# Bakken Pool

Oil and Gas Production Facilities

Air Pollution Control Permitting & Compliance Guidance

North Dakota Department of Health

Division of Air Quality

Effective Date May 2

, 20112 Table of Contents

1. AC RONYMS AND ABBREVIATIONS 4

2. BACKGROUND

A

. Introduction 5

B

. Unique Issues w ith Bakken Pool VOCs 6

C

. Applicability 6

D

. Potential to Emit Action Levels 7

E

. Registration Only 8

F

. Permit to Construct and Ti tle V Operating Permit (Major Source) 8

G. Prevention of Sig nificant Deterioration (PSD) 9

H

. P otential to E mit 9

I

. New Source Performance Standards (NSPS) and Maximum

Achievable Control Technology (MACT) Applicability 9

J

. Regulated Air Pollutant Source s 9

K

. Control of Bakken Pool O&G Production Facility VOC Emissions 10

L

. G reenhouse Gas Emissions 10

M

. Multiple Well P ad Statement 10

3. FORM COMPLETION

A

. Oil & Gas Facility Registration Process 10

B

. Emission Calculation Workbook 11

C

. Emission Calculation Workbook Instructions 11

4. EMISSION SOURCE DETAILS

A

. Oil/Condensate Tanks 17

B

. Calculating Tank Emissions 17

C

. Bakken Pool Tank Vapor Emission Factor 17

D

. Tank Emissions Control Threshold 18

E

. Tank Emissions Control Requirements 18

F

. Produced Water Tanks 18

G. Glycol Dehydrators 18

H

. Calculating Glycol Dehydrator Emissions 18

I

. Glycol D ehydrator C ontrol T hreshold 18

J

. Glycol D ehydrator Control Requirements 18

K

. Glycol Dehydrator Federal Regulations 19

L

. Calculating Treater Gas Flare Emissions 19

M

. Control Requirements for Treater Gas 20

N

. Natural Gas Fired Heaters & Burners 20

O

. Truck Loading 20

P

. Truck Loading Control Requirements 21 Q

. R eciprocating Internal Combustion Engines (RICE) 21

R

. RICE Control Requirements 22

S

. Federal Regulations for RICE 22

T

. Pneumatic Pumps 223

U. Pneumati c Pump Control Requirements 22

V

. Pneumatic Controllers 23

W

. Pneumatic Controller Control Requirements 23

5. EFFECTIVE DATE 23

APPENDIC ES Appendix A

– Oil & Gas Production Facility Registration Form 24 Appendix B

– Oil & Gas Production Facility

Emission Calculation Workbook Screenshots 27 Appendix C

- ND DoH Acceptable Control Systems or Devices 38 Appendix D

- Control Requirements for Tank Emissions 40 Appendix E

– The Basis for the 0.6 Decline Factor 414 

### 1. ACRONYMS AND ABBREVIATIONS

AP

- 42 EPA Publication AP

- 42, Compilation of Air Pollutant Emission Factors (5 th Edition)

Bakken Pool Oil from Bakken, Three Forks, and Sanish Formations

bbl barrel

B O PD barrels of oil per day

BTEX benzene/t oluene/ ethyl

- benzene/x ylenes

Btu B ritish thermal unit

Btu/hr Btu per hour

CO carbon m onoxide

DRE d estru ction and removal e fficiency

EF emission factor

EPA Environmental Protection Agency

g pm gallons per minute

H 2 S hydrog en s ulfide

HAP hazardous air p ollutants

h p horsepower

lb pound

lb/lb

- mole pound per pound mole

LACT Lease Automatic Custody Transfer

MMBtu one million B tu

MM scf one million standard cubic feet (scf × 10 6 )

MM scfd = 1,000,000 scf per day

M scf one t housand standard cubic feet (scf × 1000)

M scfd = 1000 SCF per day

NDD o H North Dakota Department of Health

NESHAP National Emission Standards for Hazardous Air Pollutants

NO x nitrogen o xides

NSCR Non

- Selective Catalytic Reduction

NSPS New Source Performance Standards

O&G Oil and Gas

PSD Prevention of Significant Deterioration psig pounds per square inch gauge psia pounds per square inch absolute

PTE p otential to e mit

RICE reciprocating internal combustion engine

scf standard cubic foot

scf/bbl standard cubic foot per barrel

SO 2 sulfur d ioxide

S/W/B standing/working/b reathing l osses TEG tri

- ethylene g lycol

Title V Title V of the Clean Air Act Amendments of 1990

TOC total organic compounds

TPY tons per y ear VOC vol atile organic c ompounds5 

### 2. BACKGROUND

A. Introduction

The creation of this guidance document (Guidance) was a coordinated effort between the North Dakota Department of Health ( NDDoH ) and the Bakken VOC Task Force , which is comprised

of an Emission Factor Committee and an Emission Control Committee.

This Guidance provide s an approach that may be used by Bakken Pool Oil and Gas ( O&G ) production facility owners/operators to demonstrate compliance with the applicable North Dakota Air Pollution Control Rules (including, but not limited to the requirements established by Chapters 3 3

- 15

- 07 and 33

- 15

- 20

, N

. D

. Admin. Code ). This Guidance provides owners and operators of Bakken Pool O&G production facilities t hat have the potential to emit air pollutants below the major source thresholds (minor Bakken Pool O&G production facilities) with an alternative to obtaining North Dakota air pollution control permits. O wners and operators of

minor Bakken Pool O&G production facilities may still choose to apply for facility

- specific air pollution control permits . T he NDDoH will consider those applications on a case

- by

- case basis.

It should be noted that emissions associated with th e exploration and production of O&G resources cannot be predicted with any degree of precision or accuracy until after it is

determined the oil or gas well will actually produce and site specific production data are

collected and known. Therefore, unlike o ther stationary sources for which projected emissions

u pon startup can be estimated in advance for purposes of pre

- construction air permitting,

emissions from O&G exploration and production facilities are only known post

- construction and completion. This s ituation is unique to O&G explor ation and production facilities and, therefore, requires a p ractical regulator y response. To accommodate this reality, the NDDoH has tailored its O&G registrati on process and this Guidance to allow for the start

- up of new ex ploration and production facilities, and the modification of existing facilities, to occur prior to requiring the

submittal of the appropriate O&G Registration Packet, provided the o wners/operators of such facilities meet certain emission control requireme nts that have been established within this

Guidance document. This represents a rational and p ractical regulatory response to operational realities posed by O&G exploration and production operations

.

Control r equirements have been established within this Guidance for tank emi ssions and

emissions from dehydration units , treater flares and pneumatic pumps . Emissions from other

sources such as pneumatic controllers, truck loading, etc

. are also included in this Guidance

.

