1. HANDLING FUGITIVE EMISSIONS IN THE JUBILEE FIELD OFFSHORE
GHANA: SELECTING THE RIGHT SEALS AND OTHER ALTERNATIVES.
A Project Report presented to the
DEPARTMENT OF PETROLEUM ENGINEERING
Faculty of Chemical and Materials Engineering
College of Engineering
KWAME NKRUMAH UNIVERSITY OF SCIENCE AND TECHNOLOGY
by
HERMINIA NCHAMA ELA (MISS)
AND
BRUKUM DANIEL
in Partial Fulfillment of the Requirements
for the Degree of
Bachelor of Science (HONS)
Petroleum Engineering.
UNDER THE SUPERVISION OF MR. ABDUL HAMEED MUSTAPHA
KUMASI, GHANA.
©April, 2015.

2. I
DECLARATION
We hereby declare that the project work entitled “HANDLING FUGITIVE EMISSIONS IN THE
JUBILEE FIELD OFFSHORE GHANA: SELECTING THE RIGHT SEALS AND OTHER
ALTERNATIVES” submitted to the Department of Petroleum Engineering – Kwame Nkrumah
University of Science and Technology, is a record of an original work done by us under the
supervision of Mr. Abdul Hameed Mustapha, a lecturer of the Petroleum Engineering program,
College of Engineering, and this project work is submitted in partial fulfillment of the requirements
for the award of Bachelor of Science Degree in Petroleum Engineering. The results embodied in
this project report have not been submitted to any other University or Institute for the award of any
degree or diploma.
Date: ……………………….
HERMINIA NCHAMA ELA (MISS) ……………………………..
BRUKUM DANIEL ……………………………..
It is certified that this project has been prepared and submitted under my supervision.
MR. ABDUL HAMEED MUSTAPHA
…….…………………………………….
Date..........................................................

3. II
ACKNOWLEDGMENT
We give thanks to God Almighty for graciously guiding us through our studies and for a successful
completion of this project.
The success and final outcome of this project couldn’t have been possible without the assistance
of our supervisor, Mr. Abdul Hameed Mustapha who gave us the inspiration to pursue the project.
We are sincerely grateful for the initiative and the zeal he filled us with.
Our heartfelt gratitude also goes out to our parents, family and friends for their understanding,
encouraging and supporting us to pursue our vision of becoming petroleum engineers.
We are very grateful, God bless you all.

4. III
ABSTRACT
Fugitive Emissions (FE) from oil and gas operations are a source of direct and indirect greenhouse
gas emissions (GHG) which can lead to climate change. Fugitive emissions can cause significant
damage to the environment or harm the health of plant workers and the general public. Also these
emissions can cause regional or local concern for the air quality decolorisation and global warming
potential.
Unfortunately, these emissions are difficult to quantify with a high degree of accuracy, despite the
considerable effort made to detect, measure accurately and monitor such emissions. Also not all
the fugitive emissions are covered to the same extent i.e. flaring and venting vs. equipment leaks.
Regulations are based on an economic model rather than on a need to address environmental
impact issues. Again, according to Good Practice Guidance and Uncertainty Management in
National Greenhouse Gas Inventories “the oil and gas industry is very diverse and complex making
it difficult to ensure complete and accurate results”( of fugitive emissions).
In finding ways to mitigate the effects of these spurious emissions, there is the need to employ the
best measures in ensuring that the integrity of the sealing system associated with equipment leaks
and other sources are addressed. Other alternatives for handling fugitive emissions will be
underscored in this project. The quality of air will be improved upon as the quantities of air
pollutants are released into the atmosphere are reduced to the barest minimum. The Jubilee Field
offshore Ghana will be used as a case study.

5. IV
LIST OF ACRONYMS
API - American Petroleum Institute
AAQM - Air Ambient Quality Monitoring
AMR - Annual Monitoring Report
AMSE - American Mechanical Society of Engineers
ANSI - American National Standards Institute
BOPD - Barrels of Oil Per Day
BTEX - Benzene, Toluene, and Ethyl-xylene
CAPCOA - California Air Pollution Control Officers Association
DI&M - Direct Inspection and Maintenance
DIAL - Direct Absorption of Light
DWT - Deep Water Tano
EAs - Environmental Aspects
EI - Environmental Impact
EMP - Environmental Management Practices
FE - Fugitive Emissions
FPSO - Floating Production Storage Offloading
GHG - Green House Gases
GNPC - Ghana National Petroleum Corporation
GTG - Gas Turbine Generator
IFC - International Financial Corporation
IPCC - Intergovernmental Panel on Climate Change

6. V
ISO - International Standards Organization
LDAR - Leak Detection and Repair
LPG - Liquefied Petroleum Gas
OGI - Optical Gas Imaging
PBP - Pay Back Period
PM - Particulate Matter
SCF - Standard Cubic Feet
SGS - Société Générale de Surveillance
TAMPSS – Temperature, Application, Medium, Pressure, Size and Speed
TGL - Tullow Ghana Limited
TOC - Total Organic Compound
U.S. EPA - United State Environmental Protection Agency
UNEP - United Nation Environmental Policy
VOC - Volatile Organic Compound
WAFCO - West African Fuel Company
WCTP - West Cape Three Points
WMO - World Meteorological Organization

7. VI
LIST OF FIGURES
Figure 1. Breakdown of oil and gas process (fugitive and vented) emissions by
sector.
Figure 2. Location of the Jubilee Field
Figure 3. Graphical representation showing breakdown of GHG emissions from
production operations at the Jubilee Field in 2012
Figure 4. Percentage of flared volumes to produced volumes at the Jubilee Field
Figure 5. Seal Selection can be based on the Fluid’s Specific Gravity and the
Maximum Allowable VOC Emission Levels
Figure 6. DI & M Decision Tree
Figure 7. Pipeline Integrity Systems

8. VII
TABLE OF CONTENTS
DECLARATION................................................................................................................................ I
ACKNOWLEDGMENT.................................................................................................................... II
ABSTRACT.................................................................................................................................... III
LIST OF ACRONYMS..................................................................................................................... IV
LIST OF FIGURES.......................................................................................................................... VI
TABLE OF CONTENTS ....................................................................................................................... VII
1 CHAPTER ONE.........................................................................................................................1
1.1 INTRODUCTION...............................................................................................................1
1.2 AIMS AND OBJECTIVES..................................................................................................2
1.2.1 Main Objective.............................................................................................................2
1.2.2 Specific Objectives .......................................................................................................2
1.3 PROBLEM STATEMENT...................................................................................................3
1.3.1 Fugitive Emissions .......................................................................................................3
1.3.2 Seals............................................................................................................................3
1.4 CONCEPTS AND THEORIES.............................................................................................4
1.4.1 Potential breakdown of emissions from Crude oil and natural gas resources .....................4
1.4.2 Toxic and Non-toxic Fugitive emission gases.................................................................5
2 CHAPTER TWO ........................................................................................................................6
2.1 LITERATURE REVIEW............................................................................................................6
2.1.1 Global concern for Fugitive emission.............................................................................6
2.1.2 GHANA ........................................................................................................................6
2.2 HISTORY OF CRUDE OIL DISCOVERY IN GHANA........................................................7
2.2.1 The Jubilee Field ..........................................................................................................8
2.2.2 Air quality ..................................................................................................................10
2.2.3 History of flaring and venting at the jubilee field ..........................................................12
2.2.4 Oil Spills at the Jubilee Field ........................................................................................14
2.3 OVERVIEW OF SOURCES..............................................................................................14
2.3.1 Fugitive equipment leaks.............................................................................................15
2.3.2 Flaring and Venting ....................................................................................................16
2.3.3 Evaporation losses at production facilities ....................................................................17
2.4 DETECTION OF FUGITIVE EMISSIONS.........................................................................17

9. VIII
2.4.1 Soap Solutions............................................................................................................18
2.4.2 Odorants....................................................................................................................18
2.4.3 Portable Analyzers......................................................................................................18
2.4.4 Static Leak Indicators .................................................................................................18
2.4.5 Electronic Screening Devices ......................................................................................19
2.5 EMISSION FLOW MEASUREMENT .......................................................................................20
2.6 ENVIRONMENTAL IMPACT OF FUGITIVE EMISSIONS...............................................20
3 CHAPTER THREE...................................................................................................................22
3.1 METHODOLOGY ............................................................................................................22
3.1.1 METHODOLOGIES AND PROCEDURES THAT THE INDUSTRY RELIES ON IN
PREPARING EMISSION INVENTORIES FOR FUGITIVE EMISSIONS ..................................22
3.1.2 THE USA EPA AND API ASSESSMENT ..................................................................23
3.1.3 THE INTERGOVERNMENTAL PANEL ONCLIMATE CHANGE (IPCC)
ASSESSMENT.........................................................................................................................25
3.2 KEY CHALLENGES DURING THE ASSESSMENT OF FUGITIVE EMISSIONS.............26
3.3 SEALS..............................................................................................................................28
3.3.1 PROCESS EQUIPMENT LEAKS...............................................................................28
3.3.2 OTHER POTENTIAL FUGITIVE EMISSION SOURCES.........................................................33
3.3.3 SELECTION FACTORS OR PARAMETERS FOR SEALS IN THE OIL AND GAS INDUSTRY.........34
3.3.4 SELECTION OF THE RIGHT SEAL....................................................................................36
3.3.5 Causes of Premature failure of Process equipment.......................................................38
3.3.6 OTHER TECHNOLOGICALLY IMPROVEDALTERNATIVESFORDETECTING ANDMEASURING
FE 41
4 CHAPTER FOUR.....................................................................................................................43
4.1 REDUCING EQUIPMENT LEAK EMISSIONS.................................................................43
4.1.1 DIRECT INSPECTION &MAINTENANCE (DI&M) PROGRAM...............................43
4.1.2 LEAK DETECTION AND REPAIR PROGRAM (LDAR)...........................................45
4.1.3 THE CONCEPT OF LEAK.........................................................................................45
4.1.4 PIPE LINE INTEGRITY...................................................................................................46
4.1.5 LEAK REPAIRS AND ECONOMIC ANALYSIS .......................................................47
5 CHAPTER FIVE.......................................................................................................................49
5.1 CONCLUSION AND RECOMMENDATION....................................................................49
5.1.1 Conclusion.................................................................................................................49
5.1.2 Recommendation and further work..............................................................................50

