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Prospectivity of the Ultra-Deepwater Gulf of Mexico
Roger N. Anderson & Albert Boulanger
Lean Energy Initiative
Lamont-Doherty Earth Observatory
Columbia University
Palisades, New York 10964
http://www.leanenergy.ldeo.columbia.edu
Overview
The oil and gas industry and the United States government both face tremendous
challenges to explore discover, appraise, develop, and exploit vast new hydrocarbon reserves in
waters deeper than 6000 feet in the ultra-deepwater of the Gulf of Mexico. Yet these new
reserves of hydrocarbons are needed to offset the economically detrimental, long-term decline in
production from within the borders of the United States (Figure 1).
Figure 1. The Sigsbee salt sheet (white) defines the ultra-deepwater at the boundary of the continental margin
and deep basin of the northern Gulf of Mexico. It’s southern terminus is marked by an 800 meter escarpment,
and the whole salt sheet is moving downhill to the south at several cm/yr. (from Advanced Resources
International, “Assessment of Natural Gas and Oil Supply in the Deepwater Gulf of Mexico Due to Technology
Advancements”, June 2001 and Oligney, R., J. Longbottom, and M. Kenderdine, Ultra-deepwater R&D
Program Needed, Hart’s E&P, Sept 2001.)
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Industry estimates of the hydrocarbon potential of the deep and ultra-deepwater in the
Gulf of Mexico range as high as 46 billion barrels of crude oil equivalent (boe) (see OCS Report
MMS 2000-022). That the nation will need these additional new reserves is evident from the
ever-increasing gap projected between continuing increases in consumption of hydrocarbons and
declining U.S. oil production estimated by the Energy Information Administration (Figure 2).
Recent oil and gas discoveries with colorful names like Crazy Horse, Thunder Horse, Atlantis,
Holstein, Mad Dog, Kings Peak, Diana Hoover, Auger, Mars, Na Kika, Neptune and Ursa have
demonstrated the potential of the ultra-deepwater in the Gulf of Mexico to fill some of this gap.
However, the production capabilities of the ultra-deepwater reservoirs in water depths from 6,000
to greater than 10,000 feet, remains largely a mystery at this time.
Figure 2. Filling the ever-increasing gap between U.S. supply and demand will require voluminous production
of hydrocarbons from the ultra-deepwater Gulf of Mexico. This, in turn, will require a deliberate, focused,
cooperative effort of industry, academia, and government to develop the needed technologies that will reduce
the costs of producing from such water depths (from Energy Information Agency, DOE, OCS Report MMS
2000-022 and Economides and Oligney, The Color of Oil, Round Oak Publishing, 2000).
The ultra-deepwater foldbelts that extend from the deep basin of the Gulf of Mexico up
and under the Sigsbee salt sheet of the continental margin contain what the oil industry calls a
significant new play concept. Carbonate production might extend northward from the prolific
Campeche Basin of offshore Mexico and the Golden Lane near Tampico to the Mexican Ridges
and as far north and east as Florida and maybe even all the way back around to Cuba (Figure 3).
Large "world-class" structures have been identified and drilled from the Perdido Foldbelt of
offshore Texas to the Mississippi Fan Foldbelt of Louisiana, Mississippi, Alabama and Florida,
although no means currently exists to produce oil and gas to market from such water depths!
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Figure 3. The Ultra-deepwater Gulf of Mexico is defined by the Sigsbee salt sheet (orange) to extend from the
Perdido Foldbelt in the west to the Mississippi Fan Foldbelt (white) in the east and the Mexican Ridges to the
south (deep blue). There is no current oil or gas production from under the salt sheet or from any of the
Foldbelts. but billions of barrels have already been discovered there.
