U.S. DEPARTMENT Or COMMERCE
Nittonal Teehnicil Information Seieto
PB-272 268
Atmospheric Emissions from
Offshore Oil and Gas
Development and Production
Energy Resources Co, Inc, Cambridge, Moss
fteparad for
Environmental Protection Agency, Research Triangle Park, N C Office of Air
Quality Planning and Standards
Jun 77
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EPA-450/3-77-026
June 1977
ATMOSPHERIC EMISSIONS
FROM OFFSHORE OIL AND
GAS DEVELOPMENT
AND PRODUCTION
PB 272J258-
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Waste Management
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
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TECHNICAL REI'ORT DATA
(Please read luumeiioai on the itvtnt before
fcrecomplrimfl
1 TITLE AND SUBTITLE
Atmospheric Emissions from Offshore Oil and Gas
Development and Production
AUTMORISI
Charles Braxton, Richard H. Stephens,
Mavnard M. Stephens
3. HEC
5. REPORT DATE
June 1977
6 PERFORMING ORGANIZATION CODE
8 PERFORMING ORGANIZATION REPORT NO
Energy Resources Company Inc.
185 Alewife Brook Pa.rkway
Cambridge, Massachusetts 02138
10. PROGRAM ELEMtNT NO.
Vl. CONTRACT/GRANT NO.
68-02-2512
1. SPONSORING AGENCY NAME AND ADDRESS
U. S. Environmental Protection Agency
Research Triangle Park,
North Carolina 27711
13. TYPE OF REPORT AND PERIOD COVERED
14. SPONSORING ACENCV CODE
ABSTRACT
*« ~2 £ ?i1S j e fl!i5t Phase of a P^ram to develop reliable emissions estimates
for offshore oil and gas development and production. The objectives of this screenin
phase are to characters the equipment used offshore, to evaluate the sources of
emissions, to make preliminary estimates of emissions rates, and to Identify current
control technologies and control technologies which require further study The two
major sources accounting for over seventy percent of total non-methane hydrocarbon
emissions are oil storage or Storage tanks on board the platforms and vents which
discharge intermittently during gas processing. Power generation during production
operations is the largest source of essentially continuous emissions of oxides of
nitrogen, sulfur oxides, carbon monoxide and particulates, but accounts for only
about ten percent of total non-methane hydrocarbon emissions. The most likely
means of achieving emissions reductions are the use of vapor recovery systems
development of combined cycle power systems suitable for offshore use, and maximum
utilization of waste heat.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
Offshore Drilling Rigs
Offshore Production
Carbon Monoxide Emissions
SOX Emissions
NOX Emissions
Paniculate Missions
IBUTIONSTATEVENT
Unlimited
(1-7J)
lUOENTIFIERS/OPEN ENDED TERMS
Drilling
Oil Production
Gas Process1no
Oil Processing
19. SECURIl V CLASS in,, htpml,
Unclassified
> SECURITY CLASS (Thilfiiifel
Unclassified
l. COSATI I Kid/I pinup
11 NO OF PAGES
. PRICE
If*
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EPA-450/3-77-026
ATMOSPHERIC EMISSIONS FROM
OFFSHORE OIL AND GAS DEVELOPMENT
AND PRODUCTION
by
Richard H. Stephens. Charles Bruton, Maynard M. Stephens
Energy Resources Company, Inc.
183 Alewife Brook Parkway
Cambridge, Maasachusella 02138
Contract No. 6842-2512
EPA Project Officer Richard K. Burr
••cpBrcd for
ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Wane Management
Office of iJr Quality Planning and Standards
Research Triangle Park, North Carolina 27711
June 1977
-------
This report u issued by the Environmental Protection Agency to report
technical data of interest to a limited number of readers. Copies are
available free of charge to Federal employees, current contractors and
grantees and nonprofit organization - in limited quantities - from the
Library Services Office (MD-35), Research Triangle Park, North Carolina
llll » -» f »ee> rr°m the National Technical Information Service.
5285 Port Royal Road. Springfield. Virginia 22161.
This report was furnished to the Environmental Protection Agency bv
Energy Resources Company. Inc.. 185 Alewife Brook Parkway. Cambridge
Massachusetts. ta fulfilllnent of Contract No 68_02_2512 The contents 8
of this report are reproduced herein as received from Energy Resources
STES'rfS' ^ °Pini°ns- findings. and conclusions e^ressed
Protean I?6 ?f Hn.d notf necessa»ly those of the Environmental
c«25 /' Y< J ntl°n °f comPany or P^duct names is noi to be
considered as an endorsement by the Environmental Protection Agency
Publication No. EPA-450/3-77-026
11
-------
ABSTRACT
This study Is the first phase of a program to develop reliable emissions
estimates for offshore oil and gas development and production. The objectives
of this screening phase are to characterize the equipment used offshore, to
evaluate the sources of emissions, to make preliminary estimates of emissions
rates, and to identify current control technologies and control technologies
which require further study. The two major sources accounting for over seventy
percent of total non-methane hydrocarbon emissions are oil storage or storage
tanks on board the platforms and vents which discharge intermittently during
gas processing. Power generation during production operations Is the largest
source of essentially continuous emissions of oxides of nitrogen, sulfur
oxides, carbon monoxide and particultes, but accounts for only about ten
percent of total non-methane hydrocarbon emissions. The most likely means
of achieving emissions reductions are the use of vapor recovery systems,
development of combined cycle power systems suitable for offshore use, and
naximum utlHztion of waste heat.
111
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TABLE OF CONTENTS
Page
LIST OF FIGURES v11
LIST OF TABLES 1x
CHAPTER ONE INTRODUCTION AND SUMMARY 1
1.1 Introduction 1
1.2 Conclusions 1
1.2.1 Emission Sources and Rates 2
1.2.2 Control Techniques 6
1.3 Recommendation and Research Needs 8
1.3.1 Field Sampling 8
1.3.2 Control Technology 9
1.4 Methodology and Scope of Report 9
1.4.L Approach 9
1.4.2 Limits of the Analysis 10
CHAPTER TWO OVERVIEW OF THE INDUSTRY 11
2.1 Introduction H
2.2 Offshore Petroleum and Natural Gas Operations 13
2.3 Government Regulations 34
2.4 Future Activity 41
CHAPTER THREE TECHNOLOGY OF OFFSHORE OIL AND GAS 52
PRODUCTION
3.1 Introduction 52
3.2 Geology 52
3.3 Drilling 53
3.3.1 Drilling Rigs 53
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TABLE OF CONTENTS (CONT.)
Page
3.3.2 Drilling Fluids 57
3.3.2.1 Purpose 57
3.3.2.2 Drilling Fluid Conditioning 58
3.3.2 The Casing Program go
3.4 Completion of the Wells 64
3.5 Field Development 68
3.6 Production Facilities 70
3.6.1 Oil and Gas Separation Equipment 70
3.7 Transportation of Oil and Gas ' 76'
CHAPTER FOUR EMISSION SOURCES 81
4.1 Introduction 81
4.2 Drilling Operations 81
4.2.1 Power Generation 81
4.2.2 Mud Degassing 86
4.2.3 Blowouts Qg
4.2.4 Dynamic Positioning and Stabilizing 91
4.3 Production 93
4.3.1 Power Generation 93
4.3.2 Gas Processing 97
4.3.2.1 Gas Compression 97
4.3.2.2 Gas Dehydration 100
4.3.2.3 Vents 102
4.3.3 Oil Processing 103
4.3.3.1 Separators 103
4.3.3.2 Emulsion Breakers ioe
4.3.3.3 Product Send-Out no
4.3.4 Water Treating H4
4.4 Control Technology 116
-v-
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TABLE OF CONTENTS (CONT.)
4.4.1 Power Generation H6
4.4.1.1 Combustion Controls us
4.4.1.2 Control by Conservation 120
4.4.2 Direct-Fired Heaters 121
4.4.3 Waste-Gas Disposal 121
4.4.3.1 Dilution Stacks and 121
Underwater Flares
4.4.3.2 Smokeless (Combustion) Flares 122
4.4.3.3 Vapor Recovery Systems 122
4.4.4 Fugitive Emissions 125
CHAPTER FIVE IMPACT ANALYSIS 126
5.1 Introduction 12g
5.2 Total Emissions Estimate 126
5.3 Ambient Air Quality 132
5.4 Outline of Field Sampling Program 137
-vl-
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LIST OP FIGURES
CHAPTER ONE INTRODUCTION AND SIIMMUPV
Page
CHAPTER TWO
2-1
2-2a
2-2b
2-3
2-4
2-5
2-6
2-7
2-8
CHAPTER THREE
3-1
3-2
3-3
3-4
3-5
OVERVIEW OF THE INDUSTRY
The National Petroleum and Natural
Gas System Model
Offshore Louisiana Oil and Gas Fields
Approximate Location of the Proposed
and Existing Pipeline-Flowline System,
Offshore Louisiana, March 1974
Offshore Texas Oil and Gas Fields
Gulf of Mexico L-sasing Areas and Oil
and Gas Fields, Offshore Mississippi,
Alabama, and Florida
Offshore Southern California Border-
land Area
Oil and Gas Fields and Offshore
Facilities in the Santa Barbara
Channel Region
Offshore Leasing Areas in the Mid-
Atlantic Region
Offshore Leasing Areas on the Georges
Bank of Primary Interest to the
Petroleum Industry
TECHNOLOGY OF OFFSHORE OIL AND GAS
PRODUCTION ~
Idealized Geologic Structures in Which
Offshore Oil and Gas Occurs
Trend in Design as Deeper Water
Drilling Becomes Necessary
Handling Toxic Gas on Offshore Rigs
Casing Program of a Typical Oil or Gas
WGJ.I
A Subsea Wellhead
12
16
17
18
19
23
24
45
46
54
56
61
63
66
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LIST OF FIGURES (CONT.)
Pac
3-6 Oil Processing Scheme 71
3-7 Gas Processing Scheme 72
3-8 A Typical Production Facility with 74
Safety Equipment
3-9 A Pictorial Sketch of the Equipment 77
Layout on Platform A
3-10 A Pictorial Sketch of the Equipment 78
on a Production Platform
3-11 Flow Diagram of Produced Fluids, South 79
Pass Blocks 24 and 27 Fields
3-12 Typical Platforms and Facilities Used 80
in Block 24-27 Fields Offshore
Louisiana
CHAPTER FOUR EMISSION SOURCES
4-1 Handling Toxic Gas on Offshore Rigs 90
4-2 Typical Glycol Dehydration 101
Installation
4-3 Horizontal Low Pressure Oil and Gas 104
Separators
4-4 Horizontal Oil-Gas-Water Separators 105
4-5 Horizontal Heater Treater 107
4-6 Type "A" Vertical Downflow Treaters 108
4-7 A Modern Oil-Water Separator 115
4-8 Froth Flotation Unit for Removal of 117
Emulsified Oil and Suspended Solids
from Produced Water
4-9 Correlation of Emission Level and 119
Engine Type Operating Range
4-10 View of John Zink Smokeless Flame 123
Burner
CHAPTER FIVE IMPACT ANALYSIS
5-1 Modified Concentration Versus
Downwind Distance for H = 27 m
-viii-
134
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LIST OF TABLES
CHAPTER ONE
1-1
1-2
1-3
INTRODUCTION AND SUMMARY
Outline of Possible Emissions Sources
Reviewed
Ranking of Emission Sources from Offshore
Oil and Gas Activities, 1985
Control Technologies for Offshore Oil and
Gas Operations
3
5
7
CHAPTER TWO OVERVIEW OF THE INDUSTRY
2-1
2-2
2-3
2-4
2-5
2-6
2-7
2-8
2-9
2-10
2-11
2-12
2-13
2-14
Offshore Oil Production and Reserves - 14
Major Fields in the United States
Offshore Platforms in Federal Waters 20
Major Oil Spill Incidents 21
Rigs Available by Types - 1976 25
Location of and Type of Drilling Sigs 26
Available for U.S. Offshore Operations
1975 Explanatory and Development Wells 29
Trend of the Num.v'r of Offshore Wells 30
Drilled in the United States
Annual Production on the Outer Continental 31
Shelf
Production from Offshore California Oilfields 32
in State Waters, 1975
Annual Production in Offshore California 33
Oilfields to Offshore Facilities in State
Waters, 1975
Summary of Offshore Transportation Systems 35
in Federal Waters
Offshore Pipeline Systems 35
Offshore Bargin Systems in Operation as 39
of March 1976
Orders Issued to Operators on the Outer 40
Continental Shelf by the U.S. Geological
Survey, Department of Interior
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LIST OP TABLES (CONT.)
Page
2-15 Platform Water Depth Capability 42
2-16 U.S. Offshore Oil and Gas Resources and 44
Reserves
2-17 Projected Oil and Gas Production in New 47
Areas on the Outor Continental Shelf
2-18 Projected Production from New Federal 48
Offshore Areas in 1985
2-19 Summary of Projected Offshore Activities, 49
1985
2-20 Projected Platforms Offshore California 51
1985
CHAPTER THREE TECHNOLOGY OF OFFSHORE OIL AND GAS PRODUCTION
CHAPTER FOUR EMISSION SOURCES
4-1 Drilling Power Capacities of Exploratory 82
Rigs
4-2 Scenario of Installed Power Distribution 84
4-3 Drilling Scenario 85
4-4 Emission Rates for Turbines and Reciprocating 87
Engines
4-5 Nationwide Emissions from Power Generation 88
during Drilling (1975)
4-6 History of Shallow Hole Blowouts in the Gulf 92
of Mexico
4-7 Power Generation, Installed Capacity and 94
Estimated Usage Required for Offshore
Production
4-8 Drilling Rigs on Fixed Platforms 95
4-9 Total Emissions from Power Generation 98
On Offshore Production Platforms
4-10 Approximate Gas Balance 99
4-11 Emissions from Heat Treating 109
-x-
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LIST OF TABLES
Page
4-12 Effectiveness of Mechanical and Packed 111
Seals on Various Types of Hydrocarbons
4-13 Leakage of Hydrocarbons from Valves of 113
Refineries in Los Angeles County
4-14 Emissions from Flares 124
CHAPTER FIVF. IMPACT ANALYSIS
5-1 Summary of Emission Factors 127
5-2 Estimates of Total Uncontrolled 129
Emissions from Offshore Facilities, 1975
5-3 Estimates of Total Emissions from 130
Offshore Facilities, 1985
5-4 Control Technology Options and 1985 131
Control Scenario
5-5 Summary of Emission Rates for a Typical 133
Offshore California Production Platform -
1985
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CHAPTER ONE
INTRODUCTION AND SUMMARY
1.1 Introduction
Offshore oil and gas production on the Outer Continental
Shelf may contribute 11 to 54 billion barrels of oil and 54
to nearly 236 trillion ft3 of gas to domestic supplies in
the future.1 The resource potential of these petroleum
provinces will be increasingly important to fulfill the
nation's needs for energy.
This study is the first phase of a program to develop
reliable emission estimates for offshore drilling and oil
production facilities. The objectives of this engineering
assessment are:
1. To characterize the equipment and processes found
on offshore facilities used for petroleum resource
development on the Outer Continental Shelf.
2. To evaluate the sources of emissions from offshore
facilities, to make preliminary estimates of
emission rates, and to identify control technologies
for these emissions.
3. To identify emission sources and control tech-
nologies which require further study. Field
testing of both point sources and ambient air
concentrations is one response to this objective;
control technology development is another.
1.2 Conclusions
Offshore oil operations generate a small but significant
amount of air pollutants resulting from stationary combustion
or. from venting produced gas.
U.S. Department of the Interior, Geological Survey
estimates.
-1-
-------
This conclusion is based upon the preliminary estimates
contained in this report and is subject to the following
limitations:
1. Because this work was intended as a preliminary
screening, several simplifying assumptions have
been made. While the accuracy of these assump-
tions will affect the accuracy of emissions
estimates, they will not significantly alter the
qualitative findings of this work.
2. Several potential emission sources have been
identified for which supporting data are unavail-
able. However, the project team has elected not
to carry out an "in-depth" analysis of such data
because the level of effort required could not be
justified within the scope and level of effort of
this preliminary survey.
3. There are major difference in the operating and
design practices of major oil companies as well as
differences in offshore leases. Hence, there is
no such thing as a "typical platform." In carrying
out this project, however, quantitative estimates
have been required which have been based upon
generalizations of specific practices reported in
the literature or observed by the project team
during visits to several offshore facilities.
Although these estimates are believed to be quali-
tatively accurate and of sufficient reliability to
establish priorities for subsequent work, the
authors recognize that there are a large number of
exceptions to the general rules followed here.
1.2.1 Emission Sources and Rates
Table 1-1 outlines the sources reviewed in the study by
phase of activity and major subsystem. Table 1-2 ranks the
sources of emissions in terms of their anticipated uncontrolled
rates of emissions for 1985. The major source of total
hydrocarbon emissions is from oil storage or surge tanks
onboard the production platform (136 x 103 Mg/yr) and from
vents which discharge intermittently during gas processing
(93 x 103 Mg/yr) as required by process upsets and maintenance.
These two sources account for over 70 percent of the total
non-methane hydrocarbons (29,403 Mg/yr) emitted offshore.
By comparison, this is only 2 percent of the non-methane
-2-
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TABLE 1-1
OUTLINE OF POSSIBLE EMISSIONS SOURCES REVIEWED
Phase:
Subsystems:
Phase:
Subsystems:
Phase:
Subsystems:
EXPLORATORY/DEVELOPMENT DRILLING
Electric Power Generation
Mud Conditioning
- Hud tanks
- Degasser
- Shale Shaker
Fuel Storage
Deck Sumps
Flow Line (Blowouts)
WELL COMPLETION/TEST
Electric Power Generation
Flow Line
Wellhead
- Plaform Riser
- Submerged Production System
- Underwater Completion
- SEAL
PRODUCTION
Production
Energy Source-Lifting
Natural or Primary
Electric Submergible Pump
Gas Lift Systems
Power Oil/Hater Systems
Phase of Production
Natural/Primary
Pressure Maintenance or Secondary
- Gas Reinjection
- Water Injection
-3-
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TABLE 1-1 (CONT.)
Electric Power Generation
- Submarine Cable
- Turbines
- Gas Engines
- Diesels
Subsystems:
Processing
Separation
- Free Water Knockout
- Two Phase Separator
- Pressure Stage Separators
- Test Separator
- Desander
Gas Preparation for Pipelining
- Glycol Dryers (Waste Heat and Direct-Fired)
- Amine Systems (H.S)
Gas Compression to Higher Pressure
- Combustion Turbine
- Gas-Fired Reciprocating
- Electric Motor
- Diesel
Oil Preparation for Pipelining
- Treater (Direct, chem-electric, indirect)
Oil Shipment
- Storage
Dead Oil Tank
Shipping Surge Tank
Fuel Storage
Pumping
- Electric/Diesel
- Charge Pumps/Valves
- Turbine
- Gas
Water Cleanup (for Disposal/Injection)
- Skim Tank
- Flotation Cell
- Skim Pile
- Floor Drain System
- Injection Pump
Electric Motor
Gas Turbine
Diesel
-4-
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TABLE 1-2
RANKING OF EMISSION SOURCES FROM
OFFSHORE OIL AND GAS ACTIVITIES, 1985
POLLUTANT
HnNKINi! H0f SOj IK*
Uinrnt Pnwer bf.iM-r.ic lr*n Pciwr I^IM-I.H inn oil Storaiji'lnonitl
Mtlii-i K-." Turblnu - II-IM Turlili..' -
il*M I'cartiH'tiiin) il^ri Protluut ifin) Vr.uLa ((win
PriwunliuiXII
Pnwrr i«neratlon i«wpr Ct-nriiitlnn
{<•.*» Turbliw - I'du Turbine - Kuil OoqasnJnol2)
Oil "reduetlon) oil Production)
Powc Ceiinration
Power Generation Power Generation (Gas Preceosino) <3)
IDieael - Electric (Olewil - Electric
Drilling) Drilling) Power Generation
(Oil t>ron»aina) ,«)
Fired Oil Troatari PI red Oil Treatere
Can Dehydration!?)
Fired GAK Dryeri Fired Can Dryori
Valve GcalB
(Goo service) 16)
Power Generation
(Ulesel - Electric
Drill Inq) 110)
Oll-PniHHl MuilR(S)
savillfit V.ilvi* Svalti
inltrrr loll RnrvU-r) |B|
Unknown Ml. tw.nl t./l'l ri>s Hlownutii/l'iri'H nitiwouln/flri'M
Mr- 11 (i»|.|Ktlun Wfll l'r»|il.'l lull Ki'I 1 On|.l.< drill
Conpreamir Sralt
wau-r Treating
ro
l^iwur Rnnnralinn
(1:^1. Turbine -
Powvr ftoneinLiuii
«\nti Turbine -
Oil rmductiini)
rower Generation
IDieael - Electric
Drill in?)
Fired Oil Treotora
Fired Gaa Dryuro
H liiwuut f/Y\ I I'll
Well implr! lim
PACTICIILATEi; HjS
nnwer Renvrallnn nil Cloraqr
IR«* Turblnr - Ventn
On. rrottiictionl
Vnitn d-i"
tklwor l^MioiAtl«jn rruiiimiiiiit)
IGaa Turbine -
Oil Production) Valv« Son In
Innii SurviK?
Fired oil Treatcio
Firnd Gao Dryore
nkuwnutii/Kirvn lllfiwoutiiA'ii
Mill ConpluHun W.-II C..B|.I.-I
Power Rvnorailon w«l m^rwiln
(Plenl - electric
Drlllinql
ainclude.s vapor recovery in California per 1975 practice (California
source ranking shown in parentheses).
-------
emissions for all petroleum storage or less than 0.2 percent
of the total non-methane emissions from all stationary
combustion.2
Power generation during production operations in 1985
is the largest source of essentially continuous emissions of
oxides of nitrogen (36.3 x 103 Mg/yr), sulfur dioxide
(1.7 x 103 Mg/yr), non-methane hydrocarbons (3.12 x 103 Mg/yr)
carbon monoxide (9.0 x 103 Mg/yr) and particulates
(1.1 x 103 Mg/yr).
1.2.2 Control Techniques
The types of facilities onboard an offshore platform
are chosen based upon the extent of processing required, the
space available, and the cost of onshore alternatives.
While there is a wide range of process alternatives, there
are few available process changes which offer significantly
reduced emissions. Hence, the most likely means of achieving
emissions reduction are:
• Use of vapor recovery systems for major vent
exhausts such as flash gas generated in the surge
tank from the low pressure separator to the sendout
pump.
• Reduction of fuel combustion through maximum use
of waste heat recovery or through the development
of combined cycle power units which would be
economically feasible for offshore use.
• Minimization of onshore emissions (which lessens
the population at risk) through maximization of
offshore power generation and oil/gas processing.
Specific control technologies for point sources of
emissions on offshore oil and gas facilities are illustrated
in Table 1-3. Among the control technologies listed, applica-
tion of combined cycles to gas turbine operations and other
engines offers the largest potential reduction in non-
hydrocarbon emissions. Although this technology is still
under development at present, it has the potential to reduce
power generation emissions by as much as 54 percent based
2
U.S. Environmental Protection Agency, Control of Hydro-
carbon Emissions from Petroleum Liquids, EPA No. 600/2-75-042,
September 1975.
-6-
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TABLE 1-3
CONTROL TECHNOLOGIES FOR OFFSHORE OIL AND GAS OPERATIONS
SOURCE
CONTROL TECHNOLOGY
POLLUTANTS CONTROLLED
Power Generation-Drilling
Mud Degassing
Mud Tanks
(Oil-Based Muds)
.1, Fuel Storage
Power Generation-Production
Gas Drying
Compressor Seals
Gas Processing Vents
Valve Seals (Gas Service)
Oil Treaters
Pump Seals
Valve Seals (Oil Service)
Oil Storage/Surge
Water Treating
Waste Heat Utilization,
Combined-Cycle Operations
(Developmental)
Combustion Flares
Covers, Dilution Flares
Vapor Recovery
Waste Heat Utilization
Combined-Cycle Operation
(Developmental)
Waste Heat Utilization
Maintenance
Operating Practice
Maintenance
Waste Heat Utilization
Maintenance
Maintenance
Vapor Recovery, Dilution Flares,
Combustion Flares
Maintenance, Design, Vapor
Recovery
NO. SO_, HC, CO, Part.