10. IX
REFERENCES.................................................................................................................................51
APPENDIX .....................................................................................................................................52

11. 1
1 CHAPTER ONE
1.1 INTRODUCTION
Knowledge and best practices in the oil and gas industry are constantly changing. New research
and experience tend to widen our understanding, brings changes in research methodologies and
improves upon professional practices. All these processes are jeered towards developing the best
technologies for exploiting the ‘black gold’, solving and containing any problems that may be
associated with their aftereffects. In evaluating such information and methodologies, players in the
industry should be mindful of their own safety, thus, the safety of their workers, that of the
equipment being worked with and most importantly the safety of the environment in which they
are working.
According to ISO 14001, Environmental Aspects (EAs) are ‘‘elements of an organization’s
activities, products or services that can interact with the environment’’, for example, waste
management, worker protection, compliance, public safety, property damage, global warming,
process emission, toxic material management, etc. Also, the charter goes on to define Environment
Impact (EI) as ‘‘any change of the environment, whether adverse or beneficial, wholly or partially
resulting from an organization’s activities, products or services.’’ One thing that should be worth
noting is that significant EAs are the most important ones that cause the highest EIs. The petroleum
industry is among the highest generators of pollution. Whilst the industry has made major strides
to reduce hazardous waste generation and emissions, it continues to be a culprit of generating
significant levels of toxic air emissions and poorly manage its other EAs practices.
Fugitive emissions, which is a major component of process emissions, are sources of gases and
vapour from pressurised equipment due to leaks and other unintended or irregular release of gases,
mostly from industrial activities. Oil and gas operations are direct and indirect sources of
greenhouse gas emissions of which fugitive emissions play a chief part in. It has been observed
that quantification of these emissions to a high degree of accuracy remains substantially uncertain
in the values available for some of the major oil and gas producing countries. This is partly due to
the types of sources being considered. Furthermore, the oil and gas industry is very large, diverse
and complex making it difficult to ensure complete and accurate results. (D. Picard et al, 2006).

12. 2
Leaks from pressurized process equipment generally occur through valves, pipe connections,
mechanical seals, or related equipment. Fugitive emissions also occur at evaporative sources such
as waste water treatment ponds and storage tanks. Because of the huge number of potential leak
sources at large industrial facilities and the difficulties in detecting and repairing some leaks,
fugitive emissions can be a significant proportion of total emissions. Though the quantities of
leaked gases may be small, gases that have serious health or environmental impacts can cause
significant environmental problems such as climate change, global warming potential and regional
or global concern for air quality decolorisation. Fugitive emissions are deemed to be an important
part of the debate on climate change, because they represent a significant portion of greenhouse
gas emissions contributed by the oil and gas industry.
Technological innovations in the past decade have enhanced the opportunity for companies to
reduce fugitive emissions from their operations and facilities, but uncertainty remains around the
scope of the problem and how to address it. The first step in controlling fugitive equipment leaks
is to minimize potential for leaks by applying proper design and material-selection standards, to
follow the manufacturer’s specifications for the installation, use and maintenance of components
and to implement practicable control technologies. The greatest challenge now experienced by
stakeholders in the oil and gas industry is how to detect, measure, monitor, control and reduce the
amounts of fugitive emissions released into the environment.
1.2 AIMS AND OBJECTIVES
1.2.1 Main Objective
This project is aimed at analysing how fugitive emissions are handled at the Jubilee Field Offshore
Ghana, the selection of the right seals to control these emissions and providing other alternatives
to reduce any further spurious emissions of process fluids.
1.2.2 Specific Objectives
 To know the potential breakdown of hydrocarbon related fugitive emissions in the world
 To know how and why fugitive emissions occur

13. 3
 Detecting and monitoring fugitive emissions
 To determine the current inventory methodologies for quantifying fugitive emissions
 Selection of right seals for trapping spurious emission
 Selection of other alternatives for controlling and minimizing fugitive emission
 Retrofitting detected leakages
1.3 PROBLEM STATEMENT
1.3.1 Fugitive Emissions
The majority of air emissions from the oil and gas industry are from fugitive emissions which are
emissions from equipment leaks, process venting, evaporation losses, disposal of waste gas
(venting or flaring), accidents and equipment failures. The main activities in the industry related
to such spurious emissions are as follows:
 Oil and gas production
 Crude oil transportation and refining
 Natural gas processing, transportation and distribution
 Storage and tanker loading
 Pressure relief and blow outs
Some problems associated with the effects of fugitive emissions are:
 Greenhouse effect which leads to a phenomenon called global warming resulting in
climate change
 Health hazards caused by air pollution
 Economic cost of loss of commodities on the part of the Operating company
 Risk of fire and accidents such as explosions
1.3.2 Seals
Minimizing emissions to the atmosphere from machinery has been long effected by seals. In trying
to meet stricter environmental regulations for the release of Volatile Organic Compounds (VOCs),
a range of advanced technologies have been developed and made available in seal design and
materials. But the best of seals can fail, especially when neglected thus when not monitored and

14. 4
repaired in time. The type of seal selected depends on the pumped medium, operating temperature,
pressure and speed of operation. These factors when not checked to specification of operation can
mal the functioning of seals.
1.4 CONCEPTS AND THEORIES
1.4.1 Potential breakdown of emissions from Crude oil and natural gas resources
Worldwide concern for the implications of the increase in global warming, greenhouse effects,
climate change and general air quality has necessitated the identification of some sources of
emitted gases arising from industrial activities. Potential emissions in the industry are from these
gaseous components:
1. Methane (CH4) emissions, from natural gas production, processing, transmission and
distribution, oil production, forms the majority of petroleum fugitive and vented emissions.
CH4 emissions can be intentional (process venting) or unintentional (fugitive leaks, system
malfunctions).
2. Carbon dioxide (CO2) emissions by the oil and gas industry are primarily combustion
related for compressor and equipment operation. Fugitive and vented CO2 is a relatively
small source (e.g., acid gas removal during processing).
3. Carbon monoxide (CO) is generated as a result of incomplete combustion. It is a toxic gas,
reducing oxygen in the atmosphere.
4. Volatile Organic Compounds (VOCs) are organic compounds that are capable of the
formation of photochemical oxidants (ozone) by reactions with nitrogen oxides in the
presence of sunlight. Certain VOCs, in addition to having a global warming potential, are
harmful to health and are stratospheric ozone depletion substances, for example benzene.
5. Nitrogen Oxides (NOx)is a general name for nitric oxide (NO) and nitrogen dioxide (NO2).
These emissions occur almost exclusively from the combustion of fossil fuels for industry,
transport and from the burning of biomass.
6. Sulphur dioxide (SO2) is an acidic gas produced during the combustion of fuels which
contain sulphur compounds.
7. Hydrogen Sulphide (H2S) is a toxic gas with an extremely low odour threshold at low
concentration occurring during decomposition. The odour threshold increases with

15. 5
increasing concentration. Natural gas is normally treated to remove this H2S to form
sulphur or it can be burned. H2S forms SO2 during the combustion process or
photochemically when released to the atmosphere.
1.4.2 Toxic and Non-toxic Fugitive emission gases
The gases included in the fugitive emissions category can be divided into two broad groups:
1. Toxic: Hydrogen Sulphide, sulphur dioxide, Volatile Organic Compounds (VOCs), and
Benzene, Toluene, and Ethyl-xylene (BTEX)
2. Non-toxic: methane, carbon dioxide, and ethane.
The toxic and non-toxic distinction is important, because the odour of toxic gases makes them
easier to identify and monitor than non-toxic gases. Moreover, there is a more compelling
motivation for companies and governments to deal with toxic gases when an immediate public
safety or health concern surfaces. The public is more likely to react to the risk, because it is noticed
as an imminent threat. This is less the case with invisible, odourless gases like methane which,
while less to non-toxic, are less noticed, and thus can be more easily ignored, though their
environmental impacts can be quite significant.
Figure 1-1. Breakdown of oil and gas process (fugitive and vented) emissions by sector (Gas Star
Production Technology Transfer Workshop May 11, 2010.

16. 6
2 CHAPTER TWO
2.1 LITERATURE REVIEW
2.1.1 Global concern for Fugitive emission
As the world grows and economies develop, future demand for energy will continue to grow
dramatically. The International Energy Agency and others predict that the world’s total energy
demand will grow by 35% in 2030 higher than it is today, and the oil and natural gas sector is
expected to account for 60% of total energy through 2030 (Glass J.S. Jr., 2009). This implies that
fugitive emissions must be minimized in order to preserve scarce resources and address the global
climate challenge. Because of the predicted growth in emissions in the coming decades, 70-80%
will come in developing countries. (T. Arrowsmith, 2009).
The amount of methane emissions released by the natural gas (NG) industry is a critical and
uncertain value for various industry and policy decisions, such as for determining the climate
implications of using NG over coal. Previous studies have estimated fugitive emissions rates (FER)
the fraction of produced NG (mainly methane and ethane) escaped to the atmosphere between 1
and 9%. Most of these studies rely on few and outdated measurement and some may represent
only temporal/regional NG industry snapshots. The IPCC has established with a high degree of
certainty that greenhouse gas emissions have risen steadily since pre-industrial times by 70%
between 1970 and 2004 (IPCC, 2007).
2.1.2 GHANA
From the 2000-inventory year, Ghana’s current total national emission was 12.2 MtCO2e for five
direct greenhouse gases namely CO2, CH4, N2O, CF4, and C2F6. It increased to 23.9MtCO2e in
2006 which is of 0.05% of global emissions. This emission levels indicated a 243% increase from
the 1990 levels. The energy sector is the major GHG emissions source followed by land use change
and forestry and agriculture (National Greenhouse Gas Inventory 2006).
From the GHG inventory done in 2006, Ghana’s emissions were low compared to other countries,
but there was a potential for the emissions to grow and peak across sectors considering emerging
economic prospects for Ghana under for example the oil and gas industry. Carbon dioxide was the
major greenhouse emissions in Ghana however; methane was predicted to contribute significantly

