TECHNICAL NOTES ON PETROLEUM INDUSTRY OPERATIONS

• Document Type: CREST
• Collection: General CIA Records
• Document Number (FOIA) /ESDN (CREST): CIA-RDP79S01091A000400010001-6
• Release Decision: RIPPUB
• Original Classification: U
• Document Page Count: 64
• Document Creation Date: December 12, 2016
• Document Release Date: March 1, 1999
• Sequence Number: 1
• Publication Date: September 1, 1974
• Content Type: BOOK

44, ogoVor"
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Intelligence Handbook
Technical Notes on Petroleum Industry Operations
A Compilation of Articles from
International Oil Developments
.
al Use Only
ER H 74-2
September 1974
Copy
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Preface
These articles have been presented in International Oil Developments during
the past five months to briefly explain some technical aspects of petroleum industry
operations. They are brought together in this publication as a service to readers
who have expressed special interest in the subject.
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CONTENTS
Page
Exploration
1
Finding Oil and Gas
1
Oil and Gas Reservoirs
5
Evaluation of New Field Discoveries
9
Drilling
13
Drilling a 15,000-Foot Wildcat
13
Drilling Disasters
21
The Cost of Oil Drilling and Producing Equipment
27
Production
31
Production of Natural Gas Liquids
31
Secondary and Tertiary Recovery of Crude Oil
33
Future Subsea Oilwell Production Methods
37
Transportation and Storage
41
Oil and Gas Pipeline Construction
41
Petroleum Storage Installations
45
Deepwater Oil Terminals
47
Refining and Petrochemicals
51
The Properties of Crude Oil
51
Refining of Oil
53
Petrochemicals
57
Conversion Factors
59
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Exploration
FINDING OIL AND GAS
Petroleum Exploration
Oilmen often say that oil is where you find it. What they mean is that, even
with the best information available, one never knows with certainty where oil is
before drilling. There is, however, general agreement that the better the information,
the better the chances for success. Supplying this information is the job of the
oil geologist and geophysicist.
Subsurface rock conditions affecting petroleum's origin, migration, and
accumulation in structures and traps fall within the province of geological science.
Measurement of the size and other physical characteristics of underground
petroleum formations falls within the province of geophysical science. The rapid
advance of petroleum geophysics over the last decade has revolutionized the
economics of petroleum exploration. Development of extremely sensitive measuring
devices has greatly narrowed the range of uncertainty in dealing with offshore
exploration areas, for example.
Oil and gas come from decayed organic material buried in sea water, sand,
clay, silt, and lime deposits. Eventually, the organic material is transformed into
petroleum by high pressures and temperatures. Because gas is lighter than oil and
oil is lighter than water, petroleum tends to float and migrate through porous
rocks to higher levels. Ultimately, the migrating petroleum either seeps out at the
surface or accumulates below ground in structural and stratigraphic traps. Migration
ceases when the petroleum encounters an impervious caprock that seals the
underlying porous sandstone or limestone reservoirs. The world's largest oilfields
are located in domal or anticlinal structures. The search for petroleum is essentially
a quest for these and other structures.
Geophysical Surveying
Three basic tools are used by geophysicists to map subsurface structures ?
magnetometers, gravimeters, and seismographs. Each instrument provides an indirect
method of exploring subsurface rock without drilling. Geophysical surveys fall into
two broad categories: reconnaissance surveys to outline new areas and detailed
surveys to locate well sites on a given structure. Airborne magnetometers and
gravimeters can survey vast terrain and locate prospective petroleum areas at a
reasonable cost. Sedimentary rock ? the only rock that can contain oil or gas ?
is practically non-magnetic and less dense than basement (metamorphic and igneous)
rocks. Continuous measurement of variations in the earth's magnetic and
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gravitational forces from an airplane permits geophysicists to infer the thickness
of overlying sedimentary rock structures. The magnetic and gravity data are then
plotted on a map. Contours of the high values indicate basement structures and
anticlines, while contours of the low values indicate depressions or synclines.
The most accurate and detailed subsurface mapping prior to drilling is obtained
by taking seismograph readings along a grid pattern of shot lines. Weights are
dropped or explosive charges detonated at specified points on the surface along
each shot line to send shock waves into the earth. These shock waves are reflected
back to the surface and received by a battery of geophones, which relay the signal
to an instrument recording truck. The time between emission and reception of
the reflected signal rarely exceeds six seconds and is measured to one-thousandth
of a second. This travel-time data is recorded on magnetic tape in digital form
and processed by a computer. Once the velocities are calculated, the geophysicist
can estimate the depth of various reflecting rock layers and determine the presence
or lack of structures and traps. However, seismic surveying usually is limited to
the mapping of subsurface rock layers that are more than 50 feet thick. Costs
vary from $250 per linear mile offshore to $3,500 per mile onshore in swamps
in southern Louisiana.
Geological Surveys
Geological surveys involve the mapping and analysis of surface and subsurface
rock formations. The geologist examines rock samples taken from surface outcrops
and wellbores of wells previously drilled in an area. He may be able to trace
producing strata across a basin and examine their surface outcrops near the basin's
perimeter. Cores, or plug-shaped samples retrieved from the wellbore, and rock
cuttings from the drill bit may reveal traces of hydrocarbons or other information.
Electric logs taken from key wells after drilling provide a more complete picture
of the rock column. Evaluation of the rock samples and electric logs from all
wells in the adjacent area enables the geologist to extrapolate subsurface data into
adjacent undrilled areas. Changes in rock thickness, composition, and depth of strata
often suggest the presence of structures and traps suitable for drilling.
Correlation
Before drilling begins, all geophysical and geological data for the site are
compared by the exploration staff of the petroleum company. If the geological
cross-section of the prospect presented by the geologists is confirmed by the
geophysical data, authorization for drilling normally is granted. If the geological
and geophysical data conflict, the staff rechecks the data for errors and gaps. If
warranted by the data, exploratory drilling is authorized. The resulting subsurface
information may give leads that permit the discovery of new oil and gas pools.
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Petroleum Exploration:
Geophysical and Geological Methods
fillIffaltro Geophysical Surveys
Airborne
Gravity Data
Airborne
Magnetic Data
Geological Data
from Abandoned Well
Geological Data
from Abandoned Well
Silt, Sand,
and Clay
WATER
ETA OPIPHIC AND IGNEOUS
BASEMENT ROCKS Granite
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OIL AND GAS RESERVOIRS
Reservoir Characteristics
Oil and gas are formed from decayed organic matter that has been
buried and compacted under intense pressure and heat for long periods
of time. Since oil and gas are lighter than water, these hydrocarbons float
on the underground water table and are driven upward by water pressure
through porous rock until trapped, sometime in vast quantities, in a natural
reservoir. These reservoirs have three essential properties which permit
accumulation of oil and gas:
(1) A porous, permeable formation to contain the oil, gas,
and water.
(2) An overlying impervious cap rock, which acts as a seal.
(3) Traps to prevent the lateral movement of the oil and gas.
If the cap rock is dome shaped, forming its own sides, the
reservoir is called an anticline. If the cap rock is a tilted
layer, and the oil bearing rock beneath it is surrounded by
impermeable rock, the reservoir is called a stratigraphic trap.
Most of the world's largest oil and gas fields are characterized by anticlinal,
or dome-shaped, structures.
Recovery of Oil and Gas
Oil and gas accumulate in reservoirs in varying proportions. Recovery
of the dominant hydrocarbon (e.g., oil) usually involves some output of
the associated by-product (e.g., gas). When trapped, oil and gas are put
under pressure by the force of the underlying ground water. If the reservoir
is tapped by a well, oil and gas move through the porous reservoir rocks
and flow up the well bore as long as the natural reservoir pressure exceeds
that of the surrounding ground water. During the initial recovery period,
reservoir pressure often is sufficient to force the oil and gas to the surface
naturally.
With the gradual decline in reservoir pressure, some water will
eventually surface with the oil, reducing the amount of oil extracted.
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Reservoir pressure, along with the permeability and porosity of a producing
formation and the viscosity of the oil, govern the rate of oil recovery. The
maximum efficient rate of recovery (MER) is determined for each well and
pool individually to optimize overall recovery and profits. Eventually, pumps
must be used to lift oil to the surface and compressors installed to force
low-pressure gas into field gathering lines. In areas remote from gas
consuming markets, gas may be reinjected into the reservoir to repressure
the oil pool. Where pressure is adequate or equipment is lacking, the gas
may simply be flared.
Most petroleum reservoirs are characterized by three types of natural
production drive forces:
(1) water drive,
(2) gas cap drive, and
(3) solution gas (dissolved gas) drive
A combination of these drive forces may operate simultaneously in the
same reservoir, although one is usually dominant. These drive forces are
depicted graphically in the chart.
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Water Drive
Rising water table pushes oil up well
Gas Cap Drive
Gas under pressure pushes oil up well
Solution Gas Drive
Pressure of dissolved gas in oil
forces both up well
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EVALUATION OF NEW FIELD DISCOVERIES
New Discoveries of Oil
The discovery of oil in exploratory drilling does not always mean that a
commercially viable oilfield has been found. Indeed, before recent crude price
increases lowered the profitability threshold, only about one discovery in four was
commercial. In addition to the price of crude oil at the time of the discovery,
several other factors determine whether a new field will be considered worth
exploiting. The most important of these factors are: the size of the reservoir, the
thickness and characteristics of the formation, and the quality of the oil. Tentative
judgments must be made on the basis of information derived from the first well.
Misjudgments can result either in abandoning a potentially profitable field or in
wasteful drilling of additional expensive wells.
The flow rate of the exploratory well ? now often determined by a drill
stem test -- is an important early indicator of reservoir potential. Several discoveries
of 100,000 b/d or more have been reported in the past, such as Gach Saran in
Iran and at Spindletop, near Beaumont, Texas. A 50,000 b/d flow test suggests
a very large reservoir. Flow rates of between 500 b/d and 10,000 b/d are much
more common and usually indicate commercial finds. Flow rates well below 500
b/d may be commercial if the quality of the oil is high, the formations are shallow,
or the new field is located near existing fields with transportation and other
facilities.