Nothing in this Guidance is intended to relieve owners and operators of Bakken Pool O&G production facilities of the responsibility to comply with all State and Federal environmental laws and rules. Owners and operators of Bakken Pool O&G production facilities with the potential to emit at or above major source thresholds must follow the normal permitting

process es established in Chapter s 33

- 15

- 14 and 33

- 15

- 15 of the North Dakota Air Pollution

Control Rules.6

B. Unique I ssues with Bakken Pool VOCs

Crude oil from t he Bakken Pool (defined as wells in the Bakken, Sanish and Three Forks formations) typically contains a high a mount of lighter end components which have the potential

t o produce increased volumes of flash emissions. Because of this, customary correlations such as

AP I’s E&P Tan ks and Vasquez

- Beggs do not work well for estimating flash vapors in the

Bakken , potentially overestimating and undere stimating emissions

.

Recognizing the need to predict tank emissions at Bakken Pool O&G production facilities, the

NDDo H and in dustry collaborated and formed the Bakken VOC Task Force. The Task Force

included the Emission Factor Committee and the Emission Control Committee.

The Emission Factor Committee ’ s goal was to gather direct measurement data collected by

various owners/operators within the Bakken Pool and establish an emission factor that could be used to predict t ank e missions from producing Bakken Pool formation wells

.

The Emission Control Committee ’s goal was to evaluate available emission control technolog ies

and to recommend the best emission control for different emission scenarios.

The findings of both C ommittees were used as a platform to create this G uidance for Bakken

Pool O&G production facilities. The data from the Bakken VOC Task Force that was used to
create the default values for Bakken Pool O&G production facilities were submitted and revised by NDDoH and are available for public review upon request

. Use of the Bakken default values

to calculate VOC emissions is expected to result in a conservatively high estimate of VOC

emissions. As an alternative to using the Bakken default values, site

- specific data can be used to

estimate emissions. In the vast majority of cases, the use of site

- specific data instead of the

Bakken default values i s expected to result in lower calculated VOC emissions.

As mentioned above, Bakken P ool O&G production facilities are differ ent from other O&G production facilities in North Dakota because of the higher potential for flash emissions. This

Guidance was cr eated to provide a consistent and more accurate approach for calculating

emissions from the Bakken P ool O&G production facilities . While all producing wells in the

State will need to have a registration form filed with NDDoH (see Appendix A) and emissions calculations performed, it is not expected that non

- Bakken Pool O&G production facilities will require emission controls for tank emissions to the same extent as Bakken P ool production

facilities

.

Although the Guidance is app licable to Bakken Pool O&G production facilities , the Emission Calculation Workbook may also b e used for non

- Bakken Pool O&G production facilities ; however, it should be noted that some of the default values in the Workbook are specific to

Bakken Pool O&G production facilities

. Whe n applying the W orkbook to non

- Bakken Pool O&G production facilities , the user should review the Workbook to ensure that the val ues are appropriate for the production facility being evaluated.7

C. Applicability

All Bakken Pool O&G production facilitie s (excluding those facilities on Tribal Land) within the

State of North Dakota that emit regulated air contaminant s into the atmosphere are subject to the requirement s discussed in this Guidance and are required to submit either a new o r an updated

O&G registration packet to NDDoH.

Each Bakken Pool O&G production facility owner or operator will receive a letter detailing

instructions on well information submissions. The following summarizes the content of the

submissions.

Existing Bakken Pool O&G pr oduction facilities are those where the first date of production

occurred on or before June 1, 2011 . Owners/operators that have previously submitted registration forms will be required to submit the worksheet detailing well information such as controls, calculations and dates. The NDDoH will supply a blank work sheet to perform the calculations that contains all required fields

. Each owner/operator must submit the spreadsheet

information to the NDDoH by Decem ber 1, 2011 (note that the worksheet is in lieu of a new registration )

.

All owners/operators of existing Bakken Pool O&G production facilities that have not previously

filed a registration form must submit a new registration packet to NDDoH by no later Dec ember 1, 2011 or within 90 days after the first date of production, whichever is later. The se registrations

will include information on each well

, including all prior controls

, in the worksheet (supplied by

the NDDoH )

.

New Bakken Pool production facilit ies are those where the firs t date of production oc curs after

June 1, 2011. The owner/operator of a new Bakken Pool O&G production facilit y must submit a registration pack et to NDDoH within 90 da ys after the first date of production.

D. Potential to Emit (PTE) Action Levels

Based on the total facility

- wide emissions, there are three different registration/permit action levels that will require varying submittals for Bakken Pool O&G production facilities , regardless

of location

. All new and previously unregistered Bakken Pool O&G production facilities must register with the NDDoH as provided in the Applicability section above. The owner/operator of

p reviously registered Bakken Pool O&G production facilities need only submit a sum mary spreadsheet as outlined in the Applicability section above. The flowchart bel ow can be used to

determine the action/actions an owner/operator needs to take depending on the potential to emit

of the Bakken Pool O&G production facility.8

Action Flowchart

E. Registration Only

If a Bakken Pool O&G production facility has a potential to emit (PTE) < 100 TPY of any criteria poll utant, < 25 TPY of combined HAP and < 10 TPY of any single HAP , the owner/ operator only

needs to submit a completed registration packet for that facility within 90 days after the first date of produc tion for new production facilities or by December 1, 2011 (whichever is later ) . No further action is required. See example forms in Appendi ces A and B.

F. Permit to Construct and Title V Operating Permit (Major Source)

If a Bakken Pool O&G production facility has a PTE > 100 TPY of any criteria pollutant, > 25

TPY of combined HAP or > 10 TPY of a single HAP , the facility is required to obtain a Permit to

Construct and a Title V permit as required by Chapter 33

- 15

- 14. Although the O&G production facility is subject to permitting requirements, a r egistration p acket is still required to be submitted within 90 days after the first date of production. These permitting requirements are beyond the scope of this Guidance

, but more information on the perm itting process can be

obtained from the NDDo H website at: http://www.ndhealth.gov/AQ/AirPermitting.htm

. 

### VOC, CO, NOx

<100 TPY &

Combined HAP

<25 TPY & S ingle

HAP <10 TPY

 Submit Registration

Packet within 90 days after the first date of production (new well) or by 12/1/11 (for existing wells)

 No further action 

### VOC, CO, NOx

> 100 TPY or

Combined HAP

> 25 TPY or S ingle

HAP > 10 TPY

 Submit Registration

Packet within 90 days after the first date of produ ction (new well) or by 12/1/11 (for existing wells)

 A Permit to

Construct is required

 Submit Title V Application within 365 days

of the first date of production 

### VOC, CO, NOx

> 250 TPY

 Requires a PSD Application and

Permit

 PSD is a pre

construction permit

 Contact the

NDDoH for further guidance9

G. Prevention of Significant Deterioration (PSD)

A Bakken Pool O&G production facility that either e mits

, or has the PTE

, > 250 tons per year of any air contaminant regulated under North Dakota Century Code Chapter 23

- 25 (or > 100,000 tons per year of greenhouse gases ) , as determined by the NDDo H , must comply with the permitting requirements of Chapter 33

- 15

- 15 (Prevention of Significant Deterioration of Air Quality).

