Chilingarian G.V. et al. Surface Operations in Petroleum Production, II
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41
5
(2) Flotation method.
In
the case of flotation method, the pipe joints are first
welded into a number of long strings onshore. Pontoons are attached to provide
buoyancy and the strings are towed section by section, into position. A tie-in barge
holds together the ends of the two sections that have to be tied in. Pontoons are
released systematically to lower the pipe to the bottom (Lamb, 1972).
Although the flotation method overcomes the length limitations of the bottom
pull method, it is highly vulnerable to rough or even moderately rough seas. It is
ideal for long lines in protected waters.
(3)
Reeled pipe method. The pipeline can be laid by the reel method
if
it is
relatively short and of small diameter. The pipe is fabricated into a continuous
length and spooled into a large-diameter reel. The line
is
laid much like a cable by
simply unspooling it from a mooring barge. Tension is applied to limit sag,
especially in deep water. The advantages include:
(1)
rapid installation speed and,
consequently, lower sensitivity to weather, and (2) the possibility of advance testing
of the pipeline (Lamb, 1972). The main limitations
of
the reel method are mainly
due to the pipe deformations resulting from coiling and uncoiling.
(4)
Lay barge method.
In
the case of lay barge method, pipe joints are welded on
the barge, which is equipped with an assembly line type of arrangement for this
purpose. The barge moves ahead periodically and each joint progresses through
several stages of welding, radiography, and coating. Then pipe joint
is
lowered into
the water over a stinger that allows it to reach the seafloor without undue stress on
the pipe. The stinger, which
is
a ramp extending at a controlled angle from the barge
to almost sea-bottom, also limits the sag in the pipe (Lamb, 1972).
The lay barge method is limited by
(1)
the downtime requirements in rougher
seas,
(2)
tensioner capacity,
(3)
barge mooring system capability, and
(4)
the ability
of the pipe to withstand the loads incurred during installation as it passes over the
stinger (Lochridge, 1980).
Tankers
Subsea pipelines are normally used to transport crude oil from offshore-produc-
tion facilities to onshore-storage terminals and thereon to the refining facilities.
As
the industry moved further offshore and into areas that presented serious techno-
logical and economical challenges for the installation of subsea pipelines, conven-
tional tanker transportation techniques were modified considerably to serve as a
viable alternative.
Although tanker transport is a fairly routine procedure, it requires careful design
and planning. The tanker transport process is intimately related to the type of
offshore storage (fixed or floating), the loading facilities (both offshore and onshore),
etc.
Offshore storage
The fixed storage types, which were some
of
the earliest to be developed, include
the Khazzan tanks, Ekofisk tanks, and the Condeep structure (Fig.
10-26).
The
416
FIXED TYPES
B
1.
KHAZZAN
4.
DUBAl
1
2.
EKOFISK
FLOATING TYPES
5.
PAZARGAD
3.
CONDEEP
6.
SPAR
Fig.
10-26.
Offshore storage types. (After Coleman,
1980,
p.
158;
courtesy
of
the National Academy
of
Sciences.)
Khazzan tanks, installed in the Persian Gulf, are steel structures of the shape shown,
fixed to the seafloor by piles. They are 270
ft
in diameter and
205
ft
tall. The
Ekofisk tanks in the North Sea are
302
ft in diameter, prestressed concrete storage
tanks designed to withstand the rough conditions in the North Sea. They were built
in nine modules and towed to location. The Condeep design consists
of
19
vertical
66
ft in diameter reinforced concrete cylinders,
16
of which are
154
ft
high. They
provide a very high oil storage capacity.
The floating-type storage units are essentially barges and tankers that have been
converted to storage units. Dubai Petroleum used spread moored tanker forebodies
-
1.
CALM
FLOATING
2.
ELSBM
3.
SALM
-1
FIXED
OR
MOORED
4.
SALM
-2
5.
ALP
6.
SPAR
Fig.
10-27.
Offshore
tanker
loading systems; single-point moorings
(SPM).
