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Abstract:
Many oil and gas fields are now entering (or already have) entered the end of their
productive lives and as of consequence, the hydrocarbon industry presently faces the
dilemma of decommissioning redundant oil and gas installations. The purpose of this report
is to probe into the various treatment options available to reduce pollution caused by
decommissioning and abandonment of offshore oil rigs, in accordance with both international
and domestic regulating bodies. According to the UK Offshore Operators Association
(UKOOA), decommissioned was defined as the process which the operator of an offshore oil
and gas installation goes through to plan, gain government approval and implement the
removal, disposal or re-use of a structure when it is no longer needed for its current
purpose.” Firstly, this report outlined the decommissioning process which comprises of well
abandonment, pre-abandonment, engineering, decommissioning, structural removal,
disposal and site clearance. It was observed that the choice of removal method depended
on cost, proximity to disposal sites, availability of removal equipment, location of the removal
relative to shipping lanes and fishing interests, and safety and environmental issues. In
addition, the disposal method played a key role in the decision on the removal method.
Furthermore, it was also found that, the planning phase of the decommissioning and
abandonment process took the longest time, since it had to be established at the time of
erection of the offshore platform by the operator involved. This was followed by outlining the
legal framework that is stipulated by international regulatory bodies and conventions, with
emphasis on the decommissioning phase in oil and gas industry. As of consequence, this
report looked into two general types of treatments namely: technological and alternative
treatments (i.e. re-use and recycling) which are adopted by oil and gas operators to conform
to the legal requirements stipulated by both international and domestic regulatory bodies.
Technological treatments dealt with well plugging and other decommissioning options which
included alternative treatments as a subset of a suite of remedies that could be utilized.
Finally, limitations of environmental laws and conventions was looked into, and the report
concluded that in some cases the definition of pollution in the law was ambiguous,
consequently mechanisms were established to limit the possible exploitation created in
claims for compensation for environmental damages.
INTRODUCTION - Chapter one
Background Information to Oil and Gas Installation Decommissioning
The offshore oil and gas industry had its beginnings in the Gulf of Mexico in 1947. The first
offshore development used a multiplied steel jacket to support the topside production
facilities, a design which has since been used extensively. Now there are more than 7000
drilling and production platforms located on the Continental Shelves of 53 countries (Day
2008). Over 4,000 are situated in the Gulf of Mexico, some 950 in Asia, some 700 in the
Middle East and some 600 in the North Sea and North East Atlantic. Some of these
structures have been installed in areas of deep water and treacherous climates, and
consequently structure designs have adapted to withstand the environmental conditions of
these areas. Commonly used structural designs are illustrated below:
FIGURE 1.1. Steel-jacketed structure (Day 2008)
FIGURE 1.2. Tension leg platform (Day 2008)
FIGURE 1.3. Concrete gravity base structure (Day 2008)
FIGURE 1.4. Floating production system (Day 2008)
Figure 1.5 Cell Spar (Day 2008)
The United Kingdom Continental Shelf (UKCS) is home to some 312 structures extracting oil
and gas. These include subsea equipment fixed to the ocean floor as well as platforms
ranging from the smaller structures in the Southern and Central North Sea to the substantial
installations in the Northern North Sea built to withstand very harsh weather conditions in
deep waters. Many of the structures were constructed in the 1970s and were hailed as
technological feats when they were installed (Gibson 2002). The table below shows the
location of North Sea installations by type and country:
Country Steel-Jacket Concrete substructure Subsea Floating Total
UK 227 12 56 17 312
Norway 69 13 54 9 145
Netherlands 118 2 7 127
Denmark 39 39
Germany 1 1 2
Total 454 28 117 26 625
The table 1.1 above shows the location of North Sea installations by type and country
(Gibson 2002).
In the proximal future
Many oil and gas fields are now entering (or already have) entered the end of their
productive lives and as of consequence, the hydrocarbon industry presently faces the
dilemma of decommissioning redundant oil and gas installations. The purpose of this report
is to delve into the various treatment options available to reduce pollution caused by
decommissioning and abandonment of offshore oil rigs, in accordance with international
environmental laws and conventions.
To date there is relatively negligible experience in removing structures from the North Sea.
Presently, approximately 30 small steel structures and sub-sea installations have been
successfully decommissioned in the shallow waters (30-50 metres) of the Southern North
Sea sector, including 20 from UK waters.
The largest structure decommissioned so far is the Odin platform in 1997. The steel
substructure, weighing 6,200 tonnes, was removed from the North Sea in waters 100 metres
deep. None of the largest structures, those weighing over 10,000 tonnes, has ever been
removed anywhere in the world
THESIS STATEMENT
Substructure, removal of topsides, well plugging, abandonment in-situ, recycling of waste, as
well as the use of non-explosives, are some of the treatment options employed as
containment measures to reduce pollution caused by decommissioning and abandonment of
offshore oil rigs, in accordance with international environmental laws and conventions.
Objectives:
To define what is decommissioning.
To encapsulate and to provide a comprehensive review of the decommissioning and
abandonment process.
To outline the legal framework of platform decommissioning.
To demonstrate the use of technology as treatment options in decommissioning and
abandonment, in adherence with environmental laws and conventions.
To examine limitations of environmental laws and conventions.
Chapter two
Definition
According to the UK Offshore Operators Association (UKOOA) defines decommissioning as:
“The process which the operator of an offshore oil and gas installation goes through
to plan, gain government approval and implement the removal, disposal or re-use of a
structure when it is no longer needed for its current purpose.”
Decommissioning is usually, a long-term process. For example, Petroleum UK began to
think about the decommissioning of their Maureen platform in 1993 – the platform was finally
removed in 2001.
The abandonment process
The entire abandonment process can be broken down into seven distinct activities:
1. Well abandonment: the permanent plugging and abandonment of non-productive
well bores.
2. Pre-abandonment surveys/data gathering: information-gathering phase to gain
knowledge about the existing platform and its condition. Governing ministries or
standards organizations should be contacted to determine permit and environmental
requirements.
3. Engineering: development of an abandonment plan based on information gathered
during pre-abandonment surveys.
4. Decommissioning: the shutdown of all process equipment and facilities, removal of
waste streams and associated activities to ready the platform for a safe and
environmentally sound demolition.
5. Structure removal: removal of the deck or floating production facility from the site,
followed by removal of the jacket, bottom tether structures or gravity base.
6. Disposal: the disposal, recycle, or reuse of platform components onshore or
offshore.
7. Site clearance: final clean-up of sea-floor debris.
Well abandonment
The precise formulae devised in order to determine cessation of production can be quite
challenging. However, a close working relationship between the reservoir, downhole and
salvage engineers should be developed to establish the timing of a well and platform
abandonment project. Before abandonment can begin, the salvage engineer must confirm
that all wells on the platform are abandoned. The wells should be permanently abandoned
according to the recommended procedures in adherence to the appropriate jurisdiction.
Generally this means isolating productive zones of the well with cement, removing some or
all of the production tubing and setting a surface cement plug in the well with the top of the
plug approximately 30–50 m below the mudline. The inner casing string should be checked
to ensure that adequate diameter and depths are available for the lowering of explosives or
cutting tools. If the well plug and abandonment are not performed properly, removal of the
conductor by explosive or mechanical means becomes unsafe and much more expensive.