The ultra-deepwater foldbelts in U.S. waters are comprised of large northeast-southwest
trending compressional “box folds.” Volume potential in this province is tremendous, with
dozens of box folds providing 1-2 billion boe reserve potential EACH. The largest box fold in the
Perdido Foldbelt is the size of Washington D.C. and contains over 14,000 feet of stratigraphic
closure spread over more than 50,000 acres. Additional folds and resultant volume opportunities
are believed to exist under the Sigsbee salt sheet that bounds the Perdido, Walker Ridge and
Mississippi Fan Foldbelts on three sides. This sub-salt component to the play could extend its
impact into much shallower and thus more accessible water depths (see yellow of Figure 4).
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Figure 4. The sediments that make up the new Carbonate Play concept in the Ultra-Deepwater Gulf of Mexico
(yellow) form an extensive, but deep reservoir target. Most current production from offshore Texas and
Louisiana is from shallower deltaic sands that cover the carbonates in 20,000 feet or more of sediments.
http://www.research.ibm.com/resources/magazine/1998/issue_1/quest198.html
If successfully developed, the new play concept would fill an essential gap in the overall
strategic defenses of the United States by decreasing the gap that results in the nation's
dependence on foreign oil and gas reserves in this volatile and hostile, post 9/11 world. However,
the successful production of oil and gas from this new carbonate play concept requires much
more cost-efficient evaluation and appraisal technologies than exist today to economically
conduct exploration, appraisal, and development activities. These new technologies must be
developed before production can be practical in the ultra-deepwater operating environment
(Figure 5).
The Ultra-Deepwater and Unconventional Gas Trust Fund of the DOE has as its mission
to cut costs and time-to-market not incrementally, but radically, so that the United States can
optimally utilize these strategic hydrocarbon reserves. The DOE, with extensive industry,
academic and non-governmental assistance, developed an Offshore Technology Roadmap, which
identified 1) High Intensity Design, 2) Accelerated Reservoir Exploitation, 3) New Drilling
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Technologies (both surface and sub-sea) and 4) Environmental Stewardship as critical systemwide improvement areas required for successful development of ultra-deepwater reserves.
http://www.fe.doe.gov/oil_gas/reports/ostr/roadmap.html
Figure 5. New surface and sea floor technologies will dot the ultra-deepwater landscape in the future if
technological development produces the required paradigm shift. Modern production technologies from
deepwater Brazil and West Africa will have to be streamlined and adapted to the ultra-deepwater Gulf of
Mexico (upper left image from OCS Report MMS 2000-022, upper right from DeepStar, and lower image
from Anderson, Scientific American, March, 1998).
The monies from the trust fund will be invested in the development of a more efficient,
integrated production system. If successful, production from the ultra-deepwater will result in
vastly more royalty revenues than from the current, dwindling supply – a true investment in
America’s future economic well being.
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Prospectivity
Significant hydrocarbon reserves must be discovered within the borders and economic
boundaries of the United States by the end of this decade to make any impact on this decline.
Furthermore, it will not be enough to concentrate on the low volume end of the production
spectrum. Enhanced oil recovery projects provide limited assistance in reversing the decline in
United States hydrocarbon production. For example, Cambridge Energy Research Associates
(2002) estimates that 4D Time-Lapse Seismic technologies, some of the most promising new
secondary recovery methods, can add 3 to 5% to U.S. recovery.
Enormous quantities of oil and gas have been discovered in reservoirs in the shallow
waters (0-1,500 feet) of the Gulf of Mexico since 1950. However, most of this oil and gas has
already been produced and delivered to markets. The major realm for present exploration is in the
deepwater (1,500-4,000 feet), and future prospectivity will take us into the ultra-deepwater (4,000
to >10,000 feet). However, the current production technologies of oil companies are confined to
reservoirs in water depths up to approximately 7,000 feet, and only exploration efforts are
focused on greater ultra-deepwater depths at this time.
The deepwater Gulf of Mexico province from 1000 to 4000 feet of water depth offers rates
of production and volumes of sufficiently increased size to have already impacted domestic
production (Figure 6). The Thunder Horse discovery by itself contains an estimated recoverable
volume of up to 2 billion barrels crude oil equivalent (boe) and both the Mars and Ursa fields are
producing over 125,000 barrels of oil per day from only a few horizontal wells each.