X »
HC
HC
HC
NO .
N0x'
SO,
so"
2'
HC, CO, Part., H_S
HC, C"), Part. , H,S
N0, SO, CO, Part.
HC
HC
HC
NO
HCJ
HC
HC
HC
SO
CO, Part.
-------
upon a cycle efficiency of 40 percent as compared with cur-
rent operations at 26 percent efficiency.3 Fuel rate reduc-
tions of 24 to 37 percent have been achieved in gas turbine
combined-cycle tests to date. Application of vapor recovery
systems may reduce hydrocarbon emissions from offshore
operations projected for 1985 by up to approximately 80 percent
in the Gulf of Mexico and in the Atlantic. Vapor recovery
is already required in the offshore California region.
Waste heat utilization may reduce pollutants by approx-
imately 10 percent or more depending upon the extent of
application. It is necessary to evaluate the economics of
waste heat recovery system applications in order to assess
the actual extent to which the industry will adopt this
control technology in the absence of new regulations.
These conclusions are based upon the control technology
scenario for 1985 discussed in Chapter Five. A different
scenario may alter these conclusions somewhat.
1.3 Recommendation and Research Needs
1.3.1 Field Sampling
The following potential point sources of emissions on
offshore oil- and gas facilities have the highest priority
for characterization study by field sampling of all pollutants:
• Gas vents
« Oil storage vents
• Water separators
• Compressor seals and thrust-bearing vents
• Well completion, blowouts and oil spills
The emissions from a blowout could be very large if the
well remained out of control for a significant period of
time, but such emissions are clearly uncontrollable once a
blowout occurs. Fortunately, blowouts are an infrequent
occurrence.
R.M. Wardall and E.E. Doorly, Current Prospects for
Efficient Combined Cycles for Small Gas Turbines, presented
at ASNE Gas Turbine Conference, New Orleans, Louisiana,
March 1976.
-8-
-------
1.3.2 Control Technology
Development of a combined cycle for gas turbines and
other engines generating power onboard offshore facilities
should be encouraged because of the substantial potential
emissions reduction and concomitant energy savings. Specific
development should be focused on systems that would be
economically feasible even on scales in the range of 1,000 hp
to 5,000 hp.
of
Waste heat utilization to replace electrical resistance
heating and direct-fired vessels onboard operating platforms
should be studied for imm«diate application where energy
savings and pollutant reductions may be achieved.
The costs and feasibility of changes in operating prac-
tices onboard platforms, particularly during periods of com-
pressor shut-down, should be evaluated. The impact en
emissions as well as the effect of any changes in operating
practice on the long-term productive potential of the
reservoir should be examined.
1«4 Methodology and Scope of Report
1.4.1 Approach
Data on the major offshore drilling and production
facilities, processing schemes, operating practice and
future planned configurations were compiled from discussions
with the industry, the U.S. Geological Survey (USGS), state
agencies, industry associations and technical journals.
Published emission factors to be applied to these operations
have been supplemented with independent estimates developed
in the study and with data collected from operators' records
analyzed during the project team's field visits. Detailed
dispersion modeling and sampling program planning were
subordinated as objectives of the study in order to develop
projections of oil and gas drilling and production activities
for the 1985 time frame. The emissions from the projected
activity level were utilized to rank the sources of emissions
and to evaluate the potential emissions reduction from
applying control technologies.
-9-
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1.4.2 Limits of the Analysis
n 4. T5e ?e°9r£Pnlcal scope of this report encompasses the
Outer Continental Shelf in Federal waters offshore of the 48
contiguous states. Where data were available for the
Alaska Outer Continental Shelf activities, these were included
in the report. Offshore activities in waters under California
State uunsdiction were included in the report to provide a
complete picture of the emissions in that region. Production
in state waters along the Gulf of Mexico was not included
because of the difficulty in delineating offshore activities
from onshore activities there and because oil and gas produc-
tion in these areas is relatively mature.
Emissions from all activities during drilling, completion
and production of an offshore oil and/or gas well were included
in the analysis as data permitted. The major exceptions
would be support activities emissions from such sources as
transportation equipment, cranes, and workover rigs which
operate intermittently.
In terms of the flow path of hydrocarbons the emissions
evaluated included sources at any point from the oil or gas
reservoir beneath the sea to the point at which the oil and
gas were dispatched from an offshore processing facility or
up to the point at which loading and transportation operations
began. Onshore facilities emissions would be the subject of
a separate project.
The emissions estimates are based upon a single composite
processing scheme for each region. The USGS has under
development a data compilation program which may enable
further segmentation of oil and gas production into their
respective processing schemes. However, the USGS project
was at too early a stage to include these production schemes
in this report. Considering that three sources account for
over 90 percent of the total hydrocarbon emissions identi-
fied and that power generation is the major contributor of
other pollutant emissions, it is doubtful that a more detailed
partitioning of oil and gas production into various schemes
would provide meaningful insights.
Although some gas-fired reciprocating compressors are
present on offshore platforms, the total emissions estimates
are based upon gas turbines as the prime movers in operation.
No data were found on the number of reciprocating compressors
installed offshore. Although accounting for these units
would increase estimates of pollutant emissions of nitrogen
oxides, hydrocarbons and carbon monoxide, the change in total
emissions estimates would not be sufficient to significantly
alter the preliminary conclusions stated in this chapter.
-10-
-------
CHAPTER TWO
OVERVIEW OF THE INDUSTRY
2.1 Introduction
The oil and natural gas industry is a highly complex
mixture of many companies, large, medium, and small in size,
actively competing with each other yet, in total, working as
a gigantic system to supply the energy needs of the nation.
Figure 2-1 shows a model of the total petroleum and
natural gas system.1 Stephens identified the following
functions of the industry:
1. Seeking out of accumulations hidden in geological
structures (Geological Exploration).
2. Drilling of exploratory wells and completing them
so as to extract safely the crude petroleum and
natural gas from its resevoir (Drilling).
3. Producing crude oil and gas - The development
drilling of "discovered" resevoirs and the pro-
duction of oil and gas (Production or Operations).
4. Transporting crude oil to refineries (Crude Oil
Transportation).
5. Refining or separating the crude oil into usable
products. Petroleum is a mixture of many natural
hydrocarbon compounds (Refining).
6. Transporting refined products to consumer areas
(Product Transportation).
7. Distributing oil, gasoline, jec fuel, asphalt and
the many other products to consumers (Marketing).
This chapter addresses offshore activities of the
industry primarily in the second and third functions listed.
M.M. Stephens, Vulnerability of Total Petroleum Systems,
Department of Interior Office of Oil and Gas and Defense,
Civil Preparedness Agency, Washington, D.C., May 1973.
-11-
-------
ro
Figure 2-1. The national petroleum and natural gas system model.
(M.M. Stephens, "Vulnerability of Total Petroleum Systems," Department of
Interior Office of Oil and Gas and Defense, Civil Preparedness Agency,
Washington, D.C., May 1973.) .
-------
Upward from 75 percent of the total energy used in the
United States comes from the petroleum and natural gas
industries. A plot of the Gross National Product with
energy use indicates that the two parallel each other. It
follows, therefore, that the petroleum and natural gas
industries are of utmost importance to the nation.
Each day the country produces about 8.2 million barrels
of crude oil from domestic sources. Added to this are
roughly another 1.5 million barrels of natural gas liquids.
But the country uses about 17 million barrels of petroleum
products daily. Much of the relatively easy-to-find land-
based oil, or relatively shallow depth oil, has long ago
been discovered and most such wells either are now marginal
producers or have been abandoned.
To date, in excess of 100 billion barrels of petroleum
have been discovered and produced in the United States.
There is a never-ending search for new oil. Our future
domestic crude oil supply is in a critical situation, for
present estimates of known reserves indicate that only 32
billion barrels are available, scarcely 10 years at present
domestic production rate and only 5.5 to 6 years of our
total annual demand. Of this known reserve, it is estimate?
that possibly as much as one-fourth will come from offshore
California and Louisiana.
Most present day domestic petroleum and natural gas
exploration is looking to potentially oil-bearing formations
beneath the sea, the outer continental shelf areas of the
Atlantic, Pacific and the Gulf of Mexico. Oil and gas pro-
duction is well established in the Gulf and smaller areas of
the nation's Pacific shelf off of California and Alaska, but
the Atlantic and Alaska are horizons for exploration and
development in the future.
2.2 Offshore Petroleum and Natural Gas Operations
The major offshore oilfields are shown in Table 2-1.
In 1975, the offshore oil production from all major fields
amounted to 964,383 bbl/d, about 11 percent of the nation's
total output.2 In 1974, the Gulf of Mexico offshore
2
J.C. HcCaslin, "Gulf of Mexico Current is Offshore
Leader," Oil and Gas Journal 74(35) (August 30, 1976); Oil
and Gas Journal 74(18) (May 3, 1976).
-13-
-------
TABLE 2-1
OFFSHORE OIL PRODUCTION AND RESERVES
MAJOR
FIELDS IN THE UNITED STATES
(million bbl)
Elite
M»ko
California
toulilini
rieid,
Dlfenmy Data
Craoltt Point
HcArthur liver
Middle Ground Ihoel
Do> Ciudro. Ill*
s»«a rnea. 19IB
Runtlngton Belch, mo
WlUingUm. 1(11
l<) Mircnard.
Ik. tllncl.
ooihorel, 111!
Cvgent Ulead
ik. us, mo
Eugene lilnd
Bk. )U. 1971
Eugene laland
U. 111. 1916
I*|ene Island
U. 2ti. 1914
Oiand lele IV.
li. Ull
Claud lale ik.
41. l»l
Cr.nd nu M.
It..
If, 1HI
IKIn P«t It
19. Illl
Min nn n.
JM, 111*
>Mp >bni tk.
>0«. l»ll
Ship Ihoal, n.
III. im
IMp Shoal Ik.
101, Illl
MHUl Nltlh
lalaod >k.
>1, 1961
South Pa«a Sk.
11. line, onatarel
1910
loulh paia Sk.
11, I9I«
South ran ik.
11. !«>>
South ra» •>
M. IK9
Tioballer Bay.
St. 11. I9M
Kit Helta Ik.
1*. 1919
Oil Delta Bk.
ss, mi
Kelt Delta Ik.
». 19U
No.
fella
11
51
15
III
1,0*1
I.l»
19!
SC
US
89
60
It
IIS
(I
U
111
114
II
41
7]
1!
Ill
MI
«l
SS
111
194
70
111
I91S
Production
4
II
'
14
17
II
11
1
»
S
1
11
17
1
1
1
S
1
S
S
i
n
9
S
1
«
U
9
S
emulative
rrnductlon
10
191
96
Hi
111
1,717
IS1
91
II
•I
II
111
Itl
(I
SI
191
17
11
19
101
II
III
ISS
M
M
MS
1U
17
Ul
Zatluted
loalnlnt
Kanrvaa
SO
101
19
79
1.000
11>
111
191
II
IH
II
111
117
119
11
19
il
III
11
US
111
(0
IOC
111
IIS
111
IS
IM
111
111
Ply lone
Depth. Ct
Renal, 1.711
lenal, 1,571
Penal, 7,776
•lloeina. 1,M)
Nloceno, 10,000
Hlo-Mlo.. 1.100
Mo-Pllo., 1,1001
1.I1H
Miocene, 1,0001
Miocene, I.9S1
Kloetne, 9,4)1
Pliocene. 1.01]
Miocene, 1,SJ9»
Hlacene, 1,11S<
Hlocene, l,»s>
Nlocern, 6.0001
Miocene. S.inoi
Hlocane, 4,1(7
Hlocent. l.s»i
Miocene, 11.I1K
.•locMe, 9.IS9*
Miocene. 1.7101
Mlocnt. 6.510.
Miocene, l.sut
Miocene, S,»l4
Miocene. I.O11*
Miocene, 1.1161
Hlocene. I.1S1.
Miocene. II.SII*
Klocene. 8. Ill*
Source: Oil and Gas Journal 74(10) (ray 3, 1976): 1*9-150.
-14-
-------
Fi*urea 2-2, 2-3 and 2-4 produced about
barrels of oil or about 73 percent out of a
total of 533 million barrels produced of rsSore. SnUl
SfxSo'L Iff? ^ AtlantiG are dev*loped, "the Gulf of
Somo^- Jikfly t0 continue to be the most important
domestic offshore source of oil and gas.
there has been considerable dispute over
?wnershiP e«ds offshore and where federal
r *-K eera
Dunsdiction begins. This is due to the fact that at places
where the wetlands merge into the sea, it is difficult to
determine exactly where the shore might be Furth"er7 grants
related to early Spanish and French treaties have been de-
fJST* by. the 8tate t0 give ri*hts beyond the f-mill
limit. Recent court decisions have partially settled this
dUte
S0m£
£he C°aSt' mOSt of
shallow water and amphibious
u °r might not ** considered to be
Aitnou9h much of the technology for offshore
dev?loPe* in these areas, thlse nearshore
n0t considered to be within the scope of this
murestaoTrei the8e nearshore operations a?e in a
?h! n, 4- ? °? deve^Pment compared to the activities on
the outer Continental Shelf. Emissions from these sources
will be considered in a future report.
off«hore wel* was drilled in 1945 by Magnolia
C°mPa"? (n°W M°bil Oil Company). 3 A converted
cKaS,b^11: °n a wooden structure in 20 feet of water
Ship Shoal Block No. 58. The well was a dry hole?
exP?nded in the Gulf ffom 2 platforms in
ia H M K ^Jtiple-well platforms in Texas and
^3?9 ?y f?h ^974 (S6e Table 2'2) ' Of ^e original
ann ? le:we11 Pjatforms built, hurricanes have claimed
il,3^ °" X LVete*0st by fires' blowouts or other unusual
since i«i bj" ^;3 summafizes the frequency of incident
since 1964. Eight companies own 498 major platforms contain-
ing six or more wells or 77 percent of the ?otal Sor
structures. Some platforms have dual ownership '
f«™,e *' ?ari"iC?aeli "The Industry Has Built Over 800 Plat-
forms in the Gulf of Mexico," Offshore 35(5) (May 1975): 83
4 ~~
,^4. %'S' Ge°l°9fcal Survey, Conservation Division, Acci-
dents Connected with Federal Oil and Gas QPerv>!-<»»" ^9°^
Outer Continental SheJf. .Tni» iatu r =iiH
-15-
-------
I
(-•
0%
-------
i
H
-J
Figure 2-2b. Approximate location of the proposed and existing
pipeline-flowline system, Offshore Louisiana, March 1974. (W.M. Harris,
S.K. Piper, and B.E. McFarlane, Outer Continental Shelf Statistics.
U.S. Geological Survey, Department of the Interior, 1976^, p. B) .
-------
...... > .
i-'V'/v*.
Figure 2-3. Offshore Texas oil and gas fields. (Bureau of
Mines Information Circular 8408.)
-18-
-------
«•
MOBILE
MpBILE SOUTH
GULF
•i*-*^' **^^
PENSACOLA
.-'' N>Xv\
PENSACOLA SOUTH '
OF MEXICO
iiiiii! iiiii iiiiiiiiiiiiiiiiiiiiiiiiiiiiiiiiii
t
'\» i
\ S, v\
\ N> ^
\ \ \
APALACH'ICO LA SOUTH
\ \
* \
t \
t \
i i
i V
1 \
1 \
TAMPA V/EST '
I
\
\
LEGEND \
• PLATFORM ^KKMM0 %
W.US
"slH;-;;;;;;;;;;;;;;;;
^Iniiiijiijilllli
GAINESVILLE::
\
i TARPAN SPRINGS
x /i;;:;;;;
\ )i::::::::J
i ?L
% °»
f \
1 FT. MEYERS WEST
Figure 2-4. Gulf of Mexico leasing areas and oil and gas
fields, offshore Mississippi, Alabama, and Florida. (Offshore,
36(7) (June 20, 1976), Supplement.)
-19-
-------
TABLE 2-2
OFFSHORE PLATFORMS IN FEDERAL WATERS
LOUISIANA
West Cameron 45
East Cameron 39
Vermillion 42
South Harsh Island 47
Eugene Island 107
Ship Shoal Area 85
South Timbalier 62
Grand Isle 62
West Delta . 94
South Pass 15
Main Pass 40
Bay Marchand 15
South Pelto 2
TOTAL 655
TEXAS
High Island 6
Galveston 3
Brazos 4
TOTAL 13
MISSISSIPPI, ALABAMA, FLORIDA
(MAFLA)
Mobil South *1 1
TOTAL 1
CALIFORNIA
Santa Ynez la
Santa Barbara Channel 5
TOTAL 6
GRAND TOTAL 675
aUnder construction.
Source: Offshore 35(5) (May 1975): 84.
-20-
-------
TABLE 2-3
MAJOR OIL SPILL INCIDENTS
CALENDAR
YEAR
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
1975
INCIDENTS
5
2
0
1
1
6
3
1
0
4
2
1
OIL SPILLED
(bbl)
14,928
2,188
None
160,639
6,000
30,024
83 ,.895
450
None
22,175
22,046
Unknown
NUMBER OF
FIXED
STRUCTURES
1,100
1,200
1,325
1,450
1,575
1,675
1,800
1,891
1,935
2,001
2,054
2,079
ANNUAL OCS
PRODUCTION
(106 bbl)
123
145
189
222
269
313
361
419
412
395
361
328a
TOTALS
26
342,345
3,537C
Estimate
-21-
-------
M-n Ear»Y Platforms had from 3 to 12 slots or positions for
wells. AS recently as 1974 one 40-slot, three 3°-slo? and
f^r°uSii ~S Platforms were installed in water depths
Oil ComSi -Water ^° "5 feet in dePth- At Present, Shell
ato^v NP L1S Completing its 40-slot platform in South Pass
closp h»'il oond " C°nstructing another 40-slot platform
tho rnSn I !eet °f water' shell's Platform slated for
the Cognac structure in the Gulf will be 1,265 feat tall and
Sii* 3X* 6?,9lots a"d will stand in 1.020 feet of water
ri out_ miles southeast of New Orleans. All told, the
a^'mS??°?1Cali?UrYey (USGS) reP°rts 2,079 (1975) single-
and multiple-well platforms under their jurisdiction in
offshoia Louisiana and Texas.
i * Cafifornia offshore areas are shown in Figures 2-5 and
-i-b. Five platforms presently operate offshore in the
BhH«ra"Santa.Barbara area in Federal waters. Eight near-
shore production platforms and one production island are
also located here. On the Par-iffi-. »*»««. j.w_ , .
*** Pa°ifiC C°aSt' the water
deep a rt; * a°C C°aSt' the water becomes
aeep at a fast rate, so even the site of the newest platform
8 0'5" 8 '
85° feet of water °"ly S.ues off-
ss s?.s
In CalLnr ?ep^mber ^976' i'7" ri9s "ere active and working.
to" 84 ^ ?™a ^6f r-9- are drillin9 offshore, as compared
oL ^ i "J; " Louisiana 73 ar« operating offshore as
compared to 53 in inland waters, fiand 104 on land; in Texas
41 are offshore and 635 on land.6 Tables 2-4 and 2-5 sum-
marize the rigs and vessel types which are available.
The jack-up type rig has considerable popularity in
relatively shallow water up to 300 feet in depth. Submer-
sifcles, drilling vessels and semisubmersibles are used in
deeper water. As of June 1976, 283 offshore rigs were
working, 50 were idle, 10 were en route and 87 were under
construction. '
a, 11 ?'!!; l*19ht» Jr" "Exxon Begins Installing World's
Tallest Platform," World Oil 193(1) (July 1976)?
1976) I'lol!168 R±9 COUnt'" 0*1 and Gas Journal 74(30) (September 29,
"Mobile Units," Offshore 36(6) (June 5, 1976): 91.
-22-
-------
i
to
UJ
I
SANTA CRUZ ISLAND
AREA
SANTA BARBARA
ISLAND AREA
Figure 2-5. Offshore Southern California Bocderland Area. (U.S.
Department of the Interior, Bureau of Land Management, Pacific Outer Continental
Shelf Office.)
-------
I
1-0
-------
TABLE 2-4
RIGS AVAILABLE BY TYPES - 1976
ui
RIGS ATLANTIC OCEAN
Working
Idle
En Route
Drill Ships
Semisubmersibles
Submersibles
Jack-Ups
7
1
-
3
5
-
-
PACIFIC OCEAN
4
4
2
7
2
-
1
LOUISIANA GULF
51
6
-
5
11
15
26
TEXAS GULF
5
3
-
4
5
1
18
-------
TABLE 2-5
LOCATION OF AND TYPE OF DRILLIUG RIGS AVAILABLE
FOR U.S. OFFSHORE OPERATIONS
M»MI • IOCATION
OWNER
NAME t IOCATION
OWNER
Globol Marino Inc.
Global Maring. It*.
ATLANTIC
7 working; I idlo
OOirNIN Dolphin Drilling
jgmliubnuriiblo drilli n JO.OOO' in I.300-
Omran, Ipoin
GlOwAt CHAUENGE4
Orillihip diilli u Jl.OOO- in unlid. wotir diplh
Scrropi. Atlantic
GlOvAf. SIBIE
Dri'linlp drilli la 21.000' In 400'
Oalltfigtr, Faro Portugal
M. V. HIION Anocialfd Marino Sirvicii. Inc
Orillihip drilli to 1,3W in 600'
Idlo. lailan. Man.
PINIAGCNE 14 farm Nipnui* (and/ar alfilialid Cy)
Sortiubmiriiblo diilli la 20,000- to tW
1 N P.A . Franco, anrnnny If mill I Mar d'lroiio
MfSUSA OHihan Drilling Inc. (Kolukundii!
Soniidbmiriiblo drilli la lo.W in 660-
Slwl. SooniiH tar ol Bitcny. Mar Caolabrico C-I
StOCO I Saulhoailcm Commonwialrh Drilling lid.
iMiIubmnMl* drilli la J5.000' la BOB*
Union T«ai. Spain Tarragona E-2
1EDCO J Soulnooitorn C°fnmon»tallh Drilling, lid.
SMH,.bn»riiblo dfilU 10 15.000- in NO*
Ouao Production Co, Atlantic OCS
CARIBBEAN
4 worMngi 1 an icnifo
Amaihor*
Zapoia Olf-Shon Co.
C.iCCSEIER III
3r llifi.a drilli in 1000'
Tr iidod. May 74
LOUISIANA
SM.wMn.i.bla drllli la JO.OOO1 In AUT
ti rayii Trinidad far Oimlnii
•AT lUTHllfOIO. U. B.W-Vill»9 D..lling J. d. I I
t^:iubiM>l.bla drill! la JJ.OOO" In MB
•..«<». Trinidnd. Calaata feint
LOUISIANA
31 walking) 6 Idh
SA«S: A
Swoi-.'I.bl. dnlli In tt.OOO- in '75
Ov i. So-th T.mboL.r II
ll'jE WAttt Na i
San1 »tb-n»ri!bl> drilh IQ M.0001 in 600'
U* x>. Win Cornwall 39J
r-ATH NO. 4
I*«:i.a~...i!blt drilli la 75.000' in IJOO"
St M
*«i.a~...it ri a .
