Both the gas industry and United States government face tremendous challenges to deliver the supply required by the increasingly gas-dependent electricity demand in the United States of the 21st century. The U.S. will be hard pressed to build the large number of Liquid Natural Gas terminals that provide the only significant alternative to North American supply increases. Huge new reserves of gas must be brought to market to offset the natural exponential decline in known gas production from within the borders of the United States. We must explore, discover, appraise, develop, and exploit the vast new gas reserves discovered in waters deeper than 1500 meters in the ultra-deepwater Gulf of Mexico if we are to have any hope of meeting this demand increase. In addition, we must deliver to market new gas from deep and tight reservoirs on land, coal bed methane, and Alaska or we may have to ration gas between heating and power, particularly in the Northeast. No one wants to be responsible for such a choice.
Figure 1. Filling the ever increasing gap between U.S. supply and demand (Source EAI/DOE) will require voluminous production of hydrocarbons from the ultra-deepwater Gulf of Mexico, as well as from deep continental supplies, coal bed methane, and new Alaskan, Canadian, and Mexican pipelines. Each year's discoveries are tracked to show their depletion over time in the inlay above (each color is the decline in production from wells drilled that year and tracked for the rest of their productive life).
The United States has struggled since the 1970’s to meet natural gas demand. Throughout the 1980’s, both supply and demand declined as the global economy slowed. Since 1986, demand has shown a dramatic increase caused by the shift from coal to environmentally friendly, gas-fired electric power generation. This natural gas supply/demand gap has grown each year since, even though supply increased somewhat due to exploration driven by higher prices. Beginning in 2000, however, natural gas production in the United States began to actually decline, accelerating the growth of the gap (Figure 1). A major reason for this drop in supply is that all gas and oil fields decline exponentially once they are placed on production. This is an inevitable fact of subsurface physics – both reservoir pressures and recovery efficiencies drop during production. This geological reality can be seen from declines in production of wells identified and tracked by their year of initial production from 1970 to 2000 (Figure 1). More gas must be discovered each year than the year before to replace this declining supply. In fact, the Energy Information Agency (EIA) of the Department of Energy estimates that the U.S. will need more than 8 trillion cubic feet of newly discovered natural gas to supply demand by 2013. Again, this large increase in forecasted consumption is driven by the increase in demand from gas-powered electricity generation. The gap will continue to escalate unless vast new supplies are found and piped to market in North America, and/or Liquid Natural Gas imports are dramatically escalated. Candidates for increased supply are the Alaskan North Slope, deep continental gas, coal bed methane, Canadian imports, and the Ultra-Deepwater Gulf of Mexico. Already, imports have steadily been increasing since 1985, and may exceed 20% of consumption in 2003 (Figure 2).
Figure 2. The increase in imported natural gas into the United States has taken a dramatic increase since 1985 (from the Gas Technology Institute).
The Northeastern United States is facing a particularly tight supply period. As the Independent Services Operators of New England have recently pointed out, the Northeast is short of natural gas pipeline capacity. Even with additional gas supplies from Canada, companies may have to choose heat versus electricity for the limited supply of natural gas in the near future (Figure 3).
Figure 3. Major interstate gas pipelines and LNG facilities in the Northeast. The NY LNG facility is built but has never been approved for operation. Source: Levitan & Assoc, Steady State analysis of New England Gas Pipeline delivery to 2005, ISONE, Jan. 2001).
The fact is that we will need natural gas from all of these sources to supply demand by 2020. However, each has technical, economic and policy problems that must be solved. This paper discusses the prospectivity of the ultra-deepwater Gulf of Mexico, and the technological and economic barriers that require significant new Research and Development, in particular. We know the gas is there, but the petroleum industry does not know how to economically produce it to market. A new paradigm is required.
The Ultra-Deepwater continental margins of the world (defined here as water depths exceeding 1500 meters) have become the “last frontier” of offshore hydrocarbon exploration and development. Gas and oil discoveries in the ultra-deepwater from throughout the world have already exceeded 45 billion barrels of oil equivalents, with 30% of that gas (Figure 4). The Minerals Management Service estimates of the potential of the ultra-deepwater in the United States Gulf of Mexico range up to about 30 billion barrels of crude oil equivalents (boe), with fully one quarter of this projected to be natural gas and gas liquids (OCS Report MMS 2002-021, p. 77).
Figure 4. Global ultra-deepwater oil (green) and gas (red) discovery volumes have increased steadily since 1985. These hydrocarbons are only just beginning to be delivered to market (Walker, SPE, 2003).