To ensure no delays in structure removal, all well plug and abandonments should be
completed several months prior to commencement of offshore decommissioning. After well
plug and abandonment responsibility and schedules have been established, the following
step is the information-gathering phase (Day 2008).
Pre-Abandonment surveys/information gathering
This phase is of paramount importance for a successful abandonment program. Adequate
preparation requires a thorough knowledge about the platform to be decommissioned.
Information must be combined from the topside deck and support structure design,
fabrication and installation as well as any structural modifications that may have occurred
since installation. The pre-abandonment survey should assess the condition of the platform
facilities and structure prior to commencement of abandonment (Day 2008). The survey
should include the following:
i. File surveys. All available documentation concerning the platform design, fabrication,
installation, commissioning, start-up and continuing operations should be
investigated. The file survey will inform the project engineer with the other
appurtenances to the platform facility such as living quarters, process equipment,
piping, flare system and pipelines and any additions/deletions or structural repairs to
the jacket or the topside since the original installation.
ii. Geophysical surveys. Depending on the results of the file survey, the engineer may
choose to have additional data gathered by means of side-scan sonar. This survey
will indicate the amount of debris on the seafloor. In the case of deep-sea disposal,
the sonar can determine if there are any obstructions at the dump site. Proximity of
an available dump site or ‘rigs to reef’ site, water depths and obstructions along the
tow route should be investigated as part of the geophysical survey.
iii. Environmental surveys. This consists of an environmental audit of the offshore
platform to identify waste streams or other government controlled materials. At this
time items such as naturally occurring radioactive materials (NORM), asbestos,
PCBs, sludges, slop oils and hazardous/toxic wastes should be identified and
quantified. The problem of dealing with these waste streams should be addressed in
the scope of work for handling during the decommissioning phase of the project. The
project engineer should determine what permits or operating parameters are required
by the host government or international standards.
iv. Structural surveys. A structural engineer can use observation and non-destructive
ultrasonic testing techniques to evaluate the structural integrity. Items inspected will
include condition and accessibility of lifting eyes, obstructions on the deck which may
require removal and interfaces between production modules/deck and deck/jacket
which may require cutting for disassembly. Discrepancies between actual conditions
and as-built information identified in the files should be noted during this phase. The
platform legs should be checked for damage that may obstruct explosives or cutting
tools from accessing the proper cutting depth. If obstruction from damage is
anticipated or found, smaller diameter charges or cutting tools should be provided by
the removal contractor as a contingency. Information concerning the underwater
condition of the structure should be available from previous underwater inspections.
If not available, consideration should be given for gathering this information by divers
or remote-operated vehicles (ROVs).
Engineering:
Upon completion of pre-abandonment surveys, a strategy for decommissioning and
abandonment can be developed. The engineering phase takes all of the data previously
gathered and pieces it together to form a logical, planned approach to a safe
abandonment. Of major concern during the development of this strategy is the safety of
the operations. As with all offshore operations, there exists a high potential for accidents
involving bodily injury or loss of life and the accidental discharge of oil and flammable,
corrosive or toxic material into the environment. A risk analysis for all phases of the
decommissioning should be performed. The results of this risk analysis are used to
develop a decommissioning safety plan. Safety targets can be set and achieved
provided the appropriate attention is devoted to the elements of the decommissioning
plan. These procedural elements include the following items:
Regularly scheduled safety meetings;
Identification of safe work areas;
Safety equipment and training for emergency situations;
Working at high elevations and over water;
Safe operations of cutting tools and explosives;
Safe demolition to maintain structural integrity;
Proper use of rescue and evacuation equipment;
Diving and ROV operations;
Testing for and monitoring of toxic/explosive gases;
Pollution controls and containment;
Methods for handling and disposal of oil wastes, corrosive, NORM, or toxic
materials;
Weather monitoring/night watch procedures;
Addressing each of the aforementioned items will assist in the development of a safe
decommissioning and salvage plan. After all the safety and environmental aspects of the
project have been considered, details of the salvage process need to be identified. The
sequence of process equipment and structure decommissioning and the salvage and
disposal methods need to be determined. Any required government permits should be
submitted for approval.
A key element in the determination for an effective and efficient abandonment program is
proper selection of the salvage equipment. Equipment selection for lifting purposes is
determined by maximum weights of components to be lifted. Oceangoing derrick barges
or Heavy Lift Vessels (HLV) currently available to the industry range from approximately
135 to 7000 tonnes (as shown in figure 2.1 below).
Figure 2.1 showing a Derrick barge (Day 2008).
Cost comparisons must be made between the time savings afforded by heavier lift, more
expensive equipment and time-consuming, lighter lift, less expensive equipment. In
addition to costs, the project engineer must assess the safety and environmental risks
associated with sectional removal. Sectional removal will require significant time at the
site for dismemberment and removal of production piping and equipment prior to cutting
the topside deck into pieces. Additional hazardous tasks involved with decommissioning,
lifting and rigging operations need to be performed offshore in a sectional removal, and
thus the time during which personnel will be exposed to increased workplace hazards
will be increased.
Decommissioning
The main goal during the decommissioning is to protect the marine environment and the
ecosystem by proper collection, control, transport and disposal of various waste streams.
Decommissioning is a dangerous phase of the abandonment operation and creates the
possibility of environmental pollution. Decommissioning and removal or abandonment in
place should be carried out by personnel who have specific knowledge and experience
in safety, process flows, platform operations, marine transportation, structural systems
and pipeline operations. All contractors involved with the decommissioning should be
brought in early in the planning stage to further assure a smooth decommissioning
project.
The sequence of decommissioning the process system, utilities, power supplies and life
support systems is important. The platform’s power, communications and life support
systems should be maintained for as long as practicable to support the decommissioning
effort. Process systems throughout the platform will have to be flushed, purged and
degassed in order to remove any trapped hydrocarbons. Safe lock-out, tag-out, hot work
and vessel entry procedures must be in place to ensure safety. Procedures must outline
all duties of the standby/rescue teams including the use of breathing apparatus, air
purging and lighting and caution must be exercised in removing all amounts of gases,
oils and solids which may still remain in valves, production headers, filter housings,
vessels and pipework that could present hazards to the crew.
Platform decommissioning normally result in large amounts of waste liquids and solids.,
Waste liquids can be dealt with most cost effectively by placing them in existing pipelines
and sending them to existing operating facilities. If no ongoing operations are available,
then the waste streams will have to be pumped into storage containers and transported
onshore for disposal or recycling. The constituents of the waste stream is instrumental in
determining the cost of disposal. Solid wastes such as discarded batteries, glycol filters
and absorbent rags will also have to be handled onshore according to acceptable
disposal practices. Most times many platforms will have chemical treatment additives as
well as possible toxic/hazardous materials such as methanol, biocides, antifoams,
oxygen scavengers, corrosion inhibitors, paints and solvents, some of which may cause
damage to the marine environment if accidentally discharged. As of consequence, the
methods for handling and containing must be followed. The presence of radioactive
scale, NORM, PCBs, hydrogen sulphide, etc., should have been detected during the
environmental survey and a disposal plan developed. Disposal will generally entails
transporting this material in drums to disposal wells or approved landfills. Prior to
removal, a detailed plan on how each material will be disposed of should be developed
(for instance, in the case of Trinidad and Tobago, certificate of environmental clearance
and HAZOPS must be applied for). The plan should identify recyclable materials such as
steel, rubber and aluminium and the recycling centres that will take delivery of these
materials. For those items not to be recycled, the abandonment plan should include the
environmental impact that disposal will have on the dump site.