T he PSD permit is a pre

- construction permit . A facility cannot construct until a permit application has been filed and the permit has been issued. The PSD permitting process is a complicated, time

- consuming process that is beyond the scope of this Guidance . M ore information on the PSD permitting process can be obtained from the NDDo H website at: http://www.ndhealth.gov/AQ/AirPermitting.htm

.

H. Potential to Emit

The federal regulations define "potential to emit" as: “ The maximum capacity of a stationary source to emit a pollutant under its physical and operational design. Any physical or operational limitation on the capacity of the source to emit a pollutant, including air pollution control equipment and restrictions on hours of operation or on the type or amount of fuel combusted,

stored or processed, shall be treated as part of its design if the limitation or the effect it would

have on emissions is federall y enforceable. ”

Chapter 33

- 15

- 07 of the North Dakota Air Pollution Control Rules states

, “No person may cause or permit the emission of organic compounds gases, vapors.....unless these gases and vapors are burned by flares or an equally effective control device as approved by the Department. Chapter

33

- 15

- 07 has been approved by the EPA as part of the North Dakota State Implementation Plan

and as a result, is federally enforceable. Therefore

, for an oil and gas production facility, the

PTE of VOCs and the associated HAPs is calculated post

- controls

. Please refer to Appendix C for approved contr ol devices. This Guidance is intended to assist O&G owners/operators demonstrate compliance with Chapter 33

- 15

- 07.

I. New Source Performance Standards (NSPS) and Maximum Available Control Technology (MACT) Applicability

Equipment at Bakken Pool O&G production facilities may be subject to rules and regulations

under 40 CFR Parts 60 a nd 63. Th ese federal regulation s are beyond the scope of this document.

It is the owner/operator ’s responsibility to determine if equipment is subject to these federal

reg ulations . A summary of numerous Federal rules that may a pply to Bakken Pool O&G production facilities is located at: www.ndhealth.gov/AQ/OilAndGasWells.htm

.10

J. Regulated Air Pollutant Sources

When registering a Bakken Pool O&G production facility

, all emission sources at that particular facility must be considered to determine source status (major or minor source) . Generally, the following are the most common e mission sources and the type o f regulated air pollutants they

may emit at a typical Bakken Pool O&G production facility :

 Oil/Condensate Tanks

– VOC, HAP, H 2 S (NOx, CO, SO 2 when controlled)

 Produced Water Tanks

– VOC, HAP, H 2 S (NOx, CO, SO 2 when controlled)

 Treater Flares

– VOC, HAP, NOx, CO, H 2 S, SO 2

 Heaters/Burners

– VOC, HAP, NOx, CO, SO 2

 Truck Loading

– VOC, HAP

 RICE Engines

– VOC, HAP, NOx, CO

 Pneumatic Pumps

– VOC, HAP

 Pneumatic Controllers

– VOC, HAP

 Fugitives

– VOC, HAP

K. Control o f Bakken Pool O&G Production Facility VOC Emissions

Based on historical in formation from Bakken Pool O&G production facilities , flashing emissions from the production tanks may be significant. Acceptable VOC emission control systems or

devices are discussed in Appendix C . The c ontrol requirements for emissions from production tanks are outlined in Appendix D of this document.

L. Greenhouse G as (GHG) Emissions

It is the responsibility of each owner/operator to determine the applicability of GHG em issions inventory reporting and permitting rules to their facilities and to comply with the rules. If multiple wells are drilled from a single pad, GHG emissions from all wells may need to be aggregated (see Multi Well Pad Statement below).

M. Multi Well Pad Statement

When multiple wells are drilled from a single pad, it may be necessary to aggregate all emission sources at the multiple well production facility and additional permitting requirements may apply (Title V, PSD, etc.), which are beyond the scope of this document. Questions regarding permitting requirements for multi

- well producti on facilities should be addressed to Craig Thorstenson of the Division of Air Quality at 701

- 328

- 5188 or cthorstenson@nd.gov.



### 3. FORM COMPLETION

A. Oil & Gas Facility Registration P rocess

Within 90 days after the first date of production or recompletion of any Bakken Pool O&G production facility

, the following documents (registration packet) must be submi tted to the

NDDo H for the facility :11 Registration Packet Contents

1) A completed Oil/Gas Registration Form (AP

- 114) 2) A gas analysis of any gas produced from the well 3) The first 2 pages (Input and Emission Summary) of a completed Oil and Gas Facility

Emission Calculation Workbook

The Registration packet, ( forms and examples found at: http://www.ndhealth.gov/AQ/OilAndGasWells.htm )

, which includes the above three items, must be sent to the following address:

North Dakota Department of Health Division of Air Quality

918 E Divide Ave , 2 nd Floor Bismarck, ND 58501

- 1947

B. Emission Calculation Workbook

The Emission Calculation Workbook can be downloaded from the NDDoH O&G website in Excel format. The workbook will serve two functions: it will provide a simple way of calculating

fa cility

- wide emissions, as well as insuring that all owner/operators are calculating emissions in a consistent manner that meets the requirements of NDDoH.

The Oil & Gas Facility Emission Calculation Workbook contains the following 10 tabs:

 Input

– T he necessary data to perform the required calculations are entered here (required to be submitted in Registration Packet).

 RICE Input

– The necessary data to perform the required calculations for RICE are entered here (required to be submitted in Registration Packet).

 Emission Summary

– T he calculated emissions are summarized by source and pollutant

here (required to be submitted in Registration Packet)

.

 Oil/Condensate Tanks

– T he tank vapor emissions are calculated here

.

 Treater Flare

– T he treater flare emis sions are calculated here

.

 Treater Burner

– T he treater burner emissions are calculated here

.

 Truck Loading

– T he truck loading emissions are calculated here

.

 RICE

– T he RICE emissions are calculated here

.

 Pneumatic Pump

– T he pneumatic pump emissions are calculated here

.

 Pneumatic Controllers

– T he pneumatic controller emissions are calculated here

.