Figure 6. The deepwater has produced at significantly greater production rates, as can be seen from the
heights of the columns reflecting the barrels per day (bpd)in the offshore Gulf of Mexico wells. Yellow is less
than 1000, green 1000-5000, and red is greater than 25,000 bpd. The deepwater is shown in light blue, the
ultra-deepwater is in blue and dark blue (from OCS Report MMS 2000-022).
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Production in the deepwater province is centered in turbidite sands recently deposited
from the Mississippi delta. Even more prolific rates have been recorded in the carbonates of
Mexico, with the Golden Lane and Campeche reporting 100,000 barrel per day production from
single wells. However, most of the deep and ultra-deepwater Gulf of Mexico is covered by the
Sigsbee salt sheet that forms a large, near-surface “moonscape” culminating at the edge of the
continental slope in an 800 meter high escarpment (Figure 7).
The ultra-deepwater Foldbelts in the northwestern Gulf of Mexico of offshore Texas and
Louisiana represents the largest of these anticlinal structures, within which might reside supergiant hydrocarbon reserves. Each objective horizon has approximately 6,000 feet of vertical
closure. As such, the anticlinal structures contain volumetric closures that are many times larger
than Ekofisk, the largest oil field in the North Sea. The North Sea has produced about 10 billion
boe, to date. Other foldbelt anticlines are believed to be buried beneath the Sisgbee salt sheet
throughout the ultra-deepwater in the United States territories of the northern Gulf of Mexico
basin. If the poorly imaged subsalt region between the Perdido and Mississippi Fan contains
anticlinal structures, this would represent a tremendous untested exploration opportunity that
would make prospectivity of the Alaskan National Wildlife Reserve (3 to 10 billion boe,
according to the USGS), pale by comparison.
Figure 7. The carbonate play of the ultra-deepwater is buried under the Sigsbee salt sheet that produces the
moon-like, cratered appearance on the seafloor. The escarpment at the right forms an 800 m cliff onto the
abyssal plain of the Gulf of Mexico proper. The only discoveries to date have been from the mini-basins that
form the crater-like holes in the salt sheets horizontal cover. (NOAA image).
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Opportunity
There has been a significant shift of resources, capital, and technologies overseas since the
reconfiguration and mega-mergers of the oil industry that began in 1998. From an industry
dominated by American firms, it has evolved into an global commodity business driven by low
costs. Now, significant portions of the world's oil industry, not just its reserves, are controlled by
international companies. That said, oil and gas exploration is attractive in the United States
because of the stable political climate and robust energy markets. However, United States crude
oil output has been dropping yearly since 1986, not only because vast numbers of marginally
profitable oil and gas wells have been shut-in, but also because no new super-giant, greater than 1
billion barrel fields had been found within our borders since the discovery of oil on the North
Slope of Alaska in the late 1960's. That all changed with the milti-billion barrel Crazy Horse
discovery in the ultra-deepwater Gulf of Mexico in 1998 (now called Thunder Horse).
Before plans to produce ultra-deepwater reserves can move forward, however, many
economic and technological hurdles must be overcome. Of key importance are assessments of
reservoir producibility, hydrocarbon quality and the ultimate recoverable reserve volumes. A
discovery containing volumes approaching 1 billion barrels recoverable is believed to be required
to support an ensuing development project, which may cost upwards of $1 to $2 Billion dollars in
up-front Capital Expenditures (CAPEX).
Industry has many cheaper and more easily accessible reserves accessible in Russia, the
Caspian Sea and offshore of Western Africa. Consequently, the U. S. Energy Bill of 2002 has
allocated significant resources to fund innovative industry, academic, and national laboratory
research initiatives to develop the new technologies necessary to explore and produce these new
ultra-deepwater reserves economically. The purpose is not only to impact the national defense,
but also to regain our international technological leadership in the deepwater, recently lost to the
Brazilians, Norwegians, and Europeans.