After the process piping and vessels have been cleaned and it has been determined that
there is no future utility for the pipelines, pipeline decommissioning should commence.
Pipelines departing the platform will either board another platform or commingle with
another pipeline via a sub-sea tie-in. A surface to surface decommissioning is the least
costly to perform. This requires pigging the line to vacate any residual hydrocarbons
followed by flushing with one line volume of detergent water followed by final rinsing with
one line volume of sea water. Upon completion of the pipeline purging operation, pipeline
ends should be cut, plugs inserted and the ends buried below the sea-bed. In the case of
a sub-sea tie-in, details of the sub-sea tap will have to be obtained so that pipeline
decommissioning plans can be developed. The flowline can be pigged, flushed and
disconnected if the receiving platform can accept the fluids, otherwise the pipeline
segment will have to be isolated from the adjoining trunkline and then decommissioned.
This usually involves a boat capable of mooring over the sub-sea tie-in, connecting
flexible piping to the tie-in using divers or ROVs, then pumping pigs, detergent water and
rinsing water toward the platform for handling. Decommissioning involves a variety of
waste streams, disposal handling methods and specialty contractors. This phase more
than any other will determine the success of the abandonment and salvage.
Structure removal
The procedure of a structure removal will be determined by the structure design,
availability of removal equipment, method of disposal and the legal requirements
governing the jurisdiction in which the abandonment occurs. The legal requirements will
usually be based on various parameters such as the social, economic, environmental
and safety concerns of the local governing bodies. All of these issues are interdependent
and will have a direct repercussion on the overall cost of the removal operation. The
economics of the removal are of prime importance to the party responsible for the
removal, whether it is third parties such as a contractor, local government or producer.
Each structure consists primarily of the topsides or deck above the water line and the
jacket below the waterline.
Deck removal
Topsides removal is essentially the reverse sequence of the installation. Any piece of
equipment obstructing the deck lifting eyes must be removed prior to the lift. The deck
section is removed by cutting the welded connection between the piles and the deck
legs. Slings are attached to the deck lifting eyes and the crane hook on the HLV. The
HLV’s crane lifts the deck section from the jacket. The deck is then placed on the cargo
barge and readied for transportation to a land based facility for offloading (Day 2008).
Jacket removal
The jacket portion of the platform comprises of the steel template which resides in the
water column. Prior to removing the jacket, the piles must be cut to dislodge the jacket
from the seafloor. The majority of structures in moderate environments will be totally
removed. Most regulatory bodies throughout the world require that the structure be
removed anywhere from the mudline to 5 m below. The predominant consideration when
developing a removal method is to determine if the piles or well bores will be severed
using explosive or nonexplosive methods.
(a) Extraction using explosives. Severing platform piles and well bores with explosives is
relatively effective compared with using non-explosive methods, as multiple cuts can
be made in a short period of time. This limits the amount of time that removal support
equipment must be on the site and limits personnel exposure to unsafe working
conditions. Generally, explosives are the least exorbitant and the method of choice
for structure removal. However, when explosives are used, more stringent
regulations may become effective, including consultations with the local fishery or
natural resource agencies. A project plan should allow lead time for consultations
and permit approval from these agencies. Explosives emit high-energy shock waves
that can be harmful to habitat fisheries immediately adjacent to a removal site and
some endangered species, such as marine turtles or mammals, in close proximity to
the detonations may be mortally affected by these shock waves. Local regulations
should be researched to ascertain limits to the amount and size of charges allowed
and to determine if moratorium periods exist during marine migration periods. In
some areas, a condition for approval requires that observers from the local regulatory
agencies and/or resource groups be present at the removal site prior to detonations,
to observe that permit requirements are being observed and to ensure that no harm
is done to endangered species that may be in the area. Other conditions that may be
imposed to limit the effects of explosives on habitat fisheries are predetonation aerial
surveys, daylight-only working hours and staggered detonations. The disadvantage
of focused charges is that they need to be properly set in the well bore or pile and
corrosion scale or damage in the piles can prevent the charge from applying its full
energy to the target. One approach used to reduce the effects of explosives on
habitat fisheries is to evacuate the platform piles of all water. This reduces the
resistance of the shock wave from the charge to the target. Also, special shock-
attenuating blankets can be placed at the mudline to limit the energy emitted from the
seafloor. Another approach is to avert fishes from entering the blast area. Small, pre-
set charges set off prior to the detonation of the severing charges, known as scare
charges, have been used. However, there are risks that scare charges may actually
draw some species of curious fish toward the blast site. The use of strobe lights
similar to those used to keep fish away from dam intakes may be warranted.
(b) Non-explosive Extraction. Another option for the project engineer is to eliminate the
use of explosives in the removal. Use of non-explosive removal methods eliminates
the impact due to shock waves. As a result, costs and time associated with observers
and additional permit conditions may be curtailed. However, salvages using non-
explosive methods can be more costly since only one pile or well bore can in practice
be severed at one time. Each nonexplosive cut will typically take several hours to
perform. The additional time and cost can be minimized depending on the scope of
work and with proper project planning. The project engineer should perform a precise
cost estimate, evaluating the costs and risks between using explosive and non-
explosive methods of severing. The following is a discussion of some non-explosive
severing techniques.
High-pressure water/abrasive cutters
This system uses a high-pressure water jet operating at anywhere from 200 to 4000
psi to perform the cut. In other systems, sand, garnet or other type of abrasive is
injected into the water stream to aid in the cutting process. The nozzle is lowered into
the hole attached to an umbilical hose line or a hard pipe supply line. The nozzle is
rotated 360° inside of the pile or well bore until the cut comes back on itself. A merit
to this system is its effective cutting ability. The casing strings do not have to be
concentric in the well bore. The wall thickness of the platform piles is generally not a
concern. The reaction of the water spray and the returns of the water indicates to the
operator that the cut is literally being made. However, the drawbacks of using this
system are the tendency for system downtime due to the high working pressures,
electrical and mechanical complexities, the delicate characteristics of the abrasive
injection and wear and tear on the nozzle. Interrupting the cutting operation requires
that the tool be placed in the exact location of the cut to avoid incomplete cuts. The
effectiveness of these cuts is reduced at deeper cutting depths owing to the
hydrostatic head that the water jet needs to overcome. As with all cutters, the tool
must be centred in the pipe to maximize cutting efficiency. This can be difficult in
heavily scaled pipes or in battered piles. Topside instrumentation can be used to
monitor the position of the cutting tool during the cut. Camera technology has been
used to inspect visually the status and effectiveness of a cut (Day 2008).
Mechanical cutters.
Mechanical cutters use tungsten bit cutters that are extended from a housing tool
with hydraulic rams. The tool is rotated constantly using friction to perform the cut.
Disadvantages include incessant downtime of the tool due to frictional wear and tear,
high labour intensity in handling heavy and bulky tools, the need for a work platform
around the piling/well bore to be cut and poor cutting performance on non-concentric
casing strings. Also, it can be difficult for the operator to determine if a cut is
complete. Shifting of the well strings or platform piles downward can jam the tool into
the kerf of the cut.