C. Emission Calculation Workbook Instructions

The Emission Calculation Workbook can be completed in three steps: Calculating production numbers, calculating g lycol dehydrator emissions using G RI

- G LY Calc ( if applicable ) and entering data into the Emission Calculation Workbook

.12



### S tep 1
Thirty days after the first date of production or recompletion of a Bakken Pool O&G production facility , the average daily production for the facility needs to be calculate d. Once calculated, this production data will need to be entered into th e Emission Calculation Workbook in order to perform the required emission calculations.



### Step 2
If the facility has a glycol dehydrator in operation, the NDDo H recommends using G RI

G LY Calc V 4 or higher to calculate the emissions

. Other programs may be us ed upon approval

from the NDDoH

.



### Step 3
Complete the entire Emission Calculation Workbook per th e detailed instructions below:



### Data Input

Facility and Registration Information: Lines 1

- 3

Line 1: Enter the name of the facility and the well number

.

Line 2: Enter the first date of production or date of recompletion of the facility.

Line 3: Enter the date that the registration packet is submitted to the NDDoH.

Production Data: Lines 4

- 8

Line 4 : New wells: e nter the average daily production in BOPD , based on the first 30 days of production , excluding any days the well was not operating during that period of time

. Existing wells: enter the average daily production in BOPD, based on the most recent 30 days of production, excluding any days the well was not operating during that period of time.

Line 5 : New wells: e nter the aver age daily production of gas in Ms cf per day, based on the first 30 days of production , excluding any days the well was not operating during that period of time

. Existing wells: enter the average daily production in Mscf, based on the most recent 30 days of product ion, excluding any days the well was not operating during that period of time.

Line 6 : New wells: e nter 0.6 on this line. This equates to an 80% decline in production from the well during the first year of production. If the expected decline rate is less than 80%, then the expected decline rate should be used

. E xis ting wells: in most situations, a decline factor may not be used for an existing well; therefore, enter 1 on this line

. The Department will accept a decline

factor other than 0 .6 or 1 in the fo llowing instance: an actual decline factor (based on well production) must be submitted for each well t hat is producing for less than one year before June
1, 2011. Wells that have produced for more than one year before June 1, 2011 must use a decline factor of 1. See Appendix E for an explanation of the decline factor and how it relates to an 80% decline in production during the first year of production.13

Line 7 : No input required. This is the projected first year average daily oil pro duction rat e (BOPD). This is automatically calculated by multiplying the avera ge daily rate entered on Line 3 by the decline factor entered on Line 5.

Line 8 : No input required. This is the projected first year average daily gas production rate (M scfd ). T his is automatically calculated by multiplying the average daily rate entered on Line 4, by the decline factor entered on Line 5.

Oil/Condensate Tank Data: Lines 9

- 1 9

Line 9 : Using the drop down box, select the appropriate flash gas method used for deter mining the tank vapor emission factor (scf/bbl).

 Default Bakken EF

 Site Specific Direct Measurement

 Representative Average (This average can be established from direct measurements from

a minimum of six different wells within the same f ield and operating under sim ilar parameters; however, it requires a case

- by

- case review and approval by the NDDoH prior to submitting the registration packet).

Line 10 : Enter the scf/bbl EF based on the method chosen on Line 8.

 Default Bakken EF: If site specific data is not available, the default Bakken EF of 97.91

scf/bbl should be used.

 Direct Measurement: If site specific direct measurements have been taken, enter the measured scf/bbl EF determined from taking the direct meas urement.

 Representative average: E nter the representative average scf/bbl approved by the

NDDoH.

Line 1 1 : No input required. This is a calculated value determined by multiplying the adjusted

BOPD value on Line 6, by the scf/bbl entered in Line 9.

Line 1 2 : Enter the lower heating value (Btu/scf) of tank vapors. If site specific data is not available, use the Bakken default value of 2000.

Line 1 3 : Enter the molecular weight of the tank vapors in pounds per pound

- mole (lb/lb

- mole). If site specific data is n ot available, use the Bakken default value of 45.19.

Line 1 4 : Enter the VOC weight fraction of the tank vapor gas (C3+). If site specific data is not available, use the Bakken default value of 79.8%.

Line 1 5 : Enter the HAP weight fr action of the tank vap or gas . If site specific data is not available, use the Bakken default value of 2.26%. A complete list of HAPs is located at http://www.epa.gov/ttn/atw/orig189.html

.

Line 1 6 : Enter the H 2 S weight percent of the tank vapors.14

Line 1 7 : Enter the H 2 S mole percent of the tank vapors.

Line 1 8 : Use the drop down menu to select the type of device used to destruct tank vapors from the following options:

 Vapor Recovery Unit or Oil Stabilizer

 Enclosed Smoke less Combustor

 Utility Flare or Other 98% DRE Device

 Ground Pit Flare or other 90% DRE device

Line 1 9 : No input required. This is a fixed destruction efficiency based on the control type

selected on Line 17.

 Vapor Recovery Unit or Oil Stabilizer = 99% DRE

 Enclosed Smokeless Combustor = 98% DRE

 Utility Flare or Other 98% DRE Device = 98% DRE

 Ground Pit Flare or other 90% DRE device = 9 0 % DRE

Treater Gas Data: Lines 20

- 2 9

Line 20 : Enter the site specific Btu/scf of the wellstream gas.

Line 2 1 : Enter the average molecular weight of the wellstrea m gas in lb/lb

- mole

.

Line 22: If it is necessary to convert specific gravity to molecular weight, enter t he specific gravity of the well stream gas.

Line 23: This is the calculat ed molecular weight of the well stre am gas based on the specific gravity entered on Line 22. Enter this value on Line 21.

Line 2 4 : Enter the VOC weight fraction of the wellstream gas (C3+). Note that this is the weight percent, not the mole percent of the gas.

Line 2 5 : Enter the HAP weig ht fraction of the wellstream gas

. Note that this is the weight percent, not the mole percent of the gas. A complete list of HAPs is located at http://www.epa.gov/ttn/atw/orig189.html

.

Line 2 6 : Ente r the H 2 S weight percent of the wellstream gas.

Line 2 7 : Enter the H 2 S mole percent of the wellstream gas.

Line 2 8 : Use the drop down menu to select the type of device used to destruct the wellstream gas from the following options:

 Enclosed Smokeless Combustor

 Utility Flare or other 98% DRE Device15

 Ground Pit Flare or other 90% DRE device

 Connected to Sales Line

Line 2 9 : No input required. This is a fixed destruction efficiency based on the control type

selected on Line 25.

 Enclosed Smokeless Combustor = 98% DRE

 Utility Flare or Other 98% DRE Device = 98% DRE

 Ground Pit Flare or other 90% DRE device = 9 0 % DRE

 Connected to S ales L ine = 100% DRE

Treater Burner (s) Data: Lines 30

- 31

Line 30 : Enter the total burner rating fo r the treater burner (s) in B tu/hr. If there are multiple burners at the facility, enter the total heat input of all burners.