A.-O.BI. •Miahna. MaWU Sanlh. St MU CAS
hn..i.bn«iiblt drilh fa 35.000' in MXT
8U11TN TWO SIXTY
laa-jp drillt la 10.000- In 740'
Sk \r. W«t Caniran tU
fl SOIAOO
Summibh diilli la 11.000' In 70'
Onan 'rad»algn. Ship Sh«il II*
Jaaw drill! la U.OOO* in MO'
V.-1. V,rm.lian »
RCM
Jatko drill! la JO.OOO' In MO*
Sh.ll. Varnuliaii IK
ClCVAl II
MlliMo Jrllli to 75.000' in MO-
A.a.lahU, Qiill Coon
CI.CMAI CONCEPTION
0»»ih,p drilh I. 73,000- .n MO'
•ala O«tt Coa.r
GLO-A9 OIANO ISK
Dnllinip dnlli lo 7J/MO" in 600'
A.ailaato, Cull "» M...CO
Sanla f. Intl.
S«nlo h Infl. Carp.
Diamond M Biilling Co.
Ol.ilyn Intunallongl Inc.
ODECO, Inc.
<""« • «g»l«o'' A/S
D!a~and M Drilling Ca.
Olabal Marbw. Inc.
Olabal Wari™ Inc
Olobol Mo.i»» Inc.
INTREND
Jackup rfrilh la JO.OOO1 in MO'
Pmncail. Cugnnn liland 110
J. 5TOIM I
lockup drill! la M.000' in JJ3'
M«a. Sa. P«ll« II
JOHN HAYWADD
S.bm.mbl* drilli la 23.000' in 10
Maralhen. Engm liland M
MAIUN HO. 3
Jackup drill, to 11.000- in 150
Sktlly. ntain Pan 28
MARUN NO. 6
Jackvp drilh la 30.009' in 300'
Tannoco. W.il Cam«an Ia5£l2
MISSION EXPIOIATION
Drlllihip drill! la 38,000' in 400'
Panniail. Gulf Mi.ico
MOVISIE NO. 1
Siikmmihla diilli la 15,000' hi W
9h»ll. South Pail. 17
MOVISIE NO. 1
Submoriibta drilli lo 20.000' in 4V
Union, lo.ih Mo.lh Uland MO
MR. CHAIIIE
SvbnwiiMa drilh la 35.000- In W
Ovlntana. Boy of Marchond 5
M*. GUS II
Jackup drilli la 15.000' in ISO-
Union' Eugona liland 17= OCS-G-I21I Af-l
MR SI Plvar Drilling Sirviai. Inc. Carol
Jackup diilli in W
Cull Oil. Wnl Camgran 1M OCS-G-1841 Z\
NEW EIA Diamond M Oiilllng
Stmiiukmariiblg dnlli In 1.000'
Amoig. Mobilg Sa. S3 461 -N
OCEAN 44 ODECO Inc.
lockup dnlli to 23,000' in 170'
Chivfon, Scwih Morih Uland 283
OCEAN Df.lll.Et ODECO Inc.
SamiuihmgriibU drilli lo 13.000' in 600'
Chivron. Main Pail 212
OCEAN IEADE* OOECO Int.
Jackup drllll to 21000' «i 175'
Panniail. Vcrmillaii 22(
Zapala Olf-Sho.« Ca.
ntarin. Drilling Co.
OOCCO, lot
Marlin Drilling Ca.. Inc.
Marlln Drilling Co., Inc.
Minion Drilling & Eiplaralian
Tilidrni Ma»ibli OUihara. Inc.
Tolidyno Mo.ibli affihera. Inc.
QOKO Inc.
•luar Drilling Sgrvicci. Inc. Caral
OCEAN QUHN
S«iiiitibnwHlb1i dnlli la 25.000 in I.JOC
Shell, Vormilion 391
OCIAN PtIDE
Jaikup diilli la 25.000' in 110
Skill. Vormllian 22
OCEAN SCOUT
Scmiiubimiilbla diilli la 20.000' In 600
Panniail. Evggm liland 137
OCEAN STAR
Jackup drllll la 21AM' in 171'
Ocaan Prod.. So. Timballor 16
ODECO tEVEN
Subnnrilblg drilli to 23JXW in 15*
OwMon. Soulh Timbolifi II
OCEAN TIAVEUE
SomiHibnwitblo diilli la 25.000' in 600'
Oil, Wgil CamMen 311
PMI III
Jockup drilh In 70-
Sh.1l, Soul* Pun 17
PMI IV
Jackup dill'. In 70-
Mobil, ihiayaid far upairi
PMI V
Jackup drill! In 70'
MoMf Main Pail M
PMI VI
tickona'.'oil1* Cai. Win Com.™ 2I-6-NII-16
P1NROD M
Svbmoriiblg drilli to 23.000 in 50'
Sk.ll. V.rmllian 12
PCNIOD SI
Subnunlbb drllll to 15,000' in 6»
Kirr-M
-------
TABLE 2-5 (CONT.)
NAMI 1 LOCATION
tENIOD 9
lockup diilli lo ».00fl- In JOtT
Vickiborg bf ropaiii
PENIOD it
Jaikiia diilli to 30.000* in MO"
Oottr, W»l Cannon 17
PINIOD 60
Jackup drilli la JO.OOO' in 140*
Placid. Smith Marih liland 111
PINIOD oa
Jackup drill! i« 30.000- In 140'
Mobil. Grand lib J1
PINIOD 72
Somiiubnuiiibb drllll to 30.000* in 2.000'
Placid. Mobil. South -2 N«62 E69
IANCEI III
Jorivp diilli lo 1I.WO- in 7i-
Mobil Coil Common. U
DC 44
Submaiirblo Ailli n 20.000* In 40'
K.rr-WcOn, Skip Shoal
IIC 41
SubnwiIM* d-nlli to 20.000* In 33'
brr-McCeo, Bftlw Sound M
IIO 47
SvbM'riblo drilli lo 20.000- In 70*
Superior. WNI Conxion, 71
IIC S4
Jubmcnibll drilli lo 70.000' in I7J-
Mobil. Main Pan 7)
IIC 39
Jockup drllli la 20.000* in 121-
Mobil. Virmilian A
IOWAN.HOUSTON
Jaikup rinll. IB 71.0001 In 221*
Enorgr Ruouron GIB. Iraiai 747 I-1
(OWAN-IOI/ISIANA
JoiVup drill! la 10.000- in 3W
ConiaEdahan Natural Col. Vnmili
S-ll
Suanwiioh diilli l> M.OOO1 in 60'
In iSipro'd lot iguiprnont itniion
ST. IOUIS
Submviibb drilli lo 73.000' In IT.
Quintano. Evgino lilond 12
TEMPEST
Drillihrp drilli to 2J.OOO' In MO'
Mua. South Marih liland. 174
TOPPEI I
Jotkup d)!lh la 12.000* in 120*
Homton Oil a. MIntrali. Cull of Mnica
WISTEIN PACESITTH III
Smiiivbmtitibto diilh la 2J.OOO' in l.ZOO'-j-
(••on. Mobilo South 1 Noil 1041
ZAPAIA LEXINGTON
S.n!iub>»ii-bb drilh lo M.OW in 2.00O'
C»on. Mobilo So. 22 N6SI fOAl
WISTEIN POIAIIS II
Joikirp aVillt lo 21.000- in 2*0
Cm«i Sa*«i». turmali Oar al BoKgol
TEXAS
29 walking; 3 Ula
DIAMOND M CINEIAL Dlomond/Ovmial Drillrng lid.
Samiii/amariibU drill, la 10.000- rn T.COO1
lilion 229
OWHEI
Ponrod Drilling Co.
Ponied Orilling Co.
Poniod Dillliiig Co.
Ponrad Orilling
Poniod Drilling Co.
Allanlic Padllc Mariao
Tiuniwoild Dtining Co.
Tioniworld OilHing Co.
Traniwolld Drilling Co.
Tromwoild Drilling Co.
Trartiworld Diining Co.
lowan Inlirnolianal. Inc.
lei»an Coi., Inc.
Nabta Drilling
ODECO. Int
Japan Odin S.A.
Zapolo Ofl*SKoro
WMtorn Ocoanii
Zopala Otl-Shoro
Woitam OnaMi
OWNII
fhior Dtllllng Soniui. Int. Coral
Auailobhj. Sobino Pan
DIAMOND M 99
Jackup drilli to 30.000' In 300'
E*:on. Wtii Dolia 117
OIIUYK THIEE-SEVEMTY
Jack*! drilh la 10.000* In 370'
Clark. Higk liland AS6I
GIOMAI OIAND I ANN
Drilhhie d'ilb la 25MO- to 600
Euan. W«il Doha 71
CIOMAK JAVA SEA
Drillihip drilli la 23,000' in 1.300'
Aroo. Weil Dalla 120
J. STOIM III
Jackwp drilli fn 210'
Oil A Mmwall. Goblilon 1IJ-S
J. STOIM IV
Jackup
Canon. Moiogordo oil-1
MAILIN NO. 7
SemiivbmoriiBle drilli lo 10.000- in 1.000'
Slacked, Sooin* Peru
MISSION VIKING
DrJIlMp drilli la 30.0001 In IJ901
Ml. AlfHUI
SufetMnibb drilb la 20.000* in W
Getty. High Ulnnd 74. OCS-O-3I1O 91
Source: Offshore 35(5)
Diamond M Drilling Co.
Dlrilyn Inlarnolianal Inc.
Global Motint Inc.
Global Motint Inc.
Mailno Drilling Co.
Marino Drilling
Moilln Drilling Co.. Ini
Million Viking
NAMI I
Ml. Mil
Jockup drilh lo 30.000' in MO1
lurmoh Oil 4 Got. High lilond AO17 OCS-G-2412 XI
Ml. SAM Fluor Drilling Snticti. Inc.. Coial
Jockup drilb to -AOOO- In IS!'
Rutherford Oil Corp, Gahroilaa SI 104-L
OCEAN CHIEF
Jockup drilh lo 2UOO' In 224-
ODECO Inc.
Octidtnlol. High liland A-JIO
OCfAN EXPLOIEI
SimliHbmiriiblo drilli to 23.000' in 6W
Shall. Muilang lilond 740
OCEAN EXPCESS
Jackup diilli lo 25.000- In J30'
Marathon, Muilang liland A4I31
OCEAN KIND
Ja»kup drilli lo 25,000' In 140'
Svpoirar, Muilang liland 030
ODECO Inc.
Od.co
ODECO Inc.
PtNIOD «1
Jeckvp drilb lo 30.000 in 340'
Chioi Sonic*. Mvitang liland A-S4
IANGEI I
Jackvp diilli la 10.000* in 70*
McMoran Eiplaration. Maiagoida liland. S/T 6*1 \£>
Pinrod Dillling Co
Allontii Pacific Mannt
•1C 10
Jockup drilh lo 11.000- in 70*
Suporiar. Mologorda lilatid ST HJ-S
ScDNEIH 1
Sintiiubmiriibb drilb la 21.000' In 600*
T..CTCO. High lltenrl A-1M
STORMDIIll V
Jackvp drilb lo 20.000* In 171'
Continental. High Icland 137
TELEDYNE NO. 16
Jackvp drilli la 23.000' in 210*
HA. Cull of Mvilco
TIAN1WOI1D IIO 63
Jackvp drllll 10 20.000' In 200*
Cltgo. Golv.lton A-14
TIANSWOILD IIC 44
Jackvp drilb la 20.000' in 300'
KwMcG». Gulf af Moiica
TIANSWCILD RIG 67
Jackup drilli la 10.000' in 40'
Milchlll Enngy, High bland 21-1
WESIE1N DELTA
Jockup drilli to 11.000* in 171'
KiL-or7 High lilond ST 9B-LS3
ZAPATA CONCOID
Somiiubmiiilbb drllll ID 21.000' in 2.000'
Mobil, lay City N6» E07I
ZAPATA TRADER
Drilhhip drilh la 20.000' in aOO'
Stacked, Oulf Caalt
Tronnroild Drilling Co.
(rilling Nfhirlandi. N.V.
Molina Drilling Co.
Tobdrm Mo.lbb Olfihait Inc.
Traniworld Drilling Co.
Troniworld Drilling Co.
Trontwarld Drilling Co
Weitirn Ocoomc
Zopota Olf-Shor.
lapalo OH-Shoio Co
CAIDIIU I
Dlllhlllp drilh lo 6,000- In 3.000'+
Idlo. Call!
CANMAI EXPLOIil II
Oiilhhla drilb la *UA»* in «00*
PalroUvjn, laowfolY Svo
PACIFIC
4 working. 4 Mi. 2 in nun
Morixo Drilling & Coring Co.
Cannot lOamo Ptlialovm
O.obo, Ma-in. In,.
Caldan Loot Drilling Co
Orilhhlp chilli 19 1r\000* In 400'
Union. California
GEORGE P. FERRIS Svn Marin. D,||,.>iB 4 OHiharc. Canitiuflaii. Ini
Jackup drilb «o U.OOO' In 200*
Union. Upper Cook Inbl. Alaiio
GIOMA* CORAl SEA Glebal Mann. \n.
Drlllihlp drilli to 23.000' in 1.300-
Gull. CoWomia
GOIDIIU 4
Dilllihip drilli lo 12,000* In ADO*
Remodeling, long Itach. Cclil.
HUGHES OlOMAP EXPIOIEI Svmmo Corp. (Gkbol Matin. lnc<
Drillihip diilli lo 12,000' in 18,000-+
Idle, long liodi. Calif.
IA CIENCIA Anociotcd Marino S*i»ic.i. Inc.
Drilhhip dnlh lo IJOO* in 400
OC!AN PIOSPECTOR COECO/IIID
Simiiubmnlbl* drilli 10 2S.OOO'In «00
En loula U S. w.it coail
ALIUTIAV K|r. OFFSHORE CALIFOIMIA *.„ Orlll«g Co.
Smbiamnbri onlh u JS.OW in I.OfXr
Drillrni Co
tauiingaik
(May 1975): 397-417.
-27-
-------
A trend in rig design popularity is indicated by those
under construction as of June 1976 which include 19 drill
ships, 32 jack-ups and 36 semisubmersibles. An estimated
361 mobile offshore rigs will be available worldwide by
1978.8
In the United States, in 1975, a total of 932 offshore
wells were drilled.9 of these, 581 were exploratory and 351
were drilled on known structures. In total, 256 oil wells,
194 gas wells and 482 "dry" holes were drilled. Table 2-6
shows that most of the successful activity occurs offshore
Louisiana. Texas offshore provided 12 gas wells, no oil
wells, out of 172 tries.
In California, there has been an increase in drilling
activity. Two recent discovery wells have been drilled in
the San Pedro Bay area by Shell and Standard Oil of California
in about 650 feet of water 15 miles south of Long Beach. It
is reported that the oil is 19.5 degrees API gravity on the
average. If production is typical of other fields in offshore
California, a gas-oil ratio of 200 to 500 ft3/bbl would be
expected. Exxon expects a gas-oil ratio of about 1,000 in
the Santa Ynez field where platform Hondo is located. The
oil has a sulfur content of 4 to 5 percent and is 18 to 19
degrees API gravity.
Three rigs are drilling in Federal waters of California.
The Aleutian Key, under contract to Gulf Oil Company, is
drilling in 680 feet of water on OCS-P0258 (Tract 76) at
Tanner Bank \n the Santa Rosa-Cortes South area. Texaco is
drilling with a semisubmersible rig in the San Pedro area
adjacent to the earlier discoveries. Well depths are typi-
cally 10,000 feet or less.
Table 2-7 shows the trend of wells drilled and produc-
tion offshore during the past 5 years. In most statistics,
the completion of two zones or more in a single hole is
reported as two or more wells, as the case may be. The
above data varies slightly with that of the USGS because
some offshore wells in state waters are included.
Offshore production of oil, gas, and condensate by area
is shown in Tables 2-8, 2-9, and 2-10. This production
g
J.V7. Speer, Manager of Drilling and Production Operations,
Shell Oil Company, in "Lengthy World Mobile-Rig Surplus Seen,"
Oil and Gas Journal 74(45) (November 8, 1976): 130.
g
"Worldwide Statistics," Offshore (June 20, 1976): 65, 77.
-28-
-------
TABLE 2-6
1975 EXPLORATORY AND DEVELOPMENT WELLS
DEVELOPMENT HELLS
STATE OR DISTRICT
Alaska
California
Louisiana
Texas
Gulf of Mexico
north
TOTALS
OIL HELLS
WELDS FOOTAGE
U 124,504
60 214,264
179 1,578,602
252 1,917,370
GAS HELLS
HELLS FOOTAGE
177 1,771,008
5 42,294
182 1,813,302
DRY HOLES
HELLS FOOTAGE
2 4.774
139 1,338,431
5 50,713
1 9,489
147 1.403,437
TOTAL
DEVELOPMENT HELLS
KELLS FOOTAGB
13 124,504
62 219,038
495 4,688,041
10 93,037
1 9,489
581 5,134.109
EXPLORATORY WELLS
STATE OR DISTRICT
Alaska
California
Louisiana
Texas
Gulf of Mexico
North
TOTALS
OIL HELLS
HELLS FOOTAGE
2 12,340
2 25.EB4
4 38,023
GAS HELLS
HELLS FOOTAGE
5 44,924
7 70,504
12 115,428
DRY HOLES
HELLS FOOTAGE
1 14', 01 5
4 32,579
144 1,302,702
155 1.345,956
31 336,593
335 3,031,845
TOTAL
EXPLORATORY WELLS
HELLS FOOTAGE
1 14,015
6 44.919
151 1.373,310
162 1,416,460
31 336,593
351 3,185,297
Source: '1975 Totals for Exploratory and Development Hells," Offshore 36(7)
(June 20, 19761: 77.
-29-
-------
•I'Ani.r: .•-•/
TREND OF THE NUMBER OF OFFSHORE WELLS DRILLED IN THE UNITED STATIC!
YEAR
1975
1974
1973
1972
1971
i
Ul
o
I
Number of Wells
Drilled
Production*
932
1,128
1,029
926
(103 bbl/day) 964 1,148 1,589 1,667
916
1,692
Includes some production in state waters (e.g., 135,000 bbl/day in 1975)
Source: Oil and Gas Journal 74(18) (May 3, 1976): 150.
-------
TABLE 2-8
ANNUAL PRODUCTION ON THE OUTER CONTINENTAL SHELF
CONDENSATE LPG
OFFSHORE OIL PRODUCTION3 GAS PRODUCTION3, GASOLINE
AREAS (barrels) (thousands of ft ) (barrels)
California 15,304,757 3,95'l,633
Louisiana 287,515,795 3,332,169,057 72,463,738
Texas 338,589 1,218,139,769 10,959,837
Delivered onshore, i.e., sales volume.
-31-
-------
TABLE 2-9
PRODUCTION PROM OFFSHORE CALIFORNIA OILFIELDS IN STATE WATERS, 1975*
i
LJ
FIELD NAME
Belmont
Hun ting ton Beach
Newport, West
Torrance
Venice Beach
Wilmington
Carpentaria
Montalvo, West
Rincon
Summer land
Caliente
Alegria
Coal Oil Point
El wood
El wood , South
Point Conception
Molino
TOTAL
OIL
(106 bbl)
2.48
13.90
0.10
0.46
0.12
44.00
1.44
0.07
0.41
0.25
-
0.03
0.01
0.04
1.17
0.08
™
65.50
GAS
UO9 ft3)
0.62
1.95
0.04
0.60
0.05
10.00
1.76
-
0.21
1.2B
0.35
0.08
0.04
0.20
0.04
0.04
3.49
21.44
LOCATION AND TVPE OF FACILITIES
Manmade islands (2)
Platforms (2), onshore wells
Onshore wells
Onshore wells (Redondo Drill Site)
Onshore wells (Venice Drill Site)
Manmade islands (4) , onshore wells
Platforms (2) plus 2 platforms
in Federal
Onshore wells
Onshore wells, seafloor well.
piers, manmade island
Platforms (2)
Seabed wells
Seabed wells
Seabed wells
Onshore wells, piers (abdn.)
Platform
Onshore sites (2) , platform
Seabed well
aTotals may not agree with totals due to rounding. Excludes Ryers Island gas field
which is located in the Sacramento delta area (1975 production, 3.1 x 109 ft3) .
Source: Resources Agency of California, Department of Conservation, Division of
Oil and Gas, California Oil and Gas Production Statistics and New Well Operations,
Report PRO3, 1975.
-------
TABLE 2-10
ANNUAL PRODUCTION IN OFFSHORE CALIFORNIA OILFIELDS
i
to
CJ
TO
FIELD NAME
Belmont
Hun ting ton Beach
Wilmington
Carpenteria
Suiranerland
El wood , South
Rincon
Conception
Cuarta
TOTAL
OFFSHORE FACILITIES IN STATE WATERS. 1975
PRODUCTION TO
OFFSHORE
OIL
(106 bbl)
2.48
3.5 (E)
14.5 (E)
1.44
0.25
1.17
0.02 (E)
NR
NR
23.36
FACILITIES
GAS
<109 ft)
0.62
0.5 (E)
3.3 (E)
1.76
1.28
0.04
0.01 (E)
NR
NR
7.51
FACILITIES TYPE AND NAME
MANMADE ISLAND PLATFORM
Ester, Belmont
Emmy , Era
THUMS Islands (4)
Hope, Heidi
Hilda, Hazel
Holly
Rincon
Heiman
Helen
7 9
E = Estimated.
NR = Non reported, shut in.
-------
reaches shore facilities by pipeline or barge following
Tnrrh^^ g~u6S °f Processin9 onboard platforms as discussed
in Chapter Three The current distribution system is sum-
marized in Table 2-11. Some 66 pipelines and 14 barge
systems deliver production to shore with pipeline systems
handling over 95 percent of the production. Tables 2-12 and
^-u list the pipeline and barge systems, respectively
Exxon will utilize a tanker system to handle oil from its
platform Hondo in the Santa Ynez field off of California
At present, Exxon plans to reinject the gas rather than
pipeline it to shore. The reasons given for this are envi-
ronmental costs and the inability of the company to obtain
required permits for movement to shore.!0 The crude oil
production will be sent to an offshore storage and treating
facility onboard a converted tanker moored near the plat-
form. Up to 200,000 barrels of crude can be stored there
tor loading later onto tankers for shipment to refineries.
2.3 Government Regulations
With some noted exceptions, the USGS is now responsible
for control of the oil and gas activities offshore beyond
the 3-mile limit. The U.S. Coast Guard, the U.S. Corps of
Engineers, the U.S. Navy and some other Federal agencies
cooperate to allow the oil operations and coastal barge and
sea traffic to mutually exist in relative safety.
The operation of the offshore platforms must be kept
safe for the personnel aboard as well as serious accidents
or damage to the platforms from outside sources. Kessler
discusses the issues and government agencies that have some
involvement in the protection of these structures.il There
have been some collisions. There is a constant trend to
enhance the physical security of these structures but at
this time there is little protection for the structure itself,
Major damage to the structure could cause a release of oil
or gas and possibly extensive and expensive fires as well as
possible loss of life. The U.S. Geological Survey of the
Department of the Interior makes daily inspections of the
offshore facilities to assure that regulations and safe
operating standards are maintained. Twelve basic orders
cover their efforts as shown in Table 2-14.
,c » Personal communication to R.K. Durr from E.P. Crockett
(for API), February 14, 1977.
C.J. Kessler, "Legal Issues in Protecting Offshore
Structures," Prof. Paper No. 147, Center for Naval Analyses,
Arlington, Va., June 1976.
-34-
-------
TABLE 2-11
SUMMARY OF OFFSHORE TRANSPORTATION SYSTEMS
IN FEDERAL WATERS
CFFSHORE
AREA
PIPELINE
COMMINGLING SYSTEMS
BARGE
SYSTEMS
Louisiana
Texas
California
59
5
2
10
4
-35-
-------
TABLE 2-12
OFFSHORE PIPELINE SYSTEMS
(MARCH 19761 ~~
AREA
GULF OP MEXICO
Brazos
Calves ton
High Island
West Cameron
Cast Cameron
Vermilion
South Marsh Island
SYSTEM NAME
OR TERMINAL
Brazos
Blue Dolphin
Black Marl in
Mci'adden Beach
Sabine Pass
Sabine Terminal
Mobil No. 1
Cameron Meadows
Cameron Meadows
Mobil No. 2
Cameron Meadows
Stingray
Cameron Creole
Iowa
Grand Chenier
Deep Lake
Grand Lake
Geffstown
Grand Chenier
South Pecan Lake
Sea Robin-Hewy
White Lake
Jupiter
Freshwater City
Freshwater Bayou
South Bend
Tiger Shoal
AVERAGE
OPERATOR DAIT.Y OTT.