Drill Stern Tests of Exploratory Wells
The best measure of a potential new reservoir's productive capacity is the
drill stem test. A cylindrical tool with ports and valves is attached to the drill
pipe and lowered through the drilling column to the bottom of the well. A rubber
packer at the top of the tool, resembling a tire around the drill pipe, expands
when the drill pipe rests on bottom, sealing off the section to be tested. When
the valves of the tool are opened, gas, oil, and water enter the drill pipe, usually
in that order. A diagram of a drill stem test follows.
If reservoir pressures are moderate, only a portion of the drill pipe is filled.
If the reservoir pressure is high, the drill pipe may fill to the surface, and spill
oil and water from flow lines into excavated earth pits or, in the case of offshore
drilling, into reserve storage tanks. Large gas flows usually are flared into the air
for safety reasons. Offshore platforms rarely can store more than 3,600 barrels
of fluid, and excess petroleum recoveries must be atomized and flared off with
special burners. After one to six hours, the test tool is raised to the surface.
Throughout the test period, recording devices at the bottom of the tool measure
the reservoir pressure.
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Confirmation Wells and Field Evaluation
Petroleum geologists' original estimates of subsurface conditions are confirmed,
rejected, or revised on the basis of the data obtained from the discovery well.
Analysis of geophysical logs of the wellbore, samples of fluid and rock, and prior
seismic data provide a more complete picture of subsurface conditions. To estimate
ultimate total oil and gas recovery from the reservoir, it is necessary to drill a
series of confirmation wells. The number of confirmation wells required for
complete evaluation of a field varies from several to a couple of dozen.
Plans for the initial confirmation wells are based on immediate needs for more
specific geological and reservoir data. The size and shape of the petroleum-bearing
strata and the position of the gas-oil-water contacts can be verified only by drilling.
In some wells, cores (plug-shaped rock samples) need to be taken from the
petroleum-bearing sections of the wellbore so that porosity, permeability, and oil
and water saturation can be determined by laboratory tests. Also, samples of oil
and gas must be taken from all prospective reservoirs for laboratory analysis.
Identification of the chemical and physical properties of the petroleum samples
often determines the choice of production and treatment methods and allows early
ordering of specialized equipment and services.
Locating the Confirmation Wells
The locations of the initial confirmation wellsites are based on the best
geological and seismic data available at the time. If, for example, the initial discovery
well is located on the crest of a typical elongated dome-shaped structure, two
rows of confirmation well are drilled -- one row along the crest and another
bisecting the first at a right angle. Drilling of evaluation wells usually proceeds
in all four directions at specified intervals until the pool edges are located. The
distance between evaluation wells normally is governed by the presumed size of
the structure and the thickness of the reservoirs. On very large structures with
thick reservoirs, confirmation wells may be sited from one to several miles apart.
On small structures with thin reservoirs, the wells are spaced closer and are called
stepouts if less than one mile apart. Evaluation drilling programs are kept flexible
so that one well's results can determine the next well's location.
As drilling proceeds down the flank of the structure, intermediate wells may
be required to locate precisely the gas-oil and oil-water contacts. These points are
critical in determining the limits of the producing layers and in the calculation
of oil or gas reserves. When reserves in commercial quantities have been proved,
development drilling for production is initiated while delineation drilling continues.
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Drill Stem Testing Tool for Reservoir Evaluation
Note: Details are not to scale and are exaggerated for clarity.
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Drilling
DRILLING A 15,000-FOOT WILDCAT
Preparing Location
After exploratory geophysical and geological studies indicate that a new area
is worth drilling, the oil company acquires leases over the prospect and hires a
drilling contractor. The best drill site is selected on the basis of subsurface geological
data and its surface location is staked by a surveyor. A bulldozer levels the drill
site and excavates pits for drilling fluids and sludge disposal. Usually a small cellar
is dug around the surveyor's flag for the future installation of blowout prevention
equipment.
Preparing Location
AMBulldozer
?A
Staked Location
Graded Surface
Mud Pit
Cellar
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Drilling Tools and Methods
The most widely used drilling technique in the Free World is rotary drilling,
although cable tools, turbodrills, and dynadrills also are used in certain areas and
for specific tasks. In rotary drilling the entire drill column and bit are rotated
from the surface by a chain-driven rotary table. High-quality steel drillpipe and
drill collars are required to withstand the torque, and durable bits are essential
to withstand high axial loads in deep drilling.
Cable tools are suitable only for very shallow wells, while turbodrills and
dynadrills are used mainly for "sidetracking" or the directional drilling of slanted
wells. Both turbodrills and dynadrills employ downhole motors powered by drilling
fluid that rotate the bit while the drillpipe remains stationary. In the USSR and
Eastern Europe, normal drilling is also done with turbodrills, so lower grades of
drillpipe can be used.
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Moving in and Rigging Up Rotary Tools
Rotary rigs can be moved by truck, helicopter, or barge. The mast, or derrick,
usually "jackknifes or "telescopes" so that it can be raised and lowered quickly.
Large masts break down into two or three sections when moving. The rig
substructure, powerplants, mud pumps, and pipe platforms also divide into compact
units that permit rapid movement and reassembly.
The substructure is centered over the newly staked location and cellar and
is aligned properly with the mud pits. The mast is reassembled on the ground
in a horizontal position while two legs are hinged to the derrick floor, on top
of the substructure. Once the powerplant and the drawworks are installed, the
mast can be raised to the vertical drilling position. The mud tanks and other
ancillary equipment are then moved into position and connected.
An important last-minute task is to check out the drawworks and drilling
line between the crown block and traveling block. This block and tackle
arrangement raises and lowers the swivel hook and drillpipe during drilling
operations. The brakedrum of the drawworks also must be inspected. If either
the brake or the cable fails, the entire drill string could be lost in the hole and
the traveling block could fall on the crew members working on the derrick floor.
Rigging Up Rotary Tools
Derrick
Draw Works
Substructure
Diesel
Engines
Cellar Mud Pit
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Spudding the Well
Once the rig is ready to drill, a large bit or "hole opener" is placed at the
lower end of the "Kelly joint." The Kelly is a square joint of pipe 45 feet long
which hangs from the swivel hook above the derrick floor, and it is raised and
lowered through the square slot of the rotary table. The Kelly is always the
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uppermost joint of the drill string. As the rotary table turns, the Kelly rotates
the entire drilling column and bit below.
A 24-inch diameter bit may be used to "spud" a 1 5,000-foot-deep well. Drilling
fluid or "mud" is pumped continuously down the Kelly and out through jets at
the bottom of the bit. This fluid flushes the rock cuttings up the hole to the
surface and also lubricates the drillpipe and the bit. Drilling fluid technology is
complex. Many additives and fluids are mixed in specific proportions to remove
cuttings and to coat the wellbore surface to prevent the sloughing of rock chips
and pebbles into the hole.
As the well deepens, the Kelly sinks down the hole with the bit. After 45 feet
of hole has been drilled, the Kelly is raised and the bit is removed. The first 30-foot
drill collar is added between the Kelly and the bit. The drill column is reassembled
and lowered back into the well and drilling is resumed.
Each drill collar may be 7 inches in diameter and weigh about 110 pounds
per foot. As drilling progresses more drill collars are added directly below the Kelly
to add weight and stiffness to the drill string. At a depth of about 500 feet, drilling
ceases and a large-diameter conductor pipe is sunk to case-off the hole from top
to bottom. Some 100 tons of rock cuttings from "spudding" a typical
24-inch-diameter 500-foot-deep hole is flushed to the surface by drilling fluid and
collected in the shale pits.
Setting Casing
Surface casing is set after all of the loose unconsolidated rock has been
penetrated. A conductor pipe 18-5/8 inches in diameter is hung from the surface
to about 10 to 15 feet from the well bottom.
The casing is set with cement, which is pumped down through the casing
ahead of a shoe chased by drilling mud. As the shoe, or plug, reaches bottom,
the cement is forced up the annulus between the pipe and the wellbore, where
it is allowed to cure and harden for several hours. Spudding and cementing 500 feet
of surface casing can require two full days.
Drilling to Total Depth
After the surface casing is cemented in place, the blowout preventer stack
is secured to the flange of the casing beneath the rig on the cellar floor.
Deep drilling is resumed using a smaller 17-1/2 inch bit which bores through
the cement and continues beyond. At a depth of about 1,000 feet, the full
complement of 20 to 30 drill collars will be in use. Faster penetration rates are
now possible because the driller can place more weight on the bit safely. In soft
rock, the well may be drilled almost as rapidly as the drill string can be lowered.
Penetration rates of 300 feet per hour have been achieved in sandstone. In
formations of dense hard rock like chert, the driller must watch a weight indicator
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Spudding the Well
Derrick
Derrick Floor
Mud
Pit
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Kelly
Rotary Table
Drill
Collar
4901i
Substructure
24 inch Bit
to maintain the maximum safe load on the bit. In such formations, penetration
rates of 3 to 6 feet per hour may be the maximum attained.
The interaction of weight on the bit, bit revolutions per minute, and drilling
fluid viscosity and composition determine drilling penetration rates in a given
formation. Selection of the proper type of bit as well as normal bit life also affect
drilling efficiency. When a bit wears out, the entire drill string must be raised
to the surface and uncoupled in sections. The stands of pipe are racked upright
in the derrick in "doubles" (two joints), "thribles" (three joints), or "fourbles"
(four joints), depending on the height of the mast. The old bit is replaced and
the drill string is reassembled and lowered back into the hole. The complete
out-and-in procedure is called "tripping for bit." A "round trip" from 10,000 feet
may take eight hours. New and better bits -- such as the tricone journal bearing
bits with tungsten carbide teeth for hard rock and diamond bits for soft rock --
permit more than 400 hours of continuous drilling between trips, compared with
16-20 hours five years ago.
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Setting Casing
Surface Casing
Drilling Mud
Shoe, or Plug
Undrilled Rock
Cement
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Drilling operations may continue to depths of 3,000-5,000 feet, when another
"anchor string" of 13-5/8-inch casing is cemented, and to depths of 8,000 to
10,000 feet, when an "intermediate string" of 9-5/8-inch casing is set. If oil is
discovered, an "oil string" of 7-inch casing may be run to a total depth of
12,000-15,000 feet. As each string of casing is cemented in place, further drilling
requires the use of a smaller bit.