Diver cut.
Internal or external pile or well bore cuts can be accomplished by using diver’s
underwater burning equipment. This type of cut can be made internally if there is
access for the diver into a large-diameter casing or piling. If there is no internal
access and the cut must be made below the mudline, a trench must be excavated to
afford the diver access to the area to be severed. In some soils, keeping a trench
open to the required 5 m depth may be impractical and may put the diver at undue
risk from trench collapse. If the cut must be made below the mudline, it should be
consulted to the local jurisdiction of the required depth of the cut. This may require
obtaining a waiver to reduce the required cutting depth due to local soil
characteristics and safety concerns for the diver personnel. Another concern to the
diver’s safety is oxygen entrapment in the soil near the cut or on the backside of the
pipe being cut. Oxygen build-up can lead to an explosion if contacted with a
flammable source such as a burning rod.
Plasma arc cutting.
Plasma arc cutting can be accomplished by an extremely high velocity plasma gas jet
formed by an arc and an inert gas flowing from a small-diameter orifice. The arc
energy is focused on a small area of metal, thus forcing the molten metal through the
kerf and out of the backside of the pipe. Water can act as a shielding agent to cool
and constrict the arc. The procedure requires a high arc voltage provided by
specialized power sources. This method is not frequently used, and is therefore not
highly developed. For it to be effective, the tool must be set properly in the cut pipe. It
is difficult to determine if a cut is being made unless camera technology is utilized.
Regardless of which ever method is being used (i.e. explosives or non-explosives),
obstructions in the pile can interfere with the proper placement of charges or cutting
tools in the well bore or pile. Examples of such hindrance includes: scale build-up,
damaged piling, mud or pile stabbing guides. The removal of mud from the pile is
generally accomplished with the use of a combination of a water jet and air lifting
tools. When properly designed, these work well. This task is traditionally performed
after the topside deck has been removed by the heavy lift contractor. A more cost-
effective technique is the use of a submersible pump to excavate mud from the
platform pile prior to removal. A small inexpensive work spread can be mobilized to
the site prior to the arrival of the heavy lift equipment to perform this task. A window
is cut into the jacket leg/pile and the submersible pump is then lowered down the
jacket leg on a soft umbilical line.
Alternative removal techniques
Many installations are removed with heavy lift equipment such as oceangoing derrick
barges. In faraway areas of the world, another concern in dislodging the platform
from the seafloor is the availability of salvage support equipment. International
Maritime Organization (IMO) guidelines permit the host government to allow a
structure to remain in place provided that the structure is properly maintained to
prevent failure. Maintenance costs over the life of the installation may eventually
exceed the cost of the removal. When left in place, the platform may remain a hazard
to navigation, exposed to collapse during storms or become a haven for refugees.
These risks and liabilities may outweigh high removal costs to the host government
and the operator, thus the decision to remove the platform may prevail.
Another technique that can be used for the lifting of platform topsides is the
Versatruss system (see figure 2.2 below). The method uses a series of A-frames
mounted on tandem cargo barges. The combination of the A-frames, tension slings
and the topside deck create a catamaran and truss effect for lift stability. This lift
method also uses available equipment and requires relatively low-cost preparation.
Figure 2.2 showing Versatruss method (Versabar Inc. 2008)
Disposal
Once a platform or portions of a platform have been removed, the structure must be
disposed of. Some disposal options include the following:
● Transport inshore for disposal, storage or recycling;
● Toppling in place
● Disposal at a remote rigs to reef site;
● Emplacement;
● Deep-water dumping
Site Clearance
The final phase of the abandonment process involves restoration of the site to its original
predevelopment conditions by clearing the seafloor of debris and obstructions after platform
removal. If the abandonment was a partial removal, site clearance procedures may vary
from a total removal. In the case of total removal, debris should be removed, leaving the site
trawlable and safe for fishing or other maritime uses.
A site clearance plan may consist of two or three stages, depending on the information
gathered during the pre-abandonment surveys and the water depth at the location. The first
phase may occur before actual removal with divers making sector sweeps around the
platform site during pipeline decommissioning. High-frequency sonar can be used to locate
obstructions and direct divers to debris. Searches should be performed inside and outside
the platform a distance of at least 100 m. Following this initial debris removal, site clearance
can be discontinued until the structure removal has taken place (Day 2008).
Once the structure has been removed, the site is ready for a final clean-up if required. In
shallow waters, a trawling vessel can be used to simulate typical trawling activities that may
occur in the area after the platform removal.
Chapter Three
The legal framework of platform decommissioning
General Framework
The British Government’s policy with regard to the decommissioning of offshore oil and gas
installations on the United Kingdom Continental Shelf (UKCS) is stated quite clearly in the
Guidance Notes for Industry (Decommissioning of Offshore Installations and Pipelines under
the Petroleum Act 1998) produced by the Aberdeen-based Oil and Gas Office of the
Department of Trade and Industry (DTI):
“Government will seek to achieve effective and balanced decommissioning solutions
which are consistent with international obligations and have a proper regard for
safety, the environment, other legitimate users of the sea and economic
considerations. The Government will act in line with the principles of sustainable
development.”
International Conventions
International law has established the basic foundation of the legal requirements for the
removal and disposal of offshore structures. The removal of installations was addressed by
the 1958 Geneva Convention on the Continental Shelf, which stated that any installations
which are abandoned or disused must be entirely removed. However, several customized
local conventions were adopted by third parties to the Geneva Convention because it
allowed partial removal offshore installations. These local conventions were as follows:
i. United Nations Convention on the Law of the Sea
Internationally, the UK has a number of obligations concerning the decommissioning
of offshore installations which have their origins in the United Nations Convention on
the Law of the Sea (UNCLOS) of 19825 which entered into force in 1994 and was
finally ratified by the UK in 1997. Article 60(3) notes that:
“Any installations or structures which are abandoned or disused shall be
removed to ensure safety of navigation, taking into account any generally
accepted standards established in this regard by the competent international
organisation. Such removal shall also have due regard to fishing, the
protection of the marine environment and the rights and duties of other
States. Appropriate publicity shall be given to the depth, position and
dimensions of any installations or structures not entirely removed.” (Gibson
2002)
The International Maritime Organisation (formed in 1989 and based in London), which
adopted the IMO Guidelines and Standards setting out the global criteria for removal of
offshore installations, is the competent international organisation for UNCLOS (1982).