Cities Service
Shell
Shell
Chevron
Texaco
Chevron
Mobil
VOLUME
(barrels)
757
1,080
2in
£XU
348
J t 9
42
468
7BBa
General American ~78a
Gulf •>•>•>
Mobil
Sun
Chevron
Mobil
Transocean
Superior
Superior
TGTC Continental
Mobil/Amoco
Amoco
Texaco
Trans-Union
Union
Conoco
Union
Exxon
*m * &
& .100
- f •*• 7 V
72
1. 140
• f * T§ W
120
696a
1,760
3,785
408
84
O Tt
2,810
1,240
493
^ y
-------
TABLE 2-12 (CONT.)
AREA
Various
Eugene Island
Ship Shoal
South Timbalier
Bay Marchand
South Timbalier
Bay Marchand
South Timbalier
Bay Marchand
Grand Isle
West Delta
South Pass
SYSTEM NAME
OR TERMINAL
MCN-Burns
South Bend
Calumet
Exxon Trunkline
Tarpon Whitecap
Bonito
Coon Point
Cocodrie and
Pecan Isle.
Cocodrie
Gulf No. 3
Gulf No. 1
-
-
-
Gulf No. 2
-
_
Pelican Isle
Pelican Isle
Pelican Isle
Gulf No. 1
Gulf No. 2
Gulf No. 3
Venice
Burrwood
Shell No. 1
Burrwood
Garden Island
Shell No. 2
OPERATOR
Mobil
Pennzoil
Continental
Exxon
Shell
Skelly
Tenneco
Odeco
Gulf
Gulf
Tenneco
Chevron
Shell
Gulf
Chevron
Exxon
Conoco
Shell
Exxon
Chevron
Gulf
Gulf
Gulf
SLAM
Conoco
Shell
Gulf
Texaao
Shell
AVERAGE
DAILY OIL
VOLUME
(barrels)
14,400
18
178
1,182
228,150
1,482
7,452
7,438
2,826
16,516
798
6,876
23,298
28,020
336
29,850
29,166
5,562
2,700
11,990
12,348
12,011
218
28,056
1,200
5,670
774
1,560
34,495
-37-
-------
TABLE 2-12 (CONT.)
AREA SYSTEM NAME
OR TERMINAL
Main Pass shell No. 2
Venice-Getty
Terminal
Chevron No. 1
Chevron No. 2
Chevron No. 3
Chevron No. 4
Grand Bay
OPERATOR
Shell
SLAM
Chevron
Chevron
Chevron
Chevron
Gulf
AVERAGE
DAILY OIL
VOLUME
(barrels)
32,628
14,148
7,806
7,872
11,670
7,419
PACIFIC
Santa Barbara
Standard of
California
Phillips
21,000
11,000
-30-
-------
TABLE 2-13
OFFSHORE BARGING SYSTEMS
IN OPERATION AS OF MARCH~1976
AREA
GULF OF MEXICO
Eugene Island
Eugene Island
West Cameron
Main Pass
Various
Various
Vermilion
South Marsh
Ship Shoals
Calveston
High Island
SYSTEM
NAME
Beaumont
Gibson
Cameron
Chalmette
Shell "A"
Shell "B"
Lake Charles
Port Arthur
Morgan City
Texas City
Texas City
OPERATOR
Union
Chevron
General
American
Mobil
Shell
Shell
Tenneco
Gulf
Mobil
C&K
Texaco
APPROXIMATE DAILY
OIL OR CONDENSATE
PRODUCTION
(barrels)
2,910
unknown
155
1,150
4,900-6,680
890-2,640
4,050
1,400
155
140
2,232
-39-
-------
TABLE 2-14
ORDERS ISSUED TO OPERATORS ON THE
OUTER CONTINENTAL SHELF BY THE~
U.S. GEOLOGICAL SURVEY. DEPARTMENT OF INTERIOR
PCS ORDER
1 Marking of wells, platforms and fixed structures.
2 Drilling procedures.
3 Plugging and abandonment of wells.
4 Suspensions and determination of well producibility.
5 Installation of subsurface safety devices.
6 Procedure for completion of oil and gas wells.
7 Pollution and waste disposal. '
8 Approval procedure for installation and operation
of platforms/ fixed and mobile structures.
9 Approval procedures for pipelines.
10 Sulfur drilling procedures off Louisiana and Texas.
11 Oil and gas production rates, prevention of waste
arid protection of correlative rights.
12 Public inspection of records.
-40-
-------
It is possible for more than 70 percons to be on a
platform or rig at one time so personnel safety is of major
consideration in the inspection program. Control of pollu-
tion of the sea and air is also an important aspect of the
inspections.
Each state, as well as the Federal government, has en-
vironmental laws and regulations which apply to the drilling
and production of oil and gas. While these may vary from
state to state, basically the laws are designed to protect
the offshore environment. The American Petroleum Institute
has published a review of various state and Feder. I regula-
tions related to environment protection and oil operations.12
2.4 Future Activity
On the Outer Continental Shelf of the contiguous 48
states, several new provinces have been or are likely to be
leased for exploratory drilling and development of oil and
gas resources. As discussed above, the availability of
mobile offshore rigs, particularly semisubmersibles, should
not be a constraint to activity in these offshore areas.
Over the next 10 years, the industry's offshore exploration
and development budget, the state-of-the-art and the antici-
pated economics of these new areas will set the course of
development.
The implications of these factors for development
through 1985 are recognized by the industry. Drilling will
be carried on in water depths where platforms can be installed.
Table 2-15 illustrates the present and anticipated capabili-
ties of the technology. As Table 2-15 shows, this means
water depths of less than 600 feet in the East coast areas
and less than 1,500 feet for the Gulf of Mexico and offshore
California areas of the Pacific.13 In 1975 the offshore
exploratory drilling cost for the industry was approximately
$4,300,000/day and planned increases for 1976 over 1975 are
7.8 percent.1'
American Petroleum Institute, Environmental Protection
Laws and Regulations Related to Exploration Drilling, Pro-
auction and Gas Processing Plant Operations. API Bulletin D18
1st ed., Washington, D.C., March 1976.
Speer, in "Lengthy World Mobile-Rig Surplus Seen," p. 130.
14
W. Plamondon, Director of Sales, Zapata Offshore, in
"Lengthy World Mobile-Rig Surplus Seen," p. 130.
-41-
-------
TABLE 2-15
PLATFORM WATER DEPTH CAPABILITY
WATER DEPTH OF
TRACTS CURRENTLY
OSC AREA LEASED
(meters)
MAXIMUM DEPTH
OF WATER AT
PLATFORM
LOCATIONS
[(meters) (feet))
OPERATOR
AND
PLATFORM
IDENTIFIER
Atlantic
Baltimore Canyon to 200
Gulf of Mexico
to 600
Southern California to 750
315 (1,020) Shell Cognac
262 (850) Exxon Hondo
Current or planned and under construction.
-42-
-------
Table 2-16 shows the estimated discoverable and known
reserves offshore the United States. The level of activity
in the Atlantic will depend on the size of the oil and gas
reserves chat are discovered. The first lease sale in the
V? IQ^C WaS held by the DeParUnent of Interior on August
l/, 1976. In this lease sale 101 tracts out of 154 offered
were acquired by the industry in the Baltimore Canyon through
JLnr I , L?" °f N6W Jersey and Delaware, as shown in
Figure 2-7. Other prospective petroleum provinces in the
Atlantic are also shown in Figure 2-8.
,,« i*" U?G? resource estimates are verified, these tracts
could contain 400 million to 1.4 billion barrels of oil and
«;L V pillion ft3 of gas. Projections of drilling and
production in new areas are greatly dependent upon the
anTiro/ ^3rly exPloratory efforts. However, development
and production activities have been estimated; 15 these are
given in Tables 2-17 and 2-18. To develop the Santa Ynez
s^ifl W5frK "r° WU1 °Perate' a"d the nearby Pescado and
Satfnrmf*0" ^elds, it: is estimated that three to five
platforms will be required and may be supplemented by one or
more subsea production systems.16
Using the estimates given in Tables 2-17 and 2-18 and
assuming an exponential decline rate of 5 percent on current
oil production and 14 percent on current gas producEiS"
the time frame to 1985 would be as
Based upon the drilling activity shown in Table 2-19
and an assumed drilling program of 30 days in the Pacific
and Gulf of Mexico and 45 days in the Atlantic, with 75
percent availability, an average of 22 drilling rigs would
rUnf01^9 *" the Pacific °«shore California; 3ti in the
Gulf of Mexico; and 11 in the Atlantic. These totals would
include mobile rigs as well as platform-baaed rigs, but
exclude service rig activities. Recent data from the Gulf
of Mexico operations1/ indicate that 467 new major (two or
S^^n^fS6^1"61^ °f the Interior' Environmental Impact
statements for Oil and Gas Lease Sales on the Outer r«»n»
-------
TABU-1. 2-\
U.S. OFFSHORE OIL AND GAS RESOURCES AMD RESERVES
RESERVES
Alaska
Pacific
Gulf of Mexico
Atlantic
TOTAL
STATISTICAL MEAN
Source: U.S.
OIL
<10& bbl)
0.150
1.116
2.262
-
3.528
-
Department
GAS
(1012 ft3)
0.145
0.463
35.348
-
35.956
-
of the Interior,
ESTIMATED UNDISCOVERED
OIL
(109 bbl)
3-31
2-5
3-8
0-6
8-50
26
Geological
GAS
(1012 ft3)
8-80
2-6
18-91
0-22
28-199
107
Survey, in Oil
RESOURCES
GAS LIQUID
(109 bbl)
1.1
0.1
1.3
0.3
2.8
-
and Gas
Journal 74(34) (August 23, 1976): 160.
-------
76°W
72°«
7(fvV
42°N
f .'MASSACHUSETTS
38 N
VIRGINIA
O NORTH CAROLINA
Cape Hatiei
74°W
- 1.000m
7.000 m
JO irulit (nout.l
^6 roilti litatvli)
42°N-
38°N
Oirilino cl OIH itu—
in lonntdun with
piopoin) Iron lolt Ht. 4?
Woitr dtp*, m
^- 1.000 m
' VollMti I
doll No. 40)
I
7(AV
Figure 2-7. Offshore leasing areas in the Mid-
Atlantic Region. (R.E. Mattick, P.A. Scholl, K.C. Bayer,
U.S. Geological Survey, "Second Atlantic Sale May Involve
Tracts Off Virginia, Maryland," Oil and Gas Journal 74(47)
(November 22, 1976): 168.)
-45-
-------
Figure 2-3. Offshore leasing areas on the Georges Bank of primary interest to
the petroleum industry. (Hew Unglancl Regional Commission, Fishing and PetrolJu^
nrCnonS_Bank, Boston, Mass. 1976.) 9 etroieum
-------
TABLE 2-17
PROJECTED OIL AND GAS PRODUCTION IN NEW AREAS
ON THE OUTER CONTINENTAL SHELF
OPFSIIOHE
AREA
PACIFIC
N. Gulf of Alaska
Lower Cook Inlet
Southern California
i
&
-j
1
GULF OF MEXICO
Texas
Louisiana
Outer Continental
Slielf
ATLAWTU:
Mid-Atlantic
Nurtli Atlantic-
Source: U.S. De
S.ilcs on the Outer Co
Mf»rp{n.
OCS
LEASE
SAI.1J NO.
39
CI
35
34
33
41
40
<14. -»5, 39, 40.
41, and 42 are included
-------
TABLE 2-18
PROJECTED PRODUCTION FROM
NEW FEDERAL OFFSHORE AREAS IN 1985*
EXPECTED VOLUME OF PRODUCTION
OIL GAS
(106 bbl) (106 bbl)
OCS Atlantic 145 340
Gulf of Mexico 197 i co->
X • D 7 <£
Pacific 165 180
Alaska 455
Assuming constant 1975 dollar costs, oil price of
S12/bbl, gas price of $1.25/MCF and Bureau of Land Manage-
ment estimates of areas to be leased through 1978.
Source: Arthur D. Little, Inc., OCS Oil and Gas Costs
and Production Volumes - Their Effect on the Na tion' s~EHeT^v
Balance to_j.990, fOr the U.S. Department of Interior, Bureau
of Land Management, Contract No. 08550-CTS-48, December 1976
as cited in personal communication with F.w. Mansvelt-Beck
Arthur D. Little, Inc., Cambridge, Mass., December 4, 1976
-48-
-------
TABLE 2-19
SUMMARY OF PROJECTED OFFSHORE ACTIVITIES. 1985
AREA
PACIFIC:
Federal - 1976 nxlflting fl»lrlii
Cjll forma stati? - l«7fi ••xlvtina"
CULK OF MEXICO:
rX-diiral - 1976 rxiBtinq field*
N»u Areas
ATLANTIC;
North - NOW areas
Middle - N»w areas
CUMULATIVE HELLS
DRILLED TO 198*
NUMBER TOTAL FOOTAIX
.
Oln 4,|h(I.UUI!
3,000 30,(>OO,OUO
600 9.000,000
NUMBER OP
PRODUCTION PLA.TFOW1S
n
!lh
f-bl
inn
4
12
pRonurriiiN
OIL
(ID6 hbl)
.
"•'C
IIIH
!97d
312
36
101
1«"
t'JH'j
CAS
(ll)"* fl '>
l'
IIIH
IH 1
I.I?/
2. Hid
•*"
3 SO
lin
A3sutiK"i no rx^anoirjn of El wood South. Cdrpenrnrla or Summorlond nrrchorc fi»ltls nr o*hi-r rirl.ls tn Ttat.- w.itr-r^ i-,
pp resitted. Expanslnn of lh»n» thrci- ficlJi If biqun In 1977 could rcnult 1.1 drill Inn 01 additional wt-lli nnd urortm-r ion
totals of a x 10" bbl of oil jnd B x in"* ft' of •,»•> t.. ..ffHlmrt: facllitiDH in rdllforiiln iiat» walfr-. in
D
tlK llldus I'XlSLttiq DUIUUll" IHl.HHl'l.
Bawd iliun a S |ii-l (im.
Talile 2-1H.
-------
more wells) platforms could exist in the Gulf, in the 1985
time frame. Actual facilities requirements will depend upon
the economics of the petroleum resources discovered.
Table 2-20 indicates projected platforms offshore California.
-50-
-------
TABLE 2-20
PROJECTED PLATFORMS OFFSHORE CALIFORNIA, 1985
1976
AREA, UNIT OR FIELD EXISTING
Santa Ynez Unit 1
(Hondo Offshore,
Pescado Offshore,
Sacate Offshore)
Carpenteria Offshore 4
Dos Cuardras Offshore 3
Hueneme Offshore
Pitas Point Unit
Santa Clara Unit
(San Miguel i to Offshore,
Sockeye Offshore)
San Pedro Bay
TOTAL 8
1985
PROJECTED
3
5
4
1
1
3
7
24
aUnder construction.
-51-
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CHAPTER THREE
TECHNOLOGY OF OFFSHORE OIL AND GAS PRODUCTION
3.1 Introduction
This section of the report describes the technology and
current practices to develop oil and natural gas resources
beneath the sea. Trends in technology which may be applied
within the next 10 years are identified. The scope of this
discussion encompasses the oil reservoir, drilling, fluids,
production and processing of oil and gas offshore. The
operations of specific pieces of equipment or subsystems which
may be sources of emissions are covered in further detail in
Chapter Four.
3.2 Geology
A well is drilled in the hope that it will penetrate
some geologic structure holding commercial amounts of oil or
gas. Crude oil and natural gas occur in void spaces created
by the pores in sandstone or in the pore space between
gianules of a porous limestone. The older the formation,
and the deeper it is buried, usually the more cemented are
the granules forming the rock. Is is also harder and has
lower porosity, less capacity to hold oil, gas and water.
Most oil sands in currently producing areas offshore are
soft and highly porous; in California offshore, much of the
sand has little or no cement bord between the grains. Oil
is held in pore space within rock or sand formation like a
sponge or paper towel holds liquid. An area of oil-saturated
rock is called an oil pool or reservoir, and a group of
reservoirs an "oil field." or gas, as the case might be.
The exact origin of petroleum is unknown, but most
theories agree on the following points. Throughout past
geologic ages, ancient shallow seas became the burial ground
of dead animal and plant life. In geologic time, the decom-
posed organic life created petroleum and natural gas, the
oil mass, or gas, collected in porous rock ^ing formed at
the same time. As the sand bars and beaches of the seas of
geologic past became further buried under additional sediments,
?he differential compaction, and flexing and shifting (faulting)
of'the earth or the upward invasion of a salt plug, created
geologic structures in which the products of °^anic^°™P°-
iitions (oil and gas) were trapped. These geologic structures
may be subtlely hidden and can be found only by geophysical
-52-
-------
surveys, careful geological work and exploratory drillinq
In some areas, such as the Santa Barbara Channel, natural
seeps of oil occur which give the explorationist hopeful
r^o^10"3 ofl*rV*T reservoirs. A porous formation, the
reservoir, must be overlain and sealed by an impermeable laver
of shale or anhydrite, to complete the oil or gas trap.
var?on«, ; ' althou9h highly idealized, graphically illustrates
various types of geologic structures or,* might search for,
thousands of feet below the surface. Gas, oil and water
separate within the structure and reservoir according to
their specific gravities, water being the Waviest. "Asso-
hinSo 9a* 4-i8 I** difsolved " the oil and held in solution
because of the formation pressure. It comes out of the oil
during its production, like bubbles from a freshly opened
bottle of ginger ale.
f ^ °f,th! Oil reserv°irs of the Gulf of Mexico are
formed by salt domes - thick salt plugs that have pushed up
and through zones of earth weakness, and domed the rock over-
it into oil traps. They are highly cracked or faulted.
Several sedimentary rock zones often produce at the same
well in California, faulted blocks of porous sedimentary
formations form many of the oil and gas structures.
In general, most oil reservoirs are highly complex,
geologically speaking, and might well be a combination of
several types of structures. Also, at a specific location,
oil and/or gas might occur in several zones of differina
geologic age and, of course, depth.
3.3 Drillin
3.3.1 Drilling Rigs
eaiiinLn^ii1^^19-13 basically * derrick; a drawworks,
equipment to lift pipe into and out of the hole; a system for
turning pipe (rotary table) to which is attached a drill bit-
and a drilling fluids circulating system. '
The drawworks and rotary table on offshore rigs are
driven by electric motors. Electricity for rig ooerations
n,ay be provided by submarine cable to shore, o? more commonly
is generated onboard by diesel engines on No. 2 fuel. The
o^nn w . diesel capacity on an offshore rig ranges from
2,500 hp to as high as 10,000 hp in the case of some drill
-53-
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MONOCLINAL PINCHOUT
ANTICLINE OR DOME
i
en
IMPERVIOUS
SHALE
This is a trap rf tutting from faulting in which
f block oft ihf right Has movett up with resprct to
f onr on rbf left.
GAS
IMPERVIOUS
CAP ROCK
<— CAP ROCK
)IL
WATER
WATER
Oil ii trapped under an uiuoitfomiiy In this
iltialralion.
WATER
Salt domrj often dfjnrm ow
form traps like ihr ottf thown htr?
iprki K
Figure 3-1. Idealized geologic structures in which offshore oil and
gas occurs. (For upper illustrations, Maynard M. Stephens, "Vulnerability
of Natural Gas Systems," Department of the Interior and Defense Civil
Prepardness Agency, Washington, D.C., June 1970. For lower illustrations,
Committee on Vocation Training, Primer of Oil and Gas Production (Dallas,
Texas: American Petroleum Institute, 1976), Figs. 3,4,5, p. 9.)
-------
A well is drilled by rotating a specially designed
drill bit at the end of drill pipe. Pipe is added to the
"drill string" as the hole gets deeper. Drilling fluid or
mud circulates constantly through th« pipe as drilling
progresses, balancing the pressure of the geologic formations,
cleaning the drill cuttings from the bottom of the hole, and
carrying them to the surface.
When the drill bit wears out or another type of bit is
needed to drill a particular formation, the drill string is
pulled out of the hole, a 90-foot section of pipe at a time.
A "trip" can take 4 hours or more in each direction.
However, tripping is a normal and necessary part of the
drilling program.
An offshore exploratory drilling rig has all of the
features of one used solely onshore, but it must be further
totally self-contained with racks for drill pipe, the drilling
machinery, tanks for and devices to handle drilling fluids,
fuel storage, and living quarters for the crew. Final well
completion is often done with equipment of the production
platform, discussed later.
The history of offshore rig development is traced by
R.L. Gear.1 He points out that in the early 1930's, land
type oil derricks were mounted on barges and floated into
the marsh lands of Louisiana. Nearshore wells were being
drilled at this tirae in California off of long docks, some
of which can still be seen. Soon jackup and spud barges
became popular in Louisiana. By 1953, a Navy 176-foot
patrol vessel, "Submarex" was made into a floating drill
ship, a "deep" water venture. Cuss I, a 260-foot Navy barge
also was constructed in 1956 for such drilling. At present,
four types of rigs are popularly used: the jack-up, submersible,
the semisubmersible and drill ship. Figure 3-2 illustrates
the types of vessels in use today and the maximum water
depths in which they can operate.
A jack-up type rig has considerable popularity in rela-
tively shallow waters, up to 300 feet in depth; submersibles
to 40 feet. Semisubmersibles and drilling vessels are used
in deeper water.
R.L. Geer, "Offshore Drilling and Production Technology-
Where Do We Stand and Where Are We Headed," Paper, Third Annual
Meeting, American Petroleum Institute, Denver, Colorado,
April 9-11, 1973.
-55-
-------
BARGE OR
8'
LAND RIG ' SUBMERSIBLE 4Q.
(may go to 50 ft) JACK UP
(may go to 300 ft)
SEMISUBMERSIBLE
DRILLSHIP
Figure 3-2. Trend in design as deeper water drilling
becomes necessary. (M.V. Adams, C.B. John, and R.F. Kelly,
"Mineral Resources Management of Outer Continental Shelf,"
L'.S. Department of the Interior, Geological Survey, Circular
720, Reston, Virginia, 1975.)
-------
The trend in deeper water drilling has led to other
types of vessels. The drill ship Discoverer Seven Seas,
owned by the Offshore Company, is being built for 6,000 feet
of water. It should be ready for activity soon. This rig
will have the capability to drill in the deepest water.
Most semisubmersibles can operate in water depths up to
1,000 feet but three vessels being built are for use in
water dopths up to 3,000 feet. At present, there are no
active wells in sea depths beyond 900 feet.
The rig chosen for use at a specific location is deter-
mined by water depth, environmental criteria, type of sea
bottom, depth of drilling, wind and hurricane history of the
area, rig availability contract terms and other factors.
While a semisubmersible may operate either sitting on the
ocean floor or floating, it is designed to operate as a
floater in deep water. Anchoring becomes a most exact
science so as to provide for a drilling platform that stays
over the hole throughout any severity of wave action and
weather that might be encountered.
3.3.2 Drilling Fluids
3.3.2.1 Purpose
There are constantly changing conditions as the drill
bit penetrates the ground. At the surface, soft muds and
silt cover the ocean floor; this layer can be several
hundred feet thick. Soft semi-compacted materials are
usually encountered below this and, in-depth, better consoli-
dated materials. As the bit penetrates deeper, shale, salt,
gypsum, sulfur, limestone or sandstone beds may be drilled.