(After Coleman,
1980,
P.
160;
courtesy of the National Academy
of
Sciences.)
417
for storage. Pazargad, designed and built by Mobil, is a barge moored by a single
buoy mooring system. The SPAR type
is
a vertical floating storage tank with a six
leg catenary mooring. It is quite stable in even rough seas.
Offshore tanker loading
Two concepts have emerged in the area of offshore tanker loading. One is the
single-point mooring (SPM), which was developed for areas with directionally
variant environmental forces (wind, waves and currents). The other is the single-
anchor leg mooring (SALM), which was developed by Exxon to handle larger
tankers (Fig. 10-27). The former (SPM) use spread mooring, whereas the latter
(SALM) are attached
to
a base on the seabed by a single anchor chain
or
leg.
Another system called SPAR combines storage and offloading capabilities provided
by a retractable loading boom.
Combined storage and tanker loading
The single buoy storage (SBS) consists of a modified CALM and a storage tanker
and is useful for smaller shuttle tankers. The SALS (single-anchor leg storage) is a
storage tanker moored by a rigid yoke to a SALM structure, and is suitable for
small
to
large shuttle tankers. The SPAR structure can accomodate small to
medium-sized tankers.
Mobil Oil Co. has developed the loading-mooring-storage (LMS) system for
handling very large crude oil carriers (VLCC) that can operate in severe environ-
mental conditions. SCOTBUOY consists of vertical concrete cylinders moored to
the seafloor. The details of these systems are beyond the scope
of
this chapter and
the original references may be referred to
for
a complete discussion (Coleman, 1980;
Jones, 1981; and others).
EXISTING
1.
SES
(TUNISIA)
2.
SALS
(MALAYSIA)
3.
SPAR
(BRENT)
NEW DESIGNS
4.
Lms
5.
SCOTEUOY
Fig. 10-28. Combined storage and tanker loading facilities. (After Coleman, 1980,
p.
163; courtesy
of
the
National Academy
of
Sciences.)
41
8
SAMPLE QUESTIONS
(1)
List and briefly describe the different types
of
offshore structures.
(2)
Discuss the
(1)
advantages and
(2)
disadvantages of Template, Tower and
(3)
Justify the statement that “the Tension leg platforms have the brightest
(4)
Where are the subsea production systems advantageous to use?
(5)
Discuss the important operational and environmental forces on an offshore
Guyline platform types.
future”.
structure.
REFERENCES
American Bureau of Shipping, 1980.
Rules /or Building and Classing Mobile Offshore Drilling Units.
Am.
Bur. Shipping, New York, N.Y.
American Petroleum Institute, 1969, 1979, 1982.
Recommended Practice /or Planning, Designing and
Constructing Fixed Offshore Platform.
API RP
2A,
American Petroleum Institute, Washington, D.C.,
33 pp. (Also Supplement No.
1).
Anonymous, 1977. Union’s Beaufort Sea ice island success.
Oil Gas
J.,
75 (28): 42-43.
Anonymous, 1981.
Safety and Offshore Oil.
National Academy Press, Washington, D.C., 331 pp.
Baker, W., 1981. Offshore exploration. Lecture given at the University of Southern California, Los
Angeles, Calif., Sept. 9.
Brown, D.A., 1975. A study
of
the multiple aspects of construction
of
a drilling vessel. Thesis. Univ.
South Calif., 46 pp.
Clark, J., Zinn, J. and Terrell, C., 1978.
Environmental Planning /or Offshore Oil and Gas, Volume
I:
Recovery Technology.
Conservation Foundation, Washington, D.C.
Coleman, D.M., 1980. Offshore storage, tanker loading, floating facilities. In:
Outer Continental Shelf
Frontier Technology, Proc. Symp.
National Academy
of
Sciences, Washington, D.C., pp. 155-172.
Collipp, B.G., 1972. Analyzing mooring line catenaries. In:
Offshore Technology.
Energy Communica-
tions, Dallas, Tex., 202 pp.