Drilling Breaks
The driller always observes the Kelly's rate of descent through the slot of
the rotary table. Painted stripes or chalk tick marks enable him to determine normal
penetration rates. If the rate doubles, he assumes that the "drilling break" indicates
the penetration of a porous zone. After a few feet of penetration, all weight is
removed from the bit while drillinc, fluid continues to be circulated to flush the
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Drilling to Total Depth
Diesel EngInes-Power Plant
Mud Pump
"Mud In"
Crown Block DK\
Steel Cable
Mud Line
Removes Rock
Cuttings
Mud and Shale Pits
Traveling Block
Swlvel-Hook
Kelly Joint
Drawworks
Cernent.
Bit
Cellar
Derrick Floor
Substructure
Filow.Out Preventer Stack
Surface String
(18 s4 inch casing)
Anchor String
(13,1, inch casing)
Intermediate String
(9 54 inch casing)
011 String
(7 o,,ch casing)
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rock cuttings to the surface. The last few feet of rock cuttings are examined by
the geologist for the presence of oil, gas, and water saturation. If the samples
fluoresce under an ultra-violet light, the presence of hydrocarbons is established.
A drill stem test is then taken to make a more definitive evaluation of the reservoir
potential.
Lost Circulation
Experienced drillers also observe the drilling fluid level in the mud pits or
tanks. If the fluid level drops unexpectedly during a "drilling break," it indicates
that the drilling fluid is being lost and pumped into the porous strata just
penetrated. Countermeasures must be taken immediately to raise the viscosity of
the mud with additives. If the loss of circulation continues, bulkier materials such
as cottonseed hulls, walnut shells, sawdust, wood chips, or other sealing materials
may be pumped down the hole to close off the porous zone. Failure to curb
the loss of drilling fluid can result in stuck drill pipe and loss of the hole and
tools.
"Gas and Oil Kicks"
Sometimes a "drilling break" is encountered and the driller decides to bore
through the entire porous zone before stopping to test for potential hydrocarbons.
If oil and gas are present in the rock cuttings, it will not be known until the
returns from the well bottom arrive at the surface for the geologist to examine.
In the meantime, the driller watches the drilling fluid level in the mud tanks or
pits for a surge, or buildup. If gas or oil are present and they start to flow, the
fluid level will rise. If the fluid surges beyond a specified point, an alarm is set
off, indicating a gas or oil kick. The driller then closes the upper blowout preventers
and tries to kill the flow with heavier mud. If the well pressures build up to the
point that the well could blow out of control, the blind-ram preventer is activated
to shear the drillpipe and seal the well in.
Sidetracking and Directional Drilling
Occasionally tools or "junk" become lodged in the hole and, if they cannot
be recovered by "fishing" operations, the well must be abandoned. In those cases
where large sums of money have already been spent in drilling, salvaging a portion
of the upper hole is possible by "sidetracking." Special tools permit the driller
to deviate the wellbore and bypass the "junk" or obstruction. The hole is plugged
with cement above the "junk." Either a whipstock or an offset sub and turbodrill
are placed in the hole above the plug. The whipstock is a length of heavy pipe
with a window on one side and tapered walls that cause the bit to veer off and
drift laterally as it drills deeper. Turbodrills and dynadrills perform this task with
little effort, since downhole motors have a natural tendency to drift and there
is no torque on the drillpipe.
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Sidetracking and Directional Drilling
Off-Set Sub and Whipstock
Turbodrill
Cement
\Junk-in-hole ?
Broken drill pipe and bit
OFFSHORE
SIDETRACKING DIRECTIONAL
for straightening or
sidetracking a hole
for multi-hole drilling
from one location,
such as offshore
installations
ONSHORE
DIRECTIONAL
for reaching reserves
under towns and cities
663476 6-74
In other instances, it is desirable to sink many widely separated wells from
a single surface location such as an offshore production platform. "Directional
drilling" of slanted wells to widespread bottom hole targets is accomplished the
same way as in the "sidetracking" procedure.
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DRILLING DISASTERS
Introduction
The drilling of oil and gas wells involves unique hazards, yet the incidence
of disaster is surprisingly small. Of the 32,000 US wells drilled during 1973,
probably less than 1% incurred substantial damage from accidents such as blowouts,
fires, and oil spills.
Blowouts
The primary hazard is a blowout, which is defined as any uncontrolled flow
of oil or gas from a well. A blowout can lead to an extremely dangerous and
costly drilling disaster (Figure 1). Most blowouts occur during the penetration of
petroleum reservoirs with unexpectedly high pressure. Others arise from equipment
failures during maintenance operations at producing wells. Prior experience in an
area normally alerts the crews to the existence of high-pressure strata and results
in precautionary measures.
CPYRGH?
Figure 1. "WILD MARY," blowout at Oklahoma City, heralded the start of a new
era in conservation and better completion practices. Today, gushers are a rarity and
blowouts are dwindling in number.
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If a drill bit unexpectedly penetrates a high-pressure reservoir or gas pocket,
the driller may not be able to activate the blowout prevention system in time
to shut the well in (Figure 2). Although normal maintenance and repair operations
CPYRGHT
Figure 2. BLOWOUT PREVENTERS, properly designed and adequate for any kind of
modern rotary drilling, provide safety.
are performed periodically on all high-pressure producing wells, shut-off controls
and check valves sometimes malfunction as the critical zone is entered. In some
cases where the flow of oil or gas cannot be stemmed, pressures are so strong
that pipes, tools, and other equipment are ejected from the wellbore.
Drilling disasters resulting from oil and gas well blowouts fall into two
categories. The first and most dangerous type involves high flows of oil and gas
that eventually ignite and burn out of control. The second category involves
blowouts that do not catch fire and hence are easier to cope with.
Oil and Gas Well Fires
A small oil and gas leak can build up to a spray and eventually become a
gusher, a highly flammable mixture when vented into the atmosphere. Any spark
from the ejected tools or fine rock chips striking the derrick framework can touch
off an inferno. Sparks from electric switches and motors on the rig floor also
can ignite the fumes. Well fires take a heavy toll in lives and equipment. Drilling
rigs, production platforms, and other equipment can be destroyed or severely
damaged if the fire is not extinguished quickly (Figure 3). If the fire is
uncontrollable, the well and field also can be damaged. In World War II, the Ploesti
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oilfields in Romania were bombed extensively, and the resulting well fires burned
for several years before being extinguished by US specialists. During the interval,
the fires went underground, damaging the producing strata.
CPYRGHT
Figure 3. BLOWOUTS ON ROTARY WELLS occurred frequently in the early days.
This rig was almost demolished.
Most well fires are extinguished by a combination of methods employed
simultaneously. Firefighting specialists may spray the wellhead with foam retardants
and water hoses to cut off oxygen and lower temperatures. Explosives are
sometimes used to extinguish flames. Heavy drilling fluids are pumped into the
well under great pressure to "kill" the well. Often it is necessary to drill several
adjacent directional wells to intersect the burning well in order to inject enough
heavy mud to "kill" the well.
Non-Burning Blowouts
Some wells blow out of control without catching fire. Unfortunately,
non-combustible gases such as nitrogen can be just as destructive to men and
equipment as oil and gas blowouts. Any high-pressure flow of oil or gases can
carry fine sand and rock debris which is blasted loose from the wellbore surface.
This abrasive material can sandblast above ground equipment and destroy the
derrick after several days. Eventually, the legs are severed and the derrick collapses.
If toxic pure methane or hydrogen sulfide escapes, people and livestock may have
to be evacuated from the area, and local ravines and valleys may have to be publicly
identified as dangerous areas.
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Sometimes, after prolonged flows, the well site craters. Cratering is caused
by the ejection of large volumes of sand and gravel that creates a subsurface void
and surface subsidence (Figure 4). During the cratering process, other vents, cracks,
and fissures can develop at the surface around the periphery of the well site. Most
of the equipment settles into a large surface depression. Occasionally, the cratering
process may extinguish the flow of oil or gas completely.
CPYRGH
igure 4. MUD ENGINEERING and improved drilling techniques have nearly eliminated
is hazard. In this blowout, the gas well cratered and swallowed up the rig. Operator
as forced to drill i
In permafrost regions, the production of warm oil and gas streams at high
velocities through uninsulated pipe or the use of unchilled drilling fluids during
drilling operations are apt to cause ground thaw, pipe leaks, blowouts, fires, and
surface cratering accompanied by peripheral ground fissures and venting (Figure 5).
CPYRGHT
Figure 5. Dramatic night shot of Panarctic's burning gas well on King Christian Island
in the Canadian Arctic, showing both the 150-foot high flame from the well bore and
a number of fissures in the ground, with gas escaping and burning 1,000 feet or more
from the collapsed drilling rig.
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Non-burning blowouts are capped in much the same way as well fires. In
the absence of fire, it may be possible to emplace certain wellhead controls with
cranes.
Oilwell Spills and Oil Seeps
Another type of drilling disaster occurs if uncontrolled oilflows and seepage
cause damage to surrounding farmland, pollute the water, and upset the ecological
balance of an area. Leaks in pipes or storage tanks caused by corrosion once were
the source of frequent oil seepage. However, advances in technology and equipment
have all but eliminated this kind of leak.
US firms have drilled more than 17,000 offshore wells since World War II,
and fewer than 30 wells have experienced oil spills. Only four wells spilled more
than 5,000 barrels of oil in offshore waters. However, large natural seepages are
commonplace -- for example, in the Los Angeles Basin. Numerous seeps on the
ocean floor can be observed from the air along the California coast between Santa
Barbara and Goleta. Greater quantities of oil have escaped from these natural seeps
than from the famous Santa Barbara oil spill of 1969. Early oil finders were
attracted to this area because of these natural seeps. Subsequent development
proved that this basin contained more oil per cubic foot of sediment than any
other basin in the world. Ironically, the large number of oil reservoirs and seeps
in the Los Angeles Basin owe their existence to the same natural phenomenon ?
complex geological fault systems which not only trap oil but also allow it to escape.
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THE COST OF OIL DRILLING AND PRODUCING EQUIPMENT
Some readers have asked about the cost of drilling an oil or gas well. There
is no simple answer to this question. A shallow well drilled in, say, Pennsylvania
obviously costs less than a deep well in the Amazon jungles or the North Sea.
The cost of equipment, while only one factor in total drilling and completion
costs, is fairly standard throughout the oil world and gives some idea of basic
costs. These costs have soared in recent months as demand outraced supply.