Each geologic layer has a different drilling characteristic
related to its geologic age, physical and chemical composition,
As the drill penetrates deeper, the reservoir pressure
in porous zones holding fluids usually increases with depth
at a rate equal to the hydrostatic head of water. That is,
for every foot of depth, one can expect an increase in
pressure of about 0.433 to 0.465 psi, depending on the salt
concentration in the water. For example, at 6,000 feet, a
possible bottom hole pressure can be expected of about
2,700 psi. Sometimes geological conditions cause pressures
in excess of this formula (geopressure), but most wells
encounter pressures less than those determined by this rule-
of-thumb. However, the driller must be on the alert to
expect excessive pressures at any time.
-57-
-------
Temperature also increases in depth. The geothermal
gradient varies somewhat by locality, but in general, starting
at an average surface temperature of 50° F to 60° F, the
temperature of rock formations can be expected to increase
1 F to 2° F for every 100 feet of depth. At 6,000 feet depth,
one can expect an increase in bottom hole temperature with
respect to that of the near surface rocks of 60° F, a total
of 120° F. in deep holes, the bottom hole temperature af-
fects the mud used to drill the well. The drilling fluid,
while constantly changing its composition as drilled material
is added to it, nonetheless is mostly composed of prepared
bentonitic clays, caustic soda, starch, lignin or lignocellulose
and barium sulphate, a weight additive. Water or oil may be
used as the basics of the mud.
The mud, besides acting as bit coolant and drill cutting
lifter, also holds fluids from porous formations back until
proper pipe and valves can be set in the well to control flow.
Should the pressure in the formation exceed that of the
drilling fluid, an influx of reservoir fluid into the wellbore
will occur, when such flow occurs, it is called a kick.
If the kick occurs at a stage in the drilling after
conductor pipe and casing have been cemented in the hole,
special heavy-duty wellhead equipment (blowout preventers)
can be shut, and the pressure on the well controlled, until
the mud weight is increased to the point that the mud column
controls the formation pressure.
A "blowout" is a well flowing out of control as opposed
to a "kick" which can be controlled by equipment on the der-
rick or sea bottom. Some blowout occurrences have been
disastrous, causing fires, great loss of expensive drilling
equipment, and uncontrolled flow of oil and gas into the
environment. The extent of such accidents is discussed in
Chapter Four.
3.3.2.2 Drilling Fluid Conditioning
The drilling fluids are processed to remove drilling cut-
tings and any entrained formation gases. This condition,
known as gas-cutting of the drilling mud, can hamper drilling
efficiency and result in stuck pipe and a reduction in
penetration rate.
Gas also gets into the mud system when the reservoir is
being drilled at a high rate of penetration, as may occur in
firm sandstone formations. If penetration rate is slow, mud
filtrates below the bottom of the bit can drive the gas back
-58-
-------
into the reservoir. Miller identifies three forms in which
- free 9as- entrained
immo,1,, the drilling ""id from reservoirs
immediately adapts to well-bore pressure. This results in
the SvdJi^9^6"11 °f 9aS bUbblGS risin9 in the -nnulua .1
a short lif3 H PTS?Ke *« Deduced. These gas bubbles have
a short life, due to the difference between the initial
internal pressure of the bubble and the external pressure of
the surrounding fluid. When these gas bubbles rupture "
the annulus, they tend to accumulate, creating «gis heads."
nn««i« ^ mo*es.uP the annulus until the bubbles are ex-
fo£ bEJJT"P J/ conditions« usually inside the degasser
(gas buster) or mud/gas separator. If the gas bubble rup-
tures inside this separator the gas is vented to the flare
of hJ?me ^drocarbo"s. in liquid forms under the conditions
of heat and pressure found in a reservoir, can flow from
the reservoxr to the well bore and into the mud stream and
still remain liquid. In some cases, they will assume gaseous
form while still in the well bore, and in other cases will
flash to gaseous form in the mud pit or in a degasser.
.„,, Certai" ^Pes of gases, when combined with high pressure-.
and temperatures, enter the intramolecular structure of the
drilling fluid and cause only a very small fluid volume
increase.
.If.nvdr°9en sulfide is present in an alkaline drilling
,* lfc." not effectively removed by aeration. Hydrogen
sulfide will react with the caustic to form the alkaline
salt, sodium sulfide, and water. This is a reversible
^aCJ^n' The hi?her the pH of the drilling fluid, the more
the hydrogen sulfide will react.
Hydrogen sulfide poses special problems in surface
degassing the drilling fluid. As discussed above, hydrogen
sulfide is extremely poisonous and is hazardous in concen-
trations as low as 0.1 percent by volume.
The mud conditioning system consists of a mud-gas sepa-
rator and degasser vessels, and a shale shaker to separate
C'D;^1^er/ "Pr°Per Handling of Gas-Cut Mud Boosts
6nCy' Oil and Gas Journal 74(13) (March 29,
~~~—
-59-
-------
out drill cuttings. After the shale shaker, the mud enters
open tanks, where it is stored, mixed and conditioned to
maintain the desired properties.
The compactness of the surface-mud system on an offshore
facility results in enclosed areas with limited ventilation.
To avoid these hazardous gas concentrations, the mud pit is
adequately ventilated. Gas removed from the mud through the
degasser is discharged to a flare line.
Both mechanical and chemical degassing in a closed
system are usually used in handling hydrogen sulfide (H2S).
The system consists of a separator and a high-energy, or
vacuum, degasser as shown in Figure 3-3. All of the gas
must be removed from the system and vented to the flare line
before the mud is released to the open mud pits.
Some companies operating offshore have established
policies to plug the hole immediately and abandon the project
when sour gas is encountered. This is because most rigs are
not equipped to safely handle the lethal and corrosive gas.
As natural gas becomes more in demand, however, gas containing
hydrogen sulfide may be produced offshore and processed for
sale. Areas east of the Mississippi Delta in the Gulf are
expected to contain this impurity in the gas. Except for
some small H2S content in the gas coming from the Ship
Shoals area offshore Louisiana, most Gulf of Mexico wells
produce sweet gas. Two wells were drilled off the point of
the Delta in a high-sulfur gas area — these are now reported
as abandoned.
3.2.3 The Casing Program
As drilling progresses downward to the target zone,
pipe is set in the hole at intervals of depth, so as to
avoid some of the problems discussed above and to maintain
the integrity of the hole. The casing program varies with
depth and the local geology. A system used in a relatively
low pressure area will be inadequate in a deep, high pressure
formation; so, very special care is given in offshore
operation to the casing program.
When the hole is started a large diameter hole is
drilled, up to 36 inches in some cases. In shallower zones,
a smaller hole is adequate. As soon as the drill works its
way through the mud, sand, and soft, near-surface material,
a conductor or surface string of relatively large diameter
pipe is placed in the hole. This pipe not only holds back
the surface soil and mud but prevents the flow of mud from
undercutting, as drilling continues, and from undermining
-60-
-------
Figure 3-3. Handling toxic gas on offshore rigs
"Proper Handling of Gas-Cut Mud Boosts
Drilling Efficiency," Oil and Gas Journal 74(13) (March
29, 1976) : 167.)
-61-
-------
or
r»nhs-
the salt strina «or ?„ f s strl"9 ls also called
l.titute, February 72
Institute, "uly 19761
-62-
-------
TO WELLHEAD CONNECTIONS
-(AT SEA BED OR ON PLATFORM)
EA FLOOR
CONDUCTOR OR SURFACE PIPE CEMENTED
DOWN HOLE SAFETY VALVE
(DHSV)
TUBING
^|§ f|gg-HNTERMEDlATE STRING CEMENTED
OIL SAND
PACKER
PERFORATIONS
OIL STRING CEMENTED
-63-
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Once the decision has been reached to complete the well
by "setting pipe," the final casing (the oil string) is
lowered from the surface to the bottom of the hole or pro-
ducing formation. In some areas of the country, these lower
pipe strings (liners) are hung on the intermediate string
in the well on special packers so as to reduce the cost of
running pipe to the surface for each string. The oil string
is also cemented into place, but usually not from its top to
bottom as was done with the surface pipe. The string is
usually set through the "pay" formation and cemented with
enough cement to firmly seal off the producing zone and area
immediately above it, and to hold the pipe in the hole
against the high formation pressure.
After the oil string is firmly set, special logging
devices are lowered in the hole to determine the quality of
the cement bond and the location of the pipe collars. The
casing is perforated, for example, using a string of shaped
charges accurately set in the pipe so as to penetrate the
oil/gas zones accurately. If the pay zone is associated
with a saltwater zone, only the upper part of the zone is
perforated, if possible, to reduce water handling during
production. During all this operation, the hole is full of
water, the mud having been removed or squeezed behind the
pipe as the plug on top of the final cement slurry was
pumped into place. This water holds back the pressure of
the perforated formation.
3.4 Completion of the Wells
As the casing or pipe setting process progresses,
various wellhead fittings are installed to form a "Christmas
tree." The number of fittings varies with the number of
strings used in the hole. Each string has valves connected
to it for use during the cementing process and for control
during well operation.
The design of the wellhead and the completion method
depends upon the size of the casings, the well location, its
producing pressure and proportions of oil, gas, saltwater
and sand which may be produced.
On offshore wells a subsurface or down hole safety
valve (DHSV) is located in the tubing about 100 to 200 feet
-64-
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belcw the sea bed or mud line. This valve automatically
shuts off well flow in case of a sudden release of back
pressure held on the flowline. If the tubing in the well is
suddenly broken by an accident, the valve shuts in the well.
Two general types of wellhead completions are currently
in use in offshore operations and several systems for opera-
tion in deeper water are under development.
The most common offshore completion is a platform-
completed marine riser system. In this completion techni-
que, the well controls are located on the platform, and as
discussed earlier, as many as 40 wells may be completed on a
single platform. Single well platforms may be used in
shallow water up to 100 to 150 feet in depth. Maintenance
and operation of the well are performed on the platform.
Another completion technique is the subsea wellhead. In
this type of completion, shown in Figure 3-5, all well
controls are located on the sea floor. Well operation and
maintenance are carried out through the production flowline,,
or hydraulic control lines as well as with diver assistance. '
The need for diver support during some operations limits the
application of this completion technique to water depths of
less than about 250 feet. Furthermore, a jack-up rig must
be moved in for well service. Subsea-completed wells may be
located as far as 18,000 feet from the. production platform.
Advantages of subsea wells include lowi.-.- vulnerability to
storms and collision hazards, more rapid payoff of marginal
fields, and reduced capi' jl outlays. In some instances the
use of subsea wells could facilitate larger production
processing facilities on fewer offshore platforms. Between
Committee on Standardization of Offshore Safety and
Anti-Pollution Equipment, Specification for Subsurface Safety
Valves, API Spec 14A 1st ed. (Washington, D.C. :—American
Petroleum Institute, October 1973).
D.L. Morrill, "Abandonment of a Subsea Well," SPE Paper
6074, Society of Petroleum Engineers Technical Symposium, New
Orleans, Louisiana, October 5, 1976.
D.F. Keprta, "Seafloor Wells and TFL - A Review of Nine
Operating Years," SPE Paper 6072, Society of Petroleum Tngineers
Technical Symposium, New Orleans, Louisiana, October 5, 1976.
-65-
-------
WELL HEAD
Figure 3-5. A subsea wellhead,
-66-
-------
1960 and 1974 some 106 subsea wells were completed on the
outer continental shelves of the free world in water depths
ranging from 50 to 375 feet.8
The experience of Phillips in the North Sea reveals the
problems of subsea wells.9 Routine maintenance operations
such as replacing downhole safety valves, other wireline
work, and repair of the Christmas tree valves generally
requires the use of a floating drilling vessel. Considering
weather factors, mobilization cost, rig availability and
cost, even the simplest job could cost $500,000 and cover
10 days. This compares with platform well costs for the
same operations of only a few thousand dollars and a required
time of 6 hours. When lost production during well downtime
is considered, the spread in maintenance costs is even
greater. In addition, the long submarine flowline to a
seabed well can reduce well productive capacity to 25 to
50 percent of that attainable through similar platform
wells.
In deeper waters where diver assistance is not feasible
and platform structures are infeasible or prohibitively
costly, remotely operated subsea completion and production
is envisioned. Currently under development are several
production completion ay steins for water depths in excess of
1,000 feet. Tfciese include the Exxon Submerged Production
System (SPS),10'11'12 the SEAL System and the Lockheed Dry
Atmosphere System. Although these systems are not fully
n
R.L. Geer, "Offshore Technology, What Are the Limits,"
Petroleum Engineer 48(1) (January 1976): 26.
n
T.J. Robin, R.S. Hoch, and D.A. Johnson, "Subsea Well
Development and Producing Experience in the Ekofisk Field,"
SPE Paper 6073, Society of Petroleum Engineers Technical
Symposium, New Orleans, Louisiana, October 5, 1976.
10J.A. Burkhardt, "Test of the Submerged Production
System," SPE Paper 4623, Society of Petroleum Engineers,
Dallas, Texas, October 1973.
Hj.A. Burkhardt, "A Progress Test of the Submerged
Production System," SPE Paper 5599, Society of Petroleum
Engineers, Dallas, Texas, September 1975.
T.W. Childers and W.D. Loth, "Test of a Submerged
Production System - Progress Report," SPE Paper 6075, Society
of Petroleum Engineers Technical Symposium, New Orleans,
Louisiana, October 5, 1976.
-67-
-------
operational, they are under various stages of development
and testing and may extend the industry's capabilities for
deep water production in the next 10 years. These systems
generally require nearby surface or floating facilities if
the production must be pumped more than a few miles.
* everVthing is ready to start the well producing,
the fluid in the hole is carefully unloaded by swabbing to
lower the height of the water load. If there is great
pressure on the oil/gas zone, the hole may unload by itself.
The riser enters the well straight down or at a slant
from the platform, but may also be curved, at the seabed, in
the proper direction so that the well, while serviced on a
central platform, may bottom out a mile or two from it
These directional ly drilled holes fan out from the platform
to the bottom hole location in a predetermined point in the
reservoir, within the block or tract under lease by the
operator. Because most wellc are 10,000 to 16,000 feet or
greater in depth in the Gulf, there is adequate depth to
make the deflection in the hole whan it is drilled. In
California, because of the occurrence of oil and gas at
shallower depth of 5,000 feet or more, it is often necessary
to start the hole off on a slant at the surface.
3.5 Field Development
A number of test wells are usually drilled from' a
mobile drilling vessel in the manner described above in
order to delineate the oil and gas reservoir and to evaluate
the economics of various production alternatives. These
early wells are usually not completed although some might be
completed as single wells not operated from a platform.
There are several alternatives for producing the oil
and gas. The reserves or quantity of oil and gas estimated
to be economically producible from a field under a given set
of capital and operating costs is the primary factor governing
the pattern of development and type of production facilities.
When reserves are limited, it may be uneconomical to
invest in completion of the well and the required production
and transportation facilities. The size of required invest-
ment will depend up..,-, ifca water depth at the field, the
proximity of the field to other oil and gas fields under
production, the engineering demands of the site (severity of
wave action, storm action, sea bottom conditions) , the most
effective spacing of wells to drain the reservoir, and other
factors.
-68-
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A single well completed in shallow water might have
only a piling around it for protection and to serve as a
working platform support. Production of oil, gas, and water
from these jacketed wells flows to other platforms or to
shore for processing and transportation as described below.
Wells may also be completed on the sea bed and flowed
to temporary floating or permanent platforms for processing
and transportation of the oil and gas. in the Ekofisk field
in the North Sea in 260 feet of water, temporary production
began in this manner. A converted jack-up rig was used to
support the production facilities serving four subsea wells
This type of facility may occur in other fields where reserves
are found to be marginal. Similarly, another area of the
-tortn Sea, the Argyll field, has been producing to a floating
production facility mounted on a semisubmersible vessel in
245 feet of water.1J
If substantial reserves of oil and gas are delineated,
a fixed platform for 40 or more wells is usually established
Nary companies choose to drill and complete all wells on a
platform before installing the oil and gas separation equipment,
Since the amount or working space available on a platform
does not readily allow for both drilling and oil/gas produc-
tion to take place at the same time. There are situations
however, where such efforts coexist.
Over the next 10 years, fixed platform technology will
probably be limiced to oil and gas development in water
depths of less than 1,200 feet with most activity occurrinc
at water depths up to 600 feet.14 Completion and production
systems discussed above, such as the Exxon SPS and Lockheed-
designed Shell System, are designed for use in water depths
of 2,000 feet or greater. Other new platform designs have
proceeded to the prototype stage and are considered ready
for full-scale application at potential savings of up to
25 percent of th• cost of a conventional stiff-leg platform
Two designs are the tension-leg platform which has been
tested off of California by 17 operators, and the guyed-
tower platform under test by Exxon, which has application in
water depths of 600 to 2,000 feet of water. All of these
systems will enable development of offshore oil and gas
P. Elwes and J. Johnson, "Role of PPF's (Floating
i;.the Norltl se-"
M. Long, "High Costs Driving Firms Out of Deepwater
Tracts," Oil and Gas Journal 74(43) (October 25, 1976).
-69-
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resources in deeper waters on the outer continental shelf
and slope in the future.
3.6 Production Facilities
The planning and design of an oil/gas production plat-
form is dependent on several site-specific factors. Many
factors must be completely investigated, including expected
wave height and force, force and direction of currents,
maximum wind velocities and direction, depth and pressure of
the wells, rates of flow, type of production (oil and/or
gas, and saltwater), character of the sea floor, types and
amount of equipment needed, pollution control safety, seismic
activity, and many other considerations. Since a platform
can cost as much as $20,000 to $30,000 per square foot,
trade-offs must te made between having space completely
utilized and safe spacing between equipment, so as to eliminate
situations that might result in the release of explosive and
toxic gases, or a loss of flammable liquids.
The American Petroleum Institute has published a numbxT
of recommended platform installation practices.^ 16 In
the design of the platform, high priority is placed on
safety and environmental and equipment protection. It is
recommended that atmospheric conditions be completely under-
stood so as to know how adequately to ventilate the structure,
thus avoiding toxic conditions and fires or explosions on
the platform. Avoidance of oil spills, or their containment,
is given great attention.
3.6.1 Oil and Gas Separation Equipment
Fluids coming from a well are a mixture of oil, gas,
sand, and saltwater, which must be separated to obtain
saleable oil or natural gas. The type of equipment installed
on a platform is determined by the volume, pressure, tempera-
ture and composition of the production. Figures 3-6 and 3-7
Committee on Standardization of Offshore Structures,
Recommended Practice for Planning, Designing and Constructing
Fixed Offshore Platforms, API RP 2A, 7th ed'.. (Dalla^
American Petroleum Institute, January 1976).
Committee on Standardization of Offshore Structures,
Recomuended Practice for Production Facilities on Offshore
Structures, API RP 2G. 1st ed.. (Dallas:American Petroleum
Institute, January 1974).
-70-
-------
fion
oil
.•Ml
0.1
Cot —
, t / H^h-pr.,,«. ]
~~ I I wpaiaiai' I
Vi 7
T5 7 on
I T«il irparaloi I
^
Klan-picitwi \
icpoiaioi I I
'
I Won.
Wol».
Oil-iuige •iiwi
•Tognuun
Cat
To ««nl
1L
8v.nl
ii.itbbn
and In)
Oil
Hydrocarbon
droiM
0«k
4o.ru
Sump
Goi
Fuol and
gai tcnjfabir
OII-pip«l
-------
Gtr«l/fl»y
-------
illustrate the basic steps of processing through which the
fluids coming from the well pass. Actual platform complexes
combine features of these two schemes as shown in Figure 3-8.
In some cases where shore is nearby, some or all steps in
gas and liquid separation are often done on land.
The fluids in a well are usually at sufficiently high
pressure early in the life of the well so that they reach
the platform under natural forces. These forces include
water, a gas cap or solution gas pressure on the oil and
water in the reservoir. As these natural forces are depleted
flow rates into the well bore decrease. Since the column of
fluids in the well applies pressure against the flow, pumps
or artificial lift equipment are often installed to keep the
wells pumped off.
Additional investment in pressure maintenance and
pumping equipment can slow the decline in the production
rates of oil. Pressure in the reservoir may be maintained
by injecting water or gas back into the producing formation.
This does not usually eliminate the need for pumping equipment,
but is often carried out as part of an entire program to
obtain as much oil and gas as can be economically produced.
Pumping or artificial lifting techniques to raise the
produced fluids to the surface are of four types. The two
most common lift techniques on offshore platforms are gas
lift and electric submergible pumps. Less common on off-
shore facilities is power fluid (oil or water) lifting.
Beam pumping or sucker-rod pumping, a technique which is
ubiquitous in oil fields on land, is rare offshore.
Gas lift involves the injection of a part of the processed
gas stream back down the well at high pressure to operate a
series of gas-operated lifting valves in the tubing. Pressure
work in the gas raises the produced fluids to the wellhead
and the lifting gas is produced with the oil.
Electric submergible pumps can also be used to lift the
oil. These devices, which are approximately 40 feet in
length, are installed to within about 100 to 200 feet of the
bottom of the well on the tubing string.
Power fluids lift techniques operate on principles
similar to gas lift. Clean oil or water travels down a
separate tubing string at high pressure to drive a hydraulic
pump near the bottom of the well. The spent power fluid is
produced along with oil and gas from the formation and a
portion of the produced fluids are processed for reinjection.
This is a relatively costly though efficient lifting tech-
nique which requires a clean power fluid. Sand control
-73-
-------
SALES
GLYCOL CONTACTOR
SEPARATOR
SAFETY DEVICES
FREE WATER
KNOCKOUT
1 SUBSURFACE SAFETY DEVICE
2. HIGH/LOW PRESSURE SENSORS
3. HIGH/LOW LEVEL SENSORS
4. PRESSURE RELIEF VALVES
5. FLOW CHECK VALVES
6. AUTOMATIC VALVES
7 COMBUSTIBLE GAS SENSORS
MANUAL EMERGENCY SHUTDOWNS
SHORE
WATFR
WATER TREATING V0)spoSAL
Figure 3-8. A typical production facility with safety equipment. (C.C. Taylor,
"<;tatu!= of Completion/Production Technology for the Gulf of Alaska and the
Atlantic Coast Offshore Petroleum Operations," Resources for the Future, Inc.,
seminar, Washington, D.C., Dec. 5-6, 1973, Council on environmental Quality.)
-------
Em S!V ? offshore California and Gulf Coast wells as
" £ P ? limitations onboard the platform are factors
have minimized use of this technique.
the r!San™UIITin9 UnitS involve a down hole pump driven by
the reciorocatma pumping rod. Lack of space onboard offshore
known platform in the Gulf.
n,-^ i iS "° u"u!ual to have "ells on the same platform
that produce at different pressures (as much as 2,000 psT
bo^oi h"? y dlfferent llft methods, some wells have low
cCsS ah^ Pre"ure and are PumPed by various means dis-
cussed above, in case of high pressure production, typical
of new wells in the Gulf of Mexico, three stages of Jas-
liquid separation take place. The gas from each stage is
sent to gas treatment facilities or to the vapor recovery
system, depending on its pressure. Cases were observed
where some low pressure gas from the low stage separator was
flared or vented {estimated at about 20 ft* for a barrel of
oil produced,. The U.S. Geological Survey has rules which
1Ct 93S fr°m bei"9 flared or vented except during
circumstances occ'ur that'make
srmhho^ ?" iS comPressed (before or after processing),
scrubbed to remove treated entrained gas liquids or condensate
lndCthr ?entane,and heavi^ hydrocarbons, and wa?er vapor?
and then is pipelined to shore. If hydrogen sulfide were
rem°Ved On ^e P?atform Onshore
(de-ethanizing and
Prior to 9as discharge into the Min
CaSSS' a11 of the gas Processing is done
C°St °f eXt" Platf°™ space. Onfortu-
potential
The separation of oil-water-sand occurs in either a
r^l£:?o*triZTtai* VESSel kn°Wn aS 3 £"e -"- lockout.