Corporon, W., 1983. Technology for tackling Alaska’s oil.
Exxon U.S.A.
Q.
Mag.,
22 (1): 17-21.
Cowan, R. and Horton, E.H., 1983. The buoyant tower, new deepwater drilling and production concept,
Part 11, modern production risers.
Pet. Eng. Int.,
(2): 36-56.
Crosby, G., 1972a. Pacific deep water drilling techniques perfected. In:
Offshore Technology.
Energy
Communications, Dallas, Tex., 202 pp.
Crosby, G., 1972b. Mobil engineers’ new deep water system. In:
Offshore Technology.
Energy Communi-
cations, Dallas, Tex., 202 pp.
Dunn, F.P., 1980. Deepwater drilling and production platforms in non-Arctic areas. In:
Outer Continen-
tal Sherf Frontier Technology, Proc. Symp.
National Academy
of
Sciences, Washington, D.C., pp.
25-40.
Eckerfield, R.J., 1976. Sea-floor template speeds development drilling. In:
Offsore Platforms and
Pipelining,
PennWell, Tulsa, Okla.
Ellers,
F.S.,
1982. Advanced offshore oil platforms.
Sci. Am.,
264 (Apr.; 4): 38-49.
English, J.G., 1980. The one-atmosphere manifold centre. In: L. Atteraas,
F.
Frydenbo, B. Hatlestad and
T.
Hopen (Editors),
Proc.
Int.
Conf Underwater Technology, Offsore Petroleum,
Bergen, April 14-16,
Pergamon, Oxford, pp. 53-72.
Enright, R.J., 1976. Steel or concrete platforms for the North Sea-or neither? In:
Offshore Platforms and
Pipelining.
PennWell, Tulsa, Okla.
Fitch, J.L. and Jones, L.G., 1976. Artificial ice islands could cut Arctic costs. In:
Offshore Platforms and
Pipelining.
PennWell, Tulsa, Okla.
419
Geer, R.L., 1980. Introduction. In:
Outer Continental Shelf Frontier Technology, Proc. Symp.
National
Graff, W.J., 1981.
Introduction to Offshore Structures.
Gulf, Houston, Tex.
Gray, D.J., 1981.
Deep water subsea production systems.
Lecture given at the University of Southern
California, Los Angeles, Calif.
Guy, A.L., 1976. Platform for 850 feet
of
water nears the construction phase. In:
Offshore Platforms and
Pipelining.
PennWell, Tulsa, Okla.
Hams, L.M., 1972.
Deepwater Floating Drilling Operations.
PennWell, (formerly Petroleum Publ. Co.),
Tulsa, Okla., 272 pp.
Jahns,
H.O.,
1980. Arctic platforms. In:
Outer Continental Shelf Frontier Technology. Proc. Symp.
National Academy
of
Sciences, Washington, D.C., pp. 41-71.
Jones, M.E., 1981.
Deepwater Oil Production and Manned Underwater Structures.
Graham and Trotman,
London, 245 pp.
Kash, D.E., White, I.L., Bergey, K.H., Charlock, M.A., Devine, M.D., Leonard, R.L., Salomon, S.N. and
Young,
H.W., 1973.
Energy Under the Oceans: A Technology Assessment
of
Outer Continental Shelf
Oil
and
Gas
Operations.
University of Oklahoma Press, Norman, Okla., 378 pp.
Kennedy, J.L., 1976. New types
of
gravity platforms near completion. In:
Offshore Platforms and
Pipelining.
PennWell, Tulsa, Okla.
Lamb, M.J., 1972. Designing, laying and maintaining underwater pipelines. In:
Offshore Technology.
Energy Communications, Dallas, Tex., 202 pp.
Lee, G.C., 1981. Fixed drilling and production platforms design and construction considerations. Lecture
given at the University
of
Southern California, Los Angeles, Calif.
Lochridge, J.C., 1980. Deep water pipelines, In:
Outer Continental Shelf Frontier Technology. Proc. Symp.