Recent oil and gas discoveries with colorful names like Thunder Horse, Atlantis, Holstein, Mad Dog, Kings Peak, Diana Hoover, Na Kika, Baha, and Neptune have demonstrated the potential of the ultra-deepwater in the Gulf of Mexico to fill some of this gas supply/demand gap. However, the production capabilities of the ultra-deepwater reservoirs in water depths from greater than 1500 m to more than 3000m remains largely a mystery at this time, particularly for gas. Water temperatures at ultra-deepwater depths are below the freezing temperature of methane, so any sea-floor pipelines, manifolds and wet trees must mix “anti-freeze” into the gas to keep it from forming gas hydrates (also called clathrates) which can plug the pipes.
Figure 5. 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 in 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. (Sources: Oligney, et al, 2001, Anderson, DOE Ultra-Deepwater White Paper, 1994, http://leanenergy.ldeo.columbia.edu).
This battle between ever depleting gas supply and new methods and inventions required to produce it will require a deliberate, focused, cooperative effort of industry, academia, and government to develop the needed technologies that will reduce the Activation Index, or total costs of finding, developing and producing from such water depths (Economides and Oligney, The Color of Oil, Round Oak Publishing, 2000). The Activation Index for the Gulf of Mexico ultra-deepwater is estimated to be greater than $9000/barrel of oil equivalent produced per day (bpd), compared to $3500/bpd in Venezuela and Saudi Arabia, $2000/bpd for the world average, and $1000/bpd for the shallower shelf of the Gulf of Mexico (Oligney, et al, 2001) (Figure 5). On the good news side, 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. Production from limestone or carbonate reservoirs 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 as offshore Texas and Louisiana, then east to Alabama and Florida, and maybe even looping all the way back around to the south and Cuba (Figure 6).
Figure 6. 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
The ultra-deepwater foldbelts in U.S. waters are comprised of large, northeast-southwest trending “compressional anticlines”. Volume potential in this province is tremendous, with dozens of such anticlines providing 1-2-billion boe reserve potential EACH. The largest in the Perdido foldbelt cover an area the size of Washington D.C. and contain over 4000 meters of potential reservoir thickness. Additional anticlines 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 (Figure 7).
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).
Ultra-Deepwater 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 which make the ultra-deepwater petroleum system attractive. First, we will review the petroleum system of the sub-surface, and then we will turn to the significant economic and technical hurdles at the surface that must be overcome to get the gas to market.
The key technical hurdles facing foldbelt exploitation are rates of production and ultimate reserve sizes of the reservoirs. The Mississippi, Rio Grande, 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 turbidity currents. Porosities over 30 percent and permeabilities greater than one Darcy in deepwater turbidite reservoirs (very high) have been commonly found in the deepwater. Connectivity in sheet and channel sands is high for deepwater turbidite reservoirs, and gas and oil recovery efficiencies are in the extraordinarily high 40-60% range. The high production potential of ultra-deepwater sand 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. The carbonates could be even more prolific, judging by the Mexican analogy. In the early part of the 20th century, the Poso Rico field in Mexico’s Golden Lane near Tampico supported production of >100,000 barrels per day from a carbonate reservoir that seismic mapping has tracked all the way to the north into the Perdido foldbelt of offshore Texas. Hydrocarbon Source and Charge
Hydrocarbon source rocks are rich and widespread in the ultra-deepwater Gulf of Mexico. Thermal maturity modeling demonstrates that probable Mesozoic source rocks have entered the oil window throughout most of the ultra-deepwater province, with the anticlines in > 3000 m of water are currently in the gas maturity window. Expelled hydrocarbons migrate vertically along salt flanks and regional faults until permeable sand or carbonate reservoir rocks are encountered. The hydrocarbon mix, or gas-to-oil ratio is such that up to 10,000 volumes of gas are produced per unit volume of oil, even from oil wells. It is important to note that much of the free gas discovered in the ultra-deepwater to date is bacterial methane, which is usually the “tip-of-the-iceberg” in gas accumulations throughout the world. It is encouraging that in deeper water exploration wells, large thermal gas accumulations have been tested. Natural gas and oil 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 8). Numerous submersible dives have identified and sampled seeps and gas hydrates emanating from faults that break the surface on top of these anticlines. In addition, chemosynthetic communities of tubeworms, giant clams, eels, and bacterial mats have been discovered feeding off many of these seeps. The organic source rock for the foldbelt reservoirs is made up of un-decayed organisms like these, but that lived more than 100 million years ago.