From there oil and water go their separate ways. Generally
some water is entrained in the oil. NO more than 1 percent'
water is usually permitted in saleable oil. A final emuTsion
separator, which operates on chemical, electric or heat
P leSLreS °Ut Water from
^ from the oil to ma^ it mar-
=n™ i' .Th? »altw-ter produced with the oil usually carries
some oil in its stream. Clarification is required before
fonn CSnKb%?ent t0 disP°sal- Skim tanks are employed,
followed by flotation cells to remove the entrained oil
particles from the produced saltwater. Treated saltwater is
Se""U8 CeineCt er"
-75-
-------
Figures 3-9 and 3-10 illustrate the design and the
layout of production facilities on typical production
platforms in the Gulf. Figure 3-11 illustrates a shore-
based scheme; Figure 3-12 shows a variety of offshore
facilities installations.
The specific function and operating characteristics of
each unit on an offshore facility are described in Chapter
Four.
3.7 Transportation of Oil and Gas
Current offshore oil and gas operations employ pipe-
lines and barges to move oil to shore. Some 64 submarine
pipeline network systems transport 95 percent of the oil and
all of the gas to shore in the Gulf of Mexico. Fourteen
barge systems transport 5 percent of the offshore production
in the Gulf of Mexico to shore. The latter systems are used
to serve marginal or isolated fields which could not justify
the construction of a new or extension of an existing sub-
marine pipeline. In California all offshore production
comes ashore by submarine pipeline. Exxon has proposed to
barge the oil produced at its platform Hondo in the Santa
Ynez field to refineries in northern or southern California.
The configuration of transportation systems for Atlantic
operations will depend upon the project economics and extent
of the reserves discovered as well as environmental factors.
It is possible that tanker transportation similar to that
used in serving the floating production facilities at the
Argyll Field in the North Sea might be utilized if very
productive wells are drilled. Tanker loading is accom-
plished in the North Sea at a single point mooring buoy.
Produced gas is. flared in those operations.
-76-
-------
l/V) 3r»
i;oc rf.i.r t«ttii*|
VX m-«t
MM S^ytiw»
(l> L.I.C.I.'t
; uei u.ooo lore
111 ma rtooo ititci
C** S*Pf.
f»;««i«
Uj.ctto.
*.100 10ID iPT*« -I")
M.100 MID l»t»l
litrnii. irwhvti, nt.
SOUTH PASS 65 "A"
(water depth 290')
Figure 3-9. A pictorial sketch of the equipment layout
on Platform A. (Shell Oil Co., New Orleans, Louisiana.)
-77-
-------
30 ton CRM4E
w/ftO Ft BOOM
UPPER DECK
• lav. «63'M.G.L.
CELLAR DECK
•lav. MB'M.G.L.
SOUTH PASS 65 'B'
WATER DEPTH 290*
Figure 3-10. A pictorial sketch of the equipment on a
production platform. {Shell Oil Co., New Orleans, Louisiana.)
-78-
-------
«K« MISSUI! HI
L
-J
VO
I
Figure 3-11. Flow diagram of produced fluids, South Pass blocks 24 and 27
fields. (Shell Oil Company.)
-------
I
CO
o
L MV I - - I* - 'S
A ' '«S. ' \ i .* t»i •
r > i Ml «.»u i X Vi ' > •*
i't'-.:.f,,,^'
!te"vl.. -..•«fe-
W'"-^AVJ*__ -?.y,v... iP"
.,..:.. i -s.'.- .,r "*f~\'-i /•["••• •• •,;*•%i/-
vr.r ..t:*i_ "•' ^«^%3i.-} .•i-sr-.-'r-
TYPICAl SHALLOW jW-i-r*1 V ' •*
tz^&ffi •••'-
TYPICAL DEEP _.• •"
WAT6* PLATFORM ~T"
BLOCK 24-27 FIELDS
700 WELLS
CURRENT PIODUC1ION (ATI
and
and
-------
CHAPTER FOUR
EMISSION SOURCES
4.1 Introduction
The emission sources inherent in offshore operations
are the same in many respects as the emission sources onshore,
the major difference found in the very nature of offshore
operations. The offshore platform usually has either one or
two decks, each no larger than about a 200-ft square.
Within this space, not only must all wells, rigs, and process
equipment be located, but because of the often long distances
from shore, the platform must also have living quarters,
power generating equipment, and product sendout equipment.
There is a very real danger of a major catastrophe re-
sulting from a fire on an offshore platform because of the
crowded conditions and the combustibility of the products.
Special precautions are taken on all platforms to minimize
the probability of such an occurence. The platforms observed
by the project team were well maintained, run more like a
ship than an oil field. There were no obvious leaks and
spills or other signs of careless operation or lack of
proper maintenance. In this regard, offshore platforms are
much "cleaner" than onshore operations.
However, there are still several major sources of air
pollutant emissions to be found offshore and there is cur-
rently an ongoing debate between operators and state agencies
as to the impact these operations may have on ambient air
quality. In this chapter, the emissions inherent in offshore
activities are examined in depth. Emission rates have been
estimated using available data whenever applicable, but
also taking into account the unique characteristics of the
offshore environment.
4.2 Drilling Operations
4.2.1 Power Generation
The only continuous source of emissions during drilling
operations is from the generation of power. The two major
load requirements on a drilling platform are the mud pumps
and the rig drawworks. The total installed capacity in
September 1975 of these two items is shown in Table 4-1 for
-81-
-------
00
to
TTVBLF: 4-1
DRILLING POWER CAPACITIES OP EXPLORATORY RIGS*
TOTAL hp
LOCATION
Alabama
Alaska
California
Florida
Louisiana
Gulf of Mexico
New Mexico
Texas
Washington
TOTAL
NUMBER OF
RIGS
2
2
2
1
118
15
2
22
1
165
MUD
PUMPS
6,800
4,600
4,600
4,800
243,060
27,800
2,000
59,750
2,800
356,210
DRAW-
WORKS
4,000
6,400
4,500
1,600
181,930
21,550
2,630
43,360
2,000
267,970
AVERAGE
MUD
PUMPS
3,400
2,300
2,300
4,800
2,060
1,850
1,000
2,720
2,800
2,160
DRAW-
WORKS
2,000
3,200
2,250
1,600
1,540
1,440
1,320
1,970
2,000
1,620
Does not include operator-owned rigs.
Source: Petroleum Engineer (Sepv^mber 1975).
-------
the offshore areas surrounding the United States. The
average for all platforms was slightly greater than 2,100 hp
for mud pumps and 1,600 hp for rig drawworks. Although the
total installed capacity may change from month to month, the
average capacity used for this report should remain relatively
constant.
In addition, between 400 hp and 800 hp is required for
the rotary, and 500 hp is required for accessories and
housekeeping.2
The actual power demand depends upon the activity in
progress at a given time. For a typical drilling platform/
the design load (maximum available horsepower) is shown in
Table 4-2. The actual power required will be considerably
less than full capacity. For example, power usage during
drilling depends upon the size of the hole, the rate of
drilling, and the depth of the hole. Randall estimates that
the average hydraulic power at the bit required for optimum
drilling is in the range of 0.2 to 0.3 horsepower-hours per
foot square inch of bottom hole area.3 Additional hydraulic
power is required to compensate for string losses. In this
report, total hydraulic power requirements have been estimated
at approximately 40 hph/ft drilled, based upon a 10-in bit
size with 50 percent of the total hydraulic power delivered
at the bit and the remaining 50 percent dissipated as string
losses. An additional 20 hph/ft is required for auxiliaries
as discussed below.
The relationship between drilling power and total power
can be seen from the drilling scenario shown in Table 4-3.
The primary activity is drilling, which will be ongoing over
70 percent of the time. The power requirements will be
relatively low during the initial stages but will increase
with hole depth. An overall load factor of only 25 percent
has been assumed to take into account the greatly reduced
loads which will be encountered initially. Such a load
factor is in reasonable agreement with the rule of thumb
presented above.
The expected load factor is assumed to be somewhat
higher for other operations. In the absence of published
lnFall 1975 International Rotary Rig Locator," Petroleum
Engineer 10(47) (September 1975).
Douglass Bynum, "Drilling Rig Cost Effectiveness,"
Petroleum Engineer 10(48) (September 1976): 98-105.
3B.U. Randall, "Optimum Hydraulics in the Oil Patch,"
Petroleum Engineer 10(47) (September 1975): 36-52.
-83-
-------
TABLE 4-2
(Horsepower)
REQUIREMENT
Draw Works
Mud Pumps
Rotary
Accessories
Housekeeping
1 — — ^
TOTAL
DRILLING
0
2,100
800
400
100
•
3,400
CONDITION
TRIPPING
CASING, CORING
1,600
0
0
200
100
1,900
SURVEYS &
LOGS
0
0
0
200
100
300
aThese values are assumed to be "typical" and have
been used in this report to estimate potential rates of
emission.
Source: Adapted from Douglass Bynum.
" 10(48
-84-
-------
TABLE 4-3
DRILLING SCENARIO3
ACTIVITY
Drilling
Coring
Casing
Surveys & Logs
TOTAL
(Basis:
NUMBER
OF
rtAYS
22
2
4
2
30
10,000 ft.
AVAILABLE
POWER
(hp)
3,400
1,900
1,900
300
hole)
LOAD
FACTOR
(Percent)
25
50
50
80
USAGE
(hp hr.)
448,800
45,600
91,200
11,500
597,120
Based upon an analysis of notices to drill submitted
by oil companies to the U.S. Geological Survey and discussions
with operators.
-85-
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data, a load factor of 50 percent and BO percent for tripping
and logging, respectively, has been estimated. Note, however,
that uncertainty in these factors will have little impact on
the total power consumption for all offshore drilling oper-
ations.
Emission factors are given in Table 4-4 for dzesel
reciprocating and turbine engines, both of which are used in
offshore operations. The rate of emission is dependent upon
the type of engine and the fuel form. In exploratory
drilling, distillate oil is used almost exclusively. In
developmental drilling, the fuel will depend upon the extent
to which the field has been opened. Specifically, if gas is
available, the operator may switch to gas rather than trans-
porting oil to the platform. On the other hand, the operator
may choose to shut in completed wells until producing equip-
ment can be placed on the platform. Often t.iis conversion
from a drilling to a producing configuration does not occur
until the drilling schedule is completed.
In calculating the total emission load from drilling
operations, it is assumed that almost all of the power
generating equipment on drilling rigs is of the diesel-
electric type using reciprocating engines.
The calculated total emissions are shown in Table 4-5
for each offshore drilling area. These emission rates are
based upon the following equation.
Emission Rate - Emission Factor x Total Well Footage x
(Table 4-5) (Table 4-4) (Table 2-5)
60 hph/ft
(Table 4-3}
Note that over 90 percent of the drilling during 1975 took
place in offshore Louisiana. Note also that as drilling
activity picks up in the Atlantic DCS area and in the Cali-
fornia OCS area, the emissions due to power generation will
increase proportionately.
4.2.2 Mud Degassing
Although power generation is the only continuous
emission source of any significance on a drilling rig, there
are other sources having an intermittent character that
should also be considered. The most important of these is
mud degassing.
-86-
-------
TABLE
-------
TABLE 4-5
NATIONWIDE EMISSIONS FROM POWER GENERATION DURING DRILLING3 (IP75)
TOTAL
AREA WELL FOOTAGE
i
00
CO
Alaska
California
Louisiana 6,
Texas i ,
b
Gulf of Mexico
TOTAL 8 ,
138
263
061
509
346
319
,519
.957
,351
.497
,082
,406
EMISSIONS (Mg/yr)
NO
107
204
4,691
1,168
267
6,439
X
.2
.3
.5
.4
.0
.2
so2
7
13
316
78
18
434
.2
.8
.4
.8
.1
.3
HC
3.6
6.!?
156.4
38. <>
8.9
214.6
CO PARTICIPATES
15
29
687
171
39
943
.7
.9
.4
.2
.2
.4
UNK
UNK
UNK
UNK
UNK
UNK
Based upon average power requirement of 60 hp-hr/ft.
UNK = unknown
Refers to outer Gulf of Mexico provinces not included in Texas or
Louisiana figures.
-------
As the drilling bit passes through a producing formation,
gas may seep into the well bore and become dissolved or
entrained in the drilling mud. The gases are separated from
the mud in a mud separator, as shown in Figure 4-I.4
Additional gases are removed from the mud in t -> degasser
vessel, which operates under a vacuum. Finally formation
fragments and debris are screened out of the mud in the
shale shaker. The cuttings are dropped overboard, and the
conditioned mud is recycled to th; well.
The gases that are removed from the mud are usually
vented to the atmosphere without flaring. During the course
of this work, we have been unable to find sources of data
that would indicate the rate at which gases are emitted.
The total amount of gases emitted annually is considered to
be very small, although the rate of emission during a single
24-hour period could be as much as 20,000 ft3 of gas, based
upon 400 ft of 12-in hole per 24-hour day, 25 percent
porosity and 4,000 psig resevoir pressure. This is equivalent
to 0.4 Mg/d while drilling through producing formation.
A second type of emission from the mud separation
system will occur during the infrequent times that oil-based
drilling muds are used, primarily when the pipe becomes
stuck, for example. In this case, the mud will be dissolved
in oil rather than water so that as the mud passes through
the shaker, the oil vapors are exposed directly to the
atmosphere. An order of magnitude estimate for these emis-
sions can be made using the appropriate emission factor5
(0.36 lb/1,000 gal throughout) for a fixed-roof storage tank
for distillate fuels with a turnover factor of 0.5. Assuming
an average mud flow of 400 gal/min, the corresponding
emission rate is on the order of 90 kg/d. However, since
oil-based drilling muds are used very infreguently, the
annual rate of emission is not expected to exceed 0.5 Mg/yr
per rig based jpon an average usage of about 5 d/yr.
4.2.3 Blowouts
At times during drilling operations, the bit may pass
through pockets of gas prior to reaching the oil producing
C.D. Miller, "Proper Handling of Gas-Cut Mud Boosts
Drilling Efficiency," The Oil anci Gas Journal 74(13)
(March 29, 1976): 166-177:
5Personal communication to R.K. Burn, A.O. Spauldry,
Western Oil and Gas Association, February 25, 1977.
-89-
-------
horn diokf mociiloH
n«rt.vol»» ronliol
Figure 4-1. Handling toxic gas on offshore rigs• .
(C.D. Miller, "Proper Handling °fGas-Cut Mud Boosts Drilling
Efficiency," Oil and Gas Journal 74(13) (March 29, 19
-------
formation. Such an occurrence is often unexpected and the
density of the mud may not be great enough to control the
sudden increase in pressure. Reduction of mud density by
entrained gas further compounds the problem. The expanding
gas will rapidly push mud out of the hole. When a kick does
occur, the blowout preventers are closed and measures are
taken to increase the density of the mud until it can control
the increased pressure in the well bore. On rare occasions,
however, prevention techniques prove to be inadequate and
the well will get out of control, resulting in a blowout. A
blowout can be very costly in terms of the loss of equipment
and lives. Needless to say, the industry goes to great
expense to prevent such occurrences.
Blowouts usually occur during drilling, but they may
also develop during remedial work done after the well has
been completed. One particularly dangerous type of blowout
is that which occurs during the drilling of the surface
conductor hole. Five accidents have been reported which
resulted in the loss of several lives. These are listed in
Table 4-6.6
Some blowouts have been caused by the loss or damage of
a platform as a result of rough seas churned up by hurricanes.
Others have been caused by collisions with ocean-going
vessels. The USGS reports 57 blowouts since 1956 ranging in
duration from 15 minutes to over 5 months with the average
being on the order of a few days. The quantities of gas
which escaped during these accidents are comparable to the
ful] production rate of the blown wells. Note that a single
gas well can produce over 1 million SCFD (approximately 20 MG/d)
4.2.4 Dynamic Positioning and Stabilizing
One aspect of offshore drilling not common to onshore
operations is that drilling in deep wuter requires drill
ships or semisubmersible rigs, neither of which rests on the
ocean floor. In order to stay over the hole, a drill ship
will use its engines to counteract the current normally en-
countered. Dames and Moore^ have estimated the power
J. Beall, "Riserless Shallow Blowout-Control Method Is
Safe and Effective," Oil and Gas Journal 74(31) (August 2, 1976)
125.
Dames and Moore, Inc., Environmental Assessment Study,
Proposed Sale of Federal Oil and Gas Leases, Southern
California Outer Continental Shelf, Volume 3, Section IV,
Prepared for Western Oil and Gas Association, October 1974,
pp. 2-41 to 2-42.
-91-
-------
to
i
TABLE 4-6
HISTORY OF SHALLOW HOLE BLOWOUTS IN THE GULF OF MEXICO
CONTRACTOR
Reading and Bates
Fluor
Marine
Odeco
Odeco
RIG
C. P. Baker
Little Bob
J. Storm II
Ocean Patriot
Ocean Driller
TYPE OF RIG
Catamaran
Jack-up
Jack-up
Jack-up
Semi-submersible
YEAR
1964
1968
1970
1970
1971
Source: J. Beall, Oil and Gas Journal 74(31) (August 2, 1976): 125,
-------
SSSJnli*^ ents of most offshore platforms that
sagas sssu/istsr ir&ryjas--
the power capacity found — *••—- —' --- • • es*tj-mace
The power used in offshora platforms is required
primarily for gas compression (for trannlSBlm or arti-
ficial gas lift) oil pumping (the major use for eleotricitvl
and water injection, either for water flood or dispoial '
-93-
-------
TABLE 4-7
I
\0
I'd WE R r.RNEHATION, ^INSTALLED CAPACITY AND^ ESTIMATE P
ARKA
Alaska
California
Louisiana
Texas
USAOE RfiUUJRKD FOR OI-'KSHOUE PRODUCTION
h CAS COMPRESSION
CIAS COHPRESS'OIT' AND BOOSTING CAS INJECTION WATBR INJECTION ELECTRIC GRNEPAT1OMC
CAPfcflTYd
Ihp/lO^CFDl
300
300
150
ISO
Gulf of Mexico ISO
USAOC CAPACITY UbAUB CAPACITY USAGE CAPACITY USAGE CAPACITY USAGE
(hphr/10 CFI Ihp/lOnCFDI (hphr/io'tr) [hr/10bCFD| (hphr/106CP) |hp/109DOPBI [hphr/10'BBL] lhp/L03BOPU| [hphr/lO^BBL]
6,061 unk unk unk unk T - 2SO I.HiO
6,061 --.... 230 1.VIU
J.i'o «o a,530 3 ao iso 3.000 iso j,nour
3.170 UO 2.530 - - ISO 3.000 liO >,o0nf
3,170 ISO 7.5.10 - - I5u 1,000 150 1,000f
Inclurii": rni|u t crmnnt i for tins llff. q.itlirrlng. .inH sriidnut
bn-si.
Ala,.
in r.ictors:
•a. calif.
TMyl Oiscljaryp
Ipsiq] (paiol
IS 125
Ui.. Tex.. Gulf 10 to ISO 1,150
of. Mexico
Includes oil pumping ami miscellaneous aetvLcvii nlan includoa power for fixed pkatforn!).
Baa-.d upon total production: salos In 60 prreuiit uf prortnction in California and 60 percent of production in the Cnlf of MexLun.
°Transnis9ion facilities unshorc.
Based upon barrel! of oil plus condeniatc.
Source: Energy Resources Co. estimates (based in part upon data obtained during offshore visits).
-------
-------
TABLE 4-8
DRILLING RIGS ON FIXED PLATFORMS
NUMBER OF RIGS
AREA DRILLING
Alaska 7
California 1
Louisiana, Texas
Gulf of Mexico 62
TOTAL 70
WORKOVER
1
a
8
41
50
TOTAL
8
.a
9
103
120
alncludes 6 workover rigs working on THUMS (Longbeach
Harbor (California).
-96-
-------
emissions from power generation are shown in Table 4-9.
Note that accounting for the proper mix between turbines and
reciprocating engines (gas or diesel) results in a net
increase in the total emissions estimates.
4.3.2 Gas Processing
An estimate of the total production at the well of
natural gas is shown in Table 4-10, broken down into the
major use categories, i.e., sales, lifting, injection, and
platform fuel. In estimating the air pollution emissions
from the processing of gas, the total gas production at the
well (rather than sales) must be considered since the total
gas is usually processed prior to reinjection (gas lift) or
sales or use as platform fuel (some high pressure produced
gas will not regain compression).
In the paragraphs below are presented details of gas
processing operations, specifically:
• Compression
• Dehydration
• Venting
4.3.2.1 Gas Compression
The oil/gas mixture produced from the well is pumped
directly to a separation vessel where gas (and gas liquids)
are separated from a mixture of oil and water. The water-
laden gas must then be compressed and dehydrated pr Lor to
send-out. Dehydration of the gas is necessary to avoid
hydrate formation in processing equipment or pipelines.
The emissions from gas compression result from the com-
bustion of fuel necessary to generate power to drive the gas
compressor. These emissions have been discussed previously
with respect to power generation. There are three significant
differences between California operations and operations in
the Gulf of Mexico which have an effect on emissions:
1. The formation pressures in the Gulf of Mexico are
higher and therefore less power is needed to
compress the gas to pipeline pressures.
2. The ratio of associated gas to oil produced in the
Gulf of Mexico is considerably higher than in
California, and hence, a much lower proportion
-97-
-------
TABLE 4-9
TOTAL EMISSIONS FROM POWER GENERATION
ON OFFSHORE PRODUCTION PLATFORMS
AREA
California
Louisiana
Texas
TOTAL
OIL
|106bbl/yrJ
IS. 3
287.5
0.3
303.1
PRODUCTION
CONDENSATE
|106bbl/yr]
--
72.5
11.0
83.5
GAS
(109CF/yr)
4.0
3.332.2
1.218.1
4,554.3
TOTAL POWER
[106hphr/yr]
105.3
21.116.0
6,987.0
2B.228.3
EMISSIONS
HOX S02
148.5 6.3
29,801.6 1, 268.2 2
9,839.0 41B.7
39,789.3 1,693.2 3
(M9/yr)
HC CO
14.7 40.0
,959.1 8,031.7
976.9 2,651.6
,950.7 10,723.3
PARTIC-
ULATES
5.2
1,056.8
349.4
1,411.4
I
\o
00
-------
TABLE 4-10
APPROXIMATE GAS BALANCE
vo
i
AREA
California
Louisiana
Texas
TOTAL
TOTAL
PRODUCTION3
(109CF/yrl
E.7
3,914.8
1,291.3
5,212.8
GAS K
SALES0
[109CF/yrl
4.0
3,332.2
1,218.1
4,554.3
GAS
LIFT
U09CF/yrl
1.5
287.5
0.3
289. 3
CAS
INJECTION
U09CF/yrl
-
66.6
-
66.6
PLATFORM
FUEL
[109CF/yrl
1.2
218.4
72.9
292. 5
OTHER.
FUI:LC
[109CF/yrl
0.8
-
-
0.8
VENTED
OFFSHORE
Uo'cF/yrl
0.02d
U.30P-r
0.40
1.58
"At well.
Delivered onshore.
cUsed onshore; included in Gas Sales.
d,
vapor recovery systems in uso (approximately 90 percent- efficiency) .
eAssunes no vapor recovery and continuous venting o£ solution gas released at oil pressures below
65 psig (approx. 20 f tVbbl) •
Assumes vented gas proportional to liquid production rather than gas production.
Source: Enerqy Resources Co. estimates (based upon data obtained durina offshore visits.