17. 7
to the national greenhouse emissions in the coming years as a result of increased activities in the
oil and gas industry. The energy sector was the largest source of greenhouse emissions as at 2006
and it was predicted to dominate over time. Fugitive emissions from the oil and gas production
were expected to reflect as a major source of methane emissions as commercial oil and gas
exploitation comes on stream by the end of 2010.
2.2 HISTORY OF CRUDE OIL DISCOVERY IN GHANA
Ghana is a small country with population of about 24 million in the Western part of Africa along
the coast of Gulf of Guinea which has been prospecting for oil since 1890 (Samuel, 2008).
Historical records of petroleum exploration in Ghana dates beyond 100 years ago. West Africa and
Fuel Company (WAFCO) in 1896 initiated petroleum exploration in the then Gold Coast of Africa
(today Ghana). Even though it is difficult to agree on the pioneer role of WAFCO, per the available
data, their contribution is traced to the five drilled wells in onshore Tano fields in the Western part
of Ghana between 1896 and 1903 (Osei, B. D. 2011).
Hydrocarbon deposits are found in four main regions of sedimentary basins; three offshore basins
namely Tano-Cape Three Points Basin (Western Region), Saltpond/Central Basin (Central
Region) and Accra-Keta Basin (Eastern Region), and an onshore basin called Voltaian Basin
(Northern Region). After several decades of oil exploration, Ghana finally struck oil in commercial
quantities in her offshore West Atlantic Coast in 2007 in conjunction with some multinational oil
and gas companies. Kosmos Energy, a US-based oil and gas company, discovered crude oil in
commercial quantities in the West Cape Three Points Basin. Immediately afterwards, Tullow Oil
(United Kingdom) intensified its exploratory works and struck oil in the neighboring Deep Water
Tano Basin. From data and other studies it was concluded that both discoveries were likely from
a single continuous trap. The find was named the Jubilee Field because the year in which ‘the black
gold’ was struck in commercial quantities happened to be the same year the country celebrated her
fiftieth year independence from Britain.
Before this, in 1980, a minor oil discovery and subsequent production by Saltpond Oil Company
led to the production of oil in small quantities but fell short of domestic demand. The Saltpond
field was discovered in 1970 following the drilling of the Signal Amoco Well approximately 100
km west of Accra.

18. 8
2.2.1 The Jubilee Field
The Jubilee Field straddles the West Cape Three Points (WCTP) and the Deep Water Tano (DWT)
basins. The field is at deep water depth of 1100 m at an approximate distance of 16 km from
onshore Ghana and recoverable reserves are estimated to be more than 370 million barrels with an
upside potential of 1.8 billion barrels. The WCTP license is operated by Kosmos Energy (30.88%).
Partners on this license include Tullow Oil (22.9%), Anadarko Petroleum (30.785%), Sabre Oil &
Gas (1.85%), Ghana National Petroleum Corporation (10%) and EO Group (3.5%). On the other
hand, Tullow (49.95%) operates the DWT block. Other partners include Kosmos Energy (18%),
Anadarko Petroleum (18%), Sabre Oil and Gas (4.05%) and Ghana National Petroleum
Corporation (10%).
The discovered crude oil and gas resources in the two blocks were found to be in pressure
communication and as such concluded to be in the same reservoir. Per the Petroleum Law,
petroleum resources discovered under such circumstances are required to be produced as a unit to
reduce cost and maximize the recovery of oil and gas from the field, hence the unit Jubilee Field.
Tullow Oil was appointed as the unit operator and Kosmos Energy the technical operator for the
Jubilee Field development under a unitization agreement.
Jubilee was to be developed using a field proven subsea production and control system tied back
to a turret moored FPSO (Floating, Production, Storage and Offloading) vessel. MODEC was
awarded the engineering, procurement and construction contract to provide an FPSO. The tanker
vessel Ohdoh (owned and operated by Mitsui Ocean Development and Engineering, Japan) was
converted to FPSO Kwame Nkrumah MV21 for the Jubilee Field. During the conversion process,
a water treatment plant, a turret, a 120-room accommodation module, a crude oil separation plant,
gas processing unit and a power generation plant were installed. MODEC is responsible for all
operational and maintenance works of the FPSO.
The FPSO was installed in November 2010, at a water depth of 1,100m to subsea production
facilities. It is designed to operate for 20 years. The facility processes 120,000 BOPD and 120
MMSCF per day of gas, and has a storage capacity of 1.6 million barrels of oil. It injects more
than 230,000 barrels of water a day.
The Jubilee field contains substantial amounts of gas deposits and the country is expected to have
a higher stake in the gas from subsequent production. The government of Ghana has a policy of

19. 9
zero flaring but since production of oil from Jubilee from the last quarter of 2010, this has not been
realized. On the FPSO vessel, oil and gas are separated and the worthful oil is shipped. Part of the
gas is used to power some engines on the FPSO and part used for reinjection into three gas injection
wells for enhanced oil recovery. The rest must be transported, stored or disposed off (through
venting or flaring). Out of the 120 units of associated gas produced, about 20 are used to power
the FPSO, 30 for well injection and the remaining 70 flared or vented. Ghana National Gas
Company (Ghana Gas) was established in July, 2011 through a government initiative. The
company’s task is to build, own and operate natural gas infrastructure to process, transport and
market the gas to satisfy high domestic and industrial demand. This aims to ensure that gas
associated with the country’s oil is harnessed to the fullest. (Ministry of Energy, Ghana, 2012).
Currently, infrastructure has been put in place (construction begun in 2011) to transport gas from
the FPSO, which consists of a pipeline to the shore, a processing plant at Atuabo and a power plant
at Aboadze. The gas processing plant has not begun full operation but it has been test run. It is
hoped that by 2016, the gas processing plant will begin full operation so that the direct release of
excess natural gas into the atmosphere and its associated controlled burning will be curtailed to
enforce the ‘no flaring policy’ in the country.

20. 10
Figure 2-1. Location of Jubilee Field (Jubilee Field EIA, Project Information Posters)
2.2.2 Air quality
EMP Air Quality monitoring requirements at the Jubilee Field are based on two main factors;
1. Emission testing, which includes monitoring point source emissions from combustion
devices on board, point emissions sources from onshore activities, fugitive emissions and
flaring
2. Ambient air quality monitoring at FPSO and shore base.
Emission Testing
D’Appolonia S.p.A, an external independent monitoring group, according to its Tullow Ghana
Jubilee Project Report in 2013, came out with the conclusion that the Jubilee Field Project is
consistently reporting the Green House Gases (GHG) emissions data within the AMR and statutory
report. The GHG quantification is based on the use of empirical formulas starting from the fuel

21. 11
type and quantities used at each combustion source. The following data shows the GHG emissio ns
according to various activities under the operations of TGL;
Figure 3-2 Graphical representation showing breakdown of GHG emissions from production operations at the
Jubilee Field in 2012
Adding up to this study in November 2012, a stack and fugitive emission crusade was also done
to evaluate the emission levels from the Gas Turbine Generator (GTG), Emergency Boilers and
Port Side Crane. From these sources, the measurement of O2, CO, NO, NO2, CO2, CH4 and VOC
fugitive samples were the visible emissions that were documented.
Results from the study indicated that, reference limits of the Project were not exceeded with the
exception of NOX measured at GTG C (117 mg/dsm3) and at GTG B (123.5mg/dsm3). The GTG
has a reference limit of 51 mg/dsm3 (IFC applicable guidelines). For a similar campaign carried
out in the year 2013, exceeded amounts were reported at GTG A (71 mg/Nm3) and at GTG C
(89mg/Nm3). (Tullow Ghana Jubilee Project report 2013, 2014).
Flaring
Flaring activities on the FPSO is restricted to situations whereby there are incidences of process
upsets and in case of maintenance of equipment or tanks. Although no specific flaring limit is
being enforced by GH EPA and IFC, a maximum flaring volume of 2.5% of the total gas produced

22. 12
has been independently assumed by the Project. Thus, the volumes of fluid stream to be flared
must not exceed 2.5% of the total gas production for the specific period. It must be noted that, GH
EPA policy guidance is for TGL to avoid routine flaring. Non-routine flaring is allowable on safe
grounds but it has to be limited to minimal amounts possible.
Ambient Air Quality Monitoring (AAQM)
AAQM is aimed at evaluating the degrees of NOX, NO2, SO2 and VOC as postulated by the EMP
for the FPSO and its surroundings. According to a comprehensive report written by SGS for TGL
after a sampling campaign carried out in April 2012, the following decisions were made;
1. All locations onshore and offshore had acceptable ambient air quality levels in respect of
the parameters tested, except at the commercial port area, where lime was being discharged
during the sampling campaign and therefore could have accounted for the high levels of
particulate matter.
2. The TSP and PM10 level recorded at the commercial port area was the highest and
exceeded the EPA recommended limit set at 230 and 70 µg/m3 respectively. All other
locations recorded concentration lower than the EPA limits
3. The concentration of both SO2 and NO2 recorded at all locations offshore and onshore were
lower than the EPA guideline limit
4. Concentrations of CO at all offshore and onshore locations were lower than the EPA
guideline limit
5. Volatile Organic compounds concentrations measured at the offshore and onshore
locations were below the recommended WHO limit
6. The SGS study also provided recommendations on the possible adoption by TGL of a
continuous monitoring system to ensure more representative data are collected.
2.2.3 History of flaring and venting at the jubilee field
Flaring is a safety measure used in petroleum industries to ensure that gases are safely disposed
off. Since first oil production at the Jubilee Field late 2010, there has been flaring but only for
safety and testing reasons and within clear limits set by Ghana EPA. The agreements between