The IMO guidelines states that if the structure exists in less than 75 m of water and
weighs less than 4000 tonnes, it must be totally removed (Day 2008). If the removal is
done partially, the installation must maintain a 55 m clear water column. However,
exceptions to the same were as follows: for example, if the structure can serve a new
use after hydrocarbon production including enhancement of a living resource, or if the
structure can be left without causing undue interference with other uses of the sea or
where removal is technically not feasible, the installation can remain in place.
ii. The Oslo Convention of 1972 for the Prevention of Marine Pollution by Dumping from
Ships and Aircraft also provided some guidelines. However, its interpretation was
ambiguous, thus on these grounds it was not clear if this Convention applies to
dumping of platforms in place.
iii. In addition, 1992 witnessed a new regional convention, the Convention of the
Protection of the Marine Environment of the North East Atlantic (‘the OSPAR
Convention’). This convention, a replacement and modernisation of the 1972 Oslo
Convention on the Protection of the Marine Environment by Dumping from Ships and
Aircraft and the 1974 Paris Convention on the Prevention on Marine Pollution from
Land-Based Sources, came into operation in 1998. The Convention’s main roles are
to control disposal of all waste at sea and discharges from land. Including the EU,
there are 16 contracting parties of which the UK is one (Gibson 2002).
iv. Furthermore in 1992, 15 United Nations Environment Programme (UNEP) regional
conventions had been held. Here, local states have adopted varying degrees of
guidelines for potential legal concerns such as determination of the party responsible
for removal, responsibility and methods of payment, responsibility of owners in
default situations, owner designation upon non-use, maintenance responsibility and
liability for items left in place and such site-specific issues as bottom debris removal
and moratoriums for marine migrations. Some countries, depending on their
experience with removals, are fairly mature in their regulatory standards for
abandonment whilst others still have great strides to make in enacting requirements
for removals within their coastal waters (Predominantly third world countries).
v. In July 1998 a new binding framework (OSPAR Decision 98/3) for the
decommissioning of offshore installations was established by the First Ministerial
meeting of the OSPAR Commission. Generally, the primary decision was
unambiguous in that it states the following: “The dumping, and the leaving wholly or
partly in place, of disused offshore installations within the maritime area is prohibited”
(Gibson 2002). This recognition by OSPAR 98/3 of the difficulties involved in
removing in their entirety the ‘footings’ of large steel jackets weighing more than
10,000 tonnes and in removing concrete installations ensured that provisions were
made for a derogation from the main ‘general’ rule highlighted above (assessed on a
case-by-case basis). In particular:
a. The topsides of all installations must be returned to shore
b. All steel installations with a jacket weight of less than 10,000 tonnes must be
completely removed for re-use, recycling or final disposal on land;
c. For steel structures with a jacket weight greater than 10,000 tonnes it is
possible to consider whether the footings of the installation may remain in place;
d. For concrete installations it is possible to consider whether they should be left
wholly or partially in place;
e. All installations emplaced after 9 February 1999 (when OSPAR 98/3 came
into force) must be completely removed;
f. Exceptions can be considered for other structures when exceptional and
unforeseen circumstances resulting from structural damage or deterioration or other
reasons which would prevent the removal of a structure.
It is noted however, that pipelines were yet not covered by OSPAR Decision 98/3. There
were no international framework for the decommissioning of disused pipelines.
Chapter four
Technology as treatment options in decommissioning and abandonment, in
adherence with environmental laws and conventions.
There are various methods to remove and dispose of an offshore installation. Exactly which
are applicable to any individual installation will depend on a number of variables for example,
the type of construction, size, and distance from shore, weather conditions, and the
complexity of the removal operation including the safety considerations for the workers.
The diagram below depicts the main options open to offshore operators:
Figure 4.1 showing flow chart of decommissioning options (Gibson 2002).
After consideration of the relevant legislation and regulation, recommending which
decommissioning option is the most appropriate in any particular case has to take into
account at least five key factors:
• Potential impact on the environment;
• Potential impact on human health and safety;
• Technical feasibility of the plan;
• Economic impact;
• Public concern.
These criterion must be carefully balanced to ascertain the most beneficial (or the least
harmful) course of action.
Prior to decommissioning, well plugging and abandonment is the first decommissioning
activity to get underway offshore. It has been developed based on commencing
abandonment of water injection and low productivity wells while retaining high productivity
wells, simultaneous production and well abandonment. This philosophy maintains production
until its cessation is required for topside systems cleaning and preparation for topsides
removal, which then becomes the project critical path.
Wellbore-Abandonment Challenges and solutions
The key goal of any well abandonment is the permanent isolation of all subsurface
formations penetrated by the well. Although sealing depleted reservoirs is an important
concern in P&A procedures, ideal abandonment operations isolate both producing reservoirs
and other fluid bearing formations. Complete isolation prevents gas, oil or water from
migrating to surface or flowing from one substance formation to another (Barclay, Pellenbarg
and Tettero 2001).
Leaking seals pose risks to the environment – groundwater resources and the overlying land
or sea – and must be repaired, but remedial plugging operations are difficult and expensive.
Sealing a well correctly at the outset is significantly more cost effective, even if the initial
cost outlay is high. Considering well abandonment at the earliest stages of the well design
makes sense, because quality of the primary cement between the casing and formations is a
key factor for successful well abandonment later on.
Any deficiencies, in primary cementing tend to affect long term isolation performance. Wide
fluctuations in downhole pressure and temperature can negatively affect cement integrity or
cause debonding. Tectonic stresses can also fracture set cement. No matter the cause, loss
of cement integrity can result in fluid migration, impairment of zonal isolation or casing
collapse even when high-quality cement is placed properly. If fluids are migrating from a well
that has to be abandoned, then the first challenge is to locate the fluid-migration path.
Usually, subsurface fluids migrate through the completion components, leaky plugs, deficient
cement squeezes or flaws in the primary cement sheath or the caprock – the relatively
impermeable formation that encloses the reservoir. The caprock may be composed of
natural fracturing or by fracture stimulation treatments. When multiple reservoir exist,
identifying which one is leaking enables target remediation (Barclay, Pellenbarg and Tettero
2001). Knowing the condition of primary and secondary cement is of paramount importance.
The appropriate persons involved in the abandonment must be well acquainted with the
geology, wellbore geometry and accessibility, downhole equipment and its condition,
reservoir pressure and potential fluid migration path to abandon a well successfully.
Rigless Wellbore abandonment
Well abandonment begins with cleaning the production tubing and cementing or squeezing,
the production perforations. After the tubing the above the production packer is perforated,
cement is circulated between the tubing and the casing. At shallower casing-shoe levels,
multiwall perforations are shot and cement is circulated in an open annuli to achieve a wall to
wall cement barrier. Lastly, the tubing is perforated at a shallow depth of approximately 150
m (490 ft) – and a surface cement plug is placed. When all cement plugs have been placed
and tested, the wellhead and casing stump are removed.
Advantages of Rigless wellbore abandonment
The equipment cost less offshore and easier to mobilize.
Onshore its value lies in time savings over a comparable hoist operation.
Coil tubing allows precise placement of cement plugs even in deviated wellbores.
Also coiled tubing can operate without killing the well or removing the production
tubing or well head.
Challenges associated with Rigless wellbore abandonment
Heavy thick crude oil in the production tubing and annulus
Corrosion of the outer casing of some wells required additional plugging through
outer annulus of each well.
With regards to Rigless abandonment, diagram 4.2 below shows a diagrammatic
representation of a well before and after abandonment. Abandonment of Jisr-1 well, located
in southern Oman, represents an average of degree of difficulty for the PDO well
abandonment programme. Because the well was 12 years old, all valves on the Christmas
tree were backed up with new valves, and coiled tubing blowout preventers were rigged up
to ensure well control. Next, the tubing hanger plug, used for temporary well suspension was
removed. The production tubing and “A” annulus were cleaned by jetting cleaning fluids
down the tubing and up the annulus. The cleaning fluid contains surfactants and acids that
remove sludge, oil and paraffin. Cleaning is critically impertinent at this stage because seals
within the wellbore can shift if sludge or other material moves after setting cement plugs.