-------
of the available gas is burned in the Gulf (approxi-
" COmpared to °«*hore California
3. Much of the gas production in Louisiana and Texas
oil Jells?8 rathSr than aS associafced gas in
fmi*1?" t0*the emissions *«» fuel combustion,
h«l "" r°m compress°r seals have characteris-
about t^1"1"017 S°^Ce °f air P°Uut.nt emissions,
? me °rder of magnitude as emissions from
SS seals o ™
4.3.2.2 Gas Dehdration
as a
at thebo £ TfV2' ?e W6t gas *ne« thedesorer
Umn 3
a ebo
of bubbS S! « ^ JUmn 3nd passes up thr°ugh a series
«iJ! i fP °^ Sleve traVs- The direct contact with
glycol results in the reduction of water in the oas to a
level of less than 1 Ib/million ft 3 of gas? Jhe^pent
SSiie?a!!K^t?SU9h/ 9lyco1 storage ?ank and "^ ^ the
reooiler where the water is removed by heating. Note that
on many offshore installations this heating can be carried
c?rcu?at? di"ffc-fi«d Caters or a heat SanSer fluid
?ibSS SS S? fche reboiler section and a suitable
Ixhaults S°UrCe °f WSSte heat SUCh as the *»s turbine
The emissions from the glycol dehydration unit include:
• Combustion emissions (only if direct fired)
• Glycol losses
,mnn IS ?u«lre
-------
C
-------
4.3.2.3 Vents
~
gas win be vented in the unusual circumstance that th^
ftVbbi>
to
The characteristics of the oil and gas processing
The nature of the control techniques in use
Sy8teM are in use "^ reduce the
'
of
-102-
-------
4.3.3 Oil Processing
Produced fluids from an oil well are a mixture of gas,
oil, and water. The oil processing train considered in this
section includes all of the necessary operations for separating
the oil from gas and water and upgrading the oil quality to
pipeline standards, i.e., free of entrained solids and con-
taining less than 1 percent water.
The oil will first pass through a series of separators
where the gases and free water are removed from the oil. At
this point the oil will still contain as much as 25 percent
water in the form of an emulsion. The oil is then heated in
a heater treater or passed through a chemical-electric unit
to break the emulsion and remove the remaining water from
the oil. This process reduces the moisture content in the
oil to 1 percent or less. From the heater treaters, the
processed oil is pumped to a storage tank that scores the
oil until it can be pumped ashore.
Each of these steps is discussed in detail in the para-
graphs below.
4.3.3.1 Separators
The first step in the oil processing train is to separate
the liquids from produced gas using a series of two phase
separators. In the Gulf Coast, the project team observed
a 3-stage system having a high-pressure separator operating
at approximately 1,000 psig, a medium-pressure separator
operating at approximately 400 psig, and a lower-pressure
separator operating at approximately 80 psig. As the pressure
of the oil is reduced, solution gas will be evolved. A
typical separator is shown in Figure 4-3. Note that the
gases pass" through a mist extractor to prevent the entrain-
ment of oil in the gas phase. Separators such as these are
constructed in the horizontal configuration shown in. a
figure and in vertical and spherical configurations as well.
The primary difference in these designs is in the relative
ability of each one to handle different ratios of gas to
liquid.
The final separator is usually a three phase free water
cnockout. A schematic of a typical unit is shown in Figure
4-4. The flMid from the higher pressure separators enters
the low pressure separator at the centrifugal inlet where
initial separation of liquid and gas takes place. The
separator itself is of sufficient size to allow the oil and
water to separate into two phases. The interface between
oil and water is controlled by controlling the rate of
removal of oil and water independently.
-103-
-------
o
-e.
i
Figure 4-3. Horizontal low pressure oil and gas separators
(Sivalls Tanks Inc., Engineering Catalog; 322)
-------
o
01
C
A fMTO COMM4TMC*"
t«" MAMMY
^ j _Vi-Ki.a»ii._J. j
Figure 4-4. Horizontal oil-gas-water separators. (Sivalls Tanks Inc.,
Engineering Catalog; 602.)
-------
The separators are all closed systems, often operating
at high pressures. The only emissions vvould result whenever
the pressure release valve opens to relieve excess pressure.
Under this condition, the gases would be vented to the plat-
form flare system and would subsequently be exhausted or
burned. On platforms equipped with vapor recovery systems,
low pressure gas would be compressed and transferred to the
gas processing system.
4.3.3.2 Emulsion Breakers
The oil phase from the separator train will contain as
much as 25 percent moisture in the form of an oil emulsion.
In order to break the emulsion a demulsifier chemical may be
added. Then the oil is heated to temperatures as high as
150° F or passed between electrically charged plates (not
shown) whereupon the oil and water will separate.
A typical horizontal heater treater is shown in Figure 4-5.
The oil enters the separator on the heated side where it is
contacted with the firebox tubes. As the emulsion breaks,
the oil phase and the water phase collect on the opposite
side of the heater and are pumped away at differing rates to
maintain a proper interface level. Note that during the
heating of the oil additional gas is released which leaves
the separator at the gas outlet. This gas will be combined
with the exhaust from the low-pressure separator and sent to
the vent or vapor recovery system.
A variation of the conventional heater treater design
is shown in Figure 4-6 showing a vertical configuration.
This unit is slightly more compact than the horizontal
treater and it allows for better heat exchange between the
inlet oil emulsion and the outlet processed oil. The manu-
facturer claims that this design extends the life of the
firebox and results in reduced fuel consumption.
In conventional heater treater units the fuel require-
ments have been estimated at a maximum of 15,000 Btu/bbl of
oil processed. The emissions from heater treaters are
comparable to emissions from most direct-fired process
heaters. Estimated emission factors are shown in Table 4-11.
While the equipment described above is in use on many
offshore platforms, some producers have found it economical
to heat the oil with waste heat from the gas turbine exhausts
using a heat transfer fluid such as Therminol. Since gas
turbines can provide as much as 5,000 Btu waste heat/hph,
there is more than enough heat available for heat treating.
-106-
-------
o
-J
I
Figure 4-5. Horizontal heater treater
Engineering Catalog; 465.)
(Sivalls Tanks Inc.,
-------
MIST EXTPACTO
INLET
GAS OUTLET
I6'MANWAY
OIL OUTLET
FILTER SECTION
EMULSION
CONDUCTOR PIPE
—GAS SEPARATING
SECTION
-—EQUALIZING LINE
^CONICAL BAFFi.E
ADJUSTABLE WATER
SIPHON
DOWNCOMER H
FREE WATER
KNOCKOUT BY-PASS
io*aa HEAT
EXCHANGER
?.' TUBES
Figure 4-6. Type "A" vertical downflow treaters,
(Sivalls Tanks Inc., Engineering Catalog: 409.)
-108-
-------
TABLE 4-11
EMISSIONS FROM HEAT TREATING
POLLUTANT NO SO
X X
c -i
Kg/10 m 1,600 9.6
of fuel
(lb/106ft3) 100 0.6
Kg/106bbla 647 3.9
of oil
(lb/106bbl) 1,426 8.6
HC CO PARTICULATES
128 320 160
8 20 10
52 129 65
114 285 143
aBased upon heat requirement of 3,780 Kcal/bbl
(15,000 Btu/bbl), natural gas fired.
Source: U.S. Environmental Protection Agency, Compilation
of Air Pollutant Emission Factors, March 1975.
-109-
-------
Hence, this could be used to completely eliminate the emissions
from direct fired heaters. Hence, since the Therminol
system is a closed system, the only heat treating emissions
would be from the occasional vapor losses resulting from the
over-pressuring of the separator vessel.
4.3.3.3 Product Send-Out
When the dehydrated oil leaves the heater treaters, it
is sent to a storage vessel where the pressure is reduced
trom the operating pressure of the low pressure separator to
essentially atmospheric pressure. On the Gulf Coast, the
pressure reduction from 80 psig to atmospheric pressure
results in a liberation of an additional 20 ft3 gas/bbl.
On the West Coast, the wells operate at essentially atmos-
pheric pressure and hence little gas is emitted from the oil
surge tank.
The oil is sent to shore for sale either by pipeline or
by barge, in the case of pipelines, almost all of the oil
is pumped using electric pumps, drawing power from the plat-
form s electric generation capacity. The emissions resulting
from the generation of electric power were discussed previously.
A second source of hydrocarbon emissions from pumping
result from occasional leaks of pump seals. This problem
was studied in considerable depth during the late 1950s when
the Public Health Service was studying refinery emissions in
the Los Angeles area. The data from the Los Angeles study
are summarized in Table 4-12. This work showed that the
emissions were related to the vapor pressure of the fluid
being handled, the type of pump seal, and the effectiveness
of pump maintenance. With respect to the latter point, the
researchers found that only one pump seal in four actually
leaked and of the leaks recorded, approximately 95 percent
of the measured loss of hydrocarbon could be attributed to
less than 15 percent of the pumps inspected. The study also
showed that these large leaks could be corrected in most
cases through proper maintenance.
The data obtained from the Los Angeles study are not
representative of offshore practice in two respects:
1. Since the time that the data were taken (1958),
there has been a moderate change in pump seal
designs which has tended to reduce the rate of
leakage; and
-110-
-------
TABLI-: 1-12
EFFECTIVENESS OF MECHANICAL AND PACKED SEALS ON
VARIOUS TYPES OF HYDROCARBONS
SEAL TYPE
Mechanical
Avy
Packed
Avg
Packed
Avg
"Small
Source t
Compressors.
ed." Air Pol
TYPI:
PUMP TYPE HYDROCARBON
BEING F'UMPEU
L8 REID
Centrifugal 2lj
1 to 26
O.S Ln 5
0.1
Centrifugal 2fi
S to 2S
O.S La S
0.5
Reciprocating 2C
S to 26
0.5 to S
O.S
LRAJC INCIUBNCF
AVG. MrDROTAHBON
LOSS PBR
INSPECTCO SEAL,
LB/DAV
0.2
o.r.
0.3
3.2
10.3
S.9
0.4
4.8
16.6
4.0
0.1
5.4
SMALL I.CAKSa
» OP TOTAL
FNSrCCTRU
10
IB
1'J
11
?Q
32
12
22
n
24
9
20
LARGE I.EAXS
* Of TOTAL
INSPKCTEtl
21
S
4
13
37
34
4
21
42
10
0
13
leaks lose less than 1 pound uC hydrocarbon per day.
B..I. Stoigorvald. Cm j salons of llydr
Report Mo. 6, Los An-iclca County AlF
tution Enqineerlna Manual, 2nd cd. . U
ms. May i<)7,i, p. 6?£.'
ocorbons to the Atmosphere
Prom Seals on Pumps
i-olJulion eontrol blsciJct, 1958. In John A~
.5. Environmental Protection ^kgnncy, Office of
and
UAniolaon.
Air And
-------
Because all of the equipment on a platform,
particularly the pumps, are located close to each
other and also because of the hazards of fire, it
is extremely unlikely that major hydrocarbon leaks
would go undetected or unrepaired.
£rOIB «™o *" estimating the rate of hydrocarbon loss
from pumps, the frequency of leaks on an offshore platform
is assumed to be the same as the frequency of "small leaks"
as shown previously in Table 4-12, i.e., 20 percent
of leakage is assurae* to K
1 pump x 1 Ib/d x 0.2 leakage
1,000 BOPO
hvH™in Khe ab?ve. ^ay, an additional source of fugitive
hydrocarbon emissions was from leaky process and safetv
XblTi 1?" if** dat-,f«» th" study are'summaSzed in
Iate!v 0 ?'lh/5e/Verage 1Sakage rate P" valve «• Approxi
mately 0.5 Ib/d for valves and gaseous service and n IIK/H
In the S " tS1bein? P«*«ced by so-called "large leaks."
In the case of valves in gaseous service, over 97 percent of
tS8 Sf1 TS ?mitt?d fr°m °nly 5 Percent of the vSves?
the case of valves in liquid service, 90 percent of the
«-h*h ?ith r?Sp?ct to off shore operations, it is believed
that the emissions rate will be less than those reported in
the Los Angeles study because of improvement in valve
onS H°9LSinCe 1958 and also because maintenance practice
onboard offshore platforms is considerably better than would
be expected from onshore refineries. Although the exact
esXmatf J'S*! *" S6r^Ce " Unkn°Wn' 3"
estimate would be approximately as follows:
-112-
-------
TABLE 4-13
LEAKAGE OF HYDROCARBONS FROM VALVES OF
REFINERIES IN LOS ANGELES COUNTY
ui
Total number of valves
Number of vjJveu inspected
Small leaks0
Large leaks
Loaks neasurod
Total measured leakage. Ib/day
Average leak rate — large leaks,
Ib/day
Total from all large leaks, Ib/day
Estimated, total from small leaks,
Ib/day
VALVES IN
CASEOUS SERVICE .
31.000
2.258
250
118
24
218
9.1
1.072
26
VALVES IN
LIQUID SERVICE
101,000
7.263
76R
70
76
670
8.8
708
77
ALL
VALVRS
332. ono
9,521
1.024
197
100
BUR
8.9
1,780
J03
Total estimated leakage from all
inspected valves, Ib/day
Average leakage per inspected valve,
1,098
7R5
0.4B6
0.108
1,883
0.190
JCakS 1rC def'ned as lcaks to° small to be measured ~ those -stimatc.l to bo
2 pounds per day.
„ * Loaks too small to be measured were estimated to have nn ovorano rale of 0.1 pound
per day. This IF one-half the smallest measured rate.
in
in
o
ol
o ' ere 1'rom Potroleum Refineriea
CoUnty. Kcport No. 9. Loa Angeles County Air Pollution Control DiBtrict.
Danlpll">n' t*-- Air
__
S'i ~ , ' --
mental Protection Agency, Office of
r Pollution RnqineerLng Manual. 2nd ed. . U.S. Environ-
Air and Hater Programs? day 1973, p. 691. Envlron
-------
GASEOUS LIQUID
SERVICE SERVICE
(per 1Q6 SCFD) (per 104 BOPD)
Number of Valves 100 500
Emission Rates 0.01 0.0007
kg/d/valvea
Estimated Emissions, 1 0.4
kg/d
aBased upon a leak rate of 0.015 Ib/d for gaseous
service and 0.01 Ib/d for liquid service as would be
expected with proper maintenance.
^Assumes 15 percent of liquid evaporates.
By comparison with other hydrocarbon emission sources
on the offshore platform, the above estimates appear to be
insignificant.
4.3.4 Water Treating
The water leaving the free water knockout and the
heater treater will be contaminated with oil and must be
treated in oil/water separators to prevent water pollution.
Two levels of water treatment are currently in use in off-
shore platforms:
• Skim piles and oil/water separators
• Froth flotation units
Skim piles and oil/water separators are vessels which
provide sufficient residence time to allow the small quantities
of oil to separate from the water and subsequently be skimmed
off the top and returned to the oil processing train. A
typical offshore oil/water separator is shown in Figure 4-7.
The tank is designed with a series of chambers separated by
baffles so that as the water progresses from stage to stage,
it becomes cleaner and cleaner. Oil is skimmed off the top
of each chamber, using skim pipes. On offshore platforms,
systems such as these are closed systems and, as such, will
have no emissions. In some cases, platforms will not have
-114-
-------
Figure 4-7. A modern oil-water separator. (J. A. Danielson,
U.S. Environmental Protection Agency, Air Pollution Engineering
Manual, May 1973, p. 674)
-------
oil/water separators if, for instance, the oil content of
the water is sufficiently low to pass directly to the
flotation unit.
A typical froth flotation unit is shown in Figure 4-8.
In this unit, air or natural gas is bubbled up through the
water, thereby stripping out any residual hydrocarbons that
remain after the initial separation steps. These units are
designed with sealed vapor spaces to prevent atmospheric
emissions. Unfortunately, the seals often fail or the
hatches are left loose or opened following the required
maintenance of the moving parts within the device which
skim off the oil froth. During the offshore visits, not a
single froth flotation unit was observed that was not
accompanied by a very noticeable hydrocarbon odor. No pub-
lished data have been found, however, to indicate a rate
of emission.
4.4 Control Technology
The air pollution emission sources found on offshore
platforms are not amenable to tail-end control systems.
Major sources and the possible control technologies are
listed below:
Emission Source Control Technology
Power generation Combustion controls,
conservation
Direct-fired heaters Elimination
Waste gas disposal Underwater flares,
(kicks, blowouts, dilution stacks,
venting systems) combustion flares,
vapor recovery systems
Pumps, valves and com Proper maintenance,
pressor seals mechanical seals
Each of these items is discussed in more detail in the
sections below.
4.4.1 Power Generation
The ma^or single source of air pollutants from offshore
platforms is power generation required for drilling, gas
compression, water disposal, and electric power generation
(primarily for oil pumping). This power is generated using
-116-
-------
FLOTATION
CHAMBER
COVER
PUMP
AND
MOTOR
FROTH
PADDLES
FLOTATION
CELL
Figure 4-8. Froth flotation unit for removal of emulsified
oil and suspended solids from produced water. (WEMCO Division,
Envirotech Corporation).
-------
either gas or liquid-fueled turbines or gas or liquid-fueled
reciprocating engines. The emissions from these types of
engines were shown previously in Table 4-3.
The EPA has spent considerable effort in researching
control technology for turbines and reciprocating engines.
Although much of this work has concentrated on vehicle
emissions, more recent work^ has dealt with the emissions
from stationary engines as well.
The appropriate methods of control for turbines or re-
ciprocating engines are combustion modifications aimed at
reducing nitrogen oxide emissions without significantly
increasing hydrocarbons or carbon monoxide. However, because
of the unique character of offshore operations, a second
method of control of emissions is possible through the
utilization of waste heat. This could eliminate the need
for direct-fired heaters, for example, or increase the effi-
ciency of the power generating equipment through the use of
combined gas turbine/steam turbine power cycles. Each of
these techniques is discussed below.
4.4.1.1 Combustion Controls
The pollutants arising from power generation can be
directly attributed to the conditions within the combustion
chamber of the prime mover. By altering combustion condi-
tions, the relative proportion of pollutants can be changed.
This is shown in Figure 4-9. Research has shown that nitrogen
oxides are formed at high combustion temperatures and in the
presence of oxygen. Therefore, by reducing thfe air-to-fuel
ratio (fuel rich), the amount of available oxygen will be
reduced and hence the amount of nitrogen oxides that are
formed will also be. reduced. Unfortunately, because of the
relatively low excess air available, the amount of carbon
monoxide and unburned hydrocarbons that are emitted will
increase under fuel-rich conditions. On the other hand, for
fuel-conditions, the amount of carbon monoxide and unburned
hydrocarbons can be reduced but the level of nitrogen oxides
that are produced will increase at air/fuel ratios close to
stoichiometric proportions. Only at air/fuel ratios in
excess of 20-to-l will the rate of nitrogen oxide emissions
9
Aerotherm, inc., Standard Support Document and Environ-
mental Impact Statement --Stationary Reciprocating Internal
Combustion Engines, prepared for the U.S. Environmental Pro-
tection Agency, Contract 68-02-1318, to be released.
-118-
-------
EMISSION
LEVEL
.OTTO-CYCLE ENGINES
'OPERATING RANGE
DIESEL-CYCLE ENGINES
OPERATING RANGE
GAS TURBINES
OPERATING RANGE
CHEMICALLY IDEAL MIXTURE
Figure 4-9. Correlation of emission level and engine
type operating range. (Adapted from Toward Bluer Skies,
International Harvester Company.)
-119-
-------
fch/f?e^-U"f°rtUSately' a8 the air-to-fuel ratio increases,
the fuel efficiency decreases and, hence, the reduction in
air pollution emissions is accompanied by an increase in
energy consumption.
is a Production operations where the primary prime mover
is a gas turbine engine, the expected emissions are relatively
low. This is because a turbine normally operates with an
air/fuel ratio of 50- or 60-to-l. The high air/fuel ratio
required of turbines is necessary because the inlet gas
temperature to the turbine must remain below about 1,800° F
in order to avoid severe thermal damage to the turbine
blades.
4.4.1.2 Control by Conservation
Because of the characteristics of gas turbines described
above, the turbine will produce large volumes of hot exhaust
which is ideally suited for waste heat recovery. Manufac-
turers have estimated that as much as 5,000 Btu/hph can be
recovered. This waste heat can be used on the platform in
one of two ways:
1. Combined-cycle operation - Waste heat could be
used to generate steam which could then be u---d to
produce more electricity; the net result is an
increase in the efficiency of the gas turbine
operation from approximately 26 percent to as much
as 40 percent. The amount of emissions would be
correspondingly reduced.
2. Fuel conservation - Waste heat could also be used
to provide low-grade heat for regeneration of
glycol used in gas dehydration, for breaking of
the oil-water emulsion in the heater treaters, for
space heating or water purification, and saveral
others. By eliminating direct-fired heaters, the
emissions, obviously, are also eliminated.
Combined-cycle operations are currently under development
by most of the gas turbine manufacturers and could be intro-
duced in the field in the near future. With respect to the
elimination of direct-fired heaters, for example, through
waste heat utilization, the project team observed offshore
platforms which were designed to eliminate all fuel combustion
requirements except those relating directly to power genera-
tion, i.e., gas compression, water injection, and electricity
generation. The team observed that there was far more waste
heat available on the platform from power generation than
was required for process or heating use.
-120-
-------
The advantages of air pollution control using waste
heat utilization are obvious. The technique does not merely
reduce emissions, it totally eliminates emission sources
from direct-fired heaters. In addition, this type of
pollution control results in a net savings in energy rather
?han a net increase as is common to combustion modification
controls currently being considered (which result in an
increase in fuel consumption of approximately 5 percent).
4.4.2 Direct-Fired Heaters
Because of the availability of waste heat on offshore
platforms, it is the opinion of the project team that the
only acceptable air pollution control for this source of
emissions is through the utilization of waste heat. In the
team's judgment, the need for direct-fired Caters such as
are common to oil heater treaters or to gas dehydration
units could be substantially curtailed or even eliminated
through the use of waste heat recovery systems. Such systems
appear to be cost-effective and technically feasible and
should be exploited to the maximum.
4.4.3 Waste-Gas Disposal
Both the offshore drilling and production-type platforms
i-equire vents to handle waste gas. During drilling operations,
ihe waste gas is released within the mud separator during a
pressure kick. In most cases this gas is vented into the
atmosphere without further control. On a production platform
waste gas sources include pressure-relief valves, compressor
bypass loops, oil storage tanks and so on. Three types of
waste gas control techniques are currently in operation on
production platforms. They are:
• Dilution stacks and underwater flares
• Smokeless (combustion) flares
• Vapor recovery systems
Each of these systems is discussed in the following
paragraphs.
4.4.3.1 Dilution Stacks and Underwater Flares
On many of the offshore platforms waste gas is vented
directly to the atmosphere in dilution stacks or underwater
-121-
-------
flares. The purpose of these two types of control techniques
is to process the gas in such a way that it will not ignite
on the platform.
In the case of dilution stacks, the waste gas is diluted
with a large volume of air prior to exhaust. A typical
dilution stack would appear as a large-diameter vessel
having a fan at the bottom to suck in air and drive the
diluted gas out the top. Gas treated in this way will not
ignite because the mixture is maintained far below the lower
explosive limit of the gas.
In the case of underwater flares, the gas is piped away
from the platform and released under water. Tests have
shown that gas which has bubbled up through the ocean in
this manner will not self-ignite, nor will it reduce the
buoyancy of the water enough to capsize boats which acciden-
tally float over the flare.
During the field visits, the project team discussed at
length the use of dilution stacks and underwater flares for
offshore platforms. The team was informed that this practice
was no longer in vogue and only a small percentage of plat-
forms were currently using this type of control technique.
4.4.3.2 Smokeless (Combustion) Flares
The preferred method of control in the Gulf Coast is to
use a combustion flare as shown in Figure 4-10. The theory
behind the operation of this type of device is obvious. The
combustible waste gases are converted to CO- which is not a
pollutant. The combustion is controlled at appropriate
conditions to maximize the combustion of hydrocarbons and at
the same time minimize ths formation of nitrogen oxides.
Emission factors from smokeless flares are shown in Table 4-14.
Although the flare achieves a 99.5 percent reduction in
hydrocarbons, it results in the formation of carbon monoxide
and aldehydes, both of which are far more photochemically
reactive than methane.
4.4.3.3 Vapor Recovery Systems
Vapor recovery systems appear to be both the most
expensive means of control and also the most effective from
the point of view of reduction of photochemical emissions.
Using a vapor recovery system, all waste gas sources are
conducted to a small compressor. The gases are compressed
and recycled to the gas -processing system. Tests on such
-122-
-------
Figure 4-10. View of John Zink smokeless flame
burner. (J. A. Danielson, U.S. Environmental Protection
Agency, Air Pollution Engineering Manual, May 1973, p. 606.)