23. 13
Ghana and the operators of the Jubilee Field emphasize on the policy of zero gas flaring. However,
according to GNPC and Tullow Ghana Ltd, there are not existing infrastructures to convert the
natural gas into LPG to meet part of the country’s energy demands. On the other hand, re-injection
of the produced gas back into the oil wells is not encouraged because it can damage the reservoir
and a subsequence reduction of production. Also the Jubilee Field’s reservoir had reached unsafe
levels for gas to still be re-injected into it. The only option available in this situation is the flaring
of gas. Tullow Ghana received a permission to flare 500 Millions of standard cubic feet of gas per
month in May 2014 to save its infrastructure from collapsing. Routine gas flaring started in
February 2015 however there are concerns this could be dangerous for the environment.
FPSO tanks are maintained in a pressurized state and the vapour space created in the storage tanks
of the FPSO is filled with an inert gas to avoid the potential for fire or explosion, excess inert gas
is vented during cargo tank filling operations. Air pollutant emissions from the drilling rigs and
the FPSO are expected to be rapidly diluted and dispersed in the offshore atmosphere. There may
be some decrease in air quality within several hundred meters around these emission sites.
0
10
20
30
40
50
60
Figure4 Percentageof flared volumes to total produced gas
volumes at the Jubilee Field
2011 2012 2013 2014

24. 14
2.2.4 Oil Spills at the Jubilee Field
Oil tankers, underwater pipelines, offshore oil drilling rigs and coastal storage facilities can
unintentionally release crude oil into the sea, and a significant portion of the environment, both
offshore and onshore. Over the years, oil and gas industry has witnessed oil spills that have cause
considerable damage to the environment. The offshore Jubilee field Ghana has for some time now
experienced some environmental challenges as a result of oil spills during operations. The first oil
spill was encountered in December 2009 when Kosmos Energy spilled 600 barrels of low toxicity
oil-based mud during the exploration in the jubilee field in Western Region of Ghana. (EPA, 2010).
Tullow Oil also spilled some 37 liters of oil on January 1, 2010 due to the breakage of their link
pipes. In March 2010, some quantity of oil was again spilled into the sea by Kosmos. Again two
oil recordable spills event occur respectively on 06/02/2012 (63.4 barrels) and 08/07/201 2 (20
barrels). Both oil spills were reported by TGL.(Anon, 2010).
2.3 OVERVIEW OF SOURCES
The sources of fugitive emissions in the oil and gas systems include, but are not limited to,
equipment leaks, evaporation and flashing losses, venting, flaring, incineration and accidental
releases (e.g., pipeline dig-ins, well blow-outs and spills). While some of these emission sources
are engineered or intentional (e.g., tank, seal and process vents and flare systems), and therefore
relatively well characterized, the quantity and composition of the emissions is generally subject to
significant uncertainty. This is due, in part, to the limited use of measurement systems in these
cases, and where measurement systems are used, the typical inability of these to cover the wide
range of flows and variations in composition that may occur.
Even where some of these losses or flows are tracked as part of routine production accounting
procedures, there are often inconsistencies in the activities which get accounted for and whether
the amounts are based on engineering estimates or measurements.
In general, fugitive emissions from oil and gas operations offshore are attributed to the following
primary type of sources:
1. Fugitive equipment leaks

25. 15
2. Process venting
3. Evaporation losses
4. Disposal of waste gas streams (venting and flaring)
5. Accidents and equipment failures (well blowouts, tank explosions, pipeline breaks)
There are also additional sources which may be encountered at oil and gas facilities, but these
sources do not contribute to the major GHG emissions in the oil and gas industry. These may
include: land disposal of solid waste and methane emissions from wastewater handling.
2.3.1 Fugitive equipment leaks
Fugitive equipment leak is defined as the uncontrolled loss of fluid through the sealing
mechanisms separating the process fluid from the atmosphere. Leakage from equipment may be
due to the characteristics of the equipment itself or may result from faulty equipment or
inadequately maintenance of the equipment. Process equipment components that are sources of
fugitive emissions through leaks include:
 Pumps
 Compressors
 Valves
 Pressure relief valves
 Pipe connections
2.3.1.1 Pumps
Pumps are used extensively by industries to move organic liquids. The most widely is the
centrifugal pump. Most pumps have a moving shaft which is exposed to the atmosphere. The fluid
being moved inside a pump must be isolated from the atmosphere. This requires a seal. Leaks can
occur at the point of contact between the moving shaft and stationary casing.
2.3.1.2 Compressors
Compressors are basically pumps that are used in gas service. Gas compressors used in process
unit can be driven by rotary or reciprocating shaft. Rotary shafts may use either packed or

26. 16
mechanical seals, while reciprocating shaft must use packed seals. As with the seals in pumps, the
seals in compressors are likely to be sources of fugitive emissions from compressors.
2.3.1.3 Pressure relief valves
These are devices designed to open when the process pressure exceeds a set pressure. This allows
the release of vapors or liquids until the system pressure is reduced to its normal operating level.
When the normal pressure is retained, the valve resets, and a seal is again formed. There are two
potential causes of leakage from relief valves. One is when the system pressure is being close to
the set pressure of the valve. This occurs when the operating pressure exceeds the set pressure for
a short period. The other cause of leakage is improper valve reseating after a relieving operation.
2.3.1.4 Pipe connections
2.3.1.4.1 Agitators
They are commonly used to stir or bend chemicals. Like pumps and compressors, agitator may
leak organic chemicals at the point where the shaft penetrates the casing. Consequently, seals are
required to minimize fugitive emissions from agitators.
2.3.1.4.2Flanges
Flanges are bolted, gasket-sealed junctions between sections of pipe and pieces of equipment. They
are used wherever pipe or equipment components (pumps, valves, vessels) require isolation or
removal. The possibility of a leak through the gasket seal makes them a potential source of FE.
Normally pumps/ compressors account for 10%, flanges-5%, tanks-10%, relief valves-15% and
valves-60% of the total fugitive emissions in a processing facility (Fluid Sealing Association,
2008). Valves which represents 60% of fugitive emissions presents the greatest opportunity for
reducing fugitive emissions.
2.3.2 Flaring and Venting
Venting is the controlled release of gases into the atmosphere in the course of oil and gas
production operations. These gases might be natural gas or other hydrocarbon vapours, water
vapour, and other gases, such as carbon dioxide, separated in the processing of oil or natural gas.
In venting, the natural gases associated with the oil production are released directly to the
atmosphere and not burned. Venting is normally not a visible process. However, it can generate

27. 17
some noise, depending on the pressure and flow rate of the vented gases. In some cases, venting
is the best option for disposal of the associated gas.
Flaring is the controlled burning of natural gas in the course of routine oil and gas production
operations. A flare is normally visible and generates both noise and heat. During flaring, the burned
gas generates mainly water vapour and carbon dioxide. For environmental and resource
conservation reasons, flaring and venting should always be minimized as much as practicable,
consistent with safety considerations. Flaring and venting can have local environmental impacts,
as well as producing emissions which have the potential to contribute to global warming. Available
data indicate that, on a worldwide basis, gas flaring contributes only 1% of anthropogenic carbon
dioxide emissions, and flaring and venting contribute only 4% of anthropogenic methane
emissions.
2.3.3 Evaporation losses at production facilities
Production facilities are often equipped with one or more fixed-roof tanks for temporary storage
of the produced hydrocarbon liquids (i.e., oil or condensate). If these tanks are vented to the
atmosphere, they are sources of storage losses (i.e., product is lost to the atmosphere due to
evaporation effects). Such losses are a major source of emissions in the upstream oil and gas
industry accounting for about 24% of all total hydrocarbons losses emissions by the industry.
Moreover, they constitute a loss of potential revenue. In some cases there may be an attractive
economic benefit to controlling these losses.
2.4 DETECTION OF FUGITIVE EMISSIONS
A variety of approaches are used for leak detection. Advances in environmental technologies over
the past decade or so have made it increasingly possible to overcome some of the key obstacles in
identifying, measuring, and monitoring fugitive emissions in the oil and gas industry. As a result,
companies are now better able to construct economic evaluations of the costs to take action to
reduce these emissions, if they so choose.
Below is a brief description of some of the technologies used to identify and measure fugitive
emissions (intentional and unintentional).

28. 18
2.4.1 Soap Solutions
A soap solution is applied directly on the component and leaks are detected by the appearance of
bubbles. This technique is qualitative only but leak rates can be evaluated by the degree of bubbling
action.
2.4.2 Odorants
Odorants are usually used in gas distribution systems for leak detection in consumer sites. The
odorants are powerful sulphur containing components that are readily detected in small
concentrations by humans. While it is impractical to inject odorants on a continuous basis it may
be useful to periodically inject some into a gas stream to help provide a gross indication of where
there are leaks occurring.
2.4.3 Portable Analyzers
For many regulations with leak detection provisions, the primary methods for monitoring to detect
leaking components is EPA Reference Method 21. Method 21 is a procedure used to detect VOC
leaks from process equipment using analyzer. A portable analyzer is a monitoring instrument is
used to detect hydrocarbons leaks from individual pieces of equipment. These instrument are
intended to locate and classify leaks based on the leak definition of the equipment as specified
regulation, and are not used as a direct measure of mass emission rate from individual sources.
The instrument provides a reading of the concentration of the leak in either parts per million,
percent concentration or parts per billion. The analyzer requires responding to the compounds
being processed, being capable of measuring the leak definition concentration specified in the
regulation, being readable to ±2.5% of the specified leak definition concentration and being
equipped with an electrically driven pump to ensure that a sample is provided to the detector at a
constant flow rate.
2.4.4 Static Leak Indicators
This includes a number of technologies used to detect higher risk leak sources as soon as they
occur:

29. 19
 Bag and Streamer: An impermeable expandable bladder, such as a wide rubber band, or
plastic material can be wrapped around the flange and sealed. As a leak develops the
bladder expands and provides a visual display. A small hole in the side of the bag provides
a means for the gas to escape without rupturing the bag. This hole could also contain a
whistle or a streamer to provide an audible or visual signal.
 Color Indicating Tape: A chemical agent that reacts in the presence of natural gas, or a lack
of oxygen, and changes color can be added to one side of a transparent tape. This tape can
be wrapped around the flange with the reagent exposed to the vapor space inside the flange.
If a leak occurs, the reagent changes color indicating a leak.
 Chronic Leak Monitoring: Continuous monitoring on individual potential leak sources may
be possible utilizing equipment to detect a leak at a specific source which sends an
electronic signal or triggers an audible alarm for the operator. Various detection principles
may be used such as combustible detectors, ultrasonic/sonic, thermal conductivity,
vibration, or infrared.
2.4.5 Electronic Screening Devices
There are a variety of hand held instruments that can be used to check leaks where a soap solution
fails such as leaks with large holes or gaps.
 Gas Monitors: Various handheld gas monitors or “sniffers” are available. A sample of a
gas stream in the area of a suspected leak is drawn into the device and one of a number of
analyzers is used to determine if a hydrocarbon is present. Most detectors will provide a
positive response if a gas other than air is encountered.
 Ultrasonic Leak Detectors: Ultrasonic detectors can listen for leaks using acoustic analysis.
The main use for these devices is to check for leakage from relief valves and other devices
that might allow gas to be lost to flare or other relief or closed collection systems. The
devices allow the survey technician to hear the flow through the valve even though there
may be no external indication (ice build-up or vibration).
 Laser or Infrared Detectors: New devices have been developed and are coming into greater
use; they allow the plume from the leak to be detected at a distance. These systems are
generally mobile and are better for detecting leaks outdoors and in hard to reach locations
where use of hand-held devices would be difficult or require cranes or lifts.