National Academy
of
Sciences, Washington, D.C., pp. 123-154.
Mason, J.P., 1980. Subsea production systems.
In:
Outer Continental Shelf Frontier Technology, Proc.
Symp.
National Academy
of
Sciences, Washington, D.C., pp. 95-122.
McNabb, D., 1976. Guyed tower platform design nearing offshore test in Gulf
of
Mexico. In:
Offshore
Platforms and Pipelining.
PennWell, Tulsa, Okla.
Morrison, J.R.,
OBrian,
M.P., Johnson, J.W. and Schaaf, S.A., 1950. The force exerted by surfaces waves
on
piles.
Trans. AIME,
189: 149-154.
Ranney, M.W., 1979.
Offshore Oil Technology
-
Recent Developments.
Noyes Data Corporation, Park
Ridge, N.J., 399 pp.
Sellars, C., 1981.
Offshore pipelines.
Lecture given at the University
of
Southern California, Los Angeles,
Calif.
U.S. Maritime Administration, 1977.
A Technology Assessment
of
Offshore Industry. The United States
Offshore Industry. Current Status, Trends and Forecast
1976-2000,
Vol. I. The United States Offshore
Industry, Washington, D.C.
Walker, R.W., 1972. Seafloor template completions for deep hostile water. In:
Offshore Technology.
Energy Communications, Dallas, Tex., 202 pp.
Wright, D.C. (coordinator), 1977.
Artificial Islands in the Beaufort Sea
-
A Review
of
Potential Environ-
mental Impacts.
Fisheries and Marine Service, Environmental Secretariat, Canada.
Academy Science, Washington, D.C., pp. 1-12.
This Page Intentionally Left Blank
421
Chapter
I1
POLLUTION CONTROL
K.M. SASSEEN, GEORGE
V.
CHILINGARIAN and
JACK
D.
BRADY
INTRODUCTION
The petroleum and production engineers
of
today, in addition to their proficiency
in and the understanding
of
the many facets of oil and gas treatment systems, must
also become knowledgeable regarding the control of pollution- both water and air.
Although there are many industrial related types of water and air pollution, this
chapter is devoted to oilfield operations. Many regulations issued by Federal and
State agencies, especially during the last twenty years, outlined necessary steps to
control pollution. Production waters no longer can be discharged into open fields,
streams, uncontrolled earthen sumps, etc. In many areas, the requirement for better
pollution controls brought about the design improvement of systems for the
recovery and reuse of water for steam injection and waterflood operations, etc.
Most liquid waste in the oilfield, produced by surface operations, results directly
from produced water which must be separated from the crude oil. This water
typically contains relatively high concentrations of dissolved sodium chloride,
dissolved hardness (calcium and magnesium carbonates), suspended solids, and
emulsified oils.
The common source points of oilfield contaminated waters, from oilwell produc-
tion gathering systems, are as follows:
(1)
Production dehydration facilities: (a) freewater knockout vessels, (b)
water-oil-gas separators, (c) washtanks, (d) heater treaters, and (e) shipping tanks.
Most of the above facilities are equipped with automated electronic sensing controls
to establish an oil-water interface for the direct removal of production water into
downstream wastewater cleaning systems for further treatment.
(2)
Spills from collection systems.
(3)
Water drains from storage tanks and from test-sample operations.
(4)
Steam generator combustion gas (sulphur dioxide) removal by scrubber water
systems.
(5)
Rain runoff waters from oil storage tank areas, oil treating areas, and oil
loading-shipping areas.
The primary sources
of
pollutants from surface operations are thermal stimula-
tion processes in secondary and tertiary oil recovery.
To
a lesser extent, sulfide and
mercaptan emissions are produced at the wellhead and must be controlled. The
most active pollution control activities have taken place in the California
(U.S.A.)
heavy crude oil fields. Similar programs are now being instituted in the Alberta
422
(Canada) heavy crude oil fields and will be introduced in the near future in
Venezuela, Indonesia, and some of the Rocky Mountain (U.S.A.) production zones.
