf/da y l ons of NG L removal of n vironment a G L recover y m oval syste m

Table 9. A s P aramete r R ich Gas Fl o R ich Gas Fl o R ich Gas Fl o R ich Gas H e R ich Gas Pr i V olume of N N GL Price, v L ean Gas Fl o L ean Gas H e L ean Gas Pr i

p ital costs fo ing and sto r F and 1000 p w as based

allons (130 0 e missions f r c e while ga t r bons to be e more easi l

an alternat i g a lower e m

F igure 22. B

ience indic a d

ucing Bak k y of rich g L s per day. S

at least a p o a l benefit to y , a simplifi e m

evaluation

s sumptions

o w Rate fro m o w Rate Pro c o w Rate, de s e at Content i ce (cost) at t N GLs Existi n v alue o w Rate fro m e at Content i ce, value

o r the NGL r age. The co m p si (from an

on a desir e 0 bbl), or fo u r om the flar e hering lines captured a n l y utilized f o i ve, the lea n m ission profi l

B lock flow d i

a tes that 10 k en wells. A g as), the d a S ince the N G o rtion of the

the flare e m e d model w

assumes th e

for Evalua t

m the Wellh e c esse d , eco n s ign flow
t he Wellhea n g in Rich G

m NGL Re m

removal s y m

pression- a assumed pr e e to have u r 400- b bl t a
30 e d gas. Depl o are built a l n d marketed

.

o r power a n n gas can s t l e than rich g

i agram of N
to 12 gall A t an estim a a ily product i G Ls make u p NGLs from m issions. To

a s develope e parameter s

t ion of a N G

e ad, averag e n omic cutof f

d G as

m oval Syste m

y stem comp r a n d -chilling e ssure of 3 5 2 weeks o a nks. The es t o ying small

l lows the g r

. Furthe r , t h n d transport a

t ill be flare d gas.

N GL remova l

ons of NG L a ted NGL r e i on of NG L p a majority

the rich ga s evaluate th e e d based on s shown in T

G L Remov a A e f

1 0

m 85% o 1 2

r ise two ma i system is b a 5 psi at the h o f storage t imated cap i - scale NGL r r eatest valu e h e leaner ga s a tion fuel o r d , as show n

l system.

L s/Mcf of a e moval rate L s would b

of the econ o s has both e c e potential v

a JT- b ased T able 9.

a l S y stem A ssumed V a

300 Mcf/d a 600 Mcf/d a 1000 Mcf/ d

1400 Btu/ f t $0.00/Mc f 0 –12 gallons /

$1.00/gall o o f rich gas fl 2 10–1250 B t $2.00/Mc f
in compon e a sed on a d e h eater/treate r

capacity, o i tal cost for t r ecovery sy s e and most e s generated r transporte d n conceptua l

a ssociated g of 4 gallon s b e approxi m o mic value o c onomic pot e v iability of s

technology

a lue a y a y d ay f t 3 f / Mcf o n fl ow rate t u/ft 3 f

e nts: compr e e sign requir e r ). The stor a o r approxi m t he NGL re m s tems e asily

from d

as a l ly in

g as is s /Mcf m ately

o f the e ntial s mall-

. The

e ssion e ment a ge of m ately m oval31 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 calcula tions are based on NGL sale s only at $1.00/gallon and a recovery rate of 4 gal/mcf. In this scenario, it has been assume d that residue gas is flared.
Table 10. Summary of NGL Removal System Costs and Revenue Description Capital Cost Annual O&M Cost Annual Revenue 1 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 availab ility and no cost for rich gas.
Although the technical aspects of NGL removal are fairly straightforward, the business and contractual aspects do not shar e 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 se parate the liquids, and the opera tor 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, remo ves the NGLs, and sells the NGLs (and likely the lean gas as well). If the entity separating the NGL s is a third party and not the current operator, the contractual and financial aspect s 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 simila r to existing contracts with royalty owners consistent with existing contractual relationships. Conclusions Although the economic viability of NGL remova l systems is highly dependent on how the business entity is positioned in the supply chain and contractual considerations, sufficient value32 is contained within the recovered NGL to s uggest an economical busi ness plan could be developed. Clearly, NGL recovery would be most economical at wells flar ing larger quantities of gas immediately after production begins in order to capture the greates t volume of gas. Additionally, such a technology would benefit from being mobile and easily mobilized and commissioned every several months. The value achievable from truc ked delivery of NGL is also a critical factor in determining economic viability. Businesses w ith their own gas-proc essing facilities would likely gain the greatest value. Those relyi ng 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 compre ss it for use in NGVs. The gas vented or captured at the wellhead is too rich and variable in co mposition 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 fueli ng 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 ec onomics 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 adaptabl e 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 th at 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 fu eling infrastructure to remain in place as gasgathering pipelines fill in ar ound the CNG infrastructure. CNG and LNG Fundamentals NG has been used as an engine fuel si nce 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 countrie s

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i s the ne of U.S. A RB) o cess,34 Figure 23. NGV use by country (NVG Journal, 2012). Having established some of the barriers to NGV use in the United Stat es, 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 increas ed 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 C NG for fleet vehicles. CNG must be stored in tanks at pressures up to 3600 psi to offer the vehicle adequate driving range. Alternatively, L NG, which is 2–3 times more dense than CNG (3500 psi), can also be stored in vacuum-insulated pressure vessels. LNG is typi cally used only with heavy-duty vehicles, where a greater fu el quantity demand exists. LNG contains a significantly higher ratio of methane to heavier hydrocarbons. This is because of the processing required to liquefy th e NG. As the NG is compressed and significantly cooled to

− 260°F, heavier hydrocarbons (NGLs) condens e 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 meth ane than most CNG fuels, LNG does not present the same challenges in emissions or fu el quality variation that CNG does. CNG-powered vehicles attain roughly sim ilar 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 Dakot a. 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 summ ary 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 fr equently 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 cap tured in Table 13. This study also conc luded that gas quality variations over time across the nation are highly variable.35 Table 11. Select Gas Quality Data from Nort h Dakota Pipeline Stations, 4th Quarter 2011 3
WBIP 1 Williston– Ray WBIP N. Tioga Transfer– Ray WBIP Baker–

Little Beaver WBIP Dickinson– Glen Ullin WBIP Bismarck– Glen Ullin NBIP 2 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 CO 2 + N 2 , mol% 4.27 3.98 4.43 3.88 3.81 1.97 2.21 H 2 S, 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 Da ta at North Dakota Pipeline Stations, 4th Quarter 2011 1

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 CO 2 + N 2 , 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 PA 1 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 CO 2 + N 2 , 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 en tity that has established a commercial fuel quality specification for NG. The lack of clear a nd reasonable gas quality standards is, by many accounts, impeding the proliferation of CNG and NGVs. Engine manufacturers have grea tly 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 re quired 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 ha ppened largely behind the scenes in the world of gasoline and diesel engines. Th ere has always been a tension between the OEMs and the fuel providers. The OEM’s ideal is to ha ve a very tight fuel specification to preclude effects of variable fuel compos ition on their engines. The fuel s uppliers cannot generally provide that high level of quality without charging an obj ectionable premium cost. In the case of mature gasoline and diesel markets, this balance of pow er 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 fo r 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 sche dule 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 specificat ions for each major t ype 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, ra ther, sets a stan dard fuel upon which ta ilpipe 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 odor ant additive) ppm v , max. 16 Sum of CO 2 and N 2 , mol%, max. 4.0
Society of Automotive Engineers (SAE ) J1616 – Recommended Practice for CNG Vehicle Fuel SAE has published a recommended CNG specifi cation, summarized in Table 15, which presents important physical and chemical characte ristics of CNG vehicle fuel and describes test methods for evaluating these char acteristics. It does not, however, take the CARB approach to fuel specification by hydrocarbon species. Inst ead, it leans heavily on the Wobbe index as a measure of fuel quality and provides recomm endations on nonfuel contaminant content.
Table 15. SAE J1616 CNG Specifications Component Value Water Content Note 1 CO 2 3.0%, max. S and Sulfur Compounds 8–30 ppm, max. O 2 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 cons ervative approach and prescribes fuel content by hydrocarbon species as well as by maxi mum levels of nonfuel contaminants. It does not address fuel heating value dire ctly 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 Californi a unless it meets the specifications in the Table 16. Industry sources indicate that the comm ercially 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 f act, since 2010, CARB ha s been considering a major redefinition of these CNG specifications to instead rely almost solely on methane number as the key specification. This change is bei ng advocated by major CN G 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 CO 2 and N 2 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, Refrigerati ng 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 th at many major U.S. cor porations are acting on motivations to adopt NGV technology into their fleets and business strategies.Table 17 . National F AT&T – C Verizon – Federal E x
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z e on s /year41 A Distributed Model Suitable for Sm all-Scale Bakken Associated Gas Opportunities Opportunities to use wellhead gas to produ ce 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 pi peline is brought to th e first well on the new location. During this time, associat ed gas is typically flared. Afte r this time, th e assumption is that it would be difficult to compete with the economics of gathering and centralized gas processing, especially given that “pipeline qua lity” 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 a ssociated gas is treate d in centralized gasprocessing facilities connected to wellheads by vast networks of gathering pipelines. Accomplishing the same (or higher) level of ga s processing at the we llhead would require 1) miniaturization of gas purification technol ogies, 2) great reductio n in price of each purification function for the smaller scale, a nd 3) mobile purificati on/compression/dispensing systems capable of being quickly set up at on e 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 fr actionation 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 challe nge 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 grea tly increases the econom ic feasibility of a CNG project and reduces the loss of resource wh en flaring is necessar y. Based on modeling done as part of this study, the EERC concluded th at removing the NGLs (specifically butane and heavier constituents and a portion of propane) ca n be accomplished with chilling and JT cooling operated at

− 20°F and 200–1000 psi. Once the NGLs have b een separated and stabilized, they are pumped to on-site storage tanks. At an estimated NGL removal rate of 4 gall ons/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 a pproximately 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 representa tives, the capital cost for the NGL removal and storage system is estimated to be $2,500, 000. This capital cost includes the necessarycompres s the NGL
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 Decisions made on equipment purchases, cap ital upgrades, and fuel contracts have long-term impacts on the opera tional success of the fleet.

 Larger transit and refuse fleets (75+ vehicl es) tend to be profita ble and resilient to variations in pr oject parameters.

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

 Diesel prices are a powerful indicator of prof itability 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 sensitiv e to vehicle maintenance costs.

 Tax issues have a strong in fluence 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 li fe (10 years to 20 years).