Line 31 : The burner (s) is /are assumed to operate 8,760 hours per year.

Truck Loading Data: Lines 32

- 38

Line 3 2: Use the drop down menu to choose the appropriate oil sales method. If oil is sold through a Lease Automatic Custody Transfer , no input values are required in Lines 30

- 35.

Line 3 3 : Use the drop down list to choose the appropriate mode of operation. The sat uration factor will automatically be selected based on mode of operation.

Line 3 4 : Enter the molecular weight of tank vapors, l b/lb

- mole. If no site specific data is available, please refer to Table 2 on the Truck Loading tab.

Line 3 5 : Enter the true va por pressure of liquid loaded, pounds per square inch absolute (psia)

. If no site specific data is available, please refer to Table 2 on the Truck Loading tab.

Line 3 6 : Temperature of bulk liquid loaded in degrees Fahrenheit. If no site specific data is available, use an estimated average annual temperature.

Line 3 7 : Enter the load rate of liquid loaded in barrels per hour.

Line 3 8 : Enter the time (in hours) it takes to loadout one load.

Pneumatic Pumps Data: Line s 3 9

- 4 3

Line 3 9 : Enter the number of pneumatic pumps at the facility.

Line 40 : Enter the hours each pump is in operation annually. For winter months only, enter 4380

hours.

Line 41 : Enter the pneumatic source consumption rate from manufacturer ’s data (scf/m in ).16

Line 42 : Use the drop down menu to choose the appropriate emission control type.

Line 4 3 : No input required. Control efficiency is automatically calculated based on control type

selected on Line 55

.

Pneu mat ic Controllers Data: Lines 4 4

- 4 5

Line 4 4 : Enter the number of pneumatic controllers at facility.

Line 4 5 : Enter the average bleed rate of device (scf/hr).

Glycol Dehydrator Data: Lines 4 6

- 4 7

Lin e 4 6 : Enter the TPY of VOC emissions calculated in GRI

- GLYCalc V4 software. (If no glycol dehydrato r is installed, enter 0)

.

Line 4 7 : Enter the TPY of HAP emissions calculated in GRI

- GLYCalc V4 software. (If no glycol dehydrator is installed, enter 0)

.



### RICE Data Input : Lines 1

- 9 7

Line 1: Enter the number of engines to be installed at the production facility.

RICE Engine #1: Lines 2

- 9

Line 2 : Engine is assumed to operate 8,760 hours per year

.

Line 3 : Enter the manufacturer’s maximum hp rating.

Line 4 : Enter the manufacturer's emission factor , actual test results or AP

- 42 factor in grams per horsepower hour (g/hp

- hr) for nitrogen oxides (NOx).

Line 5 : Enter the manufacturer's emission factor , actual test results or AP

- 42 factor in g/hp

- hr for carbon monoxide (CO).

Line 6 : Enter the manufacturer's emission factor , actual test results or AP

- 42 factor in g/hp

- hr

for volatile organic compounds (VOC ).

Line 7 : Enter the NOx control efficiency of any applicable controls (NSCR catalyst, AFRC, etc

. )

obtained from manufacturer data or actual test results

.

Line 8 : Enter the CO control efficiency of any applicable controls (NSCR catalyst, AFRC, etc

. )

obtained from manufacturer data or actual test results

.17

Line 9 : Enter the VOC control efficiency of any applicable controls (NSCR cata lyst, AFRC,

etc

. ) obtained from manufacturer data or actual test results

.

Repeat the above inp ut instructions for line 2 through 9 for each additional engine at the facility.



### 4. EMISSION SOURCE DETAILS

A. Oil/Condensate Tanks

Vapors containing regulated pollutants are released from solution in hydrocarbon liquids as the liquids are transferred from higher to lower pressure, such as from a separator to an atmospheric storage tank. These vapors are called flashing losses

.

Vapors escaping from hyd rocarbon liquids while they are stored in atmospheric tanks are called standing/working/breathing (S/W/B) losses. Standing losses are essentially evaporation losses. Working losses are those caused by decreased tank vapor space occurring as the tank is fil led. Breathing losses are those promoted by ambient changes such as increased air temperatures.

As used in this Guidance, the term

, tank emissions include all S/W/B losses and flashing

emissions together

.

B. Calculating Tank Emissions

Tank emissions are calculated using the Oil & Gas Facility Emission Calculation Workbook. The

workbook calculates th e tank emissions by using either an actual direct measurement (scf/bbl) taken by the owner/ operator, a representative average or by using the de fault Bakken P ool

emission factor of 97.91 scf/bbl described below. In addition to the scf/bbl value, the workbook

uses the molecular weight, lower heating value of the fue l and the VOC and HAP weight fractions of the tank vapors to calculate the tank vapo r emissions

.

C. Bakken Pool Tank Vapor Emission Factor

In conjunction with the NDDo H , a VOC Emission Factor Committee was formed in 2010 to

determine an emission factor that could be used for the Bakken Pool crude when calculating tank vapor emissions.

The VOC Emission Factor Committee consisted of representatives from various O&G companies, as well as several environmental consultants. After reviewing the data from 89 direct measurements taken by several owner/ operators within Mountrail County, the aver age emission

factor of all measurements taken was 55.26 scf/bbl.

Many of the facilities could actually have emissions which are considerably higher than the average emission factor. Therefore, to better represent some of the higher emitting facilities an d to avoid underestimating emissions, the 90 th percentile ( 97.91 scf/bbl ) will be utilized . I f an

owner/ operator does not have direct measurement data to support a site specific emission factor,

o r an NDDo H pre

- approved average scf/bbl e mission factor established from direct18

measurements taken from a minimum of 6 different locations operating under similar parameters (representative sample)

, the owner/ operator must use the default value of 97.91 scf/bbl.

D. Tank Emission s Control Threshold

Tank emissions require control in accordance with Appendix D of this document.

E. Tank Emission s Control Requirements

E missio n control requirements for tank emissions are outlined in Appendix D of this document. Also see Appendix C for a list of acceptable control systems or devices.

F. Produced Water T anks

A t sites where tank emissions m ust be controlled by at least 9 0 %, VOC and HAP emissions from all active produced water tanks sh all be controlled by at leas t 9 0 % w ithin 60

- days after the first

date of production

. See Appendix C for a list of acceptable control systems or devices.