A number of new American jobs are expected to result from successful development of
the ultra-deepwater, just as previous offshore and deepwater projects have created jobs. For
example, the engineering, fabrication, and deployment of the deep water Auger platform alone
employed over 900 separate companies in 33 states. As other U.S. production winds down, ultradeepwater projects will become increasingly important to maintaining a healthy and viable
domestic energy industry. A DRI1 study from 10 years ago concluded that jobs created as a
result of exploration and development of U.S. deepwater potential would reach a peak of between
80,000 and 100,000 by 2010. Between 50,000 and 70,000 of those jobs would be sustained well
into the next decade. Furthermore, the study predicted that the economic activity created by
deepwater development has resulted in net royalty income to the Federal treasury of a cumulative
$10 billion by the end of 2000. These revenues and jobs have been realized to the point that the
Congress, never a big friend to energy interests, has acted to create the Ultra-deepwater Trust
Fund that would add an astounding $200 billion by 2017, if successful at developing the new
production technologies required.
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DRI Report “National Economic Impact of an Oil/Gas Production Tax Credit to Facilitate Deepwater Exploration
and Development” McGraw-Hill, June 24, 1993.
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Petroleum System
In addition to the carbonate play, the large salt-related structures, prolific turbidite sands,
widespread source rocks, and a favorable thermal regime are key additional factors that comprise
the ultra-deepwater petroleum system. Significant economic risks and technical hurdles still must
be overcome to profitably develop the likely large accumulations in the ultra-deepwater, however.
First, we will review the petroleum system of the sub-surface, and then we will turn to the
significant economic and technical hurdles in the surface.
Structure and Stratigraphy
Salt is the dominant structural element of the ultra-deepwater Gulf of Mexico petroleum
system. Large horizontal salt sheets, driven by the huge Plio-Pleistocene to Oligocene sediment
dump of the Mississippi, Rio Grande and other Gulf Coast Rivers, dominate the slope to the
Sigsbee escarpment. Salt movement is recorded by large, stepped, counter-regional growth faults
and down-to-the-basin fault systems soling into evacuated salt surfaces. Horizontal velocities of
salt movement to the south are in the several cm/year range, making this supposedly passive
margin as tectonically active as most plate boundaries. The Sigsbee salt sheet is presently
overriding the Foldbelt, an area of compressional Northeast to Southwest trending folds caused
by gravity sliding initiated in Middle to Upper Oligocene time (Figure 8).
Figure 8. Structure and reservoirs in the ultra-deepwater flodbelts, currently being over-ridden by the Sigsbee
salt sheet.
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Seals for the foldbelts are thought to be interspersed with the reservoir rocks throughout
the stratigraphic section due to the deepwater environment of deposition. One key interval felt to
have a very high probability of having seals is the Eocene. Reservoir-quality rock, structural
closure, seals, and hydrocarbons are all thought to be present in the anticlinal structures in the
Foldbelts.
The folds that can be mapped are found within embayments and holes through the
Sigsbee salt sheet in water depths ranging from 7,200 to 10,000 feet. The timing of the formation
of the folds is constrained by seismic correlations made from the DSDP cores 90 and 91 some
200 miles to the south. The folds are salt-cored and many of the folds show evidence of bidirectional reverse faulting. Hydrocarbons can be expected to be trapped in a variety of structural
as well as stratigraphic settings, if the deepwater is any example. Trap types there include: salt
flank (Bullwinkle), salt/fault (Auger), fault (Genesis, Joliet), stratigraphic (Ram-Powell), and
combination salt/fault/stratigraphic (Mars and Ursa).
The shallowest structure in the Perdido Foldbelt, for example, is the giant Baha structure
located in Alaminos Canyon in 7400 feet of water. There are 10 OCS blocks in faulted, simple,
four-way closure. Seismic sections show over 14,000 feet of stratigraphic section that is within
closure in the anticline. The area of closure exceeds 50,000 acres, making it the largest untested
anticlinal structure in the Gulf of Mexico visible with today’s technology. Seismic velocities
decline over the crest of the structure, perhaps indicative of porosity and/or hydrocarbon
occurrences in 4 different pay zones within the anticline. Two intervals are believed to be
comprised of turbidite sands, one of fractured and porous chalks, and one of fore-reef carbonate
debris analogous to the Tamabra reservoir in the fabled and prolific Poza Rica Field of Tampico
in the Golden Lane of Mexico (Figure 8).