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

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

 Garage upgrade (for minimal-upgrade scenario).

 Number of new attendants/hostlers (fewer th an two to more than four personnel). A Model for Use of Bakken Gas in NGVs Many of the cost factors that must be anal yzed to produce a valid economic assessment of the Bakken region’s CNG/LNG opportunities ar e 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, we t associated gas into engine manufacturer-approved C NG/LNG fuel. Few, if any, micr oscale distributed systems exist that are capable of separating NGLs, sulfur, a nd water from the rich Bakken associated gas economically to polish the resource to CNG-qua lity 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 with in the context of this study. After a brief examination, LNG did not surface as an area of em phasis. Reasons for not including LNG as an area of emphasis for this study included:
1. Significantly increased capital costs of li quefaction equipment over CNG equipment.
2. Difficulties in miniaturizing and mobilizing li quefaction 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 distri buted-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 prep aration 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 a nnually 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 a ssociated gas relative to the amount of gas available. The CNG economic assessment will nece ssarily start from an assumed, reasonably sized fleets, and project where the economic brea keven 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 th is economic analysis is the co st of fuel purification and preparation for compression and dispensing op erations. Because the North Dakota Bakken Formation associated gas is a rich gas, commercia l, off-the-shelf, distri buted-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 opportuni ty 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 a ssumptions listed in Table 20 to represent revenue generated from an NGL removal system and subseque nt 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 Revenue 1 NGLs 2400 gpd $1.00/gal $2400 $700,800 1 Assumes 80% annual system availability. For the purposes of this study, the cost of asso ciated 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 th e most economically feasible vehicle fleet scenario – that of a high-mileage fleet with sign ificant 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 convert ed to CNG can be obtained from gathering lines (thus alleviating the requirement to move as fre quently 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 assump tions, a fueling station configuration can be defined. The mobile CNG fueling trailer o ffered by IMW Industries serves as an effective example. IMW Industries has provided the cos ting information in Table 21 (Damiani, 2012).

Table 21. Estimated Mobile Refuel ing 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 Costs 1 $0.10/GGE 2 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 situati on, a project would expend approximately $15,000 per month to lease, si te, operate, and maintain the IMW mobile fueling station, assuming one site a year a nd 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 a pproximately $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 Rec overy 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 Travel ed (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 th at the fleet of vehicl es would consist of 60 converted Ford F-250 pickups used as field se rvice 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 tr ansportation to a local Ford dealer. It does not include state and local taxes on vehicle purch ases. For 60 conversions, vehicle costs would amount to $768,000.
O&M Costs NGVs are often assumed to have lower maintena nce costs compared to diesel and gasoline engine vehicles. NG burns cleaner (fewer carbon aceous 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. O il changes are recommended every 10,000–25,000 miles, depending upon the vehicle make and how the vehi cle is used. This is compared to every 3000– 5000 miles for the gasoline engine. Despite this anecdotal indicati on, little evidence is found in th e 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 expe nsive because of lower volumes.50  NGV engine users have reporte d reduced reliability of NGV engines, alth ough it should be noted that this may be a function of engi ne vintage. Manufacturers are sure to state that 1990s engines were in the early stage of their product deve lopment cycle and will continue to improve. Therefore, this study will assume that maintenan ce costs do not vary significantly from gasoline or diesel engines in similar use situations. Th is approach is validated by the approach taken independently in the NREL report di scussed 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 associ ated gas that is currently flared, but also gathered associat ed 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 fu el 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 regionall y and nationwide, and does not ar tificially push the economic analysis out of bounds. A fuel price of $2.45/GGE represents a reas onable marker for the following reasons:

 Although higher prices are repor ted at fueling stations el sewhere 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 sm aller, distributed fuel processing.

 Although lower prices are reported at fueling st ations elsewhere, this value still reflects the fact that no distribu tion 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, Publica tion 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 seller s 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 Ac t of 2010 (PL 111-312). No federal incentives for NGVs or NG fueling stations curre ntly 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 Tax51 Relief, Unemployment Insurance Reauthoriz ation, and Job Creation Act of 2010 (PL 111-312). No federal incentives currently exist to promot e 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 summari zed 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 sta tion, siting costs, amortization co sts, and fuel-processing costs. This is still a moderate price point when comp ared with other tax-inclusive price points across the nation and is thus deemed a cons ervative but reasona ble price point.

Table 23. Taxes on CNG in North Dakota Tax Component Addition to Fuel Price Federal CNG Excise Tax (refe rence 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 installatio n 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 ar e not included because of the difficulty in obtaining estimates on such an insufficiently de fined, hypothetical case. Th ese 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 Ta ble 24. This analysis s hows that approximately $6.8 million must be rolled up into the first-year expenses of a fleet conversion project. These costs also represent additional co sts that would not be incurred w ithout the conversion project.
Table 24. Up-Front CNG Fleet Implementation Costs Upfront Cost Component Cost, US$ 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 $6,808,00052 Next, a simple look at amortization costs is summarized in Table 25, assuming a 6% interest rate. No time value of money is accounte d 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 th is analysis, which is to illustrate the yearly savings in fuel costs required to justify the CNG conversion projec t on strictly economic value. The amortization summarized in Table 25 result s 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. Th is 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 ri ch gas resource purchase costs are ignored. Other noneconomic factors would have to be included to ju stify this conversion proj ect. 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 ta ble, inputs are found in bold ce lls, 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 $246,24053 A large driver in this simple model (and a la rge unknown) is the cost of the gas-processing unit. With no commercial off-the-shelf packages av ailable 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-pr ocessing unit instead, the numbers change dramatically. Total up-front implementati on costs become $2,808,000. Total principal and interest become $3,754,269, including $936,269 of intere st. Net yearly costs instead become net yearly revenue if NGL sales are accounted for (aga in, 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 ga s resource will, of cour se, 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 conve rsion 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 pus hing costs per VMT to high levels. Several other studies in the literature have c oncluded that economic justifications can be made for CNG if stationary fueling systems are us ed in conjunction with large fleet s 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 so me 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 th e location of the draw from the pipeline and the pipeline from which the gas is drawn. Howeve r, much of the pipeline gas in North Dakota does not meet minimum specifications for NGV use.

APPLICATION II – ELECTR IC POWER GENERATION Background Current Electrical Generation North Dakota possesses many abundant energy resources—coal, oil, natural gas, wind, hydroelectric, and biomass. Of th ese, the electrical generation pr ofile of North Dakota currently comprises three primary sources: coal, wind, and hydroelectric; in 2010, these represented 64%, 25%, and 9%, respectively, based on namepl ate capacity (U.S. Energy Information Administration, 2011). Because of sparse populati on and low in-state electrical consumption,54 between 60% and 70% of the electricity gene rated 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 Ca pacity 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 Se ction, 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 th e 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 gene ration. Figure 30 shows the flared NG in relation to existing coal-fired generation as well as electrical transmissi on 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 si nce 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 majo r municipalities and Basin Electric Power Cooperative (BEPC) provides power , through its member cooperative s, for the rural areas. Based on information provided by MDU and BEPC, electrici ty consumption is increasing significantly.As 1900 M W Althoug h Basin ( W expecte d
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ustry more e rritory.

gas develo p d evelopme n o n presente d

i th ensurin g a n outage o c t ed 30,000 p than 350,0 0 p ment n t and d

was

g grid c curs, eople 0 0 bbl57Table 28. Pace Report Highlights and EERC CommentsOil and Gas Development in the Williston BasinPace Findings (based on 2006 information) EERC Comments (based on 2011 information)Rapid large-scale development of the Williston Basin will beconstrained by the availability of rigs, labor, and service.This statement was valid in 2011, although development from 2007to 2011 was quite rapid as defined by the Pace “high” scenario, evenwith constrained availability of rigs, labor, and service.Lack of availability of electric power will not affect drilling plans, asall wells produce sufficient quantities of NG to be self-sustaining.The EERC does not have sufficient information to concur with orrefute this point.Pump jacks can be driven by electric motor or a gas-fired engine, butindustry strongly prefers electric.This statement still holds true.A typical Bakken well has a life of 25–30 years and will produce300,000 bbl over that life (although oil production forecasts do notdrive power load forecast).Although the life of a typical Bakken well may be 25–30 years, thelifetime production is very likely higher than 300,000 bbl.Standard spacing for a Bakken well is 1280 acres. This statement still holds true, although other spacing units are beingdefined (both smaller and larger).Power Load ForecastPace Findings (based on 2006 information) EERC Comments (based on 2011 information)Power 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 pipelinesThe EERC concurs with this assumption and will use the same forits calculations.Power load requirements in the Williston Basin are expected toincrease over the next 20 years (2027).This statement still holds true.Power requirements in the Williston Basin will be long term as wellstypically produce for 25 to 30 years.This statement still holds true.Pace used a conversion factor of0.746 to convert horsepower toelectrical demand (kW)The EERC concurs with this assumption and will use the same forits calculations.Continued . . .58Table 28. Pace Report Highlightsand EERC Comments (continued)Power Load ForecastPace Findings (based on 2006 information) EERC Comments (based on 2011 information)Demand requirements assume a load factor of 80%–100%depending on scenario.The EERC concurs with this assumption and will use the same forits calculations.Future unplanned EOR and gas-gathering, compression, andprocessing loads represent a huge potential power requirement thatwas not accounted for in the Pace load forecast.This statement may explain why even the Pace “high” scenariounderestimated the load growth from 2007 to 2011.Enhance Oil RecoveryPace Findings (based on 2006 information) EERC Comments (based on 2011 information)Oil produced from EOR activity accounts for approximately 60% ofthe oil produced in North Dakota.Although our data do not address EOR specifically, this situationhas certainly changed drastically. In 2006, oil production from theBakken Formation accounted for roughly 6% of the annual totalfrom 300 wells. By 2010, that number was up to 76% from morethan 2100 wells.Gas Gathering and ProcessingPace Findings (based on 2006 information) EERC Comments (based on 2011 information)General consensus amongst industryis that additional gas gatheringand processing are required in the Williston Basin.Although additional gas-gathering and process infrastructure hasbeen built, this statement still holds true.Oil Price ForecastPace Findings (based on 2006 information) EERC Comments (based on 2011 information)Industry currently believes $40–$45/bbl WBS is the minimum pricerequired for Williston Basin wells to be economical.The EERC does not have sufficient information to concur with orrefute this point.Over the next 20 years, the West Texas Intermediate (WTI) forecastprice averages $56/bbl and never drops below $50/bbl, thussupporting continued development of the Williston Basin assumingoperational costs do not increase.This statement has held true, although the actual WTI price hastracked more closely with the Pace “High 95%” than the “Expected”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 fo r distributed electrical ge neration (Goldstein et al., 2003). A review of that docume nt verifies that several platfo rms 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, HHV 1 30%–37% 22%–37% 5%–15% 23%–26% 30%–46% Total CHP 2 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 NO x 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 ch aracteristics of each technol ogy (presented in Table 30) eliminated some options from further discussion . Borne out of this review, three technologies warranted further consideration: reciprocat ing engine, gas turbin e, and microturbine. Reciprocating Engine The reciprocating, or internal combustion, engine is categorized as e ither spark-ignited or compression-ignited. Spark-ignited engines are typi cally 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–ignitio n engines can also be set up to operate on a bifuel configuration utili zing both diesel and NG.60 Table 30. Summary of Techno logy Characteristics Review Technology Reasons for Furthe r Consideration Reasons Against Further Consideration Reciprocating Engine  Technology maturity
 Scale
 Electric efficiency
 Cost
 Equipment life
 Fuel pressure
 Fuel flexibility (requires specific engine setup)
 NO x emissions (rich gas may pose challenge) Gas Turbine  Technology maturity
 Scale
 Electric efficiency
 Cost
 Equipment life
 Fuel flexibility (rich gas may pose challenge)
 NO x emissions (rich gas may pose challenge) Steam Turbine  Technology maturity
 Scale
 Cost
 Equipment life
 Fuel flexibility
 NO x emissions (combustion method dependant)  Electric efficiency