G. Glycol Dehydrators

Glycol, usually tri

- ethylene glycol (TEG), is used in dehydration units to absorb water from wet produced gas. “Lean” TEG contacts the wet gas and absorbs water. Th e TEG is then considered

“rich.” As the rich TEG is passed through a reboiler and a flash separator (if installed) for regeneration, steam containing hydrocarbon vapors are released. These are then vented from the dehydration unit flash separator and/or reboiler still vent.

H. C alculat ing G lycol D ehydrator Emissions

The NDDo H recommends using GRI

- GLYCalc V4 .0 or higher to determine potential uncontrolled VOC and HAP emissions from the process vents of the dehydration unit associated with the projected ( d ecline factor applied) first year average daily gas production rate. Other emission calculation programs may be used upon approval from the NDDo H.

After running the program, p rint a copy of t h e report and include it with the Registrat ion Packet

submittal. The estimated VOC and HAP emission values also must be entered on Line 59 & Line

60 on the Input Tab of the Emission Calculation Spreadsheet.

I. Glycol Dehydrator Control Threshold

Emissions that meet or exceed the following thresholds require the still vent vapors be routed to

a control device: ≥ 5 .0 TPY of any combination of HAPs, or ≥ 15.0 TPY any combination of

VOCs

.19

J. Glycol Dehydrator Control Requirements

The following control systems or devices are accepted by the N DD o H for glycol dehydrator

emissions:

1) An enclosed, smokeless combustion device or flare that is designed and operated to reduce the mass content of VOC and total HAP emissions in the vapors vented to the

devi ce by at least 9 8 % by weight.

2 ) Any other control device (e.g. condenser or ground pit flare) or configuration that can be demonstrated to reduce the mass content of total HAP and VOC in the process gases

vented to the device or configuration by at l east 9 0 % by weight. 3) Glycol dehydrator emission controls may be removed after one year of operation provided emissions have declined to <15 TPY VOC and <5 TPY HAP. An updated GRI

GLYCalc run with new calculations must be submitted to the NDDoH with a request for control removal. No controls may be removed prior to obtaining written approval from

the NDDoH

.

K. Glycol Dehydrator Federal Regulations

A Federal regulation (40 CFR 63, Subpart HH ) may be applicable to glycol dehydrators located

at B akken Pool O&G production facilities. This regulation is beyond the scope of this document, but listed below is a brief summary of the regulation :

40 CFR 63, Subpart HH

– National Emission Standards for Hazardous Air Pollutants from

Oil and Gas Production Facilities

This federal regulation a pplies to all Bakken Pool O&G production facilities that are major and area sources of HAPs with the following exceptions:

1) A facility that exclusively processes, stores or transfers black oil

. 2) A major source prior to the point of custody transfer with a facility

- wide annual average natural gas throughput < 18.4 thousand cubic meters/day and a facility

- wide annual hydrocarbon liquid throughput < 37,700 liters/day.

L. Calculating Treater Gas Flare Emissions

T he treater flare emissions are calculated within the Oil & Gas Facility Emission Calculation Workbook using the following:

1) The projected first year average daily gas production rate. This is automatically calculated by multiplying the average daily rat e entered on Line 1, by the decline factor

entered on Line 3. 2) VOC & HAP weight fraction of gas 3) H 2 S mole percent of treater gas 4) Lower heating v alue of gas 5) Average m olecular weight of gas20

6) NOx & CO emissions are based on AP

- 42 emission factors for industrial flares.

M. Contr ol Requirements for Treater Gas

Treater gas must be routed to a gas gathering pipeline as soon as p racticable in accordance with the North Dakota Industrial Commission requirements . When a pipeline is not available, treater

ga s is required to be routed to a control system or device. See Appendix C for a list of acceptable control systems or devices

. That stated, the current opportunities to capture and transmit treater gas emissions necessitates the intermittent, or otherw ise, use of combustion

devices.

N. Natural Gas Fired Heaters & Burners

Some of the byproducts of natural gas combustion in process heaters, boilers, burners, etc. are regulated air pollutants. NO x , CO, VOC, HAP & SO 2 emissions from process unit heaters are calculated within the Oil & Gas Facility Emission Calculation Workbook using the emission factors (EF) below from EPA AP

- 42, Tables 1.4

- 1, 1.4

- 2 and 1.4

- 3 :

Table 1.4

- 1 Emission Factors from Nat ural Gas Combustion ( Excerpt from AP

- 42, Tables 1.4

- 1

, 1.4

- 2 and 1.4

- 3 )

Pollutant Natural Gas EF*

NOx 100 lb/MMscf

CO 84 lb/MMscf

VOC 5.5 lb/MMscf

HAPS 1.89 lb/MMscf

*Based on an average heating value of 1020 Btu/ scf of natural gas.

O. Truck Loading

When oil and condensate are loaded into tank trucks

, the hydrocarbon vapors released from the

tanker lines

, as the truck is filling

, contain regulated air pollutants. VOC emissions from loading oil or condensate into tank trucks are calculated within the Workbook by us ing the following

formula with data from AP

- 42 tables.

LL = 12.46 × S × P × M/T

Where: LL = loading loss, pound per 1,000 gallons of liquid loaded (lb/1000 gal)

S = a saturation factor (See Table 5.2

- 1 below) P = true vapor pressure of liquid loaded (psia) M = molecular weight of tank vapors (lb/lb

- mol) T = temperature of bulk liquid loaded (oR) (oR = oF + 460)

"S" values are obtained from Table 5.2

- 1.

"M" and " P " values are obtained from Table 7.1

- 2.21

Table 5.2

- 1 Saturation (S) Factors for Calculating Petroleum Liquid Loading Losses ( Excerpt

from AP

- 42 , Table 5.2

- 1 )

Cargo Carrier Mode of Operation * S Factor

Tank Truck and Rail Tank Cars Submerged loading of a clean cargo tank 0.50 Submerged loading: dedicated normal service 0.60 Submerged loading: dedicated vapor balance service 1.00

* Splash loading is not permitted in accordance with NDAC 33

- 15

- 07.

Table below may be used to provide the “P” and “M” values for the above equation:

Table 7.1

- 2 Properties of Selecte d Petroleum Liquids (Excerpt from AP

- 42, Table 7.1

- 2)

Petroleum Liquid

Crude Oil

RVP 5 Vapor MW

at 60 F

M V (lb/lb

mole)

50 Condensed

Vapor Density at

60F

W VC (lb/gal)

4.5 Liquid

Density at

60F

W L (lb / gal)

7.1 True Vapor Pressure, P

va (psi) at various temperatures in F

40 50 60 70 80 90 100

1.8 2.3 2.8 3.4 4.0 4.8 5.7

P. Truck Loading Control Requirements

Bakken Pool O&G production facili ties are not required to route emissions displaced from truck loading activities to a control system or device due to safety concerns. However, the owner/operator shall follow any operating and/or construction requirements established in Chapters 33

- 15

- 07 and 33

- 15

- 20 of the North Dakota Air Pollution Control Rules.