Reservoirs
The key technical hurdles facing foldbelt exploration are rates of possible
production and ultimate reserve sizes of the reservoirs. The Mississippi River, Rio Grand, and
other rivers to the east and west have supplied vast quantities of sand to the deepwater. The
sediment has been trapped in salt bounded intra-slope basins and transported to unconfined
settings down-dip by turbidite currents. Gravels have been discovered not only in cores taken
from the Mississippi Fan in Leg 96 of the Deep Sea Drilling Project (DSDP), but also from
Miocene rocks at a depth of more than 17,000 feet in Mississippi Canyon block 657. This is more
than 100 miles down-dip from the time-equivalent Miocene-aged sands that have also been
encountered in the Western Gulf of Mexico in DSDP cores 90 and 91. More than 440 net feet of
Miocene and Pliocene oil bearing sand in 14 stacked pay horizons were found in the Mars basin
(MC blocks 763 and 807), amply supporting a model for voluminous sand supply to the
deepwater and the capability of turbidity currents for transporting sands great distances.
Porosities over 30 percent and permeabilities greater than one darcy in deepwater turbidite
reservoirs have been commonly cited. Compaction and diagenesis of deepwater reservoir sands
are minimal because of relatively recent and rapid sedimentation. Sands at almost 20,000 feet in
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the Auger field (Garden Banks 426) still retain a porosity of 26% and a permeability of almost 350
mdarcies. Pliocene and Pleistocene turbidite sands in the Green Canyon 205 field have reported
porosities ranging from 28 to 32% with permeabilities between 400 mdarcies and 3 darcies.
Connectivity in sheet sands and amalgamated sheet and channel sands is high for deepwater
turbidite reservoirs and recovery efficiencies are in the 40-60% range.
The high production potential of ultra-deepwater reservoirs is documented by recent
results at the Mars field. Flow rates at Mars from turbidite sands have been reported as high as
50,000 barrels of oil per day per well, far surpassing the previous Gulf of Mexico single well
record of 12,000 barrels of oil per day at Auger.
The carbonates are even more prolific, if the Mexican analogy holds. The Poso Rico
carbonates from the Golden Lane supported production from a “controlled blowout” into a
famous “oil lake” that grew by 100,000 barrels per day in the early part of the 20th century.
Hydrocarbon Source and Charge
Hydrocarbon source rocks are rich and widespread in the deepwater Gulf of Mexico.
Thermal and maturity modeling demonstrate that probable Mesozoic source rocks have entered
the oil window throughout most of the ultra-deepwater province. Expelled hydrocarbons migrate
along vertical entry points at salt flanks and regional faults until permeable sands or carbonates
are encountered. The hydrocarbon mix is fairly even between oil and gas. Much of the free gas
discovered in the ultra-deepwater to date is bacterial methane, though large thermal gas
accumulations have been tested in the deepwater Viosca Knoll area.
In contrast to shelf crudes, most deepwater oils are moderately sour (0.5-2.0 wt. % sulfur).
API gravity ranges from 15 to 60 API, with most crudes falling between 25 and 35 API.
However, ultra-deepwater oils are similar to the sweet, low sulfur, high gravity oils more typical
of the shelf. Natural hydrocarbon seeps and mud volcanoes at the sea floor attest to present day
migration of hydrocarbons and fluids along faults throughout the ultra-deepwater. More than 180
seafloor seeps from across the western Gulf of Mexico slope have been reported (Figure 9).
Numerous Alvin deep submersible dives have identified and sampled seeps and gas hydrates
emanating from faults that break the surface on top of these anticlines. In addition, active
chemosynthectic communities of tubeworms and bacterial mats have been discovered feeding off
some of these seeps. Analyses of the hydrocarbon seeps taken from piston cores indicate that the
oils are of high quality and low sulfur.