30. 20
2.5 EMISSION FLOW MEASUREMENT
Once a leak has been detected some of them may be easily stopped by simply fastening a fitting
packing or flange. Sometimes it may also be suitable to define the leakage rate, particularly if the
repair and reduction or decrease of the leak needs a process unit shut down or any other action that
would make repairs high-priced. Various methods are available for quantify leak rates.
 Hi-Flow Sampler: this method measures the leak with accuracy. The device used captures
the total leak and ambient air around the leak by the used of vacuum. It is totally portable
with battery power that allows the collection of sample. A hot wire anemometer is usually
used to determine flow rate.
 Bagging: An impermeable bag of a given volume is attached to the leaking source. Then
the time it takes to fill the bag is recorded to find the flow rate. The contents of the bag
can then be sub sampled for compositional analysis or by a hand held monitor to determine
combustible gas content.
 Rotameters: They are devices that allow for a quick and moderately precise flow
measurement based on a variable area principle. The device is positioned in the vertical
position and the flow to be measured is brought in from the bottom. While the flow
increases, the flow begins to increase and ascent and allows the gas to pass between the
float and inside walls of the tapered tube. The height of the float in the tube can be
correlated to a flow rate and is read off a scale on the side of the pointed tube.
2.6 ENVIRONMENTAL IMPACT OF FUGITIVE EMISSIONS
The oil and gas industry is the major source of greenhouse gas emissions. These emissions include
substances that are limited to global warming and others with local effects such as acidification of
lakes and forest. The oil and gas industry is an important source of volatile organic compounds
(VOC). Volatile organic compounds when combined with nitrogen oxides they can contribute to
the generation of ground-level ozone. Also nitrogen oxides contribute to acidification and
eutrophication.

31. 21
Flaring and venting can have a local environmental impact in such a way that flaring produces
predominantly carbon dioxide emissions while venting produces mostly methane emissions. Both
carbon dioxide and methane are known as greenhouse gases associated with concerns about global
warming whereas the two gases have different effects on the environment, however the global
warming potential of methane when compare to that of carbon dioxide suggest that flaring is more
environmentally friendly option than venting.
Emissions to the atmosphere from the oil and gas industry are increasingly becoming a very
important subject to both national government and the industry because of the negative effect on
climate. During the production of hydrocarbons at the Jubilee Field, the principal emissions that
comes along with flared gas contain toxic byproducts such as methane and benzene also generate
carbon dioxide, carbon monoxide, volatile organic compounds, sulphur dioxide, nitrogen sulphide
and nitrogen oxide. As we said earlier some of these gases can contribute to the effect of global
warming while the sulphur gases and carbon dioxide can contribute to the formation of acid rain
which is detrimental to soil fertility and vegetation when they become in contact with water.
Therefore, for example, the Ankasa Forest Reserve and the surrounding vegetation and farmlands
that are located near the border with Cote D’Ivoire, could be damaged due to gas flaring and
venting activities from the Jubilee Field.

32. 22
3 CHAPTER THREE
3.1 METHODOLOGY
3.1.1 METHODOLOGIES AND PROCEDURES THAT THE INDUSTRY RELIES ON IN
PREPARING EMISSION INVENTORIES FOR FUGITIVE EMISSIONS
The reason for preparing an accurate emission inventory is not just to satisfy statutory reporting
requirements. The objective of environmental acts, laws and regulations is to protect the general
public at large. Regulators in the industry are concerned with relying on reported emission values
to assess the risks of air pollution and in effect devise ways of reducing these risks. When oil or /
and gas fields, gas processing plants, refineries and industries under-report their emission rates and
values, the health of the public is placed in danger since the actual emissions from the operations
of these sectors are not made known.
Emission inventory refers to the mass rate accounting of priority pollutants from the different
sources within a manufacturing process (Cheremisinoff and Rosenfeld, 2009). In the preparation
of emission inventories for industries, emission factors to volume or mass production rates are
applied. According to USA EPA, “An emission factor is a representative value that relates the
quantity of a pollutant released to the atmosphere with an activity associated with the release of
that pollutant. These factors are usually expressed as the weight of pollutants divided by a unit
weight, volume, distance or duration of the activity emitting the pollutant (e.g. kilograms of
particulate emitted per megagram of coal burned). Such factors facilitate estimation of emissions
from various sources of air pollution. In most cases, these factors are simply averages of all
available data of acceptable quality, and are generally assumed to be representative of long-term
averages for all facilities in the source category (i.e. a population average).”
The following general data are required for fugitive emission estimation calculation:
a. The number of each service type of component ( e.g. valves, flanges, etc.) in each process
unit
b. The service each component is in (e.g. gas, light liquid, heavy liquid, water or oil)
c. The weight fraction of total organic compounds (TOCs) within the stream

33. 23
d. Operational hours for particular streams (e.g. hours/year)
Two guidelines that will be underscored in this discourse are:
(i) The method adopted in the USA for the industry sector by the US Environmental
Protection Agency (EPA) in the 1995 and the American Petroleum Institute (API) in
1996 (Method 21)
(ii) The Intergovernmental Panel on Climate Change (IPCC) in 1988.
Both guidelines have been reviewed and renewed over the years after they were first introduced.
3.1.2 THE USA EPA AND API ASSESSMENT
Four different methods have been devised that can be used in applying estimations to fugitive
emissions and these are:
1. Average Emission Factor Method
2. Screening Value Range Method
3. Correlation Equation Method
4. The Unit-specific Correlation Equation
3.1.2.1 The Average Emission Factor Method
Here, emission factors are combined with equipment counts to calculate emissions. This method
is normally recommended when no screening data are available and as such is the least-cost
methodology. Facilities that rely on this method are normally deemed to be irresponsible. This is
because there are no technological reasons why a facility is not able to perform screening audits.
In addition to the general data required for the calculation of fugitive emissions, the following
steps are used:
1. The number of components in each service type group is multiplied by the corresponding
average emission factor to obtain the subtotal of emissions from the group.
2. The subtotals of the various emissions groups are then added together to provide the total
emission from the facility.

34. 24
As an example, CAPOA (1999) investigated 5000 components at a refinery. The components were
inventoried into eight groups of component type or service type corresponding to the USA EPA
Protocol of average emission factors. The number in each group is multiplied by the appropriate
corresponding average emission factor in Appendix A. The total emission estimate for the refinery
was estimated to be 0.0944 kg/h. The subtotals in each group can also be further multiplied by the
number of operational hours in a year or quarterly in other to determine the mass emissions for the
period.
3.1.2.2 The Screening Value Range Method
The Screening Value Range Method was previously referred to as the Leak/No Leak Method. It
relies on the screening data from Organic Vapour Analyzers (OVAs) to estimate the mass emission
rates based on the component leak level. A leak below 10,000ppm is defined as no leak while those
equal to or greater than 10,000ppm are classified as leak (USA EPA). This fugitive emission
estimation method is also listed under the least-cost emission methodology inventory. In the
application of this method, the following steps are followed (Appendix B):
1. The total number of components in each group (component type and service type) with
their corresponding screening values (whether below 10,000ppm or above 10,000ppm) are
determined.
2. The total number of components under each group is multiplied by their corresponding
screening value emission factor.
3. The subtotals of emissions from all subgroups are added to estimate the total fugitive
emissions from the facility.
3.1.2.3 Correlation Equation Method
In the Correlation Equation Method, screening values for all equipment components are singularly
used in correlation equations or counted as either defaults zeros or pegged components. Following
recommended guidelines published in the CAPCOA guidance document:
 Default zero factors are applied only when the screening value, corrected for background ,
equals 0.0ppm (this implies that the screening value detected at the component is
indistinguishable from the background reading)

35. 25
 Correlation equations which apply to actual screening values, corrected for background
and 9,999ppm. This is used for components that are detected to have screening values up
to 9,999ppm.
 Pegged factors that apply for screening values, corrected for background, which is equal to
or greater than 10,000ppm and 100,000ppm. For the 10,000ppm pegged factors, the
screening value is between the background and 9,999ppm while the 100,000ppm pegged
factors are based on screening values between the background emission and 99,999ppm.
The following procedure is applied in this method (Appendix C):
1. Each individual components screening value is recorded.
2. The data is grouped into the three categories of screening ranges, thus, default zero range,
correlation equation range and pegged source range.
3. The number of components in the default zero range is multiplied by their appropriate
default zero factors.
4. The individual component screening value within the correlation range is entered into the
appropriate correlation equation.
5. The number of components with the screening values in the pegged rang is multiplied by
the appropriate pegged value emission factors.
6. The total fugitive emissions from the facility can then be estimated by summing up all the
calculated emissions from each subcategory.
3.1.2.4 The Unit-specific Correlation Equation Method
In the Unit-specific Correlation Equation Method, a particular set of individual equipment
component are selected for screening from which screening and actual mass emissions are
measured directly from. Unit-specific correlation equations and some pegged source factors are
then used to estimate emissions.
3.1.3 THE INTERGOVERNMENTAL PANEL ON CLIMATE CHANGE (IPCC)
ASSESSMENT
The IPCC was established by the World Meteorological Organization (WMO) and the United
Nations Environment Program (UNEP) in 1988. Its main objective was to assess scientific,