Q. Reciprocating Internal Combustion Engines (RICE)

The emission calculation workbook requires g/bhp

- hr values for VOC , NOx and CO in order to perform calculations for any particular engine. Those values may be obtained in three different

manners and are lis ted below in order of preference.

Engine Emission F actor in Order of P reference

1) Actual Stack Test 2) Manufacturer’s Engine Data 3) AP

- 42 Values

While any of the three emission factors are acceptable by the NDDo H , actual test data f ro m a particular engine

, is usually the most accurate and preferred method

. When test data is not readily available, manufacturer data for that particular engine model is the next best emission22

factor to be used. If neither test data, nor man ufacturer data is available, AP

- 42 values should be

used.

R. RICE Control Requirements

The NDDo H does not require any specific air pollution control equipment for RICE ; however, the RICE must be in compliance with all State and Federal Rules and Regulations.

S. Federal Regulations for RICE

There are several Federal regulations that may be applicable to RICE located at Bakken Pool

O&G production facilities. Th ese regulation s are beyond the scope of this document, but listed below is a brief summary of the Federal regulations that ma y be applicable . These regulations can be found at the following: http://ecfr.gpoaccess.gov

.

40 CFR 60, Subpart IIII

– Standards of Performance for Stationary Compression Ignition Internal Combustion Engines : Applies to any compression

- ignition internal combustion engine where construction is commenced after July 11, 2005 and the engine is manufactured after April
1, 2006

.

40 CFR 60, Subpart JJJJ

– Standards of Performance for Stationary Spark Ignition Internal Combustion Engines : Applies to any spark

- ignition internal combustion engine where construction is commenced after June 12, 2006 and the engine is manufactured:

 After July 1, 2007 for engines > 500 hp

 After January 1, 2008 for lean

- burn engines 5 00 < hp < 1350

 After July 1, 2008 for engines < 500 hp

 After January 1, 2009 for emergency engines

40 CFR 63, Subpart ZZZZ

– National Emission Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines : Applies to any (new, existing, modified and reconstructed) RICE located at a major source or an area source of HAPs.

T. Pneumatic Pumps

If a pneumatic pump uses natural gas as the motive gas, the pump will release VOC and HAP

emissions each time it strokes since all mo tive gas is vented by the pump. The Workbook calculates emissions from the pump based on the following:

1) M anufacturer’s information regarding gas usage (scf/hr) 2) T he VOC & HAP weight fraction of the motive gas 3) Molecular weight of motive gas 4) Hours of operation23

U. Pneumatic Pump Control Requirements

Bakken Pool O&G production facilities are required to control pneumatic pump s that use natural gas as the motive gas, if the PTE of VOCs from the pneumatic pump is >5 TPY per pump

.

V. Pneumatic Controllers

If a pneumatic controller uses natural gas as the motive gas, the device will release VOC and HAP emissions each time it operates. The Workbook calculates emissions from the pump based on the following:

1) M anufacturer’s information regardin g gas usage (scf/hr) 2) T he VOC & HAP weight fraction of the motive gas 3) Molecular weight of motive gas 4) Hours of operation

W. Pneumatic Controller Control Requirements

Bakken Pool O&G production facilities are not required to install add

- on control s for emissions from these types of devices.24

5. EFFECTIVE DATE

This policy is effective on the date shown below. This policy does not supersede any applicable state or federal rule, regulation or law.

Any questions about this document should be directe d to:

North Dakota Department of Health Division of Air Quality 918 E Divide Avenue, 2 nd Floor Bismarck, ND 58501

- 1947

Phone: 701

- 328

- 5188

This document is available at: http://www.ndheath.gov/aq

Approved: Date: May 2 , 2011

Terry L. O’Clair, P.E.

Director Division of Air Quality North Dakota Department of Health25 

## APPENDIX A

Oil & Gas Production Facility Registration Form

Following is a copy of the NDDo H Oil/Gas Production Facility Registration Form (AP

- 114)

which must be submitted as part of the registration packet within 90 days after the first date of production of a Bakken Pool O&G production facility. The form can be downloaded from the

ND Do H website ( http://www.ndhealth.gov/AQ/OilAndGasWells.htm ) and is available in both

Word and PDF formats. Also required is a copy of the gas analysis for the well and the first

three pages of the Emission Calculation Wor kbook

.262728 

## APPENDIX B

Oil & Gas Production Facility Emission Calculation Workbook Screenshots

The following pages represent screenshots of the Emission Calculation Workbook. The

workbook is available for download from the NDDo H website in Excel format at: ( http://www.ndhealth.gov/AQ/OilAn dGasWells.htm

The workbook is intended to provide an easy way for owner/ operator s to calculate emissions for

a Bakken Pool O&G production facility. With all owner/ operators using the same emission workbook, it will help e nsure that all emissions are calculated in a consistent manner from one

owner/ operator to another. It will also assist the NDDo H in tracking statewide emissions from

Bakken Pool O&G production facilities.

Please note: the only Emission Calculation Workboo k pages required in the Registration Packet are the Input Data Page , RICE Input Data Page and the Emission Summary Page (applies to all submittals )

.29



# INPUT DATA PAGE30



# RICE INPUT DATA PAGE31



# EMISSION SUMMARY PAGE32



# OIL/CONDENSATE TANKS33



# TREATER FLARE34



# TREATER BURNER35



# TRUCK LOADING36 

# RICE37



# PNEUMATIC PUMPS38



# PNEUMATIC CONTROLLERS39 

## A PPENDIX C

ND Do H ACCEPTABLE CONTROL SYSTEMS OR DEVICES

The following VOC control systems or devices are accepted by the NDDoH :

1. A ground pit flare (including, but not limited to pit flares, shop built flares or other similar oilfield type flares) or other 90% or greater DRE device. If a groun d pit flare is utilized, the ND DoH will allow a 90% DRE to be assumed. This is considered the minimum level of control for tank and treater gas emissions.

2. A vapor reco very unit or oil s tabilizer that is designed and operated to reduce the mass

content of VOC and total HAP emission s in the vapors vented to the device by at least 99% by weight. (Caution: a vapor recovery unit and oil stabilizer is used only to control

tank emissions .)