The organic source rock for the Foldbelts is Cenomanian-Turonian in age. Maturity
modeling shows that most of the Foldbelt of the Sigsbee salt sheet area is within the oil maturity
window. To the south of the Sigsbee escarpment, however, anticlines are currently in the
condensate maturity window. Models of maturity as a function of time indicate that most
Foldbelt structures were developed prior to the period of maximum oil expulsion (vitrinite
reflectance range of 0.7 to 0.9), which supports large accumulation potential.
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Figure 9. Oil seeps as imaged from space. Satellites that map with radar detect the unusual smoothness of the
sea surface when seeps are present. Blow-up of reflectivity image of the ocean surface showing oil seeps
(black, snakelike trails) from Ultra-Deepwater Gulf of Mexico with emission point centered on Perdido
Foldbelt of Alaminos Canyon.
Technological Innovation
The Capital Expenses (CAPEX) and Operating Expenses (OPEX) of designing, building,
fabricating, drilling, installing, and operating for 20 years or more the “factories” to produce these
hard-to-get reserves must be cut substantially (like in half) if we as a nation are to benefit from
the harvesting of these ultra-deepwater reserves – a truly Grand Challenge. Production
technology breakthroughs even more revolutionary than those of the DeepStar program for the
deepwater will be required to produce hydrocarbons in the ultra-deepwater. Even then, the time
frame required to bring the new ultra-deepwater discoveries to market may exceed 10 years. In
the meantime, U. S. oil production will continue to decline. New technologies such as low cost
evaluation methods, slimhole drilling and lean engineering design/build processes will be required
to facilitate exploration activities in ultra-deepwater frontier regions such as the Foldbelts and the
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surrounding sub-salt play. Ultimately these technologies will help reduce the cost, and the time
necessary to bring ultra-deepwater oil and gas production to the U.S. marketplace.
Both software and human process re-engineering are required. The existing upstream
energy industry is characterized by relatively low levels of information/knowledge sharing and
collaboration between stakeholders (Esser and Anderson, OTC, 2000). Other industries, such as
electronics, pharmaceuticals, and the military, have also overcome these hurdles by converting to
a software-controlled, “Hard-Wired” learning environment. These “far-field” industries have cut
product development costs up to 25%. Exemplary in this regard is the “Toyota” manufacturing
process of the 1980’s, that converted the company from the maker of “junk cars” to the industry
leader in sophisticated engineering with its Lexus brand. The aerospace industry quickly picked
up these technologies and extended them. Perhaps the most famous implementation was the
Boeing 777, known worldwide as the “Paperless Airplane”. Boeing has designed and built 4 new
airframe generations since the 777 and CUT costs and CUT time-to-production HALF-AGAIN
for each with its “Digital Manufacturing Process”.
The integrated processes and tools responsible for this improvement should be applicable
to the energy industry (Anderson and Esser, The Energy Company as Advanced Digital
Enterprise, American Oil & Gas Reporter, Jan. 2001.). There are several key similarities between
aerospace and the upstream energy industry, for example. They each have numerous contractors
and suppliers located all across the globe. There are both close collaborative relationships and
sometimes, open hostility between management, contractors and workers. There are varying
levels of Information Technology sophistication amongst contractors and suppliers, who use
multiple technical software applications for the same tasks. There are data security issues.
Lean Engineering Systems
Success in the far-field has spawned a new practice, called “Lean Engineering” (Figure
10) that has dramatically cut the cost of communicating numerous design updates to contractors
spread across various locations, added real time monitoring of project progress, and timely
approval of design changes. The latter alone has cut the number of design modifications in half.
(See http://lean.mit.edu).