Microturbine  Electric efficiency
 Fuel pressure
 Fuel flexibility
 NO x emissions Fuel Cell  Electric efficiency
 Fuel pressure
 NO x emissions  Technology maturity
 Scale
 Cost
 Equipment life
 Fuel flexibility (hydrogen fuel only)

Gas Turbine Gas turbines can be used to generate electric ity from a variety of gas feedstocks, including gasification syngas, NG, and others. Gas turbin es 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 he at 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 pr oducing 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 typi cally classified by their physical component configuration—singleshaft or two-shaft, simple-cycle or recuperate d, 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 demonstrat ed 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 basi cally the same, they convert hydrogen to electricity in much different ways and ar e best suited for different applications. Simply put, hydrogen fuel, air or oxygen, and sometimes carbon dioxide (depending on the fuel cell) are delivered to th e fuel cell, producing electricity and other byproducts such as water, waste heat, and ex cess 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 tec hnology 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 th ese 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 pow er generation scenarios is presented in Table 31. When evaluating power generation scenarios, the projects were characterized into two distinct categories based on the pr imary 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 dire ct delivery onto the electrical grid. 2) Local power – power generation for local use w ith excess generation (i f 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 mo re complex because of the introduction of significantly more design variables. The evaluati on of power generation scenarios assumes that adequate electrical infrastructure exists to a ccommodate 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 genera tor. The generator burns the gas a nd 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 co st recovery), and often there is an economy of scale that typically results in larger ge nerators being more economically feasible. This larger scale, in turn, usually fa vors reciprocating engines, gas turbines, and steam turbines and precludes technologies su ch 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 ge nerator burns the gas and produces electricity. But in this case, the electricity is first used to pow er 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 go al of the project (i.e ., satisfy only local load, satisfy local load with minimal excess genera tion, or satisfy local load with significant excess generation). For this reason, most power generation techno logies may be appropr iate, 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 Bt u/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 advant ageous 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 (a verage 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 loca tion 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/cf64  Lean gas price (value) consumed by electrical gene rator: $2.00/Mcf

 Price (value) of electricity generate d and delivered to the grid: $0.05/kWh

 Price (value) of electricity genera ted 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% H 2 O 0.01 N 2 6.10 CO 2 0.62 H 2 S 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 evalua ted 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 ev aluated 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 rela ted components would not requir e 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 proj ect, improves the performance of the genset, and reduces the loss of resource (when flaring is necessary).Ba s NGLs ( s accompl i have bee
At daily pr o NGL pr o storage c stored o n Al t industry $2,500,0 heater/tr e cost for f Th e since th e presente d unneces s It s wellhea d scenario. shows a b

Tabl e Scena r Grid S u Grid S u Local P Local P s ed on mo d s pecifically i shed with c h n separated an estimate d o duction of N o duction nu m c apacity wo u n -site at a m i hough not w representati 00. This ca p e ater at 35 p f our 400- b bl

e power ge n e authors co d

separately , s ary.

s hould be n d

was sized Table 33 s u b lock flow d

e 33. Summ a

io u

pport – Re c u

pport – Ga s P ower – Rec i P ower – Mic r d eling done butane an h illing and J and stabiliz e d

NGL rem o N GLs woul d m

ber and a u ld be appr o i nimum pre s

w idely avail a

ves, the est i p ital cost in c p si up to 20 0

NGL stora g

n eration sc e nsider it to

, it is simpl e

n oted that i n

to match th e u mmarizes t d iagram of t h

a r y of Well h

c iprocating E s Turbine i procating E n r oturbine

Figure 32. as part of t d heavier J T cooling o e d, they are p

o val rate of d

be approxi m desire to h a o ximately 5 s sure of 200

a ble in a sm a i mated capi t c ludes the n 0 –1000 psi d g e tanks.

e narios anal y

add signifi c e for the rea d

n each scen a e fuel cons u t he assume d h e NGL re m

h ead Gas F l R Flo w E ngine

n gine

NGL remo v

65 t his study, t constituent s o perated at

− p umped to o 4 gallons/ M m ately 400 0 a ve 2 weeks 5 6,000 gallo n

psi to maint

a ll, modular t al cost for t n ecessary c o d elivered to

y zed in thi s c ant value. S d er to remo v

a rio, the as s u mption of t d

wellhea d g m oval syste m

l ow and Pr o R ich Gas w , Mcf/day 1000 1800

600 600

v al system b l t he EERC c s and a p o

− 20°F and 2 0 o n-site stora g M cf (from 1 0

0 gallons of N s worth of s t ns (1300 b b t ain NGLs i n

configurati o t he NGL re m o mpression t

the NGL r e

s study em p Since the c a v e it from t h

s umed flo w t he respecti v as flow for m

as an exa m

o duct Volu m

N GLs Pro d gallons/ d

4000 7200 2400 2400

lock flow d i c oncluded t h o rtion of p 0 0–1000 ps i g e tanks.
0 00 Mcf/da y N GLs per d t orage capa c b l). NGLs w n the liquid p

o n, based o n m oval and s t o take the r e moval syst e

p loy a NGL a pital cost f h e capital e q

w of associa t

v e electrica l each scenar i m

ple.

m e Assump t d

uced, d ay Pro d 8 1 5

5 5

i agra m
. h at removin p ropane) c a i . Once the N

y of rich gas d ay. Based o n

c ity, the re q w ould need p hase.

n discussion s

s torage syst e r ich gas fro m e m as well a

removal s y f or this syst e q uation if de

t ed gas fro m l generator i i o, and Fig u

t ions

Lean Gas d

uced, Mcf/ d 8 50 5 30 5 10 5 10 g the a n be N GLs

), the n this q uired

to be

s with e m is m

the a s the

y stem e m is emed

m the i n the u re 32

d ayTh and pro d utilized t from the generato r Figure 3 3

Th rather, is in relati o electricit y from 1 t o Qu o the reci p capital c o namepla t cost was summari z Grid Su p is scenario c d

ucing elect r t o separate N NGL rem o r is deliver e 3

.

Figure 33. P

e scale of t h a function o o n to the el e y ). The sys t o 10 MW, a n

o tations we r p rocating en g

o st for a re c t e capacity)

assumed to z ed in Tabl e p

port – R ec ip

c an be basic r icity for b u N GLs from o val system e d to the el e

P rocess flo w

h e system in o f project e c e ctrical load t em scale f o n d for this st u

r e solicited f g ine genset. iprocating e is estimate d be 10% of t e 34. p rocatin g E ally describ e u lk deliver y the rich ga s are pumpe d e ctrical grid

.

w diagram, g r

this scenari c onomics a n

in the area o r this appl i u dy a scale o f rom manu f Based on i n e ngine gens e d

to be appr o t he capital c o

66 E n g ine Scen a

e d as a reci p y to the ele c s stream pri o d

to on-site

. A simplifi

r id support

–

o is not dic t n d the desir e

and the abi l i cation and o f approxi m f acturers to e n formation p e t consisting o ximately $ 4 o st, or $400 a rio
p rocating e n c trical grid. o r to the el e storage ves s ed process f

–

reciprocat i

t ated by an y e d level of g l ity of the g technology m ately 5 M W

e stablish th e provided b y of three 17 4 ,000,000 ( $ ,000. The t o n gine genset

A NGL r e e ctrical gen e sels. All el e flow diagra m

i ng engine s c

y particular e

rid support i g rid to hand l

would mo s W was chose n

e capital an d y the equip m

00-kW gen e $ 800 per k W o tal costs fo r burning le a e moval syst e e rator. The N e ctricity fro m m

is provid

c enario.

e lectrical lo a i n that area l e delivery o s t typically r n for analysi s d

O&M cos t m ent vendor s e rators (510 0 W ). Annual O r this scenar i a n gas e m is N GLs m

the ed as

a d but

(both o f the r ange s
. t s for s , the 0 -kW O &M i o are67 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 begi nning of the Detailed Evaluation section, the process and product description can be descri bed 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 NGL s. 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 produ ce 114,000 kWh of electr icity per day that would be transmitted to the electrical gri d. The revenue streams for these products are summarized in Table 35.
Table 35. Summary of Product Revenue s, Grid Support – Reciprocating Engine Scenario
Product Quantity Assumed Value Daily Revenue Annual Revenue 1 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 sc enario 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 th e 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 co mprising 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.Us i process wellhea d 1530 M c and deli v which w o that wo u summari z Figure

i ng the ass u and produc d

gas from c f/day of lea v ered to ma r o uld consu m u ld be trans m

z ed in Tabl e 34. Process

Table 36. T Turbine S c Capital C o

NGL Re m Electrical Balance o Total Capi Annual O &

NGL Sys t Electrical Total O& M

u mptions pr e

t descriptio the heater/t r n

gas and 7 2 r ket via tru c m e the entir e

m itted to t h e 37. flow diagr a

T otal Cost S c enario

o sts m oval and S t

Generator S o f Plant

tal Cost & M Costs t em

Generator S M Cost

e sented at t h n can be d r eater woul 2 00 gallons c k. The lea n e 1530 Mcf/ d h e electrical