Also cement will not form a perfect hydraulic seal with materials coated with hydrocarbon.
The production tubing and 9 5/8-in casing pump were cleaned with a high pressure jetting
tool run on coiled tubing. The tubing and the “A” annulus were then displaced with 11.4-
kPa/m [0.5-psi/ft] salt brine. High pressure jetting has proved to be an effective,
environmentally friendly method for cleaning the tubing and sump, as waste generation was
significantly reduced.
Figure 4.2 a showing Jisr-1 before (left) and after (right) well abandonment (Barclay,
Pellenbarg and Tettero 2001)
Figure 4.2 b showing Jisr-1 before and after well abandonment (Barclay, Pellenbarg and
Tettero 2001).
With coiled tubing, a set of bentonite spacer on bottom to serve as a base for the cement
plug. On Jisr-1, the perforations were shot 342 m [1122 ft] above the base cement plug as
shown above. The PDO requirement was to set the reservoir installation plug from 50 m [164
ft] below the lower perforation to 50 m above the reservoir. In order to comply with
requirement at minimum cost, a 280 m [920 ft] bentonite spacer was spacer on bottom as a
filler. The first cement plug was set through coiled tubing across the perforations. A second
plug as shown above, was set higher in the wellbore, opposite the 133/8-in casing shoe, after
a bridge plug was set inside the 31/2-in production tubing using coiled tubing. The 31/2-in
tubing and 95/8-in casing were perforated and a wall to wall cement plug was placed. Next, a
bridge plug was set at 155 m [508 ft], and the tubing was perforated at 150 m. Finally,
the surface cement was plug was pumped. In contrast to procedures for the previous
cement plugs, PDO abandonment standards do not required pressure –testing of the surface
plug (Barclay, Pellenbarg and Tettero 2001).
Decommissioning Options
Options for decommissioning assume wells have been decommissioned and plugged and
topsides have been cleaned and removed, or made safe for toppling with the jacket.
Typically, topsides are taken onshore for disposal or recycling
The decommissioning options available for an offshore installation can be separated into
three groups:
1. Alternative Use of The Facilities, either in-situ or reused at another location.
2. Full Removal Schemes, entailing total removal of all facilities, subsea and topsides,
leaving a clear seabed
3. Partial Removal Schemes, entailing removal to leave a minimum clear water depth
of 55m above any remaining structure on the seabed in accordance with the IMO.
Alternative structure uses. In some areas of the world, the host government is either wholly
responsible for structure removal or, through participation by a national oil company, is
partially responsible for the cost of structure removal. The political entity may not want to
dedicate funds to a nonrevenue generating project. These states may decide that leaving the
structure in place is the only alternative. IMO guidelines give local states the discretion to
allow offshore structures to remain in place if the removal is not economically feasible. In
these situations, operators will need to review the contract terms for possible ongoing or
future liabilities.
The benefits of the alternative uses usually offset the costs to maintain the structure in place.
Some alternative uses may be as follows:
● Fish farm
● Marine laboratory
● Military radar support structure
● Weather station
● Oil loading station
● Spur for deep-water developments
● Aviation/navigation beacon
● Tourism/recreational
● Power generation, i.e. wind/wave.
Platform reuse. Reuse is another option. If a potential development can finance the removal
of a structure, this relieves the non-revenue producing property from absorbing the salvage
costs. Platform reuse can reduce the cycle time to get the new development in production,
generating cash. However, an immediate reuse should be identified when decommissioning
is undertaken. Storage of the platform onshore prior to identifying a reuse can result in costs
that may offset the savings from reuse.
Substructure
Complete removal. Complete Removal requires the structure to be entirely removed by lifting
either in one piece or in sections depending on the size of the jacket and the capacity of the
lift vessel. The foundation piles are left in place from about 5m below the seabed. The
refloating of “self-floating” jackets has been found to be impractical as the reuse of the
flotation control system was not a design consideration; similarly, the addition of buoyancy
tanks to barge-launched steel jackets has also been found to be impractical. The removed
jacket may be disposed of by taking it to deepwater for subsea disposal, or transporting it
ashore for recycling or onshore as seen below in figure 4.3.
Figure 4.3 showing total removal of an offshore installation.
Partial removals. In the North Sea, the abandonment issue is coming into focus as some of
the area’s fields are reaching the end of their productive lives. Some of the world’s largest
structures will need to be removed before the year 2005. The large component weights will
result in removal costs that may exceed the cost of the original installation. These removal
costs will largely be absorbed by the local governments because of tax breaks from removal
costs available to the operator. Thus, local governments may need to regulate and monitor
abandonment procedures to allow for a cost-effective removal strategy without
compromising safety or the environment. These partial removal methods will consist of the
following:
a. partial removal of jacket component
Figure 4.4 showing partial removal of jacket component (Day 2008)
The Toppling option involves toppling the upper portion of the jacket in-situ, to leave an
unobstructed water column. The high degree of precision and control required to ensure the
structure is safely toppled as planned make this is an extremely complex operation.
Explosive charges are used to sever designated critical members in a controlled sequence
of cuts, allowing the jacket to collapse under its own weight. A pull barge may be used to
provide forward momentum to the collapsing structure. This option can be achieved without
the need for heavy lift vessels. Reuse. The opportunities for reuse of jackets at another field
site are limited as they are designed for specific production requirements, water depth,
environmental criteria and soil conditions. Field life is also factored into the design of jackets
in terms of fatigue and corrosion considerations.
b. Toppling in place
Figure 4.5 showing toppling in place (Day 2008)
c. Total removal of topside and toppling in place of the jacket only
Figure 4.6 showing total removal of side (Day 2008)
d. Emplacement
Figure 4.7 showing emplacement (Day 2008)
Emplacement. Emplacement (Figure 4.7) is much the same procedure as
toppling except that the top section is completely cut from the lower section,
lifted off and placed next to the lower section
e. Transport to rigs to reef site. Rigs-to-Reefs is a process, managed by
Federal and State agencies, by which operators choose to donate – rather
than scrap – decommissioned oil and gas platforms to coastal States to serve
as artificial reefs under the National Artificial Reef Plan. Decommissioned
structures are typically toppled in place, partially removed near the surface, or
towed to existing reef sites or reef planning areas. The decommissioned
platforms, like artificial reefs and natural hard surfaces underwater, attract
various encrusting organisms such as barnacles and bivalves which colonize
on them and, in turn, attract fish and other marine life as found on natural
reefs.
f. Deep-water dumping. This method is particularly reserved for huge floating
systems located in the North Sea. Essentially, the structure is disconnected from
its moorings and towed to the deep ocean waters where it is then flooded and
sunk. Prior to any dumping operations, it is important to confirm that all
components placed in the ocean waters are free of hydrocarbons in harmful
quantities to avoid pollution of the open sea. Partial removal may consist of any
combination of the above-listed options. The method of structure and component
disposal should be based on legal, environmental, safety, financial and timing
issues. Identification of a disposal site and its proximity to the removal site must
be considered to perform a cost analysis on the most effective disposal method.