There are basically two reasons that the California oilfields have been most active
in pollution control activities to date. First, the state
of
California has some
of
the
most stringent air and water pollution control requirements of any region in the
world. Second, thermal stimulation of heavy crude oil production has been most
widely applied in California. All of the pollution control techniques discussed in this
chapter are currently being practiced in California.
The pollutants of concern are sulfur dioxide
(SO,),
nitrogen oxides
(NO,),
particulate emissions, gaseous hydrocarbons, carbon monoxide (CO), hydrogen
sulfide
(H2S),
mercaptans
(R2S),
acidic and alkaline waste liquids, water con-
taminated with high levels of dissolved solids, water contaminated with oil, and
water contaminated with suspended solids.
Sulfur dioxide is produced by combustion
of
fuel containing sulfur. The major
sulfur dioxide producers in the oilfields are oil-fired steam generators used in
steamflood operations, oil-fired emulsion treaters (“heater-treaters”), direct-fired
heaters, and packaged boilers used for process heating purposes. These devices are
also the primary nitrogen oxide producers. Nitrogen oxides are also produced by
internal combustion engines used with oilwell pumps, pipeline pumps, and compres-
sor stations. Turbine-driven compressors and pumps also produce nitrogen oxides.
Particulate emissions are produced by oil-fired equipment and by site-grading
operations, unpaved road use, and natural processes including wind erosion
of
surface soil and landslides. Gaseous hydrocarbons are produced from incomplete
combustion in oil-fired equipment and from evaporative losses from storage tanks.
In addition, in steamflood operations, any steam which is vented from the well
casing carries with it volatile hydrocarbons. Carbon monoxide can be produced
from oil-fired equipment; however, these emissions, from properly adjusted
equipment, are
so
small as to be virtually negligible in oilfield surface operations.
Hydrogen sulfide and mercaptans can be produced from storage operations for
crude oil and from gas vents from the well casing.
WATER TREATMENT
In order to prevent pollution of vital natural resources, all wastewaters must be
purified prior to disposal, which requires special technology and process equipment.
Water treatment capability is an essential requirement of most production unit
facilities. Generally, there are certain impurities that must be removed or neutral-
ized to improve the quality of water
(1)
for reuse,
(2)
to meet the disposal
requirements for water well injectivity, or
(3)
to meet the disposal effluent standards
set by the regional water quality control board.
Through long and continuing research and development programs, the petroleum
industry has found useful purposes for recycled wastewater. Water produced in the
development of hydrocarbons is usually treated to certain specifications, depending
423
upon the oilfield location, and then reinjected into deep reservoirs for disposal
purposes. At other locations, water is often treated for reinjection back into the
producing formations for pressure maintenance and secondary recovery operations.
Produced water may also be treated and used as feed water in steam generators.
A multiplicity of considerations are involved in solving the water pollution
problems, in which the water quality is related to specific industrial or other process
systems requirements. The water qualities and standards that must be met are not
fixed and are subject to changes with changing environment as it affects the
elements. Sometimes, after the approval of a new process
or
system that yields a
higher degree of water quality than before, standards are upgraded because
of
the
development of new technology, for example. In the case of wastewaters, the water
quality parameters that are evaluated include:
(1)
the BOD (biochemical oxygen
demand), which quantifies the biodegradable organic matter content,
(2)
the oil
content,
(3)
the COD (chemical oxygen demand) that defines the total organic
matter content,
(4)
suspended solids content,
(5)
total solids content,
(6)
pH
(alkalinity
or
acidity),
(7)
nitrogen and phosphorus contents, and
(8)
heavy metals
and inorganic solids contents.
Obviously, the oilfield water treatment operations are primarily concerned with
oil content and TSS (total suspended solids content). If the effluent water must be
discharged into the ocean
or
a lake,
or
diverted to a sanitation district plant, instead
of injection into an oilfield water disposal well, then additional requirements such as
BOD and pH must be evaluated.