Typical Deep Well Costs
Total costs vary between exploration and development wells and according
to depth, well bore, testing, and logging expense. An example of costs for an
11,400-foot exploratory well drilled in the United States follows:
Key Equipment Items and Current Prices
Drilling Rigs and Platforms
Rigs*
Complete with 2 drill strings for 7,000-foot depth: $1.0 million;
Complete with 2 drill strings for 10,000-foot depth: $1.5 million;
Complete with 2 drill strings for 15,000-foot depth: $2.5 million;
Complete with 2 drill strings for 30,000-foot depth: $4.0 million.
Rigs for installation on large offshore drilling platforms carry three complete drill strings which can
add $400,000 to the cost of a complete rig.
Offshore Exploratory Drilling Platforms
Costs range from $10 million apiece for 250-foot water depths, up to $45
million for 1,000-foot waters. About 114 platforms are on order worldwide, 22
of which are Norwegian Aker H-3 semisubmersibles specifically designed for North
Sea service where 90-mile winds and 60-foot waves are prevalent. The Norwegians
are emerging as the strongest competitors to US platform designers.
Offshore Development Drilling Platforms
Costs range from $2 million to $80 million, depending on type, the number
of wells contained per unit, and water depths.
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Drill Pipe and Drill Collars
These items are sold in 30-foot lengths; price varies with the quality of steel
and weight and diameter of the pipe.
5-1/2" diameter grade E drill pipe: $11-$12 per foot
3-1/2" diameter grade E drill pipe: $8-$9 per foot
8" diameter drill collars sold in 30-foot lengths at 150 lb/ft: $1,500
4-3/4" diameter drill collars sold in 30-foot lengths at 50 lb/ft: $500
Rock Bits
Standard 8-5/8" diameter tri-cone (20-hour life): $300
Journal bearing 8-5/8" diameter tri-cone (400-hour life): $2,000
Diamond head 8-5/8" diameter (400-hour life): $4,000
Blow-Out Preventers (3 per rig in service)
10" internal diameter 5,000 PSI rated spherical type: $16,000
10" internal diameter 10,000 PSI rated spherical type: $25,000
10" internal diameter 5,000 PSI rated dual ram type: $20,000
10" internal diameter 10,000 PSI rated dual ram type: $40,000
?dwell Casing
Casing is sold in 30-foot lengths, and prices vary according to quality of steel
and diameter.
Standard 7" 20 lb/ft K-55 casing: $3.90 per foot
Standard 7" 17 lb/ft K-55 casing: $3.45 per foot
Standard 5-1/2" 14 lb/ft K-55 casing: $2.90 per foot
Oilwell Tubing
Tubing is sold in 30-foot lengths and prices vary slightly according to quality
of steel and weight because only small diameters are used.
2-7/8" 6.4 lb/ft tubing: $2.50 per foot
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Well Heads (or Christmas Trees)
Unit costs vary and depend on size of fixture required, number of strings
of tubing, and zones to be produced.
$5,000 to $15,000 each
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Drill Pipe
Drilling Tools
Approved For Release 2001/03
Drill Pipe
Surplus Drill
Pipe and
Tool Rack
Drilling Rig
Derrick
1,441,411.t.-10, 14411010,101
01
,--Substructure
Onshore Drilling
Rig
roved
Re
Blow-Out Preventers (stack of 3)
During Drilling; Well Head when
Producing Well is Completed
Surface Casing
Production Casing
Production Tubing
091
Offshore Exploratory Drilling Platforms
Well Head or Christmas Tree
Offshore Production
Platform
Spherical Blow-Out Preventer
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Production
PRODUCTION OF NATURAL GAS LIQUIDS
Confusion in Petroleum Statistics
Some measures of petroleum production and reserves refer only to
crude oil; others include natural gas liquids as well, giving rise to apparently
conflicting data. For example, US crude oil production amounted to almost
9.2 million b/d in 1973. Inclusion of natural gas liquids ? butane, propane,
and ethane recovered in liquid form ? raises the figure to 10.8 million
b/d. Similarly, proved US oil reserves amount to 42 billion rather than
35 billion barrels if natural gas liquids are included.
What Are Natural Gas Liquids?
Natural gas and crude oil reservoirs often lie several thousand feet
below the earth's surface. Reservoir temperatures increase at the rate of
about 2? Fahrenheit with each 100 feet of depth and reservoir pressures
at the rate of 1/2 pound per square inch per foot. Below 10,000 feet,
some light hydrocarbons ? butane, propane, and ethane ? often accumulate
in the form of natural gas liquids. The high temperatures separate them
from crude oil and the high pressures keep them from becoming gas.
How Are They Produced?
When these reservoirs are tapped by a well, the flow of oil and gas
to the surface may lower the reservoir pressure enough to permit the natural
gas liquids to vaporize. When these vapors are collected at the well head,
they begin to liquefy at the cooler temperatures in the collection pipes.
Liquefaction is completed by compressors. Whether in their liquid or gaseous
state, the natural gas liquids are referred to as "condensate" if originating
from gas wells and as "associated" or "casinghead" gas if originating from
oil wells. They are processed at field gas plants to produce the liquid
petroleum gases (LPG) ? butane, propane, and ethane ? and a residue of
the common natural gas, methane. LPG also is recovered in large volumes
as a by-product of oil refining operations.
How Are They Used?
The United States is the largest producer of natural gas liquids; other
countries such as Canada, Venezuela, Indonesia, and several Arab producing
states also recover some of these liquids along with crude oil. Elsewhere
in the world, the recovery of natural gas liquids at oil wells often is not
feasible. In the absence of nearby markets, the liquids are sometimes mixed
with crude oil or flared. If mixed with crude oil, the liquefied gases can
render the oil unstable, making it difficult to transport, pump, and store.
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In natural gas production, all liquids ? whether recovered for use or not --
must be stripped from the gas at the surface prior to being piped. Failure
to do so may result in the accumulation of volatile liquids in the low sections
of the line, reduction of pipeline operating pressure, destruction of
turbo-compressor blades, and irregular combustion as well as possible flash
explosions in burners.
CPYRGH
After processing, the natural gas liquids and the residue gas (methane)
have a variety of uses. Methane, plus some ethane, is sold to natural gas
pipeline companies for distribution and resale. Methane also may be
re-injected to maintain pressure in the reservoir. Casinghead gas (natural
gasoline) is blended with automobile gasoline refined from crude oil. Much
of the butane and propane is distributed from large central storage tanks
by tank trucks and dispensed locally in bottles or cylinders as a
clean-burning fuel for rural or suburban homes. Butane and propane also
are used as feedstocks for petrochemical production. Butane is used as a
blending ingredient for winter-grade motor fuels because it ensures quick
starting and hastens engine warmup.
The processing of natural gas liquids is illustrated in the accompanying
chart.
GAS WELL
Natural Gas Vapors
Start to Liquefy
GAS PLANT
(See Below)
Propane
Storage Tank
To Gas Pipeline
Alp
To Oil Pipeline
Liquids Pass Out of Sol4on ?and Va prize
i67.0.^Zt "4124 4-1.00,440,64
GAS PLANT
Butane and Propane to
LPG Storage Tanks
-
'dual -Methane Gas to Pipeline
ompany or Gas Injector Well
4
:and Natural Gasoline o
_ - _
il Pipeline and Refiner
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SECONDARY AND TERTIARY RECOVERY OF CRUDE OIL
Secondary Recovery
There is a time in the life of an oilfield when the natural pressure
of the reservoir is no longer adequate to force the oil out of the rock
pores into the well bore. This depletion of the natural drive mechanism
marks the end of the primary recovery phase. Prior to the 1950s, the
operator of such a deposit had little choice but to abandon the field, long
before the greater part of the oil had been recovered from the reservoir.
It was not unusual for as much as 80% of the oil to be left in the ground.
This obviously wasteful practice led to the development of repressuring
methods to increase ultimate recovery.
Forcing oil out of reservoirs by means of a repressuring technique is
termed secondary recovery. The simplest method is to inject water or gas
to rejuvenate the original natural drive mechanism. Both of these
displacement agents are cheaper than the oil being recovered. When water
is used, the secondary recovery method is called "water drive" or
Itwaterflooding." If gas is used, the process is called "gas drive" or
"gasflooding." Water drive is. the most often used secondary technique.
Water, gas, or both can be injected through a pattern of injection wells
to drive the oil into nearby producing wells. An example of each process
is illustrated below:
Waterflooding
The results of waterflooding may not become apparent until the
amount of water injected into the field equals the amount of oil previously
extracted. This may take as long as 1 or 2 years. Water forced into the
producing rock layer must be free of suspended particles or chemical
impurities that could block the pores in the reservoir. Any permeability
loss would reduce the flow of oil to the well bore. The water must be
injected beneath and at the edges of the oil pool to drive the oil upward
and sideways into the producing well.
Gasflooding
Gas injection is usually through wells located at the top of the trap
to force the oil downward and sideways into the producing well. Byproduct
gas, which surfaces along with the oil, usually is recycled back into the
producing strata to avoid the waste of flaring, if markets are not available.
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Secondary Recovery Methods
"Waterflooding"
INJECTOR WELL
PRODUCING WELL
INJECTOR WELL
563155 4-74
UNCLASSI Fl ED
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Pressure Maintenance
Shortly after water and gas repressuring techniques were developed,
it was recognized that application of these methods early in the producing
life of oilfields could avoid a reduction in natural reservoir pressures.
Prolonged high rates of production and higher ultimate oil recoveries were
thereby possible. When secondary recovery methods are applied early in
the production stage, the technique is called pressure maintenance. At
present, about 30% of the oil in place is recovered from most reservoirs
by the use of both primary and secondary recovery methods. In the United
States, secondary recovery projects add $0.35 to $1.50 to the cost of each
barrel of oil produced by these methods. Approximately 33%, or some
3 million b/d of the oil produced in the United States, comes from
secondary recovery and pressure maintenance operations.
Tertiary Recovery
Ultimate recovery rates of up to 60% of the oil in reservoirs are now
judged technically feasible. Recently developed tertiary recovery methods,
which involve complex chemical and thermal treatments of oil-producing
rocks, greatly improve the efficiency of conventional water and gasflooding.
Although such methods can double ultimate oil recoveries, they are costly.
In addition to the secondary recovery costs of $0.35 to $1.50 per barrel,
the use of chemical solvents and thermal recovery techniques could raise
operating costs by at least another $0.75 to $1.50 per barrel or a total
of $1.10-$3.00. Most tertiary recovery techniques are not fully proved and
applications have been confined to pilot projects.