An inherent concern with any disposal method is tying down the salvaged
component on the transport barges, which can be particularly difficult and
dangerous in rough weather. A well thought out plan has to be enacted to assure
a safe and stable lift and placement on the transport barges. All components
should be tied down with a system that provides the same integrity as when the
platform was towed offshore for installation. A marine surveyor should be
available on-site to monitor the tie-down operations. The marine surveyor’s
responsibilities include confirming that the structure is secure for tow, certifying
that the tow route is free of overhead, width or bottom obstructions and verifying
proper ballast of the transport barge.
The choice of removal method will depend on cost, proximity to disposal sites, availability of
removal equipment, location of the removal relative to shipping lanes and fishing interests,
and safety and environmental issues. In addition, the disposal method will play a key role in
the decision on the removal method.
Chapter five
Legal limitations and applications associated with the Decommissioning,
abandonment and removal off obsolete offshore installations.
The extremely high cost of decommissioning and removal off offshore installations led to the
need to revise some of the national and international regulations adopted about 40 years
ago. Such a revision covered, in particular, the requirement set by the Convention on the
Continental Shelf (Geneva, 1958) and the United Nations Convention on the Law of the Sea
(Montego Bay, 1982) to remove abandoned offshore installations totally. At present, a more
flexible and phased approach is used. It suggests immediate and total removal of offshore
structures (mainly platforms) weighing up to 4,000 tons in the areas with depths less than 75
m and after 1998 - at depths less than 100 m. In deeper waters, removing only the upper
parts from above the sea surface to 55 m deep and leaving the remaining structure in place
is allowed. The removed fragments can be either transported to the shore or buried in the
sea. This approach considers the possibility of secondary use of abandoned offshore
platforms for other purposes.
From the technical-economic perspective, the larger the structures are and the deeper they
are located, the more appropriate it is to leave them totally or partially intact. In shallow
waters, in contrast, total or partial structure removal makes more sense. The fragments can
be taken to the shore, buried, or reused for some other purposes.
From the fisheries perspective, any options when the structures or their fragments are left on
the bottom may cause physical interference with fishing activities. In these cases, the
possibility of vessel and gear damages and corresponding losses does not disappear with
termination of production activities in the area. Instead, abandoned structures pose the
threat to fishing for many decades after the oil and gas operators leave the site. The
obsolete pipelines left on the bottom are especially dangerous in this respect. Their
degradation and uncontrolled dissipation over wide areas may lead to the most unexpected
situations occurring during bottom trawling in the most unexpected places. At the same time,
national and international agreements about the decommissioning and abandonment of
offshore installations refer mostly to large, fixed structures like drilling platforms. The fate of
underwater pipelines is still not affected by clear regulations.
In general the 1982 UNCLOS can best be seen as serving the interest of maritime states
within the exclusive economic zone, EEZ (a 200 nautical mile perimeter around the state.
Coastal states must have due regards for the right and duty of other states, including the
right of freedom of navigation. This freedom is largely protected by ensuring uniformity of
applicable pollution standard, and by preserving the ability of the maritime state to influence
the formulation of those standards within the IMO (International Maritime Organisation)
Interest groups (and sometimes referred to as “flags of convenience”) which have adopted
the UNCLOS include: environmental NGO’s, industry association and the maritime states
have dominated the discussions on policy and implementation. The USA is one such
example.
Secondary use of offshore fixed platforms
The options of reusing abandoned platforms, their foundations, and other structures that are
out of service have been actively discussed for the last 10 years.
An analysis of scientific potential of research stations permanently based on abandoned oil
platforms in the Gulf of Mexico revealed several promising directions of marine research at
such stations [Dokken, 1993; Gardner, Wiebe, 1993]. These include studying regulation of
the marine populations and coral reproduction, making underwater observations, monitoring
the sea level, and collecting oceanographic and meteorological information within the
framework of international projects. Some other suggestions consider transformation of
abandoned platforms into places for power generation using wind/wave and thermal energy
[Rowe, 1993]. These platforms also could be used as bases for search and rescue
operations or centres for waste processing and disposal [Side, 1992].
From the fisheries perspective, the most interesting projects are the ones aimed at
converting the fixed marine structures into artificial reefs. Artificial reefs are known to be one
of the most effective means of increasing the bio-productivity of coastal waters by providing
additional habitats for marine life. They are widely and effectively used on the shelves of
many countries.
The offshore structures can undoubtedly attract many species of migrating invertebrates and
fish searching for food, shelter, and places to reproduce. In particular, observations in the
Gulf of Mexico revealed a strong positive correlation between the amount of oil platforms,
growing since the 1950s, and commercial fish catches in the region. It became one of the
reasons to suggest the positive impact of offshore oil and gas developments on the fish
populations and stock. Wide popularization of this fact led to the mass movement using the
slogan "From rigs - to reefs" in the USA in the mid-1980s.
However, further analyses of the fishing situation in the Gulf of Mexico showed that the
growth of the fish catch in this case was connected not with increasing the total stock and
abundance of commercial species but with their redistribution due to the reef effect of the
platforms. A critical point here was the use of static gear methods of fishing (e.g., lines and
hooks) instead of trawl gears. Besides, the areas around the platforms became very popular
places of recreational and sport fishing. This also made a significant contribution to the total
catch volumes. Nothing similar was noted in the North Sea, where the number of oil
platforms has also been growing since the 1960s. However, the total catch did not correlate
with this growth at all and even decreased. This fact indicates the absence of any positive
impact of the reef effect of oil platforms on the commercial fish catches in areas where the
main way to fish is trawling.
At the same time, we should not forget about the danger that abandoned offshore oil
platforms and their fragments pose to navigation and trawling fishing. With an abundance of
such artificial reefs, this problem requires special regulations for negotiating the inevitable
conflict of interests. One such regulatory program has been developed and applied in the
USA in the Gulf of Mexico on the shelf of Louisiana [Pope et al., 1993]. It requires mapping
the area to indicate the locations of platforms, underwater pipelines, and other structures left
on the bottom. The program also includes monitoring, collecting data, developing a warning
system, and other activities necessary to control the situation and ensure safety in the
region.
It is of interest that the above argument in favour of rigs-to-reef has not been well received in
some quarters and the state of California has had some success in stalling the strong
challenge by interest groups lobbying for a change in the laws.
Until recently, law required that “decommissioned” oil and gas platforms be removed at the
end of production, and the surrounding marine environment be cleaned up and restored to a
natural condition. These obligations were known to the oil industry when the platforms were
installed. However, for several years, the industry lobbied to change existing law to allow
abandonment of offshore platforms in place after production ceases. Industry's motivation
was to avoid the costs for this previously agreed-to remediation.
Beginning in 1996, after the State of California required Chevron to remove four platforms
offshore Summerland in Southern Santa Barbara County, Chevron joined with other oil
corporations to lobby the State legislature to amend the law and allow platforms to be
abandoned in place.
The State of California’s position was based on the following concerns:
• Pollution
Oil platforms contain toxic materials and are surrounded by contaminated debris. Leaving
them in place defers full clean up and threatens the ocean environment with long-term
pollution impacts.
• Marine Resources
The University of California Marine Council found that research does not indicate that oil and
gas platforms enhance marine resources.
• Invasive Species
Oil and gas platforms can host non-native species that threaten the surrounding environment
and native fisheries.
• Safety Hazards
Leaving debris in the ocean creates a safety hazard for boaters, fishermen, and divers.