36. 26
technical and socio-economic information relevant to the understanding of human-induced climate
change, potential impacts of climate change and options for mitigation and adaptation
(Cheremisinoff and Rosenfeld, 2009).
A three-tier approach has been devised by IPCC for estimating fugitive emissions from the
operations of the oil and gas industry;
1. Top-down average emission factor approach
2. Mass balance approach
3. Rigorous bottom-up approach
3.1.3.1 Top-down average emission factor approach
The Tier 1 is a top-down approach where average production-based factors are applied to reported
oil and gas production volumes. It is typically applied in countries with very limited oil and gas
industries.
3.1.3.2 Mass balance approach
Tier 2, which considers a mass balance approach, is intended primarily for systems where the
majority of gas production is flared or vented. The total amount of gas produced with oil is assessed
and then control factors are applied to account for conserved, re-injected and utilized volumes.
The results is a determination of the amount of gas either flared or lost directly to the environment.
3.1.3.3 Rigorous bottom up approach
Tier 3 is a rigorous assessment of fugitive emissions from individual sources or components using
a bottom-up approach that requires infrastructure data and detailed production data. Results are
aggregated from individual facilities to determine total emissions.
3.2 KEY CHALLENGES DURING THE ASSESSMENT OF FUGITIVE EMISSIONS
A number of challenges have been faced by the industry, government and other stakeholders when
addressing fugitive emissions. The main challenges are as follows.

37. 27
The identification of sources
When the leak occurs in a large facility area the source may be quite complex when there are
thousands or hundred components. The only way that the leak can be detected is when the leaking
fluid is toxic. How detection can be done effectively and economically also represent a key
challenge for the oil and gas industry as part of the challenge the industry need to conduct an early
detection and repair system.
Measurement of fugitive emissions
When assessing fugitive emissions both intentional and unintentional, accuracy is difficult to
achieve technically and practically. Even when using the most advance technology there is a
substantial amount of uncertainty involved. The uncertainty is due to the fact that there is an
absence of activity data. Also the complexity of the facility and the type of emissions could be a
factor.
Return on the investment
Setting up fugitive emissions management programs which can deliver the expected return-on-
investment is such that the allocation of financial resources to those programs knowing that the
return on investment is very poor than that for other possible allocations represent a particular
challenge to the industry. Again the time to see the reward is longer than any other plant production
related activities.
Lack of public engagement
Whenever the leaking fluid is of a toxic nature or when the event that occurs affects the plant
workers there is always public welfare to increase awareness, regulators and companies so that
they can take action. However when the leaking fluid is non-toxic it is difficult for such procedures
to be implemented.
Technology
The advance technology used to detect and measure fugitive emissions in the oil and gas industry
notably provide an accurate measurement of volumes and also the capacity to determine the

38. 28
potential economic benefits for acting to minimize these emissions. But the crucial issue about
technology is the cost.
3.3 SEALS
Liquids and gases mostly transferred by rotating equipment make use of seals to isolate the fluid
medium from the atmosphere during the operation of the process equipment. Pumps, compressors
and valves make use of seals in preventing leakages of process fluids from being introduced into
the environment. Generally, seals are devices that are used in connecting systems or mechanisms
so as to minimize or stop leakages in a structure which is under pressure. The oil and gas industry
has certain commonalities driven from experience for selecting the right sealing system for the
right job.
3.3.1 PROCESS EQUIPMENT LEAKS
There are various types of seals that are employed in isolating process fluids in pumps,
compressors, valves, pressure relief devices, agitators from leaking to the atmosphere.
3.3.1.1 PUMP SEALS
One of the most common piece of equipment sold for use in the industry for offshore operations
are pumps. Packing and mechanical seals are the two generic pump seals used to mitigate leakages
between the moving shaft elements and stationary housings. These packing and mechanical seals
must be used to ensure that leakages are controlled. The rotating element extends through the
stationary housing of the pump in which a sealing device can be installed.
Packing Seals
Packing seals is used on both reciprocating and centrifugal pumps. The stuffing box (cavity) of the
pump contains tightly compacted packing material to form a seal around the rotational drive shaft.
The compression applied in the stuffing box to the seal is made possible by a packing gland. To
prevent frictional heat accumulation between the moving shaft and the seal of the pump, a
sufficient amount of either the process fluid or a supplementary liquid (lubricant) is allowed to

39. 29
flow between the packing and the moving shaft. The sealing system here is parallel to the moving
shaft.
Mechanical Seals
Currently, mechanical seals are the most widely used seals in pumps. There are two types of
mechanical seals in use; single mechanical seals and double or dual mechanical seals. The single
mechanical seals are made up of two sealing elements which are the mating ring (stationary) and
the primary ring (rotating). A nearly all over seal is created where the surfaces of the two ring
element contacts are lapped. This ensures a very high degree of flatness to maintain contact over
the entire material surface.
Double mechanical seals are much more efficient than single mechanical seals in controlling
leakages. Double mechanical seal are arranged in either back-to-back or in tandem. In a back-to-
back arrangement, the inner and outer seals (both containing stationary and rotating rings) face
each other in the opposite direction. There is a closed cavity between the two seals. A seal liquid,
such as oil or water, is circulated through this seal-housing cavity. In order for the seal to function,
the seal liquid must be at a pressure greater than the operating pressure of the liquid being pumped
at the stuffing box. This lubricant is called a barrier fluid. As a result, some liquid will leak across
the seal faces passing into the stuffing box and also out past the outer seal face to the atmosphere.
The inner and outer seals face the same direction in the tandem mechanical seal arrangement. The
inner seal is located in the stuffing box housing rather than in the seal housing. The fluid used for
lubrication is of a lower pressure than as compared to the pressure of the pumped medium. The
lubricant in this case is called a buffer fluid.
The sealing elements in mechanical seal are perpendicular to the moving shaft of the pump. Also,
mechanical seals can be equipped with secondary seals. Secondary seals prevent leakage between
the rotating ring and shaft, the stationary ring and gland plate, and the stuffing box housing and
gland ring. The secondary seals are often flexible O-ring. Mechanical seals even equipped with
secondary seals are not leak-proof.

40. 30
3.3.1.2 COMPRESSOR SEALS
As with seals in pumps, compressor seals are potential sources of fugitive emissions. Shaft seals
for compressor seals maybe labyrinth seals, restrictive carbon ring seals, liquid film seals and
mechanical contact seals. One point worth mentioning is that all seals used in the various
operations are leak restrictive devices which may not completely get rid of leakages but aimed at
ensuring that emissions from such sources are greatly reduced. Compressors are normally
equipped with ports in the seal area to evacuate gases that will be accumulated there. Discharging
of gases from these ports should be done with care to prevent venting into the atmosphere.
Labyrinth Seals
Labyrinth seals are composed of a series of close tolerance, interlocking teeth that limit the flow
of gas streams along the shaft. A whole lot of teeth design and materials of construction are
available. Of the different types of compressor seals, labyrinth seals have the largest leak potential
but when properly applied variations in tooth configuration and shape can drastically reduce leak
potential to about 40% of the other types.
Restrictive Carbon Ring Seals
Restrictive carbon ring seals are made up of a series of stationary carbon rings with close shaft
clearances. This type of seal may be operated dry or with a sealing fluid. A restrictive carbon ring
seal normally attain a lower leak rate than the labyrinth type.
Liquid Film Seals
Liquid film seals are usually fitted in centrifugal compressors. The seal constitutes a film of oil
between the rotating shaft and stationary gland. The process gas can be discharged into the
atmosphere when the circulating oil is returned to the oil reservoir. To mitigate this occurrence
from the seal oil system, the oil reservoir can be vented to a control device.

41. 31
Mechanical Contact Seal
Mechanical contact seals for compressors and mechanical seals described previously for pumps
are alike. The clearance between the rotating and stationary elements is essentially reduced to
naught by the seal. Mechanical contact seals, like mechanical seals in pumps, can achieve the
lowest leak rates even though they may not be suited for all processing conditions.
3.3.1.3 VALVE SEALS
Many different types of valves exist, however, they can be classified into three functional groups:
1. Block valves are used for on and off control of process equipment. Typically, these valves
are used occasionally, such as when there is a process change (i.e., unit shutdown).
2. Control valves are used for flow rate control.
3. Check valves are used for directional control purposes.
Valves are activated by a valve stem. All the various categories of valves have stem except check
valves. The valve stem maybe in rotational or linear motion. Process fluids that flow through the
valve stem must be isolated from the atmosphere. This is where valve seals come in. Check valves
are wrapped within process piping and as such are not considered to be a potential source of
fugitive emissions. Sealing valve stems is achieved by applying a packing material or O-ring seal.
The packing material is installed around the stem area of the valve and compressed to form a tight
seal by the help of a packing gland. The packing material used depends on the valve application
and configuration. The packing gland must be tightened to continue providing a tight seal during
the self-life of the valve.
Elastomeric O-rings
These provide good seals in process valves but are not suited where sliding motion occurs through
the packing gland. As a result, Elastomeric O-rings are seldomly used in high pressure service.
The O-ring material also limits the operating temperature of this device.
Bellows seals
Bellows seals are described as having a more effective sealing system for preventing process fluid
leaks than any conventional packing or any gland-seal arrangements. This seal incorporates a

42. 32
formed metal bellows that make a barrier between the disc and body bonnet joint. The bellows is
the weak point of the arrangement and its service life can be quite varying. The bellows seal is
often backed on a packing gland and usually fitted with a leak detector in case the seal fails.
AGITATOR SEALS
In the operation of agitators in stirring or blending chemicals, leakages may occur at the point
where the shaft penetrates the casing body. Seals are therefore required to minimize fugitive
emission from agitators. Four seals commonly used with agitators are packed seals, mechanical
seals, hydraulic seals and lip seals. Of all these, mechanical seals are the most expensive.
Mechanical seals greatly reduce leakage rate. This compensates for the high cost. Packed and
mechanical seals used with agitators are similar in design and application to those for pumps and
compressors.
Hydraulic seals
Hydraulic seal is the simplest and least used agitator shaft seal. For this seal, an annular cup fixed
to the process vessel contains a seal liquid which is in close interaction with an inverted cup
attached to the rotating agitator shaft. The principal advantage of this seal over the other agitator
seals is that it is a non-contact seal. Hydraulic seals function best in low temperature and pressure
conditions and can handle only very small pressure fluctuations. Process fluids which pass through
the rotating shaft may contaminate the seal liquid and further released into the atmosphere as
fugitive emissions.
Lip seals
The sealing element of the lip seal is a spring-loaded elastomer. It is usually installed on a top-
entering agitator as a dust or vapor seal. This type of seal is relatively inexpensive and easy to
install as well. The lip seal when set up for use is in continuous contact with the rotating agitator
shaft. Fugitive emissions could be released through this seal when it wears excessively as a result
of the operational pressure and temperature exceeding that of the seal’s set pressure and
temperature limits. The set pressure and temperature limits are dependent on the characteristics of
the elastomer.