Figure 8. Natural gas seeps as imaged from space. Oil, trapped within the “gas bubbles” released to the sea surface produce unusual smoothness of the sea surface that can be imaged by satellites. Above is a blow-up of a reflectivity image of the ocean surface showing a gas and oil seeps (black, snakelike trails) from the ultra-deepwater Gulf of Mexico with emission point centered on the Perdido Foldbelt of Alaminos Canyon, offshore Texas.
The National 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 with the price collapse of 1997. It can be tracked farther back to the previous price collapse of 1985 that resulted in the closing of most oil industry research laboratories. From an industry dominated by American firms, it has evolved into a global commodity business driven by return-on-investment decisions and lowest cost production. In addition, national oil companies, like Petrobras from Brazil, have grown to control significant portions of the world’s deepwater technology industry, not just its reserves. That said, oil and gas exploration is attractive in the United States because of the stable political climate and proximal energy market. However, United States gas and oil output has been dropping not only because vast numbers of marginally profitable oil and gas wells have been shut-in, but also because no new super-giant fields (defined as greater than 1 billion barrel oil equivalents) had been found within our borders since the discovery of the North Slope of Alaska in the 1960's. That is, until the multi-billion boe Thunder Horse discovery in the ultra-deepwater Gulf of Mexico in 1998.
The petroleum industry has many cheaper and more easily accessible reserves available from Russia, the Caspian Sea and offshore of Western Africa. Consequently, the U. S. Energy Bill of 2003 is considering allocation of significant R&D resources to fund innovative industry, academic, and national laboratory research initiatives to develop the new technologies necessary to explore and economically produce these new ultra-deepwater reserves within American boundaries. The purpose is not only to improve national security and lower our dependence on middle eastern oil and gas, but also to regain our international technological leadership in the ultra-deepwater. A number of new American jobs are expected to result from successful development of our ultra-deepwater. 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, ultra-deepwater projects will become increasingly important to maintaining a healthy and viable domestic energy-supply industry. A recent study by Advanced Resources International (Oligney, et al, 2001) concluded that new jobs created as a result of exploration and development of the U.S. ultra-deepwater would reach a peak of 200,000 by 2010.
However, the successful production of gas, in particular, from the ultra-deepwater requires much more than just the market need. Completely new discovery, appraisal, design, construction, production, operational, and environmental technologies must be developed before that gas can be delivered to market from the ultra-deepwater operating environment.
The DOE, with extensive industry, academic and non-governmental assistance, developed an Offshore Technology Roadmap that outlined the research and development needed to produce from the ultra-deepwater ( http://www.fe.doe.gov/oil_gas/reports/ostr/roadmap.html). The Roadmap identified gaps in our knowledge base that must be filled before successful development can occur. Major new technologies must be invented and integrated into system-wide efficiency increases incorporating 1) High Intensity Lean Design, 2) Accelerated Reservoir Exploitation, 3) New Drilling, Completion and Intervention Technologies, 4) Enhanced Ability to Transfer Energy to Markets, and 5) Environmental Stewardship.
We believe that new ultra-deepwater technologies will dot the landscape of the U.S. Gulf of Mexico in the future only if technological developments like those identified by the DOE roadmap produce the required paradigm shift toward a more efficient, integrated systems-approach prevalent in aerospace and automotive industries today. It is not enough to simply import modern production technologies from oil provinces of deepwater Brazil and West Africa. New methods will have to be invented and adapted to the ultra-deepwater Gulf of Mexico if we are to successfully produce large gas volumes (Anderson, Scientific American, March, 1998).
1) High Intensity Lean Design
The costs of exploring, drilling, designing, building, fabricating, installing, and operating for 20 years or more the ultra-deepwater “factories” to produce these hard-to-get gas reserves must be cut substantially (in half) if we as a nation are to benefit from the harvesting of these supplies – a truly Grand Challenge (Anderson, et al, 2003). Hardware more revolutionary than that developed by the industry’s DeepStar program (www.deepstar.org) will be required. Even then, the time frame required to bring new ultra-deepwater discoveries to market must be cut in half from its present 10 years to make development cost-effective. In the meantime, U. S. gas as well as oil production will continue to decline.