A paradigm shift to Lean Engineering management should immediately affect positively
on the cash flow and profitability of the ultra-deepwater developments (Figure 11). The DOE
roadmap envisages “High-Intensity Design,” described as a methodology and tool set that seeks
to integrate concurrently all design processes one fully integrated design addressing planning,
construction, and operation. This is the very definition of Lean Engineering. Economics,
appraisal, reservoir management, surface, underground facilities, well construction, and drilling,
all will have to be upgraded dramatically, and not incrementally, in the upstream to get there. In
fact, conversion to such hard-wired management practices is likely required if the Thrust Fund is
to succeed in making a substantial difference. It is ironic that the downstream oil industry has
implemented many of the Lean Engineering tools and processes over the last 10 years, driven by
incredibly slim profit margins and cost pressures. Few of these systems management approaches
have propagated to the more “profitable” upstream. Refineries, petrochemical and LNG plants
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are already managed with Enterprise Resource Planning software and operated by plant
optimization software
Figure 10. From http://leanenergy.ldeo.columbia.edu and Womack, J. and D. Jones, Lean Thinking (New
York: Simon & Schuster, 1996).
.
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Inefficiencies of the current stovepipe design/build/produce approaches prevalent in the
upstream energy industry are inadequate access to, sharing, and integration of data, insufficient
collaboration among all disciplines and stakeholders (operators, partners and contractors), suboptimal management of projects during execution and poor supply chain management and
maintenance optimization after operations begin. Effects on performance are sub-optimal
portfolio management of assets, poor investment decisions, higher than expected project costs,
repeated cost overruns, physical disasters (like sunken production platforms and loss of life),
longer than planned project delivery cycles, re-action instead of pro-action to problems,
substantial modifications and re-workings due to wrong designs and inflexible specs, and
particularly, mismatches between the realities dictated by the subsurface reservoirs and design
constraints of surface facilities. “Lego Block” modularity has hardly penetrated the upstream
industry to date. The Ultra-Deepwater Trust Fund is intending to cause a paradigm shift that will
fix all these problems through the institution of better, more efficient, Lean Management
practices (Figure 11).
Figure 11. Lean Engineering processes drive an integrated systems approach to design/build/operate
(Anderson, and Esser, The Energy Company as Advanced Digital Enterprise, American Oil & Gas Reporter,
Jan. 2001).
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Managing the new e-define, e-manufacture, e-procure & e-operate world of the ultradeepwater will require a computer software infrastructure that is paperless (digital), that shares a
common database among all projects, that is transparent, enforces integration and understands
portfolio management and real options, that learns, that tracks key performance metrics of all
actions, and that is web-services based so that the infrastructure is collapsed and define, build,
and collaborate can be done from anywhere in the world (Figure 12).
The difference between Lean Engineering and what the upstream energy industry is using
today is that the very best tools for each task are not integrated to implement system-wide Lean
processes. In today’s xml and web-services world of commercial-off-the-shelf software, tools can
be integrated together to produce a totally seamless digital environment. This system is OPEN to
best-in-breed solutions, and it requires owners working together with all sub-contractors in an
intensely collaborative, transparent, digital environment.
Figure 12. Lean Engineering System with Reinforcement Learning loop from
http://www.energypulse.net/centers/article/article_display.cfm?a_id=31
(also see Werbos, P.J., Maximizing Long-Term Gas Industry Profits using Neural Network Methods, IEEE
trans. On Systems, Man, and Cybernetics, Vol. 19, No. 2, 315-333, 1989.
Surface and Sub-Sea Systems
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The major expense in deep and ultra-deepwater exploration is the drilling of the wells
themselves. Fully 50% of all costs are drilling related. New technologies such as Slimhole
Drilling, logging and testing are required to cut these costs. Slimhole drilling combines
conventional oil-field drilling technology with mining exploration diamond drilling techniques.
To further speed the drilling process, all the heave compensation and blowout prevention
equipment can be placed onto the sea floor (Figure 13). Slimhole technologies must also be
applied to, appraisal and testing wells. Expandable casing is a promising first step in this slimhole
technology arena.
Figure 13. Slimhole drilling technologies deployed from the sea floor will have to include heave compensation
to smooth out motion and weight on the drillbit.