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3.3.2 OTHER POTENTIAL FUGITIVE EMISSION SOURCES
FLANGES
Flanges are bolted, gasket-sealed junctions between sections of pipe and pieces of equipment. They
are used whenever pipe or equipment components (vessels, pumps, valves, heat exchangers, etc.)
may require isolation or removal. Since there is a possibility of a leak through the gasket seal,
flanges are rendered a potential source of fugitive emissions. Although there are many of flanges
in a processing unit system, their overall contribution to emission rate is small than as compared
to valves. Most flanges cannot be isolated from the process to allow for gasket replacement. The
ideal procedures to undertake when repairing a flange which is found to leak are to tighten any
loosed flange bolts or inject a sealing fluid. Much remedial works can be done on flanges when
the process operation is shut down or during maintenance operations.
COOLING TOWERS
A cooling tower extracts heat from water that is intended to be used to cool process equipment
such as heat exchangers, condensers or reactors. The cooling water is circulated through some of
the process units in tubes and delivered to the cooling tower where the water is cooled. In the
cooling tower, as air is circulated through the now tempered to hot water to remove the heat, a
portion of this water is evaporated to the atmosphere. The not used up water is cooled by furnishing
the heat for this evaporation process. Fugitive emissions can be released into the atmosphere as
contaminated water vaporizes in the tower. The contamination of the cooling water could be the
results of organic fluids entering the cooling water from leaking process equipment or directly
using contaminated process water as makeup water for the cooling tower. To counteract this
happening, the amount of hydrocarbons entering the cooling tower must be reduced. In doing this,
all nearby potential equipment leak sources should be fixed if damaged and monitored regularly.
Also, cooling towers that make use of indirect (non-contact) condensation will greatly reduce the
amount of contaminated water entering the tower.

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3.3.3 SELECTION FACTORS OR PARAMETERS FOR SEALS IN THE OIL AND GAS INDUSTRY
The problem of controlling fugitive emission from seals is acknowledged by the oil and gas sealing
industry as one of the most important technical challenges. To control fugitive emissions, correct
selection and use of the appropriate sealing technology is fundamental. Without them, pumps will
leak, valves will release chemicals into the air, flanges would spray process fluids and oil would
drip from gearboxes, among others. The process of selecting the right device for any given
application begins with defining the expected level of performance and identifying service
conditions. A simple acronym, TAMPSS (Temperature, Application, Medium, Pressure, Size and
Speed) provides a general guide to assuring selection of the correct sealing device for your
application (Drago J and Tones M, 2007).
Temperature
The first consideration should be the temperature of the fluid contacting the seal, which in rotating
equipment will increase due to frictional heat. The frictional heat generated by the rotating
equipment will increase the temperature of the fluid contacting the seal. Temperature data will
immediately limit the number of viable seals for an application.
Application
Knowing how the seal is to be used and the function it is expected to perform are keys to making
the right selection. This type of information points up the anomalies of an application and the
special requirements for optimal seal performance. Defining the parameters of a particular
application requires information about where the seal will be installed. For example, if the
application is a valve, selection of the stem, whether its motion is reciprocating, helical or
continuous, and whether a specific level of leakage must be attained to meet environment
regulations. This is extremely important sine 70% of gasket failure is attributed to insufficient load
(Drago, J, 2009).
Media
Either the common or chemical name of the gas, liquid or solid that will come into contact with
the seal can be used to determine its compatibility with the seal material. Also considered should
be any secondary media to which the seal may be exposed, such as fluids that are intermittently

45. 35
present during chemical or steam/hot-water flushing. Sometimes, the sensitivity of the media to
color contamination or extracted materials that may leach from the seal must also be considered.
Pressure
This refers to the internal pressure a seal must contain. Most systems operate at fairly consistent
pressure, but as with temperature, it is important to know if the seal will be subject to pulses and
other variations as a normal part of operation.
Size
There are standard sizes for ASME flanges, API valves stems, ANSI pump shafts and others. Non-
standard sizes are best conveyed to the sealing manufacturer in the form of dimensional drawings.
Most pumps and valves conform to API/ANSI standards. Otherwise, they must be field measured.
Speed
The speed of a rotating shaft or reciprocating rod must be taken into account when selecting oil
seals, mechanical seals or compression packing for dynamic applications. High speeds call for
sealing materials that can withstand and effectively dissipate frictional heat.
Steps to be taken with every application
1. Materials that are chemically compactible with the process fluid and will handle the
pressure requirement and consistency (slurry, viscosity, specific gravity) must be chosen.
2. Choose the design or style which is appropriate in size to fit the equipment and engineered
to handle the process fluid
3. The seal should be installed into a piece of equipment that is in good mechanical condition.
4. The best environmental controls should be provided and applied to ensure that the seal is
working in the best possible environment.
For example, in flanges, you may have the best design, installed properly in good equipment with
the very best environment controls, but if the gasket chosen for operation is not compatible, there
will be leakage denoting that the job was not done properly.

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3.3.4 SELECTION OF THE RIGHT SEAL
Figure 5. Seal Selection can be based on the Fluid’s Specific Gravity and the Maximum Allowable VOC
Emission Levels
Mechanical seals have long played a major role in minimizing emissions to the atmosphere from
rotating equipment specially pumps. Within a decade, regulators have gone from little or no
concern about fugitive hazardous emissions to making them the center of restrictions, particularly
for VOC. To meet environmental regulations, the seal industry has developed and made available
a range of technological advances in seal design and materials. To select the correct type of
mechanical seal, install the proper environmental controls, choose the right materials for your
application, and install the seal correctly there is the need to define the sealing specifications.
Greater care need to be taken during the seal installation and maintenance. The key to a successful
seal life is to minimize the types of motion transferred to the seal but the best mechanical seal can
fail due to various reasons:

47. 37
1. One of the seal materials become damaged
2. The lapped seal faces open and allow the product to leak
3. Wrong selection and improper application
4. Poor installation and adequate maintenance practices that are applied to sealing system;
These problems can be overcome through a better understanding of the types of sealing material
available, redefine selection procedures and the consistent application of sound replacement and
maintenance practices.
After taking into account the various seals categories the best seal category that should be used at
the Jubilee Field is the Dual seal in case of a leak. The reasons why we selected the double seal
are as follows:
1. Dual mechanical seals can act as a spare seal in situations when the facility cannot yield an
unexpected shutdown.
2. They are designed with a two way hydraulic balance.
3. Double mechanical seals can reduce leakage to almost zero when operating properly.
4. When using this technology, there are no significant amounts of direct or indirect increase
in emissions.
After we choose the seal type the next step is to select the seal material that is chemically
compatible with all the fluids that will be passing through the process equipment. There are various
materials that can be looked at but for the sake of this project Nitrile is the best choice. The reasons
behind this option are; Nitrile oil seals combine excellent resistance to petroleum based oils and
fuels, silicon greases, hydraulic fluids, water and alcohols. Also it has good working balance
properties such as low compression set, high tensile strength, and excellent abrasion wear
resistance with an operating temperature range of -40 0C to 135 0C with a low relatively cost.
There is also the need to take into account important environmental controls during the selection
of the right seal. Some of these environmental controls are as described below.
The first environmental control is to check the temperature in the stuffing box area. The
temperature can rise, lower or kept it within certain limits that will be prescribed by the seal design

48. 38
and product characteristics. This environmental control is the most important when the pump is
shut down and the pumping fluids can either cools or heats up due to ambient temperature.
The next environmental control is the pressure in the stuffing box area. There are many occasions
where we will want to control stuffing box pressure to stop a fluid from vaporizing, flashing or
evaporating. We seldom have to let down the stuffing box pressure, but in a case where is too high
for a conventional balanced seal, it would be better off going to a special high pressure design.
The last factor account for environmental control is cleaning up of the product in the stuffing box.
Clean products are less problematic to seal. Flushing is one of the options, although there are more.
Any of the environmental controls suggested will work better in a case where the installation of
an oversizing stuffing box on the pump is made correctly. Note that the seal need lots of radial
room to allow centrifugal force to throw solids away from the lapped seal faces and to lessen the
propagation of heat in the stuffing box. Also note that heat is a major cause of problems with both
centrifugal pumps and mechanical seals. Anything that can be done to help remove heat from the
stuffing box will add to the life of the seal and pumps bearings.
3.3.5 Causes of Premature failure of Process equipment
Coupling Misalignment
Seal and bearing failures are frequently caused by improperly aligned couplings. Vibrations that
are generated by misalignment cause chipped or broken faces as well as overheated and damaged
bearings. The solution to this problem is making sure that equipment components to be installed
are aligned in the proper orientation and by following the manufactures’ guidelines for installation.
Heat
All seals have temperature limits which they can operate. Also, most applications have limits
above or below which negative results will be realized. For example, O-rings can overheat,
compression set or cook. Furthermore, metal parts can grow and hence hinder seal flexibility and

49. 39
faces to be loosen from their carriers. Some of the ways in which heat can be generated above
system temperature and adversely affect seal performance are running a mechanical seal dry,
running a single seal with a vacuum in the seal chamber, limited flow through the seal chamber
due to front and rear wear bushing or rings and poor start-up procedures among others.
Cavitation
Cavitation is a condition created by insufficient available head (pressure) at the suction side of a
pump, to satisfy discharge demand. This causes gas bubbles in areas where pressure decreases
abruptly. The bubbles collapse (implode) when they reach areas of higher pressure, causing
hammering, vibration and damage to pump parts (impeller, volute and back plate). It sounds like
pumping rocks. (Klozure-Mechanical seal-Tech-Man). This process causes low level in supply
source, build-up obstruction or some type of restriction of flow to suction or impeller discharge
into supply tank is done improperly and air entrapment because of poor piping design. Vibration
that occurs from cavitation is transmitted along the shaft to the seal, bearings, coupling and the
motor. As this continues, the pump parts are damaged and cause seal and pump failure.
Air Entrapment or Entrainment
Whenever air is trapped in the suction piping of a pump, cavitation is developed (as mentioned
above). Usually, air entrainment is caused by positioning the return to the supply tank in a poor
elevation or above the fluid level. The return line to the tank should discharge below the fluid level
and away from the tank outlet.
Over pumping
Pumps used to deliver fluids beyond its design or recommendable limits often than not leads to the
overheating of bearings, cavitation, seal and motor failure. Over pumping operations should be
avoided at all cost.