Not only new hardware, but more importantly, software and human process re-engineering are required. The existing upstream energy industry is characterized by relatively low levels of information and knowledge sharing and collaboration among 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, which 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 four new airframe generations since the 777 airliner, and they CUT costs AND time-to-production HALF-AGAIN for each using their “Digital Manufacturing Process” (Esser and Anderson, 2001). The integrated processes and tools responsible for this improvement should be applicable to the energy industry because there are several key similarities between aerospace and the upstream energy industry (Anderson and Esser, 2001). They each have numerous contractors and suppliers located all across the globe. They both require close collaborative relationships that sometimes produces open hostility between management, contractors and workers. They both deal constantly with varying levels of Information Technology sophistication amongst contractors and suppliers, who often use conflicting software applications for the same tasks. They both deal with security issues across their enterprises. Success in the far-field has spawned a new practice, called “Lean Engineering” (see, for example, http://lean.mit.edu) 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 produces timely approval of design changes. The latter alone has cut the number of design modifications in half! A paradigm shift to Lean Engineering management should immediately affect positively on the cash flow and profitability of the ultra-deepwater developments (Figure 9). The DOE roadmap envisages “High-Intensity Design,” described as a methodology and tool set that seeks to integrate concurrently all design processes into one fully integrated, 3D solid design, addressing planning, construction, installation, and operation all at once. This is the very definition of Lean Engineering. Economic evaluation, appraisal, reservoir management, sea floor and subsurface facilities fabrication and installation, well construction, and drilling, all will have to be upgraded dramatically, and not incrementally, if we are to succeed in the ultra-deepwater. In fact, conversion to such hard-wired, Lean management practices is required if development of the ultra-deepwater is to become cost-effective. 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 Lean systems management approaches have propagated to the more “profitable” upstream. For example, refineries, petrochemical and LNG plants are already managed with enterprise resource planning and operated by plant optimization software.
Figure 9. High Intensity Design will convert the ultra-deepwater development from the current 1:5 ratio of time spent in design to construction to the 5:1 ratio common to Lean Manufacturing (from Anderson, et al, 2003, http://leanenergy.ldeo.columbia.edu and Womack, J. and D. Jones, Lean Thinking (New York: Simon & Schuster, 1996).
Inefficiencies in the current stove-piped design/build/produce approaches prevalent in the upstream energy industry are inadequate access to, poor sharing and integration of data, insufficient collaboration among all disciplines and stakeholders (operators, partners and contractors combined), sub-optimal 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 losses 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 specifications, and particularly, mismatches between the realities dictated by the subsurface reservoirs and design constraints of surface facilities. The “Lego Block” modularity prevalent in the aerospace and automotive industries has hardly penetrated the upstream energy industry to date.
Managing such a new e-define, e-manufacture, e-procure & e-operate world of the ultra-deepwater will require a computer software infrastructure that is paperless (digital), that shares a common database among all projects, that is transparent, that 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 collaboration can be done from anywhere in the world, 24/7.
The major difference between Lean Engineering processes and what the upstream energy industry uses today is that the very best tools for each task are not integrated to implement system-wide, 3-D solid design processes. In today’s xml and web-services world of commercial-off-the-shelf software, tools can be integrated together to produce the required, totally seamless digital environment. This system must then be kept OPEN to best-in-breed solutions. In addition, all stakeholders must work together, owners with all their contractors, in an intensely collaborative, transparent, digital environment. The Ultra-Deepwater must undergo just such a “Lean Management “ paradigm shift before any of the other required technology breakthroughs discussed below can make the ultra deepwater a return-on-investment worth pursuing.
2) Accelerated Reservoir Exploitation
New technologies such as low cost, sub-salt imaging methods, slimhole drilling, and new reservoir drainage designs in the subsurface will be required to facilitate exploitation in ultra-deepwater frontier regions such as the foldbelts and the surrounding sub-salt play. Sea floor gathering systems called “wet trees” and reservoir monitoring with seismic and other geophysical monitoring systems will have to be adapted for the ultra deepwater. Ultimately these technologies will help reduce both the cost and the time necessary to bring ultra-deepwater oil and gas production to the U.S. marketplace. 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 of geopressures, lithologies, physical properties and fluid compositions ahead of the drill bit. Because of the extreme water depths and ruggedness of the top-of-salt 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 10). 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.
Figure 10. 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 sensors directly to the oil and gas reservoirs (Anderson, DOE Ultra-Deepwater White Paper, http://leanenergy.ldeo.columbia.edu).