68 a m, grid sup p

S ummar y , G

t orage Syste m S ystem

S ystem

h e beginnin g d escribed a s d be proce s of NGLs. T n gas is sup p d ay and pro d

grid. The p ort – gas t u

G rid Suppo r C o

m

$2,50 0 $6,40 0 $1,00 0 $9,90 0

$25 0 $64 0 $89 0

g of the Det s follows. 1 s sed by th e T he NGLs a r p lied to the duce 140,4 0 revenue str e u rbine scena r

rt – Gas

o st
0 ,000 0 ,000 0 ,000 0 ,000

0 ,000 0 ,000 0 ,000

t ailed Evalu a 1 800 Mcf/d a e NGL rem o

re pumped t electrical g 0 0 kWh of e e ams for t h r io.

a tion sectio n a y of asso c o val syste m t o on-site st o g eneration s y e lectricity p e h ese produc t n , the c iated m

into o rage y stem e r day t s areT a Pr N G El T o

1 A

Th e prior to i on-site d power – depicts t h

A q provide d genset i s capital c o a ble 37. Su m

o duct G Ls e ctricity o tal A ssumes 80%

L ocal P o

e local pow e i ntroduction d eman d , wit

reciprocati n h e process f l

Figure 35. P

q uote was s o d

a quote fo r s approxim a o st. The cos t m mar y of P r Qua 720 0 140,400 annual syste m

o wer – R eci p

e r – recipro c

of the rich h the exce s n g engine s l ow diagra m

P rocess flo w

o licited for a r a single 2 5 tely $200,0 0 t s for this sc e r oduct Rev e ntity 0 gp d kWh/day

m

availability.

p rocatin g E n

c ating engi n gas to the g e s electricit y cenario wa s m

for the loc a

w diagram, l o

a NG-fired g 5 0-kW NG r 0 0, and the e nario are s u

69 e nues, Gri d

Assumed

Value $1.00/gal $0.05/kW h

ng ine Scen a

n e scenario e e nerator. El e y fed to the s targeted t a l power – r e

o cal power

–

g enset of ap p r eciprocatin g

annual O & u mmarized i d Support – Daily Revenu

$7200 h $7020 $14,220

a rio

e mploys th e e ctricity ge n

electrical g t o be appro x e ciprocating

–

reciprocat i

p roximatel y g engine ge n & M cost wa s

i n Table 38. Gas Turbi n

u e A n Re v 0 $2,1 0 $2,0 0 $4,1

e same NG L n erated is fi r g rid. The s c x imately 1 engine sce n

i ng engine s c

y 300 kW in

n set. The c a s assumed t n e Scenario n nual v enue 1 02,400 0 49,840

52,240

L removal s y r st used to s a c ale for the

MW. Figu r n ario.

c enario.

size. The v e a pital cost f o o be 10% o y stem a tisfy local r e 35

e ndor o r the o f the70 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 begi nning 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 th e 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 e ither stored on-site for truck transport to the pipeline or pumped directly in to a NG-gathering system for deli very 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 Revenue 1 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 pr ior to delivery of gas to the microturbine and the use of generated electricity to satisfy lo cal 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 r eason, two scenarios were examin ed at a scale close to 200 kW. Figure 36 shows the process flow diagram of the local power – micr oturbine scenario.To feet-abo v represen t derated o configur e package package s

Table 4 0
Descrip t Four 65

- Two 20 0

In processi n will be m small-sc a flares e x example s In b and uns c Figure
accurately s v e-sea-level t the worst

o utput of b e e d as multi

systems th a s offered by

0 . Flow Dia g

t ion

- kW Microt u 0 -kW Micro
selecting e i n g capacity m ost econo m a le microtu r x cess lean g s that follo w b oth cases, t c heduled m a 3 6. Process

s ize a syste m

elevation a case scenar e tween 20 % ple microt u a t were ap p the vendor.

g ram, Loca l

u rbines t urbines

i ther packa g than the el e m ical only a r bines cons u g as or is de s w , it is assu m

t he vendor o a intenance o flow diagra m

m , the vend o a nd a maxi io as far a s % and 25%. u rbines cou p p roximately

l Power – M Nominal

Power Rating 260 kW 400 kW

g e, the NG L e ctrical gen e a t the highe r u me less th a s igned to s t m ed that the e

o ffers a fac t f the syste m
71 m , local po w

o r used EER

mum ambi e s electrical p The two s y p led togeth e

200 kW i n

M icroturbin e Actual Power Rating 195 kW 316 kW

L removal e ration syste r -gas-produ c a n 100 Mcf / t ore the ex c e xcess lean g
t ory protect i m

as well a s w er – microt u

R C-provided

e nt temper a p roduction e y stems offer e e r in a sin g n scale. Ta b

e Scenario

Derate C

25% 4 20% 6
system is l e m. General l c ing wells. A / day. This m c ess gas for g as is sold. i on plan (F P s parts, incl u u rbine scen a

conditions i a ture of 10 0 e nvironmen t e d by the v g le package b le 40 su m

Gas C onsumed 4 9 Mcf/ d ay 6 8 Mcf/ d ay

l ikely to be l y, the NG L A s shown i n m eans that t

sale to th e

P P) that co v u ding an ov a rio.

i ncluding a 2 0 °F. This w t an d resul t v endor were and result e m marizes th e

Electric i Generat e 4683 kW h 7595 kW h

e much lar g L removal s y

n Table 40, t he project e e pipeline. I n

v ers all sche d

erhaul or t u 2 250- w ould t in a

both e d in e two

i ty ed h / d ay h / d ay

g er in y stem

both e ithe r n the

d

uled u rbine72 replacement at 40,000 hours of operation. The FPP “locks in” the annual O&M cost of the system, and in both scenarios presented belo w, it is assumed that the FPP is purchased. For the purposes of this report the authors c hose to analyze the smaller package (four 65- kW microturbines) as it more closely matche d the 200-kW scale and provided more flexibility should a single turbine need to be taken o ff 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 elect rical 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 Re moval 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 begi nning 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 th e 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 e ither stored on-site for truck transport to the pipeline or pumped directly in to a NG-gathering system for deli very to a gas-processing plant. The revenue streams for these produ cts are summarized in Table 42. Drilling Rig Power The use of wellhead gas as a fuel for dri lling operations derives advantages from both CNG and power production scenarios described previous ly. In reciprocating di esel engines, rich73 Table 42. Summary of Product Revenues, Local Power – Microturbine Scenario (Four 65-kW)
Product Quantity Assumed Value Daily Revenue Annual Revenue 1 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 applica tions like large-scale co al or natural gas-base d electrical production. As a separate task under this project, the EERC is working with Continental Resources, ECO-AFS, Altronics, and Butler Ca terpillar to conduct a detailed study and field demonstration of the GTI Bi-Fuel System ® . Within that task, the EERC conducte d a series of tests at the EERC using a simulated Bakken gas design ed 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 demonstratio n 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-F uel 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 aftermar ket addition providing natural gas to the air intake, engine performance is not altered in di esel-only operation. If the natural gas supply is interrupted or unavailable at a lo cation, the engines can continue to operate on diesel fuel without requiring any alterations. The cont rol system of the Bi-Fuel Syst em also provides a number of safety protocols that simply stop gas flow if any engine performance parameters exceed manufacturer-recommended limits. The Bi-Fuel Syst em controls continue to monitor engine performance, and when engine ope rational 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, additio nal 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 genera tion scenarios presented in this section and summarized in Table 43 pr ovide a preliminary technical and economic evaluation that should afford an initial indicat ion 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 Revenue 1 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, discu ssed in the previous section, there are a number of other potential natural gas uses relate d to oil production and operations that could take advantage of rich gas on a well site. Although rig power provides one of the la rgest demands for gas use, the heating of drilling fluids during winter months ca n 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 al ready available at the drilling site. Once drilling is complete, rich gas at the dril ling location can be used to provide power for hydraulic fracturing operations. Bi-fuel systems or dedicated natural gas e ngines can be utilized to provide power for fracturing operations, thereby decreasing dies el deliveries and reducing the fuel costs associated with these operations. Gas availability, in terms of volumetric flow rate, will need to be investigated sin ce the flow available may be insuffi cient to provide all of the fuel75 required for fracturing operations. However, in a bi-fuel type a pplication, 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. A lthough 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 w ith separate generators capable of operating on wellhead gas could benefit from the low-cost gas available on location. Virtually any platform or application that util izes diesel fuel as part of its operation may warrant the evaluation of using na tural gas because of the availability and price of the natural gas. However, there are a numbe r of contractual logistical, t echnical, and economic components that need to be vetted to determ ine whether a project makes sense. Due diligence is required on the part of the reader to evaluate the cost impacts of regulatory, permitting, and engine ering design requirements, wh ich were beyond the scope of this report.

APPLICATION III – CHEMI CALS DERIVED FROM BAKKEN ASSOCIATED GAS Overview of NG and NGL-Based Chemical Industry Raw NG, as produced and flared on well site s, 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 individu al 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 liqui ds with which they might have been associated. Raw NG constituents can be classified into th ree 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, pr opane, butane, pentane, hexane, and largermolecular-weight hydrocarbons. Numerous inorga nic 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 le ss, and contaminants, for the most part, are nuisance waste products. A comparison of th e 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 CH 4 − 259 Ethane CH 3 CH 3 − 128 Propane CH 3 CH 2 CH 3 − 44 i-Butane CH 3 CH(CH 3 ) 2 14 n-Butane CH 3 CH 2 CH 2 CH 3 31 neo-Pentane (CH 3 ) 2 C(CH 3 ) 2 49 i-Pentane CH 3 CH(CH 3 )CH 2 CH 3 82 n-Pentane CH 3 CH 2 CH 2 CH 2 CH 3 97 Hexanes C 6 H 14 122–156
Each hydrocarbon extracted from raw NG has a set of uses or can be further processed into products. A summary of these uses a nd products is provided as follows:

 Methane’s principal use is as a fuel to pr oduce 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 ethe r (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 el ectric power generation; and 3) industrial customers for heat and chemical feedstoc k. (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 reje cted into NG pipelines to the extent allowed by pipeline operators.