3. An enclosed, smokeless combustion device or utility flare that is designed and operated

to reduce the mass content of VOC and total HAP emissions in the vapors vented to the device by at least 98% by weight. A utility flare is any flare that is designed and operated in accordance with the requirements of NDAC 33

- 15

- 12

- 02, Subpart A 60.18 (40 CF R 60.18). Requirements of 40 CFR 60.18 include, but are not limited to the following:

 Flare shall be designed and operated with no visible emissions except for periods not to exceed a total of 5 minutes during any 2 consecutive hours;

 Flare shall be oper ated with a flame present at all times;

 An owner/operator has the choice of adhering to either the heat content specifications in paragraph (c)(3)(ii) and the maximum tip velocity specifications in paragraph (c)(4) or adhering to the requirements in (c)(3) (i);

 Flares used to comply with this section shall be steam

- assisted, air

- assisted or nonassisted;

 Owners/operators of flares shall monitor the control devices to ensure that they are operated and maintained in conformance with their designs;

 Flares shall be operated at all times when emissions may be vented to them;

 Method 22 of Appendix A shall be used to determine the compliance of flares with the visible emission provisions of this subpart. The observation is 2 hours and shall be used according to Met hod 22;

 The presence of a flare pilot flame shall be monitored using a thermocouple or any other equivalent device to detect the presence of a flame. Daily checks by an operator to verify the existence of a visible flame or to verify proper operation of

t he igniter may be used in lieu of a physical device.

4. Control devices other than those listed above may be utilized upon approval from the

NDDoH.

F or safety and air pollution control purposes on all wells: e ach flare must be equipped and operated with an automatic ignitor or a continuous burning pilot, which must be maintained in40

good working order as outlined in NDAC 33

- 15

- 07

- 02 . This is required even if the flare is used for emergency purposes only. Flares operating with automatic pilot systems are not required to operate with thermocouples.

Each combustion device must be installed with a thermocouple or any other equivalent device approved by the NDDoH designed to ensure the presence of a pilot on the devi ce. Additionally,

a continuous burning pilot is required if this department determines that an automatic ignition system is ineffective due to production characteristics.

Emissions control equipment, systems or devices, all vent lines, connections, fitt ing, valves, relief valves, hatches or any other appurtenance employed to contain and collect vapors and transport them to the em ission control system or device must be maintained and operated during any time a well is producing such th at the emissions are controlled as outlined in Appendix D

.

The owner/operator shall maintain and operate all air pollution control equipment in accordance with the manufacturer’s recommendations and in a manner consistent with good air pollution control practice for minimizing emissions. All reasonable precaution s shall be taken by the owner/operator to prevent and/or minimize opacity from the operation of the flare or combustion device. A properly operating flare should be virtually free of opacity and a minimum of a visual check of a flare for opacity should be done whenever an operator is on site. Improperly operating equipment should be thoroughly inspected and if necessary, repaired as soon as possible. Compliance with opacity requirements will be based on applicable EPA Reference

Methods.

The Department a cknowledges that emission control equipment under an operating and maintenance plan will be off

- line during routine maintenance and does not expect redundant equipment to be installed unless the uncontrolled emissions during that tim e cause the Bakken Pool O&G production facility emissions to exceed Title V or PSD thresholds.41 

## APPENDIX D

CONTROL REQUIREMENTS FOR TANK EMISSIONS

The following procedure must be fol lowed to determine the level of control required for tank

emissions from Bakken Pool O& G production facilities:

1. For production facilities where the first date of production occurred after June 1, 2011,

tank emissions must be controlled by a ground pit flare (including, but not limited to pit flares, shop built flares or other similar oilfield type flares) or other control device that

achieves at least a 90% DRE for VOCs upon startup of the facility

.

2. For production facilities where the first date of productio n occurred after June 1, 2011, the owner/operator must calculate the VOC potential to emit (PTE) from tank emissions

within 9 0 days after the first date of production and control V OC emissions as outlined in

2.a and 2.b below. For production facilities wh ere the first date of production occurred

on or before June 1 , 2011, the owner/operator must calculate the VOC PTE from tank emissions by September 1, 2011 and control V OC emissions as outlined in 2.a and 2.b

below.

a. If the PTE for VOC tank emissions is less than 20 tons/year, then a minimum of a ground pit flare (or other control device that achieves at least a 9 0 % DRE for VOCs) is required to control VOC tank emissions.

b. If the PTE for VOC tank emissions is greater than or equal to 20 tons/year, then a

control device that achieves at least a 98% DRE for VOCs must be installed and operated.

3. It is possible that the PTE for VOC tank emissions will initially be calculated to equal or exceed 20 tons/year (which requires a control devic e with at least a 98% DRE for VOCs), but future calculations may result in a PTE for VOC tank emissions below 20 tons/year (which requires at least a ground pit flare or other control device that achieves at least a 90% DRE for VOCs). In this case, the ow ner/operator may replace the 98% DRE control

device with a 90% DRE control device after receiving written approval from NDDoH . A revised well registration packet shall be submitted to the NDDoH prior to the replacement of the control device.

4. At a minimum, tank emissions must be controlled by a ground pit flare (or other control device that achieves at least a 90% DRE for VOCs). In the event of a breakdown of any control equipment used to control tank emissions, t he control equipment must be r epaired in a timely manner.42 

## APPENDIX E

The Basis for the 0.6 Factor and How it Relates to 80% Decline in Production for

the First Year

The first year daily production rates are represented by the jagged line in BOX 1 . The area

under the line represents the total actual production volume for the first year. It is difficult to calculate the total volume under the jagged line so it is smoothed out in BOX 2 using statistical

methods.

BOX 1 BOX 2

BOX 3 BOX 4

The smoothed curve is straightened out in BOX 3 , and then leveled out in BOX 4 . Now the production for the first year is represented by the area under the line in BOX 4 which is easily calculated. Production curves from a large sam pling of wells indicate the average well declines

Start Up 365 Days

MMCFD MMCFD

Actual production during the first year is represented by the area under the jagged line which ultimately turns out to be ~730 MMCF. Start Up 365 Days

MMCFD

The jagged line representing daily production is “smoothed” out using statistical methods.

Start Up 365 Days

MMCFD Start Up 365 Days

MMCFD

2 MMCFD

Leveled” out, projected daily gas production rate

vs. time
Total projected production for the first year is represented by the area under the straight line

2 MMCFD x 365 days = 730 MMCF The “smoothed” curve in BOX 2 is “straightened” out using mathematical methods.43

by 80% during the first year. That 80% decline is represented by the level line in BOX 4 after

the first 30

- day average production rate is multiplied by 0.6.

Example : For the first month the well makes a n average 3.333 MMCFD. With 80% decline during the first year, the well will make 0.667 MMCFD at the end of the first year (3.333

– 0.8(3.333) = 0.667). Then the average daily production rate over 365 days is (3.33 + 0.667)/2 =

2.0 MMCFD which is the sam e as 3.333 x 0.6 = 2.0 MMCFD.