3) New Drilling, Completion and Intervention Technologies
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 riserless drilling systems, integration of all measurement-while-drilling systems, high flow capacity wells, expandable casing, and new sea floor work-over systems will have to be developed. Slim-hole drilling, which combines conventional oil-field drilling technology with mining exploration diamond drilling techniques, promises to cut costs dramatically. Expandable tubulars and casing strings must become widespread (see http://www.welldynamics.com). To further speed the drilling process, all the drilling and blowout prevention equipment may have to be placed on the sea floor and operated remotely, thus eliminating risers and moorings and drastically shortening operational time.
Complex well architectures in which multiple horizontal wells intersect to form an extensive “drainage basin” for each reservoir offer great promise for improving recovery efficiency (Figure 11). The economics favor using slim-hole feeder wells in such a complex well architecture to achieve lower field development costs with higher ultimate recoveries and a smaller surface footprint. The latter is especially important if wet trees are required at the sea floor, as is likely in the ultra-deepwater.
Figure 11. Complex well architecture requires accurate subsurface steering (left), precise placement of production and injector wells (center) and complex intersections of multiple wellbores (right) (source: Well Dynamics Inc).
4) Enhanced Ability to Transfer Energy to Markets
Research must be directed into developing Floating Processing, Storage, and Off-Loading (FPSO) facilities that might contain small scale LNG and compressed natural gas facilities, and even offshore power generation to further lower or eliminate entirely the environmental footprint (Figure 12). Superconducting power cables buried in the sea floor could carry electricity to market without requiring that the natural gas even be transported off site in the ultra-deepwater. Offshore ultra deepwater facilities would lower the terrorism threat to these operations (especially LNG loading and unloading). Ultimately, electricity might even be produced by generators placed downhole with no wasteful energy loss from delivering the gas to the surface even required. These technologies are not that far into the future. Sea floor separation and processing units are already being tested underwater off Norway.
Figure 12. Floating Processing, Storage, and Off-Loading (FPSO) can be extended to include LNG refrigeration, CNG compression, and maybe even offshore electricity generation facilities (Anderson, Scientific American, 1998). The electricity might then be brought to shore using superconducting underground cables.
5) Environmental Sustainability The natural gas from the ultra-deepwater will be needed by the U.S. because of the significant shift from coal to gas fired electricity generation that has occurred since 1985. That alone has produced significant air quality improvements and lowered pollution levels. However, Grand Challenge change is required from a global warming perspective, as well, by the goals of producing abundant gas and oil from the ultra-deepwater Gulf of Mexico. Specific to the ultra-deepwater development system must be a sophisticated information system that includes notification and alarm services, environmental monitoring packages, and automated analytical tools to track 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 beds to track environmental compliance. The fact that controls to enhance environmental quality and reliability would be 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 convince environmentalists that the new design system is producing an optimal 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. The entire system must be made “sustainable and transparent to environmental impact” through the use of risk assessment, perception and management tools that have environmental as well as economic evaluation modules. The benefits from environmental visibility must be computed and demonstrated in economically believable terms in the ultra deepwater Lean management system. For example, CO2 might be scrubbed from all surface facilities and re-injected into subsurface reservoir to enhance recovery efficiency, a common practice on land when CO2 supplies are abundant (Figure 13). Using Lean management systems, truly zero emissions are an attainable target for the ultra-deepwater!
Figure 13. 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.
All this must lead to a clear realization on the part of all players in the ultra-deepwater arena that a paradigm change is required from the inefficient, adversarial, proprietary, stove-piped fragmented systems of the present into Lean, efficient, collaborative, integrated systems of the future if ultra deepwater gas is ever to make it to markets in the U.S. This Grand Challenge can only be confronted with the co-operation and collaboration of industry, academia, and the national laboratories. Otherwise, the gas from this vital resource will never make it to market. This Lean management paradigm shift is as significant and as difficult as any of those creating technical breakthroughs in other disciplines such as aerospace and automotive design, where they have already attained these admirable goals. The R&D program discussed above would engage the U.S. energy industry in a way that creates more U.S. jobs, creates more U.S. technology exports, enhances U.S. domestic security, and leverages the intellectual capital of U.S. entrepreneurs, all using market forces, capitalist principles, and new public-private partnerships to achieve this needed national goal. Left to their own means, the petroleum industry will simply not develop the innovations required by this Lean management paradigm shift in a time frame beneficial to the nation. Since 9/11, “the new era ahead demands a level of public engagement from business leaders that we have not seen in half a century” (Garten, 2002), and such “Corporate Citizenship” will be required to deliver the abundant gas of the ultra-deepwater Gulf of Mexico to markets in the United States.
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