Chemical Solvents
Special chemicals are injected ahead of water to help flush the oil
out of the reservoir rock and sweep it through the pores to the producing
well. At present, these chemical solvents are manufactured in small
quantities and are very expensive. If demand rises and solvent production
is expanded, prices should decline. At current price levels, the profitable
use of chemical solvents may depend on the ability of the operator to
recover the solvent along with the oil.
Thermal Recovery
The extraction of heavy crude oil from reservoirs with very low
ultimate recovery rates has been improved by the development of thermal
techniques. When thick oil is heated by injected steam, hot water, or
underground burning, the oil becomes thinner and begins to flow. In the
burning process, which is called in-situ combustion, air injected to assist
the underground combustion also becomes a displacing force.
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CPYRGH
Tertiary Recovery Methods
IN SITU
COMBUSTION
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CPYRGHT
FUTURE SUBSEA OILVVELL PRODUCTION METHODS
Introduction
The international oil industry has discovered about 176 billion barrels of crude
oil and 248 trillion cubic feet of gas on the world's continental shelves since the
first well was drilled out of sight of land 26 years ago. About 40 billion barrels
of this offshore oil already has been produced. Offshore production exceeded
10 million b/d in late 1973, accounting for almost 18% of world output. Vast
areas of the world's seabed, continental slopes, and shelves remain undrilled; and
the offshore boom is just beginning. Most estimates indicate that offshore
production will account for as much as half of total world output in 1985. Up
to this point, the lifting of offshore oil has been through the use of steel platforms
resting on the seabed. Future production methods, as described in this article, will
entail the use of underwater wellheads.
Areas of Offshore Exploration and Production Activity
Present Status of Offshore Technology
The future for offshore oil production lies in ever deeper waters, where oil
producers are certain new discoveries will be made. The improvement of existing
platform technology will allow producers to work in waters beyond the 600-foot
depth line ? normally the current limit of offshore production. Builders can readily
employ many existing construction methods and designs to make larger and stronger
platforms. Platforms have already been designed for operating wells in 700 feet
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of water off Santa Barbara, California. As improvements in equipment continue,
most operators would probably be willing to drill in up to 1,000 feet of water
where prospects are good. Shell has even begun drilling a well in about 2,150
feet of water 50 miles off the coast of Gabon. However, the techniques for
completing and operating such wells from the surface remain to be developed.
Present methods of completing offshore wells in, say, 600 feet of water have
focused on multiple platform complexes for purposes of convenience and safety.
The main platform contains the wells, crew quarters, offices, and heliport. A second
supports all production-handling equipment, such as pumps and flow lines. In some
cases, a small third platform will support equipment requiring burners or heaters
for oil and gas processing and treating operations (Figure 1). As the water depth
increases from a few feet to 600 feet, costs mount exponentially. In an effort
to limit costs, producers are turning to one all-purpose platform (Figure 2). Such
a multideck platform must be suitably compartmented to support all necessary
functions and still provide the safety of separate platforms.
Recently, a few companies have begun to develop new techniques and
equipment that would transfer most of the functions of the platforms to undersea
installations and would permit operations at depths beyond the technical limits
of platform technology.
The Subsea Alternative
At least four companies, or groups, have been experimenting with seafloor
oilwell completion techniques. The systems provide for manned "hands-on"
operations. Operators will descend to the enclosed "dry" wellhead in diving bells
and work in a "shirt sleeve" atmosphere. In contrast, "wet" wellheads conceivably
will be employed in shallow installations and would be serviced manually by divers.
? Seal's Atmosphere System (SAS), developed by Mobil and North
American Rockwell, uses "dry" subsea wellheads and a diving bell.
Members of the Seal group have also developed a companion system
for remote offshore sites (Figures 3 and 4).
? Lockheed, with Shell's help, has devised an optional "wet" or "dry"
split hemisphere wellhead (Figure 5).
? The Humble Exxon Subsea Production System (SPS) combines
optional manned and unmanned operations. A track-mounted
remotely controlled robot performs the unmanned maintenance
tasks. One platform may be used to provide centralized control of
several seafloor well clusters. Well clusters could be sealed in by
plexiglass covers to trap seepage or spills (Figures 6, 7, and 8).
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? Transworld -- a subsidiary of the Kerr-McGee Corporation ? recently
unveiled a "Total Concept" system for remote offshore development
that uses a "dry" wellhead and a complex wellhead chamber and
diving bell (Figures 9 and 10).
All of the subsea systems will require one platform or mooring buoy for each
field developed.
Advantages of Subsea Systems
Subsea systems will become essential in the event a large shallow offshore
petroleum deposit is discovered. As a rule, the lateral drift of slant wells
directionally drilled from a platform is limited by the vertical well depth. Full
development from one or two conventional platforms would be technically
impossible, while the cost of additional platforms would be prohibitive. Subsea
completions might also solve the problem of "unsightly production platforms" near
resort areas and picturesque shorelines like Santa Barbara, California. Subsea
completions also could minimize navigational problems in important shipping lanes.
Other variations of subsea well completion techniques could be used in the
development of Arctic offshore petroleum deposits. Where pack ice and ice flows
scrape or scour the seafloor, raised wellheads would be destroyed. Therefore, some
wellheads may have to be recessed beneath the seafloor (Figure 11).
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Transportation and Storage
OIL AND GAS PIPELINE CONSTRUCTION
Introduction
Pipelines are an essential complement to the development of new petroleum
deposits. They handle all overland movements of natural gas, most crude oil
shipments to refineries and deepwater oil export terminals, and distribution of
petroleum products from large refining complexes to major consuming centers.
Initially developed in the late 19th century as an economical alternative to railroads,
pipelines today provide the most efficient means of transport, rivaled only by
long-distance shipping.
Pipeline Planning
The planning of large-diameter pipelines must take into account several factors,
including long-term requirements for shipments of crude oil or natural gas.
? Detailed studies of oil and gas reserves are required to determine
the availability of supply over a period of years. Reserve life must
be adequate to amortize the pipeline project and to guarantee a
reasonable return on capital investment.
? Physical and chemical characteristics of the oil or gas must be
examined. Gravity, viscosity, and paraffin content affect oil pumping
requirements and pipeline costs. Natural gas liquids, hydrates, and
corrosive elements such as hydrogen sulfide and carbon dioxide have
to be removed prior to shipment through a gas pipeline.
? Additional points of supply and offtake along the proposed pipeline
must be considered to determine the best route and line capacity.
Where feasible, the route selected will be the shortest distance to
the receiving terminal to minimize the high cost of pipeline
construction; about 80% of the investment is in the buried pipe.
Standard pipeline construction costs in the United States in 1973
ranged from $20,000 per mile for a 4-inch line to about $260,000
per mile for a 42-inch line.
? Maps are scrutinized for general terrain conditions affecting
accessibility, such as swamps, lakes, rivers, mountains, and cities.
Preliminary field reconnaissance by airplane and jeep is followed
by a detailed land survey. Surface elevations along the route are
studied to determine the location and number of pumping stations
and the hydraulic gradient.
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? Right-of-way easements have to be obtained from all property
owners along the route. Easement widths vary but are typically 50-
to 60-foot strips.
Pipeline Diameter
Economies of scale in construction and
operating costs can be realized with the use of
"big inch" pipelines. Large-diameter pipelines are
defined as those with outside diameters of 20
inches or more. The tabulation shows that a
tripling in the diameter of small lines can result
in an approximate fifteen- to twenty-fold
increase in daily throughput.
Pipeline Construction
Pipelines are constructed in 100- to
150-mile sections, each with its own
construction crew (called the "spread"). The
length of the route will determine the number
Pipeline
Diameter
(Inches)
Average Pipeline
Throughput
(Thousand b/d)
8
17
12
38
16
100
20
140
24
240
28
340
32
500
36
750
42
1,000
48
2,000
of contractors required to provide enough spreads of men and equipment for
construction of the entire pipeline within a given time period. In good pipeline
country, each crew should complete 1 to 3 miles of line per day, and the distance
between the front and the back of the crew usually will not exceed 3 miles.
Clearing the Right-of-Way
After company engineers stake the pipeline route, gaps are cut in fences to
provide access for the right-of-way gang that clears the route of obstructions.
Ravines and draws are filled in, and small humps and hills are leveled with bulldozers
and graders. Frequently a road is constructed along the ditch line to permit passage
of other heavy equipment.
Ditching
The next piece of equipment to follow along the right-of-way is the ditching
machine. The width of the ditch is usually twice the pipe diameter, and the depth
must permit 2 to 3 feet of cover with the pipe in the ground. Where rock is
encountered, the ditch must be drilled and blasted. The ditch sometimes is cut
through a roadway; embankments under railroads and pavement usually are bored
with augers and then cased off.
Pipe Stringing
All linepipe is first delivered to centrally located storage yards where it may
be coated and wrapped with anti-corrosive materials (Figures la and lb). Stringing
42
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FOR OFFICIAL USE ONLY
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of the pipeline along the ditch is done by trucks pulling special pole-type trailers.
Pipe stringing is carried out along the right-of-way in both directions from the
storage yard, to minimize hauling. The pipe is offloaded from the trailers with
a tractor-mounted sideboom hoist (Figure 2).
Pipe Bending
It is necessary to cold-bend certain sections of pipe so that the finished line
will conform to the slope of the ground as nearly as possible. The bends must
accurately reflect the angle required at each point along the route (Figure 3).
Pipe Alignment, Joining, and Welding
The lineup crew then aligns the various pipe sections and welds them together
with a temporary stringer bead (Figures 4a, 4b, and 4c). This crew usually leaves
behind a continuous line supported by skids alongside the ditch (Figure 4d). The
welding crew follows, completing the welding of each joint by applying two or
more continuous beads. Submerged arc butt welding is the most vital craft of all
in the construction process (Figure 4e). If a weld fails to pass X-ray inspection,
or should the inspector believe any weld to be faulty, it must be cut out and
replaced.
A tie-in crew completes the welding, joining all sections to make a continuous
welded tube. All remaining exposed pipe joints and valves, as well as damaged
pipe areas that rested on skids, are coated and wrapped after welding is completed.