Subsurface Systems
Subsurface challenges to the capabilities of existing technologies come from the excessive
water depths, the obscuring salt canopy, and the new geology represented by the deep carbonates
that might be highly fractured and significantly geopressured. New technologies must be
developed for detection at and beneath the drillbit of geopressures, lithologies, physical properties
and fluid compositions. Because of the extreme water depths and ruggedness of the top-of-salt
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surface, imaging beneath the salt canopy in the ultra-deepwater requires the development of new
gravity gradiometry (see http://www.bellgeo.com) and seismic technologies such as 3D, 4D (see
http://www.ldeo.columbia.edu/4d4), and vertical cable seismic surveying (Figure 14). Another
technology that will transform subsurface efficiency is the “downhole factory”. Techniques for
separation of oil, gas and water using equipment embedded in the wells themselves, or perhaps
installed on the sea floor, will strip out water and pump it back into the reservoir. Only the
valuable oil and gas will be produced to the surface at all. And then, perhaps it is more cost
effective to put electric generators out on the ultra-deepwater surface facilities and convert the oil
and gas to electrons, sending them to sore via superconducting sub-sea cables.
Figure 14. Subsurface imaging using submarine remote vehicles and exotic 3D and 4D seismic technologies
such as vertical cables will direct the drillbit with its inertial navigation system and measurement-while-drilling
directly to the oil and gas reservoirs.
Environmental Sustainability
Grand Challenge change is required from an environmental perspective as well by the
goals of the Trust Fund. We suggest that RPSEA adapt a Management System that will help
train a new generation of energy professionals in ways to cope with the radical new
environmental world they will face in the workplace of the future. Specific to the ultra-deepwater
development system will be a sophisticated Information System (including notification and alarm
services, educational packages and automated analytical tools) to teach a new breed of energy
workforce in proper environmental stewardship. On-line facilities and services will train the users
in how to get maximum benefit from emissions simulations, and how to use benchmarking test
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beds to track environmental compliance. Assurance that controls to enhance environmental
quality and reliability are built into the Lean decision support system (including regulatory
constraints and incentives, emission monitoring, and integrated control systems that always
compute the likely environmental impact of each decision) should win over environmentalists
that the new design system is producing a minimal footprint. The design system must account for
environmental upgrades in equipment and controls (including incentive programs for next
generation distributed generation systems) that will surely follow in the coming years, along with
new tools for proper analysis of the environmental impact of all activities in the ultra-deepwater.
New risk assessment, perception and management tools must have environmental as well as
economic risk modules.
The entire system must be made “sustainable and transparent to environmental impact”,
though present day operations of all components of the upstream energy industry are far from
that ideal. The benefits from environmental visibility must be computed and demonstrated in
economically believable terms in the Lean management System. For example, the CO2 might be
scrubbed from all surface facilities and re-injected into the reservoir to enhance recovery
efficiency, a common practice on land where CO2 supplies are abundant (Figure 15).
Figure 15. Condensate can be seen billowing from melting ice from the outside of piping that carries liquid
CO2 back into an injection well designed to enhance recovery by extracting even more oil and gas from the
ultra-deepwater reservoirs.
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© Columbia University
Conclusion
There is a clear realization on the part of all players in the ultra-deepwater arena that a
change from inefficient, adversarial, proprietary, stove-piped systems into lean, collaborative,
integrated systems of technical cooperation of industry with academic and national laboratories is
required to economically bring these hydrocarbons to market. This ongoing paradigm shift is as
significant and as difficult as any of those creating technical breakthroughs in other disciplines
such as aerospace and automotive design.
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© Columbia University
References
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Economides, M., and Oligney, R., The Color of Oil, Round Oak Publishing, 2000.
Esser, W. and Anderson, R., The Advanced Digital Enterprise in the Ultra-Deepwater
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Oligney, R., Longbottom, J., and Kenderdine, M., Ultra-deepwater R&D Program Needed, Hart’s
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