 Propane’s primary use is residential and co mmercial heating with the remainder being used by 1) industry for chemical feedstock a nd other uses, 2) agriculture for heating and drying, and 3) commercial entities as a motor fuel for forklifts a nd 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 pos sess slightly different chemi cal properties and uses. The majority of butanes are used for heating when alone or combined w ith propane to create liquefied petroleum gas (LPG) and as petroleum refinery feedstock, eventually becoming motor fuel. Regulatory restrictions on motor fuel vapor pressure, however,

Fi g distribut i b ecause o Th which is gatherin g and pip e processi n discrete limit butan e result, refi n higher-octa n ether) (an o x refrigerants plastic and p Pentanes, h e gasoline.” T to higher- o individual c processes, a name a fe w transported enable it to b
g ure 37 des c i on system. A o f the multi p e NGL sup p represented g networks t line-quality n g facilities NGLs, can e levels, esp e

ers convert n e compou n x ygenate) b e and as fee d p olybutadie n

e xanes, and T hese comp o o ctane fuels ,

c omponents a s refrigera n w . Increasi n to Canada t o b e pu m ped i ribes the s u A s is appar e p licity of co m
p ly chain st a

in Figure 3 8 t o gas-proce

natural gas close to w h be perfor m

Fi g e cially duri n butanes to o n ds by rout e e fore blendi n d stock to pr o n e synthetic larger hydr o o nents typic a

, and even t

are used a n t, and as bl o n gly, natur a o dilute bit u i n pipelines.

u

pply chains e nt, the NG L m

ponents th

a rts with pr o 8 . Raw natu r ssing facilit i produced. T h ere natural m ed at the g a

g ure 37. NG

77 n g the summ o ther comp o e of alkylati n g into mot o o duce chem i rubber.

o carbons ar e a lly become t ually appe a a s feedstoc k o wing agen t a l gasoline, u men crude o

for natural L chain is lo at comprise

o duction, t h r al gas is co l i es in whic h T ypically, t h gas is prod u a s-processi n

and NGL s u er and in bl e o unds, such on and to M o r fuel. Ad d i cals and m a

e often refer r

refinery fe e ar in moto k

and solv e t for produ c

with som e o il so as to r
gas and N G nger and al s NGLs and t h e predicted

l lected at w e h the raw ga h ese activit i u ced. Fracti n g plant as

u

pply chain. e nds contai n as conversi M TBE (met h d itionally, b u

a terials suc h

r ed to colle c e dstock, oft e r fuel. To e nts for ch e c tion of pol y e butane in c r educe the o

G Ls from th s o is much m t he range of

geographic e ll sites and a s is treated, i es are acco onation, or a means o f n ing ethanol.

on of i- b ut a h yl tertiary u tanes are u s h as polybut

c tively as “n a e n with upgr a

a lesser e x e mical and y styrene foa c luded, is b o il’s viscosit y

e well site t m ore compl i

products. concentrati o sent throug h NGLs extr a mplishe d i n separation o f separating . As a a ne to

butyl s ed as ylene

a tural a ding x tent,

food m, to b eing y and

t o the i cated

o n of h gasa cte d , n gaso f the

themfrom me t (KS) or (AB).
O n b atched turn to t r transpor t farther t o more ar e the USG C

In 2 daily ca p facilities class an d nine pla n on the U 19.7 Bc f/ 28% an d t hane, or a m Mt. Belvie u

n ce fraction a

i n a shared r avel), or m o t ed far to r e o go to get t o e b eing con s C

. NG- P ro c 2 010, the U n p acity of 7 7

. Figure 40 c d

the cumul a n ts account e U SGC. In 20 f/ day, repres e d

14%, resp e Figure 3

m ixed NGL u (TX), Cha

a ted, pure N

pipeline ( w o ved by rail. e ach petroc h o the USGC s tructed to m

c essin g In f

r

a

n ited States 7 billion cu b c lassifies th e a tive capaci t e d for 31% o

10, Texas h a e nting 26% e ctively, of 3 8. Lower 4

stream can n nahon (IL )

N GL comp o w hich requir e

Componen t h emical fac i

or to crack e m ove the in c

a structure had 493 op b ic feet (Bc f e plants by c t y of plants o f U.S. gas

a d the large s of total U.S

. total U.S. p

78 8 states’ sh a
be transpor t ) , Sarnia (O

o nents are m e s substanti a t s on the U. S i lities and r e e rs in Illinoi s c reasing vol u

erational N G f ). Figure 3 9 c apacity, th e within eac h

- processing c s t number o f

. capacity. T p rocessing i n a le plays (20

r ted to remo t O N), Fort S a

m oved sepa r a l storage a s S. Gulf Co a e fineries. C o s and Iowa, b u mes of co m

G -processin g 9 depicts t h e n describes h class. EIA

c apacity. N G f plants, 16 3 T exas and L o n 2010. Du r 11).

t e facilities, a skatchewan

r ately by m s each com p a st (USGC) d

omponents b ut pipeline s m

ponents, e s

g plants tha t h e location a

the number data indica t G processin g 3 , and proc e o uisiana we r r ing this sa m such as Co n (AB) and J

m

ultiple pipe p onent awa i d o not have in Conway s are in plac s pecially to w

t had a com b a nd size of

of plants i n t e that the l a g is concen t e ssing capac i r e responsib m e period, N n way J offre
lines, i ts its to be have e and w ards

b ined these n each a rgest t rated i ty of le fo r N orthFigure 4 Figure

0. Capaciti e 39. U.S. N G

s and numb

79 -processin g

er of U.S. N plants (20 0

G-processi n 9).

g plants (2 0 10).80 Dakota processed about 0.6% of the U.S. tota l. Two other regions performed significant processing in 2010: Alaska (17%) and the Roc ky 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 processi ng plants in North Dakota in 2011. The number and capacity of plants in the state is forecast to increase s ubstantially between 2006 and 2012 as projected in Table 45. Because of expansion in gas-gathering and processing infrastructu re, 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 Mi neral 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 pipe lines pass through and are accessible within North Dakota. These include WBIP, which extends through eastern Montana, northern Wyoming, western South Dakota, and acr oss North Dakota; NBIP, which connects to an Alberta collection system in Montana and ex tends through the Dakotas , Minnesota, Iowa, and Illinois to northwest Indiana; and the Alliance Pipeline, which extends from British Columbia through North Dakota, Minnesota, a nd Iowa to Illinois. The capacit y of the three pipelines is adequate to absorb North Dakota’s gr owing 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, incr eased compression, and increased ethane rejection without expanding or repl acing trunk pipelines. In 2008, WBIP added 42 MMcfd (expandable to 60 MMcfd) to its system and has proposed adding roughly 20 MMcfd of delivery cap acity 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-MMc fd processing plants and will commence service in 2012–2013. The incremental load of th ese 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 reje cted into the NG product and result in NG flow reduction of up to 20%.F igure 41. N o (Nor t rth Dakota h Dakota P i

81 g as-process i peline Auth i ng and tran s ority, 2011 a portation ).Th e rich gas p at Bantr y North D a Tioga pl pipeline than 90 M
If N b y Augu processi n

C u Rose Pi p Dakota, r e Alliance P p ipeline. C u y , North D a a kota, will a ant, which w by Aux Sa b M Mcfd) of e N G producti s t 2013 and n g capacity i
Current

u rrently, Ba k p eline. Ope r r emoves he a Table 45. N Capacity ( 2 2006 227

Figure 42

P ipeline, wi t u rrently the p a kota; howe v a dd a secon d w ill more t h b le, named t h e thane to cra

on growth c 1100 MMc f i n North Da k
N

GL Distri b
k ken NGLs a r ated by A u a vier NGL c N orth Dak o 2 006–2012) 2008 380

. Interstate N

t h a FERC- c p ipeline’s o n v er, a new p d

point. This h an double h e Vantage cking facili t

c ontinues as f d by Januar y k ota should b b ution In f

r

a

a re transpor t u x Sable, t h c omponents

82 o ta NG-Pro c

, in million

2010 500

N G pipeline s

c ertified ca p n ly U.S. rec e p ipeline fro m

constructio n the plant’s Pipeline, th a t ies in Alber t

it has recen t y 2014. As i b e adequate

a structure
t ed out of st a h e Palermo C

to provide a c essin g

cubic feet p 2011 670

s in North D

p acity of 1. 5 e ipt point is m

Hess’s T i n is in conj u capacity, a n a t will trans t a.
t ly, product i i ndicated in

to handle t h

a te by rail a n Conditionin a 110-Mcfd r p er day 2012 1100

D akota.

5 13 Bcfd, is

Prairie Pipe ioga gas pl a u nction with n d construc t s port up to 6

i on will exc e Table 46, t h h e new prod u

n d by pipeli n g Plant ne a

r ich gas str e a high-pre s line’s conn e a nt to Sher w

expansion o t ion of an e t 6 0,000 bpd (

e ed 1000 M M h e forecaste d u ction.

ne via the P a r Stanley, N e am to the P s sure, e ction w ood, o f the t hane ( more

M cfd d

NGP rairie N orth P rairie83Table 46. NG-Processing Capacity in North Dakota, MMcfdOwner Company Facility County 2006 2008 2010 2011 2012 2013North Dakota6Bear Paw/ONEOK Lignite Burke 7.5 6 6 6 6 6Bear Paw/ONEOK Marmath Slope NA 7.5 7.5 7.5 7.5 7.5Bear Paw/ONEOK Garden CreekMcKenzie NA NA NA 100 100 100Bear Paw/ONEOK Stateline 1Williams NA NA NA NA 100 100Bear Paw/ONEOK Stateline IIWilliams 32 NA NA NA 100 100Petro Hunt Little Knife Billings 4 32 32 32 32 32True Oil Red Wing Creek McKenzie 0.5 4 4 4 4 4Sterling Energy Ambrose Divide NA 0.5 0.5 0.5 0.5 0.5EOG Resources Stanley Mountrail NA 20 0 0 0 0Whiting Oil and Gas Robinson Lake Mountrail NA 30 45 90 90 90Whiting Oil and Gas Ray Williams NA 10 10 10 NA NAWhiting Oil and Gas BelfieldStark NA NA NA 30 30 30XTO–Nesson Ray Williams 63 10 10 10 10 10Bear Paw ONEOK Grasslands McKenzie 110 100 100 100 100 100Hess Tioga Williams 4 120 120 120 250 250Hiland Partners Badlands Bowman NA 40 40 40 40 40Hiland Partners Norse Divide NA NA 25 25 25 25Hiland Partners Watford CityMcKenzie NA NA NA 50 50 50Summit Resources Knutson Billings NA NA NA NA NA NASaddle Butte Watford City McKenzie NA NA NA 45 45 45Plains Ross MountrailNA NA NA NA NA 50–75Aux Sable – Chicago, ILAux Sable Prairie Rose Mountrail NA NA 110 110 110 110Total 227 380 510 780 1100 1150–1175Rose Pi p Illinois. P to 10 M b Vantage gas-proc e from the with an i mid-201 3 Pipeline (expand a Th e Figure 4 3 Carringt o however , that pass North D a

If N transpor t advanta g transpor t the price “frac sp r heavier p eline whic h P ipeline cap b pd) of mi x Pipeline sh o e ssing plan t Tioga plan t i nitial capac i 3 , ONEOK ’

in norther n a ble to 100 M

e Kinder–M o 3 . It has a o n, which h

, Alliance P es through N a kota.