Pipe Laying and Burial
The lowering-in-crew places the finished pipeline into the ditch, usually with
a sideboom tractor pipelayer (Figure 5). The pipe is lowered into the trench by
a series of slack-loops. The distance between loops varies with the pipe size, the
terrain, temperature, and other factors that might damage the pipe.
As the pipe is laid in the trench, certain portions are tied in position with
earth until the backfilling crew arrives to completely bury the line. Backfilling
usually is done with special tractors; bulldozers or draglines also can be used. Before
the final crown of dirt is placed on the ditch, one tread of a heavy tractor is
run over the fill to compact it. Burial of the pipeline is complete when this surface
fill is leveled and smoothed.
Cleanup
The last crew in the spread removes all pipe skids, waste, and refuse from
the right-of-way. This cleanup crew also levels the terrain, erects diversion dikes,
drainage ditches, or levees where needed, and replaces previously cut fences.
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Testing
Pipeline testing is done hydraulically. Water from a convenient source is
pumped into the line with portable units at one end. A specially designed scraper
is inserted ahead of the water and pumped through the line to remove all dirt,
scale, and refuse. The pipeline then is given a 24-hour pressure test for leaks. After
the automatic controls and monitoring devices are installed and checked out, the
pipeline is completed.
Offshore Pipelines
Construction of offshore pipelines is considerably more complex than onshore
operations. Tractors are replaced with floating, self-contained barges that perform
all of the construction operations at one point (Figure 6). Anchoring and securing
the line to the sea bottom is performed with draglines. Cement coatings and
concrete weights may be used to hold the pipe to the seafloor. Weather and water
conditions frequently halt construction for many days at a time.
44
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FICI USE
Approved For Release 2001/03/04: CIA-RDP79S01091A000400010001-6
For Official Use Only
Oil and Gas Pipeline Construction
Figure la
Pipe Yard at a Port
Figure 2
Pipe Stringing and Offloading along
Right-of-Way
563572 6-74
Figure lb
Pipe Yard Inland
Figure 3
Pipe Bending Machine
Figure 4b
Pipe Alignment and Joining
Figure 4e
Final Pipeline Arc Welding Operations
Figure 4c
Tack Welding of Pipe
Figure 5
Pipeline Being Laid
Approved For Release 2001/03/04: CIA-RDP79S01091A000400010001-6
Figure 4a
Pipe Alignment, Joining, and Welding
Operations
Figure 4d
Wrapped and Coated Pipeline
Figure 6
Offshore Pipeline Construction from
a Barge
For Official Use Only
Approved For Release 2001F/RdIFF611NRRETO:111691A000400010001-6
PETROLEUM STORAGE INSTALLATIONS
Introduction
Petroleum production, transportation, processing, and marketing require large
amounts of storage capacity to avoid interruptions in supply. Crude oil, natural
gas, and petroleum products can be stored (1) above the ground in wood or steel
tanks; (2) below the ground in depleted petroleum reservoirs, abandoned mines,
or excavated rock or salt caverns; and (3) offshore in concrete or steel containers.
The location and purpose of the storage unit determine the type of installation
and the choice of construction materials.
Above-Ground Installations
Oil fields, pipeline facilities, tanker terminals, and refineries require
above-ground storage. Storage sites vary in size from 1,500-barrel wood and steel
tanks at producing wells (Figure 1) to large tanks (Figure 2), tank batteries
(Figure 3), and tank farms (Figure 4). The farms may include as many as 200
tanks ? each with a capacity of nearly 1 million barrels. Such tank farms require
20 to 30 acres of land for each million barrels of storage capacity. The floor area
of one 800,000-barrel tank is roughly equivalent to the area of a football field.
Storage sites for product distribution systems are smaller and are located near
railroad spurs, highways, ports and waterways, or pipelines. Crude oil and product
tanks are normally cylindrical, while tanks for pressurized storage of liquefied
petroleum gases such as butane and propane are spherical (Figure 5).
Underground Installations
Natural gas, liquefied petroleum gas, and petroleum products are sometimes
stored underground. Crude oil ? although not yet stored underground in the United
States ? has been successfully kept in abandoned mines in South Africa since 1969.
In Europe, more than 100 million barrels of underground crude storage capacity
is in use, under construction, or planned. Natural gas is kept in many depleted
oil reservoirs throughout the world.
The potential for additional underground storage is great. The United States
has more than 200 large salt domes along the Texas-Louisiana coast that could
be used for this purpose (Figure 6). The total potential storage capacity of these
domes is estimated at about 650 million barrels. Thick saltbeds can also be used
for storage. Cavities can be created in salt masses at moderate cost by circulating
water down through the tubing of a single well and forcing the brine solution
46
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Approved For ReleasiQ60,101044 aik-PPEIPY9S01091A000400010001-6
up through the casing (Figure 7, a, b, and c). More costly storage in rock caverns
can be obtained through conventional room and pillar mining (Figure 8). Such
manmade caverns are now being used for propane storage in the eastern United
States. Abandoned mines and depleted oil and gas fields (Figure 9) provide other
storage options.
The operation of all underground storage installations, whether in mines,
caverns, or depleted oil reservoirs, is based on the displacement of water and brine
by oil, gas, or refined products. The storage area is filled by pumping petroleum
down through the well casing and forcing water or brine to the surface through
the tubing. By reversing the process, the stored petroleum is brought back to the
surface when it is needed. In salt caverns, opening of the cavity can proceed
simultaneously with storage operations. The storage area gradually expands if fresh
water is used instead of a saturated brine solution. Brine solutions may be recycled
from a surge tank at the surface to reduce fresh water requirements and eliminate
saltwater disposal problems, once the desired cavern size is obtained. Costs for
salt dome oil storage are estimated at $0.75-$1.00 per barrel of storage capacity,
compared with $5.00-$7.00 for steel tank storage. The latter range does not include
the cost of pilings sometimes needed beneath large tanks.
Offshore Installations
Growing offshore oil production in remote deepwater locations has led to
the use of steel and concrete underwater storage structures. Submerged steel
bell-shaped tanks (Figure 10, a and b), floating steel buoys (Figure 11), and
"Condeep" concrete silo-type production platforms (Figure 12, a and b) are a few
of the more novel departures from conventional platforms and tanks. Concrete
silo structures cost about half as much as steel production platforms and provide
storage capacity at no extra cost.
"Condeep" platforms may dominate development of the North Sea, where
water depths range from 200 to 600 feet and 90-foot waves have been reported.
Phillips, Mobil, and Shell-Esso have ordered four "Condeep" platforms measuring
600 feet to 738 feet high, with base diameters of 330 feet. Oil storage capacity
amounts to 900,000 to 1,000,000 barrels for each platform. Phillips recently
installed the first "Condeep" platform at the Ekofisk field in 230 feet of water,
at a cost of almost $30 million. This compares with a cost of about $200 million
for a steel platform with much less storage capacity.
46
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Above-Ground Storage
Figure 1. Small Oilfield Storage Tank
Figure 2. Large Oil Terminal Storage Tank
Approvd For Release 2001/03/04 : C1ik-RDP79S01091A0004 0010001.6
Figure 3. Small-Tank Battery at Trinidad
Approved For Release 2001/03/04: CIA-RDP79S01091A000400010001-6
Large-Tank Farm at Kharg Island, Iran
Figure 5.
Pressurized Spherical Gas Storage Tank
Figure 7a. Salt Dome Storage Cavern
BRINE
SURGE
TANK
DISPLACED OIL TO
PIPELINE, REFINERY
OR MARKET
Figure 7b. Typical Salt Dome
SURFACE
CAPROCK
TOP OF
SALT
SALT
DOME
TYPICAL
STORAGE
WELLS
SALT BED
. . -
pprovecl For Release 20
, _ . ,
1/03/
1/03/
(1)
(2)
(3)
TOP OF CAPROCK
LEGEND
WELL CAPACITIES:
IN 10 MILLION BARRELS
12) 7.5 MILLION BARRELS
MI 5 MILLION BARRELS
S.0.1091A00,240010001-
Toed Depth Dimmer
Ill 4500 Ft.
RI 4000 Ft.
293 Ft.
223 Ft.
Figure 8. Storage in Excavated Rock Caverns
and Abandoned Mines
BRINE
SURGE
TANK
PUMP VALVE
r111.011001.1.11,
OIL
OR
GAS
DISPLACED GAS
OR OIL TO PIPELINE,
REFINERY OR MARKET
VALVE
CASING
TUBING
Figure 9. Gas Storage in Depleted Oil and Gas Fields
WATER
INJECTION
WELL
7Erl PUMP
GAS WELLS
lp. i. I,
.11-,1A-4111,g1iI
Underwater storage tank topped by production platform. When floating, the Khazzan Tank
No. 2 is higher than a 20-story building with a base of almost 300 feet. For an impression of size,
note the person circled on the production platform floor. Each tank stores 500,000 barrels of oil
and costs almost $9 million.
Figure 10b.
e 2001/03/04: CIA-RDP79S01091A000400010001-6
Ap roved For R a e 2001/
The largest underwater oil storage complex in the world is in Fateh field. Persian Gulf, off the
Figure 11. Floating Buoy, North Sea
This floating buoy tank will store 300,000 barrels of crude
001-6
First "Condeep" under construction near Stravanger, Norway for Phillips Petroleum
Company's Ekofisk field.
Figure 12b.
In the heart of Ekofisk Center is the world's largest offshore oil storage tank, fore-
Approved For Release 20099it3OW:14MCMPAM011091A000400010001-6
DEEPWATER OIL TERMINALS
Introduction
The advent of the very large crude carrier (VLCC) has made most of the
world's oil ports obsolete. Supertankers ranging from 175,000 to 500,000
deadweight tons (DWT) now constitute about 45% of world tanker capacity. Few
ports can accommodate these tankers, which have drafts ranging from 55 to 90 feet.
Only about 30 ports capable of unloading the giant ships are presently in use or are
under construction. Vast tonnages are delivered to deepwater terminals such as
Rotterdam, Bantry Bay (in Ireland), Genoa, and Yokohama?all of which are key
refining and distribution points in the world oil trade. US ports cannot handle ships
of more than 100,000 DWT unless part of their cargo is offloaded into smaller ships
in deep water.
Supertankers are expected to account for nearly 60% of the world oil fleet
capacity by the end of 1978 because they offer savings in transport costs per barrel
of up to 50%, compared with small ships. The need to develop deepwater oil
terminals will increase accordingly.