Contaminants
Suspended free contaminants which may consist of both settleable (e.g., fine-
grained sand particles having oil film) and floatable material (mainly free oil), are
held in suspension in water by turbulence. These suspensions can usually be
removed by gravity separation within a surgetank or receiving watertank, for
example, that allows reduction of velocity and provides retention of settled material.
The methods of removal of free floating oil droplets after gravity separation and the
settleable sand particles are discussed within the equipment process sections.
Entrained contaminants consist of floatable and settleable material, which is
dispersed and sometimes tightly emulsified in the water. The following processes are
used
to
remove entrained contaminants:
(1)
retention,
(2)
chemical treatment,
(3)
coalescence,
(4)
air-gas flotation, and
(5)
filtration.
Dissolved contaminants, which comprise organic and inorganic groups, include
substances that are extremely detrimental to the environment. Organic compounds
are resistant to biological oxidation. Inorganic dissolved solids which must be
controlled if wastewater
is
to be reused, can be removed by
(1)
precipitation,
(2)
ion
exchange,
(3)
reverse osmosis,
(4)
distillation and
(5)
electrodialysis. Typical oilfield
water treatment, however, does not include any of these treatment systems. In
certain cases, a particular sludge, resulting from oilfield water treatment operations,
424
could contain a critical heavy metals content that would prohibit local typical
disposal means and necessitate special handling.
When oilfield waters are to be reused, dissolved oxygen is considered as a
contaminant, e.g., in the case of a waterflood operation. Dissolved oxygen must be
removed to reduce the corrosion. Oxygen reduction can be accomplished by gas
stripping, vacuum stripping, and/or chemical oxidation.
Before deep-well water injection (waterflood), the wastewater must be treated to
control the content of materials that would cause damage to the injection apparatus
and piping or cause plugging of the formation. The treatment may include
(1)
the
removal of suspended solids, oil, biological growths, dissolved gases, and precipita-
ble ions, and
(2)
the control of pH (acidity or alkalinity).
Thus, the disposal means of oilfield wastewaters can be summarized as follows:
(1)
injection into a porous subsurface stratum, after minimal water treatment, within
the oilfield drilling-production area (disposal wells),
(2)
reuse of the wastewater,
after complex water treatment, as feed water to a steam generator facility within the
production area,
(3)
transferring the wastewaters, after minimal water treatment, to
a
central cooperative plant, receiving variable in composition wastewaters from
different companies, for further treatment to satisfy local regulatory agency disposal
requirements,
(4)
reinjection of the wastewaters, after complex water treatment, into
the producing formation (waterflood or combination water-CO, injection oper-
ation), and
(5)
disposal into a large body
of
water (ocean, inlet, bay, river, or gulf)
after strict compliance with the local regulatory agency effluent standards.
WASTEWATER TREATMENT DESIGN
The basic design phases of an oilfield wastewater treatment system are:
(1)
(1)
Collection section
collection and primary separation,
(2)
main treating, and
(3)
polishing.
The collection phase consists of a surgetank, which receives incoming variable flow
wastewaters from freewater knockout vessels and
oil
dehydration facilities. This
tank provides a system to handle surge capacity and, by gravity separation, the
means to collect and return free oil back to the dehydration facility. The range of
the oil content in water entering the surgetank might range from
200
to
2000
ppm
(parts per million, mg/l). The reduction in the oil content might range from
40
to
70%,
depending on the temperature, gravity of the oil, and viscosity of the oil as
they affect settling velocity obeying Stokes’ Law. The contaminants (including
settleable sand) that can be removed by gravity separation are eliminated in
surgetank prior to the more elaborate treatment.
The main treating section consists of that part
of
any wastewater treating system
whch is designed to reduce the content of contaminants or remove the oil and oily
sand particulate contaminants that are present in
a
tight, stable oil-in-water emul-
sion. Ths treating section may consist
of
pumps, pressure vessels, a dissolved air (or
(2)
Main treating section