Figure 4

N GL pipeli n t ing NGLs g e in that o n t ing compo n

received fo r ea d ” (A si m component s h connects t o

acity is exp a x ed NGLs w o uld be in o p t by pipelin e t to Allianc e i ty of 120,0 0

’ s 525-mile n Colorado M bpd) of mi x

o rgan Coch i single ter m a s 21,430 b P ipeline ope r N orth Dakot

4 3. Allianc e

n e transport a by rail or n e train can n ents by pip

r NGL com p m ilar term, s ). This va l o the Allian c a ndable. A t w as added t p eration, tr a e to Canad a e ’s mainline 0 0 Mcfd of

pipeline f r should be x ed NGLs t o i n Pipeline, t m inal in the

b l of stora g r ates a rich a and trans p

e Pipeline sy s

a tion is not fractionatin ship multi p eline might p onents and

NGL mar g l ue varies

84 c e Pipeline, r uck rack c a o the Paler m a nsporting 4 0 a . By mi d -2

near Sherw o rich NG to f r om wester n

in service, o facilities n
t he only N G

state that g e on-site. I n

NG pipelin e p orts light N

s tem map ( A
available, m g and ship p p le NGL co m

involve m u that paid f o g in, refers t o

over time carrying g a a pable of re c m o Plant i n 0 –60 Mbpd 013, Allian c o od, North D f acilities in n

North D a with an i n n ear Conwa y G L pipeline i

is a propa n n addition t o e between B GL compo n

A lliance Pip e

m idstream c o p ing comp o m

ponents a s u ltiple pipel i o r the origin a o the same on the ba s a s to faciliti e c eiving 5 M b n April 201 2

of ethane f r c e Pipeline ’ D akota, sho u Channahon, a kota to th e n itial capac y , Kansas.

i n North D a n e delivery o Kinde r

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o rt of nents86 Petrochemical Industry Relevance in North Dakota North America has four major petrochemical centers: the Mt. Belv ieu (TX) and Conway (KS) hubs, Edmonton (AB), and Sa rnia (ON). Mt. Belvieu’s cap acity 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-Gat hering System) has a 5-MMbbl capacity. BP operates 12 salt caverns in Sarnia that hol d 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 (i ncluding 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 grow ing shale gas production. Traditionally, the North American petrochemical industry has been lo cated in areas that possess large gas reserves and ge ologic storage features like salt domes and depleted reservoirs where gas, NGLs, and intermediate products can be stored in ve ry large quantit ies. Currently, 96% of U.S. ethane-cracking cap acity is concentrated on the USGC, especially Texas and Louisiana. As illustrated in Fi gure 44, the USGC possesses a large fraction of gas reserves and, as mentioned previously, has si gnificant geologic storage capacity to accommodate the industry. Based on these factors, significan t infrastructure has been built around the USGC. Distribution capacity exists to transport gas and gas liqui ds to the region from across North America. Additionally, NGL fractionation, cr acking, and downstream processi ng capacity exist to convert these hydrocarbons into products that are ship ped 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, re lationships, and timing that consid er complete supply chains. A detailed discussion of how market factors im pact 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 c onstantly at full throughput)

 Long life (operate plant for decades)

 Use of synergies to reduce re quired investment, such as restarting shuttered plants, converting units from petroleum-based f eedstock 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 clim ate, plus grants and tax incentives87 Chemicals in North Dakota can be produced at two different locations, the well site and downstream of gas processing, each of which has different advant ages and issues. The principal advantage of well site chemical production in No rth 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 disadva ntages of well site ch emical production are lack of economy of scale and decreasing utilizati on because of production decline over the life of a well. The production processes w ith the best opportunity for econom ic success at the well site are simple processes, such as NGL collection or processes that manufactu re products for which a local market exists and are suited for downsizi ng to small scales, such as novel fertilizer production technologies or innovative gas-to-liquid approaches th at can capitalize on the price difference between gas and liquid transportation fu els. All such processes would benefit by being mobile to periodically relocate to better-produc ing wells and avoid redu ced utilization rates. North Dakota’s NGL production is forecast to be adequate to support NGL-based chemical manufacturing. Based on the generic raw NG com position that was presented earlier in this report and at the 600,000-Mcfd raw NG producti on 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 pot entially be supported. If cons tructed, it is likely that polymerization or chemical plants would also be constructed to convert the output into plastics and chemicals. Such construction, however, woul d 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 w ould benefit from many factors discussed previously, including large ge ologic storage, downstream pr ocessing 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 re gional interest or produce nich e NGL-based chemicals, but it is unlikely that investment fo r a conventional petrochemicals i ndustry 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 woul d otherwise be flared, whic h could provide an economic advantage of cheaper NG feedst ock and an environmental bene fit of avoiding flaring, and production of chemicals that can be used loca lly, 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 woul d otherwise be flared at Bakken well sites. Of the Bakken wells that flared in Decem ber 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 site s. However, NG producti on characteristically declines over time which would result in underutilization of the equipment if the plant was88 designed to capture at initial pr oduction rates. This effect and that of varying NG price are depicted in Table 47, which shows estimated ca pital and operating costs for ammonia production based on a design described in Appendix B. The NG f eed is assumed to be that of the rich gas composition discussed earlier in this report.

Table 47. Ammonia Production Cost Esti mate 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 ga s 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 re alistic, 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 larg er flow achieves lower production cost.

 No ROI assumed.

 The deleterious effect of underu tilization is ev ident as the capital cost of an oversized unit substantially increases the unit produc tion 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, rese arch and engineering) at the 1% of sales level have little impact on product cost.

 While large-scale units are routinely construc ted and operated, units at this scale are not routinely manufactured or operated so shoul d be considered developmental items.89 When compared to production rates of industr ial 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 sy stems and reduce this handicap. The size and complexity of a plant at even the 14-ton/day scale is too la rge to be considered portable— moving such a plant would be possible, but expensive and time consuming. The U.S. Department of Agricu lture 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 indi cates that a 10% before-tax retu rn on investment is possible, even at a 320-Mcfd feed rate, with appropria te 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 retu rn on investment for a small unit. These economics could be favorably imp acted if fines were imposed on flaring and producers would pay a charge to dispose of th e NG. Ultimately, the economics will have to compete with wellhead prices as gas gathering is deployed. In addition to ammonia, anothe r 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 conver sion 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 a ssociated with FT fuels producti on 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 Bint ulu (Malaysia) facility

 Sasol’s $250 million 10,000-bpd GTL Mossgas (S outh 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 a nd 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 technol ogy to a 320-Mcfd unit would produce about 32 bpd of FT liquids and likely be exorbitantly expe nsive when scaled down. A few companies have claimed to be developing novel small-scale technologies that mi ght be applicable. Velocys is a microchannel equipment devel oper that has been working on GTL technology for more than a decade. The company has three demonstration units under way: 50-bpd and90 25-gallon/day biomass-to-liquids un its in Brazil and Austria, re spectively, 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 de veloped hydrogen reactors and studied GTL. CompactGTL, a relatively new mi crochannel 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 possi bility that their technol ogies might be more eco nomical at small scale than conventional technologies, th eir technologies are un tested at this time and their economics estimates subject to large errors.

OVERALL STUDY CONCLUSIONS This study concludes that of the four altern atives (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 rem oval and distributed power generation. All of the technologies, regardless of likelihood of depl oyment at small scale, have the potential to reduce, but not eliminate, the numbe r of flares and the amount of flared associated gas in North Dakota (to varying degrees). A su mmary of all evaluated technologies with their pertinent characteristics is provided in Table 48.
Table 48. Summary of Evaluated Technologi es 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 th e number of flares, but it will reduce the overall quantity of flared gas and will create a viable secondary revenue stream for wells for91 which gathering pipelines have not yet been in stalled. In fact, several companies are now pursuing this business opportuni ty within the Bakken region. Distributed power generation s eems 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 experienci ng the highest levels of activit y related to oil exploration. However, the evaluation of power generation s cenarios assumes that adequate electrical infrastructure exists to accommodate the a dditional electricity these systems generate. The CNG application could be pursued, but requires extensive gas cleanup and polishing activity to achieve the gas quality levels curre ntly demanded by engine providers. The CNG application also requires a fleet with some flexibility to follow th e flared gas opportunities where they exist. More appropriate for CNG applicati on is implementation at existing downstream gas supply for fleets of sufficient size to ach ieve significant financial benefit. Finally, the chemical production application ho lds the least promise of any applications investigated. This has much to do with supply ch ain logistics, and lack of demand for producible products in the upper Midwest. Chemical pr oduction tends to be tightly centered in petrochemical hubs, where all inputs are readily av ailable, and a nearby pipeline for products is readily available. With that said, the producti on of nitrogen-based fertilizers (a subset of chemicals) may hold some promise at small scale.