50. 40
Pipe Strain
Piping at various discharge or suction points when not properly aligned with flanges will result in
a phenomenon known as pipe strain. Its causes include improper support, thermal growth, poor
installation and settling of old system. Some of the consequences of this condition are vibrations
caused by pipe deflection and misalignment, overheating of bearings as a result of side loading
and impeller binds in casing. Pipe strain can be curbed when proper support (hangers) and proper
piping alignments are affected in the installation of process equipment.
Bearing Failure
When pump bearing fails, it loses its ability to support the rotating shaft. The rotating element will
whip unpredictably making rotating parts to strike stationary parts. In such a situation, the quality
of the seal being used matters less since the damage to the equipment has already occurred.
Poor Gasket Area
In flanges, a good gasket surface perpendicular to the shaft is essential. Gaskets to be used for
operations should be such that the surface area is rid of pit, rough, mar or any erosion. If the gasket
surface area is eroded, a facing tool or a lathe can be used to recondition it to the desired state.
Improper Installation
Before process equipment are installed for operations, they need to be checked for:
1. Dirty or damaged faces
2. Secondary seal (elastomer) damage
3. Seal set at wrong working length
4. Improper environmental controls
5. Seal improperly aligned
6. Wrong seal for application

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3.3.6 OTHER TECHNOLOGICALLY IMPROVED ALTERNATIVES FOR DETECTING AND MEASURING
FE
The differential absorption light detection and ranging (DIAL) technology and enhanced infrared
video imaging appear to offer more precise methods for the identification of emission sources. It
has been used to remotely measure concentration profiles of hydrocarbons for refinery survey in
Europe for over 15 years. DIAL method is the only technique that empowers mass emissions fluxes
to be obtained directly. This technique is non-invasive and single-ended, and gives concentration
profiles of hydrocarbons and mass emissions of various forms in the area being studied. A pilot
study carried out in 2005 using this approach found that the actual emissions at a refinery were
fifteen times higher than those previously reported using the emission factor method.
(Cheremisinoff and Rosenfeld, 2009).
Currently, portable analyzers provide an effective approach for both locating and measuring the
concentration of leaks from oil and natural gas production sites. There are several other technologies
being used to detect leaks for the oil and natural gas sectors. These technologies include optical
gas imaging (OGI) and ambient/mobile monitoring. OGI is a technology that operates much like
a consumer video-camcorder and provides a real-time visual image of gas emissions or leaks to
the atmosphere. The OGI camera works by using spectral wavelength filtering and an array of IR
detectors to image the IR absorption of hydrocarbons and other gaseous compounds. As the gas
absorbs radiant energy at the same waveband that the filter transmits to the detector, the gas and
motion of the gas is imaged. The OGI can be used for monitoring a large array of equipment and
components at a facility and is effective means of detecting leaks when the technology is used
suitably.
The detection of the OGI camera is based on a variety of factors such as detector capability, gas
characteristics of the leak, optical of the plume and the temperature difference between the gas and
the background. Further investigations are currently studying OGI technology in order to find its
limitations and capabilities.
The OGI provide a technology that can potentially minimize the time and cost efficient method
for locating leak than traditional technologies, such as portable analyzes. By increasing the
number of equipment that can be viewed per hour the OGI system could potentially reduce the

52. 42
cost of identifying leaks in upstream oil and gas facilities when compared to other equipment.
However, there are limitations to this technology.
The OGI system is sensitive to the ambient conditions around the equipment that is being audited
or inspected. Thus the higher the temperature difference between the leaking gas and the
contrasting background, the easier the leaking gas is to see. Additionally variable wind conditions
can reduce the optical depth and make it difficult for gas leak to be distinguished. Also the
effectiveness of an OGI instrument is dependent on the training and expertise of the operator. (US
EPA, 2014).

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4 CHAPTER FOUR
4.1 REDUCING EQUIPMENT LEAK EMISSIONS
There are three primary techniques for reducing equipment leak emissions:
(1) Modifying or replacing existing equipment
(2) Implementing programs such as: Leak Detection and Repair (LDAR) program and Direct
Inspection and Maintenance program (DI&M) and
(3) Selecting the right sealing system
4.1.1 DIRECT INSPECTION &MAINTENANCE (DI&M) PROGRAM
The first step is to determine which types of components will be targeted. The targeted components
are those components with high levels of leakages. The objective is to minimize the potential for
leaks in the most practicable manner possible. This is done by focusing efforts on the types of
components and service applications most likely to offer significant cost-effective control
opportunities. Non-target components are subjected to coarse or less frequent screening.
Typically, a facility will phase the DI&M program over a certain number of years by progressively
adding to the list of target components until all key potential contributors are being targeted. Once
a leak is detected, regardless of whether it is a target or non-target component, the Decision Tree
reproduced under Figure should be followed to determine if a leak need to be repaired. Once a leak
is determined to need fixing, this should be done within a reasonable period of time, or at the next
facility turnaround if a major shutdown is required. A facility may choose to simply repair or fix
the leak. If it is not a simple repair or fix, an operator may choose to program the repair at the next
shut down without quantification or, alternatively, the leak should be measured or estimated to
determine if it is economical to repair. Where an operator believes that it may not be economical
to repair, this should be documented based on reliable quantification of the amount of leakage and
the repair cost. If a leak poses a health, safety, or environmental concern, then it needs to be
repaired regardless of whether it is economical to fix.

54. 44
Figure 6. DI&M Decision Tree
Source: Management of Fugitive Emissions at Upstream Oil and Gas Facilities, 2007.

55. 45
4.1.2 LEAK DETECTION AND REPAIR PROGRAM (LDAR)
An LDAR program is a structured program to detect and repair equipment that is identified as
leaking beyond acceptable limits. It is designed to identify pieces of equipment that are emitting
sufficient amounts of material to warrant reduction of the emissions through repair. The site LDAR
program consists of the activities that the site initiates to stay in compliance with fugitive emission
standards. Thus, the purpose of the agency LDAR program is to monitor and verify the
effectiveness of the site's LDAR program. To effectively evaluate the source LDAR program,
workers must be able to:
I. Determine which equipment leak regulations are applicable
2. Understand the overall approach of using both equipment standards and leak detection and repair
standards
3. Determine if a source is complying with all the requirements of component identification,
component marking, equipment design, monitoring, repair, recordkeeping, and reporting as part
of a source LDAR program
4. Understand the analyzer performance specifications required by Federal Reference Method 21
5. Evaluate source personnel's calibration procedures and records
6. Evaluate field monitoring procedures used by source personnel to detect leaks from regulated
components.
Those programs are best applied to equipment types that can be repaired on line, resulting in
immediate emissions reduction, and/or to equipment types for which equipment modifications are
not feasible. An LDAR program has proved to be best suited for centralized facilities where there
are a large number of sources under high pressures such as valves and pumps, and can also be
implemented for connectors.
4.1.3 THE CONCEPT OF LEAK
Fugitive emissions control is becoming more common as a condition of a facility’s operating
approval. Firstly, a leak could be defined as a screening concentration of 10,000 ppm or more for
the purposes of deciding whether to measure the emission rate and evaluate the practicability of
making repairs. Below this threshold the emissions generally become too small to quantify.
Moreover, usually only the top 5 to 10 percent of leaking components account for 80 to 90 percent

56. 46
of the emissions at a facility. Consequently, there is limited value in dedicating resources to
measure or estimate emissions from components that do not achieve the screening value identified.
However facilities may still choose to repair these below 10,000 ppm emissions without
measurement.
4.1.4 PIPE LINE INTEGRITY
Pipeline integritycanbe ensuredbyappropriate design,constructionandoperation;the use of apipe -in-
pipe system with annular-space leak sensing would, significantly cut down or entirely eliminate the
possibility of fluid release to the general environment. Whilst this approach can be applied to new
pipelines, it is much more difficult to retrofit an existing pipeline to ensure inherent integrity. Most
integrity systems are therefore based on specific instrumentation and methodologies to reduce the
likelihoodof pipeline failure andminimizethe consequencesof suchan event.Pipeline integritysystems
can therefore be splitupintoBefore-the-event and After-the-event systems as indicated in the figure.
Figure 7. Pipeline Integrity Systems
Before-the-event systems are aimed at ensuring the integrity of a pipeline and use a combination
of operational procedures, maintenance procedures, and dedicated hardware and software as part
of an overall pipeline integrity management system (PIMS) to provide advance warming of any
events or changes in the physical state of the pipeline which may lead to a loss of integrity. After-
PIPELINE INTEGRITY
LINE INTEGRITY
BEFORE THE EVENT
SYSTEM
TEM
IPE LINE INTEGRITY
BEFORE THE EVENT SYSTEM AFTER THE EVENT SYSTEM
AVOID AN EVENT
EVENT SYSTEM
AVOID AN EVENT REDUCE EFFECT OF
AN EVENT