• Liability to California
If the platforms are left in place, the State of California would be left with the liability of
accidents or further mitigation efforts. Financial liability for abandoned platforms could thus
result in significant, ongoing costs for the state.
It is to be expected that similar concerns would be shared by the Trinidad and Tobago
population, its immediate neighbours and should provide awareness for the wider Caribbean
region.
These views were challenged by lobbyists so in order to protect the marine environment the
Environmental Defence Center, EDC led three successful efforts to defeat such legislation
and hold the oil and gas industry to the responsibilities it had previously agreed.
If consideration of alternate uses for decommissioned offshore oil and gas facilities were to
occur, EDC noted that the following issues should be addressed:
• Science-Based
The decision must be made based on objective scientific research addressing the potential
ecological implications platforms may have on regional fish populations (e.g. UC Marine
Council Report)
• Costs and Benefits
The full breadth and extent of environmental costs and benefits are considered
• Site Specific Analysis
Platform decommissioning is considered for each individual platform
• Burden of Costs
Platform owner should not be freed of costs associated with platform removal and
remediation.
If an artificial reef program is to be pursued, it should follow the State of California’s
established guidelines for artificial reef design and construction, such as mimicking in size
and substrate (e.g. rock and concrete) the reefs that naturally produce and maintain greater
numbers of fish, and incorporating various rock and crevice sizes in order to help fishes
recruit from the water column, find shelter, and reproduce. In many cases, platform
structures do not follow these guidelines.
The related guidelines relevant to Trinidad and Tobago are still not clear. (to be checked).
Scientific data in favour of rigs-to-reefs in the context of Trinidad and Tobago may be very
limited and with the need to encourage exploration and investment by international oil and
gas companies it is quite possible that relaxing such laws could serve as an incentive to
participate in our oil based economy.
Explosive activities
Complete or partial removal of steel or concrete fixed platforms that weigh thousands of tons
is practically impossible without using explosive materials. Bulk explosive charges have
been used in 90% of cases. This is very powerful, although short-term, impact on the marine
environment and biota, which should not be neglected.
It is extremely difficult to get any reliable estimates of possible mortality of marine organisms,
especially fish, during an explosive activity even if the initial data, such as the type of
explosive, depth of the water, bottom relief, and others, are known. This large uncertainty is
connected, in particular, with the high heterogeneity of fish distribution that strongly depends
on specific features of fish schooling behaviour. Calculations show that with a 2.5-ton (TNT
equivalent) charge, the mass of killed fish will be about 20 tons during each explosion. At the
same time, if, for example, a school of herring happens to get into that zone, the fish kill
figure may be much higher [Side, Davies, 1989].
One of the few known observations of fish damage in zones of explosive activity was done in
1992 in the Gulf of Mexico near the shore of Louisiana and Texas [Gitschlag, Herczeg,
1994]. In order to remove over 100 fixed platforms and other structures, more than 12,000
kg of plastic charges were exploded. The amount of dead fish floating on the surface was
visually recorded after the explosions. It totalled to about 51,000 specimens. The actual
number of killed fish was undoubtedly higher because many specimens could not float to the
surface or did not get in the zone of visual observation.
Whatever number of adult fish actually died during the explosions, it will hardly influence the
total abundance of commercial species. Much more hazardous for the fish stock are
explosive impacts on fish larvae and juveniles. The threshold of lethal impacts for the
younger organisms weighing up to several grams is tens of times lower than that for adult
specimens [Yelverton et al., 1975; Side, 1992]. Thus, the zone of mortality of fish at the early
stages of development is respectively wider. The quantitative estimates of possible effects at
the populational level are even more complicated because of the absence of corresponding
data and methods. Nevertheless, enough evidence exists to enforce strict regulations of
explosive activities and to forbid them in areas and in seasons of spawning and fry
development of commercial fish.
Removal of the offshore structures also decreases the number of habitats for structure-
related fish. For example, in the mostly soft-bottom environment of the Gulf of Mexico, these
structures provide hard substrates for marine organisms. The decline of stocks of reef fish
observed in this region within the past decade can be connected, in particular, with
elimination of over 400 oil-related structures that had served as an artificial habitat for marine
life [MMS, 1995].
Despite the fact that the State Legislature had rejected rigs-to-reefs proposals three times, a
new bill was introduced in 2010. EDC and other groups opposed the bill (AB 2503:
California Marine Life Legacy Act), due to the need for more scientific analysis and further
evaluation of the safety, management and economic ramifications of a state-sponsored rigs-
to-reefs program. See EDC's letter in opposition to A.B. 2503. AB 2503 was signed into law
on September 13, 2010.
Conclusions
Laws are proposed to protect economic states, interest groups while creating free and safe
access to the wider marine environment. The international maritime law and UNCLOS offer
some protection against some countries which, if allowed to, would impose fines to ships
that pass through their external economic zones.
In some cases where the definition of pollution in the law is so vague, mechanisms have
been put in place to limit the possible exploitation created in claims for compensation for
environmental damages. On the other hand compensation funds attract penalty payments
and associated restorative cost from the polluter.
As the cost of decommissioning and abandonment become financially prohibitive to oil
companies more efforts are being made to convert rig platforms to environmentally friendly
rigs-to-reefs havens.
Significant lobbying and lack of sufficient scientific data have contributed in several
environmental laws which govern decommissioning to them being changed or modified and
often to the possible detriment of the environment.
ReferencesBarclay, Ian, Jan Pellenbarg, and Frans Tettero. 2001. The Begining of the End: Preview of
Abandonment and decommissioning. New York: Schlumberger.
Day, M D. 2008. "Environmental control Technology in the Oil industry." In Decommissioning of offshore oil and gas installations, by Stefan T Orszulik, 188-228. New Hamsphire: Oxoid Ltd.
Gibson, Graeme. 2002. The Decommissioning of Offshore oil and gas installations: A review of current legislation, Financial regimes and opportunities for Shetland. London: Oxford Publishers.
1. http://www.offshore-environment.com/abandonment.html
2. International law and the Environment by Patricia Birnie, Alan Boyle and
Catherine Redgwell, 3rd edition, Oxford University Press, 2009
3. http://www.edcnet.org/learn/current_cases/offshore_oil/rigs_to_reefs/
4. http://www.environmentaldefensecenter.org/learn/current_cases/offshore_oil/
rigs_to_reefs/Final_EDC%20letter%20to%20OPC%20re%20OST%20study%206-
24-10.pdf
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developments on the Russian shelf.
Oil pollution of the sea - oil pollution of the marine environment, including sources and
volumes of oil input.
Oil and gas accidents - information on drilling, transportation and storage accidents during
the offshore oil and gas activities.
Gas impact on water organisms - gas impact on fish and other marine organisms is
considered. Results of field and laboratory studies, including biological consequences of
accidental gas blowouts are discussed.
Natural gas in the marine environment - chemical composition and biological impact of
natural gas in the sea.
Spilled oil in the sea - fate, transformations and behaviour of oil and oil hydrocarbons in the
sea during an oil spill.
Environmental Impact of the Offshore Oil and Gas Industry, including the impact of
decommissioning, abandonment and removal off the offshore installations, click here.
Reviews of Environmental Impact of the Offshore Oil and Gas Industry by Stanislav Patin