ACKNOWLEDGMENTS The EERC would like to acknowledge the contri butions of the following organizations and individuals who provided informa tion, 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 Hensley92  IMW/Clean Energy – Chris Damiani
 Landi Renzo USA – Marco Genova
 Linde LLC – Krish Krishnamurthy, Br yan Luftglass, and John Wei
 Montana–Dakota Utilities Co. – Andrea Stomberg
 North Dakota Association of Rural Elect ric Cooperatives – Harlan Fuglesten
 North Dakota Industrial Commission/Oil & Gas Research Council – Bruce Hicks and Jim Lindholm
 North Dakota Pipeline Aut hority – Justin Kringstad
 Saddle Butte Pipeline, LLC – Shawn Rost
 Westport Innovations, Inc. – Stephen Ptuc ha, Tahra Jutt, and Jonathan Burke

REFERENCES Alliance Pipeline LP. System map. www. alliance-pipeline.com/contentfiles/ 27_receiptdeliverymap_DeliveryMap_a ndersk_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_ga s_locations.html (accessed June 2012). Bohrer, M.; Fried, S.; Helms, L.; Hicks, B.; Ju enker, B.; McCusker, D.; Anderson, F.; LeFever, J.; Murphy, E.; Nordeng, S. Bakken Formation Resource Study Project ; North Dakota Department of Mineral Re sources Report; 2008; 23 p. California Code of Regulations, Title 13 (Motor Vehicles), Divi sion 3 (Air Resources Board), Chapter 5 (Standards for Motor Vehicle Fuels) , Article 3 (Specifications for Alternative Motor Vehicle Fuels). Damiani, C. Business Development Manager, IM W 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-A C36-99-GO10337; NREL/TP -620-34783; National Renewable Energy Laboratory: Golden, CO, Nov 2003. Huffmaster, M.A. Gas Dehydration Fundamental s. 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 Laborator y; NREL/TP-7A2-47919; June 2010.93 Johnson, C., Natural Gas Vehicles, Fueli ng Infrastructure, and Economics; National Renewable Energy Laboratory; March 2011. Lippe, D. Trends in Retail Propane Demand a nd 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 Co mposition in Select Major Metropolitan Areas of the U.S. ; Gas Research Institute Report GRI-92/0123, 1992. NGV Journal. Gas Vehicle Report, Ap ril 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 pe r Day. Press Release, Jan 10, 2012. North Dakota Pipeline Authority. Annual Report; July 1, 2010

– June 30, 2011a; pp. 26. North Dakota Pipeline Author ity. North Dakota Petroleum C ouncil 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 fo r Alaska Natural Gas Transportation Projects, May 7, 2012. www.arcticgas.gov/2012/gas-flari ng-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.c om/2012/01/27/the-biggest-winners -of-obamas-natural-gas-push/ (accessed June 2012). U.S. Energy Information Administ ration. U.S. EIA’s Alternatives to Traditional Transportation Fuels, Table V1. www.eia.gov/rene wable/ (accessed June 2012a). U.S. Energy Information Administration. www.eia.gov/cneaf/elect ricit/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. Natura l Gas Processing: The Crucial Link Between Natural Gas Production and Its Tr ansportation to Market; Special Report; Office of Oil and94 Gas; Jan 2006; www.eia.gov/pub/oi l_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 Ve hicles 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 Citi es Program Webcast, July 2007.

# APPENDIX A OVERVIEW OF PETROCHEMICAL INDUSTRY INFRASTRUCTUREA-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 regi on. As Table A-1 depicts, U.S. ethylene production peaked in 20 07; whereas, Taiwan and Ch ina ethylene production fell slightly in 2008 but recovered and set records th e following two years. In that environment, expansion of ethylene production was moving away from the Unite d States toward areas of increasing demand such as the Far East and area s possessing feedstock advantages, such as the Middle East. Underlying the Middle East feedstock advantag e was the perception that the United States would increasingly import NG. In 2006, North Am erica (excluding Puerto Rico) had five operating liquefied NG (LNG) import terminal s, 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 we ll as higher prices for both. Even with increased NG flow into the United Stat es in the form of LNG, since LNG is generally more than 92% methane, NGL processi ng 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 we re relatively high compared to those of its products and competition. Industrial NG prices averag ed $4–$6/Mcf in 2002–2003, but increased to $7– $9/Mcf in 2005–2006, and were headed higher. Add itionally, 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, producti on capacity was static or declining in the United States. In the case of NG-based chemical s, such as ammonia and methanol, production decreased by 41% and 89%, respectively, dur ing 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 cap ital 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 35A-2 Table A-2. U.S. NG and NGL Ma rket 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 Produc tion Contracting Expanding
This situation changed dramatically during the 2000s as advances in drilling horizontal well bores and hydraulic fracturin g 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 cr ude oil-based competition, at a time when NGL-derived products have maintain ed their value. The effect is expanded investment in NG and NGL infrastructure in th e 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 additiona l pursuing approval to export. Extracting maximum return from a resource such as NG requires an e fficient supply chain; inadequacies or inefficiencies in distributi on 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-e xcessive. Thus the value of resources depends upon the efficiency of their supply chains. Major determinants of the efficiency of ch emical processes are th e 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. Ma jor determinants of efficient storage and transportation are to use the cheapest storage technologies and locations, to minimize transportation distances, to use the cheapest tran sportation modes, and to operate near capacity. Other factors would be to take maximum advantag e of synergies with existing facilities and to integrate multiple steps. In practice, 60% of U.S. ammonia production ca pacity is located in Louisiana, Oklahoma, and Texas because of proximity to NG feedstock. In the case of polyethylene plastic, more than95% of ethane-cracking (ethyl ene production) capacity is in Louisiana and Texas, again in pa rt 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 ma king ethylene from et hane at 18 cents/pound and from light naphtha at 46.5 cents/pound, etha ne makes up 70% of ethylene production. The appearance of substantial production from th e 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 announ ced 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 (U SGC), recently selecting Pennsylvania for a new facility.A-3 Shell’s decision came under criticism by partic ipants at a Septembe r 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 in frastructure around it, where will Shell send its feed? To take advantage of its proxim ity to northeastern customers, Shell also is considering constructing a polyethyl ene plant with the crack er; otherwise, it would have to transport its ethylene to a polymer plant. This would not be necessary on the USGC, si nce polyethylene plants and infrastructure already exist there. The decision could also be considered risky during pe riods 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 shut ting 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 co mpared 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 Nort h 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 ly ing between Kansas and the Texas Gulf Coast, as indicated by the PennWell LPG and NGL a nd 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 stor age capacity, and 619 thousand barrels per day of fractionation capacity in the central part of the United States, as shown in Figu re A-3. The far eastern line is a propane pipeli ne 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 fa cilities 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 in clude 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 fr actionators in Mt. Belvieu, Texas (50 Mbpd), Conway, Kansas (43 Mbpd), and Gallup, NM (26 M bpd), as well as other assets in Trinidad, the Caribbe an, and Central America. Phillip s 66 (previously the midstream and downstream segments of ConocoP hillips) also owns substantia l pipeline assets, as indicated in Figure A-4. The Cochin (Dome) pipeline system (Fi gure A-5) is a 1900-mile, 12-inch-diameter multiproduct pipeline owned by Kinder–Morgan opera ting between Fort Saskatchewan, Alberta, and Windsor, Ontario, including five terminals. Operating on a batche d basis, the system has anFigu r e A-1. Penn Unit e

Figure A- 2 propan e W ell LPG/ N e d States an d

2 . Phillips 6 e pipeline m

A-4 N GL pipelin e d

Canada (P e

6 (previous l m ap (Conoco e and facilit i e nwell, 201 2

l y ConocoP h Phillips, 20 1 i es map of t h 2 ).

h illips) 1 2). h eF

Table A- 4 Facility Mt. Belvi Shoup an d Hobbs Promix Norco BRF Tebone Other (si x Total Ca p F igure A-3. E

Table A- 3 Capacity
State Texas Louisian a Kansas Mississip p 19 Other S

4 . Enterpri s

eu d

Armstron g

x ) p acity E nterprise P r (Enterpris

3 . Enterpri s

a
p i S tates

s e Product s Owne r Intere s 75 g 100 100

50 100

32 52 100

A-5 r oducts mix e e Products, 2

s e Products
U Cap a

s -Owned N G r ship s t, % Gro

.2 .5 e d NGL pip e 2 012).

’ NGL Sto r U sable Stora g

a city, millio n 120.7

13.5

8.4 7.8 9.6

G L Fractio n o ss Capacity , Mbpd 305

97 75 145

75 60 30 12 802 e line map

r a g e
g e n bbl

n ation Cap a

, Net Cap M bp 253

97 75 73 75 19 12 12 619 a cit y acity, pdFigure

Figure A

- A-4. DCP M

5. Kinder– M idstream m

organ Coc h

A-6 m ixed NGLs

h in Pipeline (Rextag St r

map (Kind e ategies, 201

er

–Morgan, 2 2).

010).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 Regulator y Commission C for the following products between the indicated points:

 Light hydrocarbon liquids between Fort Sask atchewan, 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, a nd 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, Mi nnesota, and Iowa, a nd delivery points in North Dakota, Minnesota, Iowa, Indiana, and Michigan

 Ethane between Maxbass, North Dakota, a nd delivery points in Iowa and Michigan

 Field-grade butane between Maxbass, North Da kota, and Detroit, Michigan (reference to Maxbass and Detroit refers to the inte rnational boundary near those locations). Currently, pipeline operati ons only involve propane. In June 2010, Kinder–Morgan announced a nonbinding open season to add a latera l segment to Clarington, Ohio, to transport Marcellus Shale Y-grade NGLs. Enterprise Pro ducts, Phillips 66, the Cochin (Dome) pipelines, and the Buckeye NGL pipeline (Figure A-6) co mprise 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 hydro carbons 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-crack ing capacity in the United States. The shale boom in North America has reversed the course of petroche mical 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 engi neering design of—new, multibillion-dollar complexes. In November, 2011, Bentek estimate d 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 th e end of 2016. This forecast likely did notFigur Figure A- 6

e A-7. Dow . Buckeye M

Gulf Coast p Dow’s fee d ixed NGL

ipeline sys t d stocks and o

A-8 Pipeline R o

t em transpo r o lefins busi n o ute (Rexta g

r ting hydro c n esses (Do w g Strategies,

c arbon prod u w , 2012). 2012).

u cts to supp o rtA-9 include MarkWest Energy Partners’ February 2012 announcement of 140 Mbpd of additional fractionation in the Marcellus region. Additiona lly, 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 rema inder 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 unde rdeveloped: lacking processing, pipelines, fractionation, and other infrastr ucture. In response, Caiman En ergy has announced projects in two locations that will inst all 720 MMcfd of gas-processi ng and 42.5 Mbpd of fractionation capacity within the next few years, and Mark West is adding 1100 MMcfd gas-processing and 115 Mbpd of deethanizing fractionation capacity. In North Dakota infrastructure expansion incl udes the Vantage ethane pipeline to Alberta and a rich gas line from the Ti oga gas-processing plant to the Alliance Pipeline, which will permit some NGLs to travel with NG to fractiona tors in Illinois. Purvin & Gertz, the North Dakota Department of Mineral Resources and Vantage have pr ojected North Dakota ethane supply to peak in the 2014–2020 time frame be tween 40 and 115 Mbpd, so the pipeline was designed to transport 40 Mbpd (60 Mbpd with addi tional 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 M bpd (110 Mbpd with additional pumping) Bakken Extension to the Overland Pass Pipeline that goe s 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 th e 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 ex ample, will need to more than double its 2009 fractionation capacity to be able to fr actionate its additional NGL imports. Five world-class plants are planned or are being construc ted in the United States:

 ChevronPhillips Chemical Company 1.5-millio n-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 et hylene cracker, 0.6-million-tpy propane dehydrogenation unit, and a linear low-densit y polyethylene plant in Point Comfort, TexasF Fig u

igure A-9. N re A-8. U.S

GL supply . NGL pipel

and fractio n

A-10 ines and ex p

n ation capac i ansions (B r

i ty at Mt. B e aziel, 2011 )

lvieu (Braz i .

el, 2011).A-11  Shell ethane cracker, as well as polyet hylene and monoethylene glycol chemical facilities in near Monaca, Pennsylvania In addition to these, other companies are uns huttering 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 cr acker near Charleston, West Virginia.