-123-
-------
I
!-•
(0
TABLE 4-14
EMISSIONS FROM FLARES
POLLUTANT NOX
Emission Rate,
Kg/106 CF, flared neg.
TOTAL EMISSIONS,
MT/yr
California
Louisiana neg.
Texas neg.
TOTAL neg.
SOX HC CO PARTICIPATES
8 10 145 neg.
9.3 11.6 168.2 neg.
3.2 4.0 58.0 neg.
12.5 15.6 226.2 ' neg.
-------
systems have indicated recovery efficiencies of 90 percent
or greater. One important factor to note, however, is that
uncontrolled emissions from the system are predominantly
methane which is very low in photochemical reactivity.
Partial combustion products emitted by ignited flares are
both reactive and carcinogenic although greatly reduced.
Vapor recovery systems are currently required in
offshore California operations. They have not been considered
necessary in offshore operations in the Gulf of Mexico.
4.4.4 Fugitive Emissions
The only major source of fugitive emissions that have
been identified in the course of this work has been from
leaks to seals of compressors, pumps, and valves. With
respect to pumps and compressors, the most effective type of
seal appears to be a mechanical seal which results in as
much as 50 percent lower leakage rates than comparable
packed seals.
However, once the pumps, compressors, and valves are
put into service, the most appropriate method for pollution
control is propex maintenance of the seals to insure that
major leaks do not occur. Offshore operations are expected
to be much better in this regard than onshore operations
because the equipment is all located in one area (on the
platform) and it is in open view where leaks can be readily
detected. Secondly, because of the potential hazard of a
fire onboard, the crew will be more likely to fix leaks for
their own protection than will their onshore counterparts.
Although critical, rigorous inspection was not the
objective of the site visits made by the project team, none
of the valves and pump seals examined by the team appeared
to have a significant and measureable leakage rate. The
team has concluded from this observation that further controls
would be impractible and unwarranted.
-125-
-------
CHAPTER FIVE
IMPACT ANALYSIS
5.1 Introduction
In this chapter the source estimates of emissions which
are developed in Chapter Pour are sununarized and applied to
offshore oil and gas production activities in 1975 and
projected activities for 1985 which are presented in Chapter
Two. The unpact of applying control techniques identified
in Chapter Pour to these emissions sources is assessed. A
preliminary estimate of the impact on ambient air quality is
also presented and considerations for a test program to
obtain data not presently available is outlined.
5-2 Total Emissions Estimate
Table 5-1 summarizes the emissions factors developed
from the data and analysis in Chapter Four. The total
hydrocarbons are based upon a produced gas analysis as
follows:^ 83.6 percent (by volume) methane; 5.4 percent
ethane; 6.1 percent propane? 3.2 percent butane; 1.4 percent
pentane; 0.3 percent carbon dioxide. Non-methane hydrocar-
bons have been rounded to 10 percent for estimating purposes.
The upper value for mud degassing emissions is based upon a
maximum emission of 20,000 SCFD during the last 7 days of
drilling a well and a maximum H2S concentration of 100 ppm
in California gas.2 Oil-based mud emissions are based upon
uncovered mud tanks and assume use of this type of mud 5 d/yr
per rig. Fuel storage emissions during drilling operations
are based upon No. 2 diesel oil, and EPA emissions factor of
0.5 pounds of hydrocarbon per 1,000 gallons of tank through-
£K 5°*,?.flxed roof tank' 75 Percent rig availability and
the drilling scenario shown in Table 4-3. Hydrocarbon
emissions from dehydration in gas processing are primarily
F.E. Vandaveer, Gas Engineers Handbook (New York: The
Industrial Press, 1965), pp. 2/11 for Ventura, California.
No values for Gulf of Mexico gas were found but analyses are
believed to be comparable to Ventura.
Personal communication, USGS Santa Barbara District
Ventura, California, October 11, 1976.
-126-
-------
TABLE 5-1
SUMMARY OF EMISSION FACTORS3
—
ffll'IMIM SJ4IWI'
UUJ.I.IM..
I
furl S*^l 1 K
IMq/ln1* SCKI
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inri/in4 hbl ]
Piun» S'.olS
Mq/lll<> IA1I
Vnlv- S-«J»
(M-i/lf/1 bhll
Oil Sforagn t Surge Txnk
(Ha/ in*1 bbll
tut-r Tr-.itlnq unlK
I'nl.MllXNIA
l-Aiirii -
»', '•", '• •" IIIJMI-. 11^-.
"< '•' ••'• II i link
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--OS-
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il. 1 -
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in - O.IH
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unk unk unk unk unk iinv
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Jill - - n.4
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o.ri? n no* n.m 0.11 n PI
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o.n
-------
glycol. Vent emissions from gas processing and other plat-
form operations in California offshore facilities take into
account vapor recovery at 90 percent efficiency which is
current practice. It is assumed that these emissions in the
Gulf of Mexico are uncontrolled.
The total emissions estimates for 1975 from offshore
oil and gas activities (before application of control tech-
nologies) are shown on Table 5-2 and for 1985 on Table 5-3.
It is assumed that no energy conservation technologies are
in use. Although no published information on the extent of
application of energy conserving technologies was found
during the study, systems to utilize a portion of the avail-
able waste -heat were observed on two of the six offshore
facilities visited by the project team. For example, the
emission factors for gas dehydration are based upon a fired
glycol reboiler whereas the two systems observed offshore
utilized waste heat from power generation to reboil the
glycol. No waste heat utilization systems were observed on
the drilling operations visited. No emission factors were
found for open burning of produced oil and gas which could
be used to assess the emissions from burning the initial
well flow to clean up a newly completed well. During ini-
tial flow from a new well displacement of the saltwater,
drilling fluid filtrate and completion fluids combine with
gas, oil, sand and other debris. Depending on the produc-
tion facilities available, this flow may be processed through
the treatment steps or flared until a clean flow is estab-
lished.
Table 5-4 lists the control technology ootions for the
emissions sources and identified the control technologies
utilized in the assessment of emission reduction potential
for offshore facilities. This hypothetical case with pollution
controls illustrates the large emission reduction potential
of higher efficiency combined cycle operations for gas
turbines. This technology is currently under development
and economic analysis is required. Although significant
reductions in hydrocarbon emissions can be achieved through
the application of vapor recovery in the Gulf of Mexico and
Atlantic, the economics of installing this control technology
should be evaluated. The costs of emission control technologies
for the drilling phase of oil and gas activities requires
further evaluation before particular applications are selected
because drilling emissions are only 10 to 20 percent of
production emissions.
Another observation is that the U.S. Geological Survey's
"no flare" order does address the most significant source of
total hydrocarbon emissions. The emission factors used
-128-
-------
TABLE 5-2
ESTIMATES OF TOTAL UNCONTROLLED EMISSIONS
FROM OFFSHORE FACILITIES, 1975
(Mg/yr)
CALIFORNIA (STATE I FWF.RAL1
I'AHTIC-
"", s°2 «' co uiATii'. ii 7s
orrsHow TFXAS. LOutstwiA, u:a cutr OK IKXICO IKMICVAI.)
l-AHTIl-.
""^ «l lir Ifl !>I.AThS
1 (-i
DPI U.I W. lavrraqp
nf 1 y'»ci>
Pnwi-r i-enerflt Icm
Him l^g.n>mn<4
Oll-H.iieri Muds
MoOTuro
Fuel Stonqa
PHODUCTION
Hwor Cent-ration
OAS PROCESS 1 NO
Dehydration
COfp'<"MH» 5C*H|R
v««ncn
Valuj <«i> t K i f t d Hi .t 1 1 i ••
Maip Si-al«
VMlvt- r.i-.iin
Oil Mfiinqi dnri *S *•' U>' •10-n
un» I..I/H III .,,.| H1H
... .,.,„„"
- 1,.-.
M.M1 1.687 J.91S 10.683 1.4C6
"" J-°
.
I1ii.ll"
Mi.. MO'
5. 141 :i7.D*J^ U.S41 1 .111 II.'
(Jl.llJI11
Based on average rig count 1975.
Primarily methane, non-methane hydrocarbon content approximately 10 percent.
Glycol losses (some of the loss may be in process gas rather than exhaust) .
Non-methane hydrocarbon emissions shown in parentheses.
-------
TABLE 5-3
ESTIMATES OF TOTAL EMISSIONS FROM OFFSHORE FACILITIES, 1985
(Mg/Yr)
CALIFORNIA (STATE AND
DRILLING (average
of nine years)
Power Generation
Mud Degassing
011 -Based Muds
Blowouts
Fuel Storage
PRODUCTION
Power Generation
GAS PROCESSING
Dehydration
Compressor Seals
Vents
Valve Seals
OIL PROCESSING
Direct- Fired Heaters
Pump Seals
Valve Seals
011 Storage
WATER TREATING
TOTAL UNCONTROLLED
EMISSIONS
REDUCTION FROM
POLLUTION CONTROL
(Per Table 5-4
Scenario)
waste Heat Utilization
Combined Cycles Operation
Vapor Recovery
TOTAL REDUCTION FROM
SCENARIO
TOTAL CONTROLLED
EMISSIONS
PERCENT REDUCTION
NO,
788
-
-
-
-
2,984
4
-
-
-
122
-
-
-
-
3,898
126
1,044
-
1,170
2,728
30
so2
53
-
-
-
-
130
neg
-
-
-
1
-
-
-
-
184
1
46
-
47
137
26
HC
27b
286b
9
unk
2
278
73
unk.
_ — »_n
4,700?
183b
9
}lb
8D
-
unk
5,594
(935)c
9
97
~
106
5,488_
(829 )C
, ?c
(11)
CO
115
-
-
-
-
797
1
-
-
-
24
-
-
-
-
937
25
279
"
304
633
32
FEDERAL)
PARTIC-
ULATES
unk
-
-
-
-
Ill
neg
-
-
-
13
-
-
-
-
124
13
39
—
52
72
42
H2S
-
-
-
-
-
-
-
-
8
-
-
-
—
-
-
8
-
-
~
-
8
0
^Primarily methane; non-methane hydrocarbon content approximately 10 percent.
cNon-methane hydrocarbons shown In parentheses.
130
-------
TABLE 5-3
ESTIMATES OF TOTAL EMISSIONS FROM OFFSHORE FACILITIES, 1985
(Mg/Yr)
DRILLING (average
of nine years)
PoWer Generation
Mud Degassing
Oil -Based Muds
Blowouts
Fuel Storage
PRODUCTION
Power Generation
GAS PROCESSING
Dehydration
Compressor Seals
Vents
Valve Seals
OIL PROCESSING
Direct-Fired Heaters
Pump Seals
Valve Seals
011 Storage
WATER TREATING
TOTAL UNCONTROLLED
EMISSIONS
REDUCTION FROM
POLLUTION CONTROL
(Per Table 5-4
Scenario)
Waste Heat Utilization
Combined Cycles Operation
Vapor Recovery
TOTAL REDUCTION FROM
SCENARIO
TOTAL CONTROLLED
EMISSIONS
PERCENT REDUCTION
OFFSHORE TEXAS. LOUISIANA. AMD GULK
NOX S02 HC CO
2,580 173 87h 377
932
43
unk
9
25,955 1,274 2,549 7,046
56 neg 1,126
unkh
- 93,000?
2,814
242 1 19 48
37.
. _Q
15b
- 136,524°
unk
28,833 1,448 237,155 7,471
(27,162)c
298 1 19 59
9,084 446 892, 2,466
- 20S.5720
9,382 447 207,483r 2,525
(21,568)C
19,451 1,001 29,672 4,946
(5,594)C
33 31 87C 34
OF MEXICO
PARTIC-
ULATES
unk
~
—
•
~
956
6
-
™
26
—
~
•
-
988
32
335
367
621
37
(FEDERAL)
H2S
-
"
™
-
-
149
"
-
™
"
223
•
372
335
335
37
90
bPrimar11y methane; non-methane hydrocarbon content approximately 10 percent.
GNon-methane hydrocarbons shown in parentheses.
130a
-------
TABLE 5-3
ESTIMATES OF TOTAL EMISSIONS FROM OFFSHORE FACILITIES, 1985
(Mg/Yr)
NO,
DRILLING (average
of nine years)
Power Generation 774
Mud Degassing
011 -Based Muds -_
Blowouts
Fuel Storage
PRODUCTION
Power Generation 3,987
GAS PROCESSING
Dehydration 7
Compressor Seals
Vents
Valve Seals
OIL PROCESSING
Direct- Fired Heaters 94
Pump Seals
Valve Seals
Oil Storage
WATER TREATING
TOTAL UNCONTROLLED
EMISSIONS 4,862
REDUCTION FROM
POLLUTION CONTROL
(Per Table 5-4
Scenario)
Waste Heat Utilization 101
Combined Cycles Operation 1 ,395
Var&r Recovery
TOTAL REDUCTION FROM 1 .496
SCENARIO
TOTAL CONTROLLED 3,336
EMISSIONS
PERCENT REDUCTION 31
ATLANTIC (FEDERAL)8
PARTIC-
S09 HC -CO ULATES HgS
52 26h 113 unk
188° - - unk
g - -
unk -
2 -
194 388 1,082 146
neg 136 1 1 -
unkh -
36,250? - - 58
340 -
1 7 19 10
^b - - -
6h
53,215° - - 87
unk -
247 90, 582 1,215 157 145
(9,583)
1 7 20 11
68 136. 379 51
- 80,519° - - 131
69 80,562 _ 399 62 131
(8,195)c
178 9,920 _ 816 95 14
(1,388)C
28 89 33 39 90
(86)C
Atlantic emission factors assumed to be the same as Gulf of Mexico.
bPr1marily methane; non-methane hydrocarbon content approximately 10 percent.
cNon-methane hydrocarbons shown in parentheses.
130b
-------
TABLE 5-4
CONTROL TECHNOLOGY OPTIONS AND
1985 CONTROL SCENARIO
EMISSIONS SOURCE
CONTROL TECHNOLOGY OPTIONS
OPTION FOP
TABLE 5-3
SCENARIO9
Power Generation - Drilling
Mud Degassing
Oil-Based Fuel Storage
Power Generation - Production
Gas Dehydration
Compressor Seals
Vents (Gas Processing)
Valve Seals (Gas)
Direct-Fired Heaters
Pump Seals, .Valve Seals (Oil)
Oil Storage and Surge Tanks
Combustion Control (auxil-
liaries) Waste Heat utilization
Dilution Flares, Combustion
Flare, Vapor Recovery System
Dilution Flare, Combustion
Flare, Vapor Recovery
Combined-Cycle Operation
(developmental)
Waste Heat Utilization
Vapor Recovery
Vapor Recovery, Combustion
Flares, Dilution Flares,
Operating Practice
Maintenance
Waste Heat utilization
Maintenance
Vapor Recovery, Combustion
Flare, Dilution Flare
None
None
None
Combined-Cycle
Operation
Waste Heat
Utilization
.None
Vapor
Recovery
None
Waste Heat
Utilization
None
Vapor
Recovery
100 percent application to sources assumed.
Vapor recovery at 90 percent efficiency.
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herein are based upon operators data and in each case some
gas release occurs despite such operating practices as
shutting in productive wells when the gas compressors must
be shut down for maintenance.
5.3 Ambient Air Quality
As an example impact a typical offshore California
platform producing oil and gas is selected for evaluation.
Based upon the projections developed in Chapter Two, the 16
projected new offshore production facilities would be
producing an average of approximately 28,250 barrels of oil
and 30,800,000 ft3 of gas per day in 1985. Emission rates
for this typical platform are summarized in Table 5-5.
Based upon the graph shown in Figure 5-1, the contri-
bution to short-term ambient offshore concentrations of non-
methane hydrocarbons would be 48.5 ug/m3. This assumes the
platform is represented by a single point source of emissions
release at a height of 27 meters above sea level, a wind-
speed of 1 m/sec which persists in the onshore direction
under stability class D, and a platform location at the
3-mile limit.
The primary 3-hour ambient standard for non-methane
hydrocarbons is 160 ug/m3, or the equivalent of about
199 pg/m3 for a 1-hour standard using the interpolation
formula as given in Turner's Workbook of:
where p may take a value between 0.17 and 0.20. Therefore,
the emissions from a single typical platform at the 3-mile
limit (4.8 kilometers) would be 24 percent of the standard.
By comparison, a platform 10 miles from shore would contri-
bute only 4 percent of the interpolated 1-hour ambient
standard for non-methane hydrocarbons at the shoreline. Note
that another important difference between California and
Louisiana or Texas is that the existing platforms are much
closer to the shore and they are much closer together as
well. Analysis of the ambient air quality impacts of mul-
tiple sources for long averaging times requires more detailed
modeling beyond the scope of this study. The following
discussion presents some further considerations for carrying
out such modeling and in interpreting the results of the
above calculations.
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Ul
tjj
TABLE 5-5
SUMMARY OF EMISSION RATES FOR A TYPICAL OFFSHORE
CALIFORNIA PRODUCTION PLATFORM - 1985 (g/sec)
SOURCE NOX S02 THC NMHCa CO Particulates H2SD
Power Generation 5.5 0.2 0.5 0.01 1.5 0.2
Gas Processing 0.4 neg 10.8 1.74 0.04 0.04
Oil Processing 0.2 neg 14.2 2.29 0.03 0.03
TOTAL EMISSION 6.1 0.2 25.5 4.04 2.57 0.27
-
0.02
0.02
0.04
aBased »3pon 2 percent NMHC:THC ratio for power generation (average of data from
C.M. Urban, and K.J. Springer, Study of Exhaust Emissions from Natural Gas Pipeline
Compressor Engines (San Antonio, Texas: Southwest Research Institute, February 1975),
p. 18, and 16 percent NMHC:THC ratio for produced gas. Ventura, California, Gas
Engineers Handbook (New York: The Industrial Press, 1965), p. 2/11.
Assumed concentrations of 100 ppm as maximum for estimating purposes only.
Almost all existing offshore gas production has negligible H2S content.
-------
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I-1
Ul
.£»
I
lll'I
XITII INVERSION AT 100m
Figure 5-1. Modified concentration versus downwind distance
for H = 27m.
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In assessing short-term impacts, one must develop a
conceptual model of the processes that are expected to be
active at the site of assessment. The quality of the air
being advected from a large body of water containing some
oil development activity, to a shoreline area is of concern
here. This implies that the air mass will likely be almost
completely maritime, with fairly little continental influence
in most cases.
This air mass is considered to be adjusted to the
average sea surface temperature, which means that a thermal
discontinuity will often exist at the shore. Under these
conditions, if a cooler, stable air mass, for example,
penetrates inland over a strongly heated land mass, the
lower layers of the air mass will become highly unstable,
and a thermal boundary layer will grow in height as the air
moves further inland. The dispersion within the boundary
layer will greatly exceed that above it, producing a situation
that is very similar to early morning fumigation conditions.
The main difference between these two situations is that the
morning fumigation involves a thermal boundary layer that
grows in time, but remains nearly fixed in the horizontal
plane. The shoreline fumigation height is relatively constant
in time (over, a period of several hours, say), but varies
with distance from the shore. Since air quality criteria
are developed for time-average concentrations at discrete
points, then the case of the shoreline fumigation is clearly
of greater concern. Here, a segment of a community may be
subjected to relatively high pollutant concentrations for a
period of several hours.
Another situation may also lead to enhanced ground
level concentrations of plume material. Elevated inversions
may exist over nearshore waters just as they do over land.
Should meteorological conditions produce a shallow mixing
barrier, then the resultant trapping of pollutants beneath
this level can cause increased downwind concentrations
within the mixing layer.
Both of these processes are included in this dispersion
analysis. Outside of these external influences, the major
parameters that have a direct bearing on downwind ground
level concentrations are the marine atmospheric stability
class (based on Pasquill stability classes), average wind
speed at the height of release, the height of the plume
centerline, and the source strength (rate of pollutant
release).
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Dispersion in the marine atmosphere is quite differenf
T H ^ Substit«tion of a vast^ater surf ace
d haf far-reaching implications. The diurnal
yClVf 3 land SUrfaCe is quite P^nounced;
/E^1* ab.sorbed fn a v«y th" 1-yer. and the
u fc gain 1S traPPed in a rather shallow layer
?h* P°°r.thermal conductivity of the medium. At
».t. at 1S raPldly lost ^e to conduction to the
atmosphere, and radiation to space. Under conditions of low
relative humidity, the air above the surface is especially
transparent to the long-wave radiation, and the rapid heaJ
loss gives rise to a rapid cooling of the surface
nf *.h°Vel the °ceans: insolation penetrates the lower boundary
of the atmosphere, with absorption taking place over a
dieCao^r Y6r' inS^ad °f °"1Y a thin skin- Wind-mixing of
the upper ocean hastens the redistribution of this heat
energy, so any temperature gradients near the surface are
very small compared to those of a land surface. The heat
capacity of water also tends to reduce a rapid rise in
surface temperature during the day, owing to its larger heat
"Pa?ifcy- T^ final significant difference lies in ?he
ability of evaporation at the sea surface to remove heat
energy from this surface, thereby reducing its temperature.
At night, temperature changes of the sea surface are
also less than those over land. This is primarily a result
of the mor<2 uniform distribution of temperature in the
vertical (beneath the surface), the greater heat capacity of
= ai« \S ^6 *reater water vaP°r content of the overlying
atmosphere a partial "screen" reflecting some of the long-
wave radiation back to the surface). 9
All of the differences noted above tend to suggest that
a water boundary has a great deal more thermal inertia than
a land boundary, so the extremes of stabilities encountered
over land are quite rare over the oceans. In fact, the
brief remarks made above might lead one to question the
possibility of observing even mildly unstable atmospheric
conditions over the ocean. These do indeed occur quite
frequently. The great amount of water vapor present in the
lower layers of the marine atmosphere tend to reduce the
resistance of the column of air to vertical mixing. Any
displacement of an air parcel in the vertical which leads to
some condensation will cause that volume of air to absorb
that latent heat of condensation, with a resultant rise in
temperature. This increases the net buoyancy of that volume,
which leads to further vertical movement and mixing. Tempera-
ture profiles alone do not establish the stability of maritime
air; water vapor profiles must also be known. Therefore a
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weak temperature gradient near the ground may be associated
with a mildly unstable atmospheric surface layer if proper
account of the water vapor distribution is allowed.
5.4 Outline of Field Sampling Program
A complete characterization of pollutant emissions from
offshore oil facilities is needed for any detailed assessment
of air quality impact. Parameters influencing the effective
height of release are particularly important to obtain since
release height (including plume rise) plays a major role in
determining ground level concentrations downwind of the
site. Secondary aerodynamic modification of the releases is
also of major significance in that the wake structure formed
by the platform causes both rapid dispersion and release
height modifications near the structure. These two factors
emphasize the scope of problems that must be addressed in
any field monitoring endeavor.
Sources with the highest priority to be monitored
include compressor seals and thrust bearings, oil storage/surge
tank vents and gas vents. Emiss-.ons from open burning of
produced oil and gas should be developed for use in assessing
the impacts of blowouts and well completions. Emissions from
the glycol reboiler in gas dahydration systems should also be
characterized.
Sampling frequencies shall be tailored to the typical
operating sequence of each of the components tested. For
example, gas vents, compressor seals and thrust bearing
samples must encompass a complete maintenance cycle of the
gas compressor.
Operating variations due to variations in the load or
throughput of the equipment source being sampled shall also
be accounted for in the sampling schedule. Data will be
collected on all relevant operating variables to include oil
and gas production volumes, equipment status, electric power
demand, and gas content and drilling activities.
Testing equipment shall be selected for its suitability
to the measure pollutants from the point sources in the con-
centrations expected, sensitivity of the instruments and
reliability in the marine environment, support materials and
personnel required (including sample storage precautions
where necessary), and sampling cycle time required for the
acquisition of one measurement. The overall sampling program
will be designed to obtain representative data from the
planned data collection on a limited number of platforms, in
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