Planning a Deepwater Terminal
The materials and equipment needed to build deepwater terminals are fairly
easy to obtain, and manpower and contractors capable of doing the job are available
in most cases. The biggest obstacles are political, economic, and environmental issues
such as long-range oil import policy, jurisdictional disputes between different units
of government, conflicting commercial interests, and the threat of pollution.
Comprehensive planning is necessary to assure the successful operation of
deepwater terminals. Preliminary studies must consider the precise location and type
of facility best suited to serve a refining complex. These studies must take into
account the arrival patterns of ships, types and sizes of cargoes, storage tank
requirements for different grades of oil, weather and tide conditions, and shipping
channels, as well as the environmental impact.
Siting a Terminal
The first planning problem is fitting the terminal's capabilities to the needs of
the refineries being served. Allowance should be made for future expansion of
refining operations, if appropriate. Data must be gathered on wind, wave heights,
currents, tidal movements, water depths, sea-bottom topography, and soil condi-
tions. Provision must be made for tanker approach lanes plus maneuvering and
anchoring areas. Land must be available for storage tanks. The area should be able to
provide tankers with fresh water, stores, and fuel oil bunkers.
47
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Types of Terminals
Deepwater oil ports can be developed in several ways.
Dredging Existing Channels
Dredging a new deepwater harbor like Rotterdam's Europort is economic only
where several large industrial installations are being served. In many cases, dredging
costs for deepening existing ports are prohibitive.
Sea Islands
These structures consist of a
fixed offshore berth and platform
with unloading facilities connected
to shore by submarine pipes. Sea
island terminals are restricted to
fairly sheltered locations. Tanker
supply services may be difficult to
arrange at sea islands (see Figure 1).
Multibuoy Mooring
The ship is moored in a fixed
position between a number of
anchored buoys. Cargo is dis-
r aure
For Official
,1
0
Use
Only
, , ,
?
,
?
,
,B0116 B .
Sea Island
charged through floating hoses and a submarine pipeline to shore. This type of
berth, like sea islands, is restricted to sheltered areas. Ship supply services also pose a
problem.
Fixed Berth or Finger Pier
The simplest and
best terminal installation
is the finger pier built out
into deepwater. Its use is
restricted by cost consid-
erations to adequately
sheltered areas where
deep water lies close to
shore. Given this kind of
site, the finger pier pro-
vides the best arrange-
ment in terms of safety
and ship supply services.
Moreover, its closeness to
shore often means a
shorter pipeline network
than for alternative sys-
tems (see Figure 2).
CPYRGHT
CPYRGHT
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Approved For Release 2001U31/041tKANIZOIST9gtill491A000400010001-6
CPYRGH
Single Point Mooring (Single Buoy Mooring) Systems
A single point mooring system, under which the ship has free heading,
sometimes must be employed in preference to multibuoy fixed-heading mooring.
For instance, a 100,000-DWT ship is the maximum size of tanker that can
reasonably be handled by fixed-heading mooring buoys in areas open to fairly severe
sea conditions. For larger tankers the chance of collision and the strain on mooring
lines must be reduced by allowing the ship to swing freely in the prevailing wind,
current, and wave conditions; an anchored buoy with a rotating top thus would be
preferable to a fixed tower. Monobuoys are generally used where berthage has to be
provided outside of a harbor or natural shelter. Several operating problems are
associated with monobuoys: the floating discharge hoses are vulnerable to damage
and oil spills; hoses are limited to low discharge rates, and ship supply services are
difficult to provide (see Figure 3).
Tanker Loading and Unloading
The larger oil tankers are capable of an improved oil discharge rate which
reduces the time spent in berth. Ideally, operators of tankers aim at hourly discharge
rates of about 10% of the vessel's carrying capacity. However, physical problems
prevent supertankers from achieving this target; the longest VLCCs may realize only
half this rate. Loading and discharge rates are limited by the ships pump capacity
and the pressures that the loading hoses and ship's pipework can withstand. The
maximum pressure in these systems is about 200 pounds per square inch.
Figure 3
For Official Use Only
Product distribution
Mooring
lines
Rotating
mooring
arm
unit
Rotating balance arm?,
Loading or discharging tanker
411
Mooring chains
Underbuoy hoses
Underbuoy hose floats
Pipeline end manifold
Submarine
pipeline to
shore tank farms
Anchors or anchor pile
'`.Floating Hoses
--Hose marker lights
Flanged hose connections
56346B 6.74
Single Point Mooring System
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Approved For ReleaMg001106i0.4,:teM.CROR79S01091A000400010001-6
Comparisons of Selected Crude Oil Tankers
Capacity
(Deadweight Tons)
Length
(Feet)
Draft
(Feet)
Maximum Oil
Discharge Rates
(Tons per Hour)
16,000
522
28
1,500
32,000
650
35
3,000
50,000
735
40
4,000
75,000
820
43
6,000
106,000
930
50
9,000
217,000
1,075
63
12,000- 15,000
250,000
1,100
70
14,000- 16,000
326,000
1,135
81
15,000- 18,000
500,000
1,300
90
N.A.
(Planned)
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Approved For Release 2001/EISFOLffeRMDIPT96114-691A000400010001-6
Refining and Petrochemicals
THE PROPERTIES OF CRUDE OIL
General Characteristics
Crude oils are complex mixtures of hydrocarbons plus minor amounts of
sulfur, nitrogen, oxygen, and metals. Their characteristics vary widely from one
oilfield to another and even from one well to another in the same oilfield.
Crude oils range in character from light, flowing, reddish-brown liquids with
a large proportion of easily distillable fractions to highly viscous, semi-solid, black
substances with little distillable material. Crude oils generally are flammable. The
odor of crude ranges from pleasantly aromatic for some light types to the highly
unpleasant garlic smell usually associated with high-sulfur oils.
In spite of wide differences in physical aspects, the elements present in
different crude oils vary within narrow limits, as shown below:
Percent of
Total Weight
Carbon
84-87
Hydrogen
10-14
Sulfur
0.06-7
Nitrogen
0.1-1.7
Oxygen
0.5-1.5
Metals (iron, vana-
dium, nickel, etc.)
0.03
Types of Crudes
Crude oils are commonly classified according to the residue from their
distillation. The following three classifications comprise about 85% of all crude
oils:
? Paraffin-Base crudes are good sources of high-quality lubricating oils
and kerosene as well as wax. They usually have low contents of
sulfur, nitrogen, and oxygen.
? Asphalt-Base crudes are good sources of high-quality gasoline and
special lubricating oils as well as asphalt.
? Mixed-Base crudes contain considerable amounts of both wax and
asphalt. Practically all products can be obtained from them, at lower
yields than from the other two types.
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Testing Procedures
Knowledge of the characteristics of individual crude oils is essential to
achieving maximum efficiency in refining. Comprehensive analytical methods are
employed to determine the important characteristics of the crude. These
characteristics include:
1. Specific gravity ? ratio of the weight of a unit volume of oil to
the weight of the same volume of water at a standard temperature
2. Sulfur content
3. Nitrogen content
4. Color
5. Viscosity -- a measure of the oil's resistance to flow.
6. Pour point ? the lowest temperature at which the oil will pour or
flow.
7. Fractional composition -- the array of petroleum products recovered
by vaporizing the crude and collecting the fractions that condense
at different temperatures.
52
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REFINING OF OIL
General Description of Refinery Operations
A modern petroleum refinery consists of a number of processing units designed
for physical and chemical conversion of crude oil into useful petroleum products
(see simplified flow diagram). Because refineries process different types of crude
oil and produce different assortments of products, no two refineries are exactly
alike. Most modern refineries, however, employ the same basic processes and make
use of the same basic types of equipment. The product mix of a refinery can
vary substantially, with little or no change in equipment. Refineries in the United
States, for example, are geared to maximize output of high-octane gasoline; the
same units can be operated to maximize output of other products, such as diesel
fuel or fuel oil.
Distillation
The first and fundamental step in refining is distillation, which is the rough
separation of the crude oil molecules according to their size and weight. Primary
distillation takes place in towers as high as 100 feet which contain perforated trays
set one above the other at different levels. These are known as fractionating towers
because they separate crude oil into different fractions or parts. Crude oil is heated
to about 700? F and is pumped in vaporized form into the fractionating units.
As the vapors rise, they become cooler, condense at differing rates, and are collected
in different levels of trays and piped to other parts of the refinery.
Gasoline condenses at the lowest temperature, near the top of the tower.
Other distillates, including kerosine, jet fuel, diesel fuel, and light heating oils
condense at higher temperatures. Gas oil, which is coverted by more sophisticated
processes into gasoline or fuel oil, condenses at even higher temperatures. The
heaviest fraction, which condenses at the highest temperatures, is known as
residuum. In many refineries vacuum distillation, a two-step process using two
distillation towers, is used to further condense the residuum to obtain heavy fuel
oil, lubricating oil, grease, asphalt, or wax.
Distillation can separate crude oil into its fractions, but it cannot get more
out of a particular fraction than nature put there. The demand for different
products does not necessarily conform with the proportions found in the crude
oil. Refineries are able to produce more gasoline and other high-quality fuels than
can be obtained in the distillation process by using a number of secondary processes.
Secondary Processes
The most common secondary process is cracking ? the breaking of large
molecules into smaller ones. The oldest process in use is thermal cracking, which
relies on heat alone to convert heavy, lower quality fractions into lighter,
53
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IIsomerization
NINO 3S11 IVIDIAA0 1103
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Simplified Flow Diagram of a Modern Refinery
Gases
Straight Run Gasoline
Crude
Oil
Distillation
Naphtha
Catalytic
Reform-
ing
Gases
Straight Run Gasoline
High Octane Gasoline
Gas
Recovery
and
Stabilization
of Gasoline
Liquefied Petroleum Gas
lsobutylene
Butylene
Butane
Polymeri-
zation
Di-lsobutylene
Alkylation
Hydro-
genation
c6
133
ke;kw
6
?
=
???????