 LyondellBasell is study ing 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 favor ing 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 tr ansport ethane out of the region.

 Potential underground ethane storage (as in dicated by the presence of underground NG storage in the Appalachian region shown in Figure A-10). Factors that could work agai nst 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 supplier s commen t

REFER E America n Engi n Braziel, E NG L
Conoco P 2012 Dow Ch e Enterpri s F i

The requir e polyethyle n
e most rec u g oes down: s will conti n t by the me d

E NCES

n Chemica l n eering Ne w E .R. NGL I n s Forum, S e P hillips. http

)

.

e mical Com p

s e Products. i gure A-10. U facil i

e ment to b n e market (i. e

u rrent questi o

without a n n ue to pro d d ia is that on

l Society. F w s 2011 , Jul y

n frastructur e e pt 26, 2011.

://ngl.conoc

p any. Dow. C EnterpriseP r U .S. lower 4 i ties, Dece m

b uild local e ., converte r

o n at confe r other crack e d

uce ethane, e cracker b e

F acts and y 4 , 57–61.

e – Current
ophillips.co m

C om/Pipeli n

r oducts.co m

A-12 4 8 states’ un m

ber 31, 201 0
polyethyle n r s).

r ences appe a e r in the r e

where wil l e gs construc t

Figures of

Constraints ;

m

/EN/prop a

n e/GulfCoas t

m

system ma p n derground g

0 (U.S. EIA )

n e plants t

a rs to be fe e e gion and w l feedstock t ion of a sec o

the Che m

; Future Co n

a ne/map/Pa g

t , accessed J
p (accessed J g as storage )

.

o take ad v

ed stock dis p w ithout etha n

be diverte d o nd.

m ical Indust r

n straints vs.

g es/index.as p

J uly (2012)
J uly 2012). v antage of

p osition wh e n e storage, d

to? A co m

r y. Chemic a

Surpluses. P

p x (accesse d local

e n the

since m mon

a l &

P latts

d

JulyA-13 Kinder–Morgan Cochin ULC. Notice of Open S eason for the Marcellus Lateral Project, June 14, 2010. Penwell. www.pennwellbooks.com/lppipadnf acm.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 DESIGNB-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 pr eliminary 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 nitr ogen stream with a purity level of at least 99.99%.

 Ammonia synthesis via reactin g high-purity hydrogen with ai r-extracted nitrogen in a reactor system equipped with capabilities fo r ammonia recovery, recycle of unreacted hydrogen and nitrogen, and pur ge of inert materials. This design was the basis for ammonia produc tion cost estimates presented previously. Following is a description of the ammonia proce ss, 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 proce ss inputs, along with optional modules for on-site electricity produc tion 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 se paration 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 be ing 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 require d for combustion (to provide heat to drive the endothermic steam methane reforming [SMR ] hydrogen production reacti on) and as a source of nitrogen. Approximately 1 megawatt (MW) of el ectricity is required, mo st of which is used for gas compression. To enable the quickest path to plant fabrica tion, the basic engineeri ng plant design effort incorporated—to the extent possible—commercially available technologies as primary unit ops.Based o n prepared purificat i recovery from qu a purificat i an appr o preparat i vendors b ids, pr e and deli v selected. G a G a sulfur c o The sel e carbon d operatio n approxi m equates t unit ope r to the S M compres s Figure B-1.

n input and

and let fo r i on, 3) nitr o , recycle of u a lified ven d i on, and nitr o priately si z i on of a bas i were receiv e ferred vend v ery dates, a

Descriptio n

a s Cleanup

a s cleanup i n

ntaminatio n e cted gas cl e

ioxide sepa r n s, the ra w m ately 86% o t o approxi m r ation. The r e M R unit to s ion. 20-ton/day a

output req u r supplying o gen separa t u nreacted h y d ors were r e o gen gener a z ed ammon i i c engineeri n ed in respo n ors were c o n d the tech n n s of the sel e

n the form o f n of the SM R

e anup tech n r ation and a w gas is c o

o f the raw g m ately 775 p o

e sidual met h

be combu s a mmonia pr o

u irements fo r

technologi e t ion from a i y drogen and e ceived for a tion units. B i a synthesis n g design p n se to the b o ntacted to c n ologies/ven e cted techno l

f sulfur and R

catalyst a n n ology utili z

solid sorbe n om pressed a g as-containe d o unds/hour o h ane (along w s ted for hea t

B-2 o duction pl a

r a 20-ton/ d e s for 1) g a i r, and 4) a nitrogen, a n supplying B ecause no v unit, a bi d ackage for t b id request. A c onfirm quo dors to be u t l ogies are p r

carbon diox n d ensure to z es a press u n t bed for re m a nd dried. d

methane a o f methane w ith a large t . About 2 0 a nt working

d ay ammoni a s cleanup, 2 a mmonia sy n n d purge of i

gas cleanu p v iable quote s d

solicitatio n t he unit. T w After revie w o ted prices, p u tilized in th e r ovided as f o

x ide remova l

maximum- e u re-swing a d m oval of su l The gas c a t a purity le

sent to the volume of c 0 2 kW of e l block flow d
a plant, qu o 2 ) hydroge n n thesis—in c i nert materi a p , hydroge n s were recei v n was pre p w o viable bi d w ing all rec e p erformanc e e ammonia p o llows.

l is required e fficiency S M d sorption ( P lfur impurit i c leanup tec h vel of 96% SMR (hydr o c arbon diox i l ectricity is d iagram.

o te requests n productio n c luding am m a ls. Viable q n productio n v ed for sup p p ared and l e d s from qu a e ived quote s e representa t p lant design

to ensure a g M R perfor m P SA) proce s i es. Prior to h nology de l or greater, w o gen produ c i de) is also r o

required f o were n and m onia q uotes n and p lying e t for a lified

s and t ions, were

g ainst m ance.

s s for these l ivers w hich c tion) o uted o r gasB-3Figure B-2. Aspen Plus-developed basicprocess flow diagram for 20-ton/day ammonia(35-ton/day urea) productionplant.H y Th the meth the met h water–g a used to s level of 556 lb/h o required for supp l
Ni t Ni t 1373 lb/ h air comp
A m Th respecti v vendor w plants. T

F i y dro g en Pr o

e hydrogen a ne feed str e h ane is con v a s shift reac t s eparate the h

99.99%) is o ur of wate r for combus t l ying hydro g
t ro g en Gen e
t rogen is ex t h our of nitr o ression.

m monia S yn

e high-puri t v ely, are se n w ith signifi c T he model s

i gure B-3. A o duction an d

production m e am is used v erted to hy d

t or converts h ydrogen fr o

produced f r is require d t ion. Figure g en to a 20-t o

e ration
t racted fro m o gen at a pu r

n thesis
t y hydrogen n t to an am m c ant experie hown in Fi g

A pproximate d Purificat i

m odule con v for combus t d rogen and

the carbon o m the was t f rom the 77 d

for the st e B-3 shows a o n/day am m

m

air using a r ity level of

and nitrog e m onia synt h nce in desi g g ure B-4 is

300- lb /hou r

B-4 i on

v erts metha n t ion to prov i carbon mo n monoxide i t e gas. Abo u 5 lb/hour o f e a m -reform i a n SMR uni m onia plant.

PSA unit. T 99.96%. A b

e n outputs f h esis reacto r g ning large

the b asis f

r SMR hydr o n e into hyd r i de heat for t n oxide in th e i nto more h y u t 296 lb/ho u f m ethane f i ng process, i t comparab l

T he selected b out 235 k W

f rom the S M r system c u

- scale com m f or the desi g

o gen produc r ogen via S M t he SMR pr o e first react o y drogen. T w u r of hydro g f ed to the S and 6360 l l e in capacit y

PSA syste m W of electric i

M R and nit r u rrently bei n m ercial am m g n effort. T h

tion–purific M R. A porti o cess. The r e o r. A subse q w o PSA uni t g en (with a p S MR unit. A l b /hour of y to that re q

m generates a i ty is requir e

r ogen PSA u n g designed m onia prod u h e hydroge n

ation unit. on of e st of q uent t s are p urity A bout

air is q uired

a bout e d for

u nits, by a u ction n andB-5Figure B-4.Aspen Plus model of ammoniasynthesis unit operation.B-6 nitrogen streams will undergo compression to appr oximately 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 recy cled back to the reactor. Near 100% conversion of hydrogen and nitrogen is achieved and 1710 lb/hour (equati ng to about 20 tons per day) of ammonia is produced. About 304 kW of electricity is requ ired 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 r eacted 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 se lected 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 prepare d. 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-scal e 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 hydroge n production capability. Using this 20-ton/day design and cost estimate as the basis, an analysis was performed to evaluate the economics of ammoni a production for three scenarios:

Table B-1. 20-tons/day Ammonia Plant Preliminary Capital Cost Estimate

Cost Item Cost Estimate, $million Notes Gas Cleanup 3.6 1 Includes $500K assembly cost Hydrogen Production/Purification 2.5 2 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 Storage 3 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-cap acity reactor (90 tpd ammonia)
 320 Mcfd gas flow and a 2000-Mcfd-cap acity 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 whic h to estimate siting requi rements for a compact ammonia production unit, no land acquisition cost s 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:
Cost 2 = Cost 1 *(Size 2 / Size 1 ) n Standard exponents from the t echnical literature (Towler an d Sinnott, 1991) were adopted, and a 0.79 exponent was adopted ba sed 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 90.1 ton/d ammonia Working 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 9,553,130 305.71B-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 90.1 ton/d ammonia Working 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 1288.91B-10 Table B-4. 2000 Mcfd and Small Reactor Desi gn 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 14.4 ton/d ammonia Working 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: Pr inciples, 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.