03
GAS
APPLIANCES
rAIRCRAFT
p+AUTOMOBILES
FARM
MACHINERY
Crude
Oil
High Octane
Catalytic Cracking
Residue
Atmospher
IC Or
Vacuum
Distillation
Vacuum
Distillation
Vacuum
Distillation
Refined
Solvent
Refining
563599 7-74
Lubricating Distillates
Lubricating Residue
Solvent
Refining
ubricating Distillates
Lubricating Oils
Light
Blending
Heavy n_and
Lubricating Oils rTag-
Dewaxing
Decolor-
izing
Bright Stock
Wax
Wax
Refining
Plant
Refined
Waxes
HOME
HEATING
LOCOMOTIVES
FACTORIES
SHIPS
ROAD
CONSTRUCTION
WAXED PAPER
PRODUCTS
ForOfficial Use Only
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KIND 3S11 1V1313,10 1103
Approved For Release 200MelE.IEVAIL-1461579tY1091A000400010001-6
high-quality stocks. Few thermal crackers have been built during the past decade,
and today the process is used primarily to prepare feedstocks for catalytic cracking.
In the catalytic cracking process, oil vapors heated to about 1,000? F are
passed over a silica-alumina catalyst, which causes the heavier oil fractions to crack
into lighter ones (gasoline and distillate fuels); these lighter fractions are then sent
to a fractionating tower for distillation. The used catalyst goes to a regenerator
where it is activated for further use by the burning off of the carbon (coke)
deposited on the catalyst in the cracking process.
Hydrocracking is a more recently developed process used to convert residual
stocks into high-quality products. It employs a series of high pressure reactors to
mix hydrogen with oil vapors at temperatures up to 1,100? F. The process combines
the use of a silica-alumina cracking catalyst with platinum or nickel as the
hydrogenating agent and obtains high yields of good-quality distillates.
Other key processes found in most refineries include:
Catalytic Reforming ? a continuous process, which uses platinum or platinum
and rhodium on alumina as a catalyst to rearrange molecules, upgrading low-octane
naphthas into high-octane gasolines or producing aromatics ? benzenes, toluenes,
xylenes ? for petrochemical use.
Alkylation a process for combining smaller dissimilar molecules into larger
ones in the presence of sulfuric acid or hydrofluoric acid to provide high-octane
components for premium motor gasoline or aviation gasoline.
Polymerization -- a process for combining similar molecules in the presence
of phosphoric acid to yield high-octane gasolines and petrochemical materials. The
process is gradually being replaced by alkylation.
Isomerization ? a process in which the atoms within a molecule are rearranged
without changing the total number. It is used in many refineries to produce
high-octane gasoline components.
Coking -- a thermal cracking process in which a heavy feedstock is heated
to about 900?-1,000? F under moderate pressure to produce a high-quality gas oil
suitable for use in catalytic cracking. Gas, gasoline, and coke are produced as
secondary products. The coke is used as industrial fuel or, when purified, is valuable
for production of electrodes for the aluminum industry.
Gas Recovery -- the collection of refinery gases and their separation by use
of multiple fractionating towers. The gases are used in production of gasoline and
petrochemicals.
Hydrogen Treating (hydrodesulfurization) ? a series of processes using
cobalt-molybdenum catalysts on a wide variety of petroleum stocks to improve
the quality of final products by removing sulfur.
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Blending
The final step in producing gasoline and fuel oils is blending. It involves mixing
two or more fractions having different properties to obtain a final fuel with the
desired specifications. This can be done "off-line" in blending tanks or "on-line"
in a refinery's pipelines.
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PETROCHEMICALS
A widely accepted definition of petrochemicals is: "Chemical compounds or
elements recovered from oil or natural gas, or derived in whole or in part from
oil or natural gas hydrocarbons, and intended for chemical markets."
How and Where Petrochemicals Are Produced
Since petroleum is essentially a mixture of hydrocarbons (carbon and
hydrogen), the chemicals made from it are nearly all organic chemicals. In theory,
virtually any organic chemical can be made from petroleum. In practice, the range
is wide but not unlimited. In many cases, the same compound can be made from
more than one hydrocarbon raw material. The raw materials chosen will depend
on what is economically available and the product mix needed.
Basic raw materials for petrochemical manufacture are natural gas, refinery
gases, and liquid hydrocarbon fractions. A larger number of secondary raw materials
are derived from these basic materials and form the building blocks of the industry.
These include acetylene, paraffins (methane, ethane, propane, and butane), and
olefins (ethylene, propylene, and butylene). Propane enjoys the largest use as a
hydrocarbon raw material.
Almost 90% of the world's organic chemicals are derived from petroleum
hydrocarbons; this share may rise to 97%-98% by the end of the century.
Nevertheless, in the United States the entire output of petrochemicals consumes
less than 6% of all petroleum refined.
Petrochemical manufacture commonly requires the application of petroleum
processing techniques to the production of finished chemical products.
Petrochemical units are usually continuous, elaborate, and highly automated and
operate with catalysts. They require a large scale of operation to be economically
feasible. In recent years, the sizes of petrochemical plants have risen sharply. For
example, a typical ethylene plant in the early 1960s had a capacity of about 70,000
tons per year; at present the capacity of such plants normally approximates 400,000
tons annually.
All petrochemical installations must have ready access to the various refinery
fractions used as raw materials. They therefore are placed as close as possible to
an oil refinery.
Petrochemical Groups and Types
There are three groups of petrochemicals, depending on chemical composition
and structure:
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(1) Aliphatic -- Organic compounds having an open chain of carbon
atoms, normal or branched, saturated or unsaturated. This group
includes acetic acid, acetic anhydride, acetone, butadiene, ethyl
alcohol, ethyl chloride, ethylene glycol, formaldehyde, ethyl alcohol,
and isopropyl alcohol. Most of these petrochemicals are made from
methane, ethane, propane, and butane.
(2) Aromatic -- Organic compounds containing or derived from the basic
benzene ring, which has six carbon atoms. This group includes
benzene, toluene, xylene, and their derivatives.
(3) Inorganic -- Compounds not containing carbon atoms. This group
includes sulfur, ammonia, nitric acid, ammonium nitrate, and
ammonium sulfate.
Aliphatic compounds account for about 60% of all petrochemicals produced
and are also the largest group in value terms. Aromatic compounds are smallest
in volume, constituting about 16% of the total, but are more important in value
than inorganic petrochemicals.
The number of individual petrochemicals runs into the thousands. They are,
for the most part, grouped according to type and general use, as follows:
(1) Plastics and resins -- molded, extruded, and machined articles and
materials used in the home and industry; paints and surface coatings;
films and packaging materials.
(2) Synthetic fibers ? clothing, floor coverings, decorative textiles, tire
cords, ropes.
(3) Synthetic rubber.
(4) Materials for agriculture -- fertilizers, insecticides, cattle feed
improvers.
(5) Detergents.
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CONVERSION FACTORS
1. Approximate Conversion Factors for Crude Oil*
INTO Kiloliters 1,000 1,000
Metric Long Short (Cubic Gallons Gallons
Tons Tons Tons Barrels Meters) (Imp.) (US)
FROM
MULTIPLY BY
Metric Tons
1
0.984
1.102
7.33
1.16
025Ii
0.308
Long Tons
1.016
1
1.120
7.45
1.18
0.261
0.313
Short Ton.
0.007
0.893
1
6.65
1.05
0.233
0.279
Barrel ?
0.136
0.134
0.150
1
0.150
O.035
0.042
Kiloliters (cub. meters)
0.863
0.840
0.951
6.29
1
0.220
0.264
1,000 Gallons (Imp.)
3.01
3.83
4.29
28.6
4.55
1
1.201
1,000 Gallons (U.S.)
3.25
3.19
3.58
23.8
3.79
0.833
1
*Based on world average gravity (excluding natural gas liquids).
2. Approximate Conversion Factors for Petroleum Products
FROM
Barrels per Day Tons per Year
Barrels to Metric Tons to Tons per to Barrels per
Metric Tons to Barrels Year Day
MULTIPLY BY
Motor Gasoline
0.118
8.45
43.2
0.0232
Kerosine
0.128
7.80
46.8
0.0211
Gas Diesel
0.133
7.50
48.7
0.0205
Fuel Oil
0.149
6.70
54.5
0.0184
3. Volumetric Measures
INTO Cubic Cubic US Imperial US
Meters Feet Gallons Gallons Liters Barrels
FROM
MULTIPLY BY
Cubic meter
1.0
35.31
264.15
219.95
999.97
6.285
Cubic foot
0.02832
1.0
7.481
11.229
28.32
0.178
US gallon
0.00379
0.1337
1.0
0.8327
3.785
0.0238
Imperial gallon
0.00453
0.160
1.201
1.0
4.546
0.0286
Liter
0.001
0.0353
0.2641
0.2200
1.0
0.006293
US barrel
0.1590
5.615
42.0
35.0
158.9
1.0
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4. Miscellaneous:
Units of weight:
Short ton 2,000 pounds
Long ton 2,240 pounds
Metric ton 2,205 pounds
Units of volume:
Measurement ton (ship ton) 40 cubic feet
Register ton 100 cubic feet
Representative conversion factors:
Country
Barrels per
Metric Ton
Abu Dhabi
7.493
Algeria
7.713
Angola
7.223
Bahrain
7.335
Congo
7.508
Gabon.
7.245
Iran.
7.370
Iraq
7.541
Israel
7.286
Kuwait
7.261
Libya
7.615
Morocco
7.602
Nigeria
7.508
Qatar
7.719
Saudi Arabia
7.428
Saudi Kuwait Neutral Zone
6.849
Turkey
6.400
United Arab Republic
6.901
5. Rules of Thumb:
a) Conversion between barrels per day and tons per year:
Barrels per day. X 50 = tons per year.
Tons per year 50 = barrels per day.
b) Volumetric contents of pipelines:
(Diameter in inches)2= barrels per 1,000 feet.
Example: 30-inch diameter pipeline would contain
approximately 4,752 barrels per mile.
6. Approximate Energy Equivalents (Conversions)
Energy
Content'
Coal
Equivalent
Oil
Equivalent 2
1 million tons hard coal
7
1. Q3
0.7
1 million tons coke
6.7
0.96
0.67
1 million tons lignite
2
0.29
0.2
1 million tons liquid fuels
10
1.43
1.0
1,000 million cubic meters natural gas
9
1.33
0.9
1,000 million cubic meters manufactured gas
4.2
0.6
0.42
1,000 KWh I electricity
0.88
0.125
0.088
1 One trillion kcaL
2 One thousand barrels of oil per day equals approximately 2 trillion BTUs per year.
3 Standard fuel?theoretical unit of energy, equivalent to 7,000 kcal per kilogram.
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