Roger N. Anderson
Lamont-Doherty Earth Observatory
Palisades, N.Y.
It is the mission of the world's oil industry to provide sufficient supplies to keep the engine of international commerce operating far into the next century. To date the technologies of the upstream industry have been wholly devoted to production from reservoired hydrocarbon "Pools."
During a Global Basins Research Network (GBRN)/Department of Energy/oil industry joint cost-sharing project to develop new dynamic technologies for extracting hydrocarbons from the migrating "streams" that feed these reservoirs, we have confirmed the importance of collaboration aimed at the proving of new play concepts within U.S. borders.
If undertaken immediately, an even more expanded national collaboration to book new U.S. petroleum reserves could provide economic revitalization as early as 2010.
INTRODUCTION
A significant change in direction is required if U.S. long term energy needs are to be met in an economically sound manner.
At present, the U.S. is reliant for its future energy supplies upon the major international and domestic oil companies, and the national oil companies of other countries, primarily those of the Organization of Petroleum Exporting Countries. We depend on these corporations to supply the crude oil and natural gas that drive our economy - through whatever sources are available to each company.
For example, when OPEC countries export oil to the U.S. it is usually through purchases by one of the international majors. The oil company then transports, refines, and markets the end product at outlets in the U.S.
When the decline in U.S. production of hydrocarbons is factored into this ever growing dependence on external supply, the U.S. is left with increasingly gloomy economic prospects into the next century.
It has become increasingly evident that there has been a significant shift of resources, capital, and technologies overseas in conjunction with the cratering of the U. S. oil industry during the late 1980s.
The number of wells being drilled in the U.S. has decreased precipitously.
Concurrently, crude oil output has dropped at an alarming rate in the U.S. since 1986.
The supply left within U.S. borders into the next century looks exceedingly tight (Fig. 1-A).
Although the world is awash in hydrocarbons at the moment, the shift in exploration from the U.S. to overseas will shift our balance-of-payments evermore into the red as more and more oil is imported to satisfy climbing U.S. internal needs (Fig. 1-B).
This flight of exploration is both an economic and geological problem. The perception is that there are no more "elephants," i.e., no more billion-barrel oil fields to find in the U.S. that are not under lands banned by Congress from exploration in the foreseeable future.
Fundamental to this predicament is the cost of discovering a new barrel of oil in the U.S. today. It is to the United States' economic advantage to produce much more oil than we import, even if it were to cost $20/bbl to produce. However, it is not in any oil company's interest to produce oil at more than about $6/bbl at the present time because their overhead and profit requirements make that a break-even point. No foreign national oil company has to produce oil at such costs.
The U.S. government must occupy a significant upstream niche if we are to correct this ominous collapse of U.S. production. Unless the U.S. becomes even more active in booking new reserves within her boundaries, large volumes of hydrocarbons will go unexploited. Compounding this problem is the present economic disincentive favoring a shut-in of existing production.
FUTURE BIG U.S. PLAYS
So why worry? The industry is inherently cyclical.
However, there is sound economic evidence to believe this flight of oil company capital from the U.S. may be different this time around.
For example, we have never before seen such a drastic cut in the U.S. technical workforce. Since 1986, employment in the oil industry in the U.S. dropped precipitously, mostly in well-paying, white collar jobs.
Where does that leave the U.S.? It very likely leaves it without even marginally adequate petroleum resources remaining within its boundaries by the year 2010.
We are now dependent upon imports (largely from OPEC) for more than 50% of daily crude oil needs. If something new isn't discovered soon, all the major fields in the U.S. will be played out very soon, including the Alaska North Slope onshore and offshore and the Gulf Coast. Why? Because few companies, major or independent, can afford to take the economic risk to explore for giant fields in the U.S. today, and it may take 20 years or more to fully exploit a large new oil play.
THE NATIONAL INTEREST
This trend is trouble! Something must be done by the U.S. government, traditionally an antagonist to the major oil companies, to correct the situation.
What is needed is a concerted, collaborative, national exploration effort to discover new play concepts, preferably together with the remaining major and independent oil companies active in the U.S., and particularly with the major geological research laboratories in the country.
There are already significant monies spent by the U.S. government on fossil fuel research, principally by the DOE. How much of an increase in "booked reserves" does this research currently result in? Not much, but this is changing. The government is beginning to develop mechanisms to influence the business of booking new reserves for the nation.
GLOBAL BASINS NETWORK
As an example of the new collaboration possible among the U.S. government, the oil industry, and academia, we review below the successes of the Global Basins Research Network's dynamic enhanced recovery technologies project funded as part of DOE's Advanced Oil Recovery Program.
We are evaluating a new play concept which, if successful, promises to result in the booking of about 20 billion bbl of newly discovered hydrocarbons in the Pleistocene Gulf of Mexico.
However, this project may have exposed just the tip of the iceberg in that a much wider collaborative national effort might arrest if not reverse the production decline within U.S. borders.
The benefits of such collaboration can be enormous to the industry as a whole, because these new dynamic technologies are also applicable to international basins where migration is currently active, such as Nigeria, the North Sea (cover of this issue), Indonesia, and the Caspian Sea.
GBRN is an electronic "Internet" network that was designed to solve two very specific fluid-flow plumbing problems: 1) What is the expulsion mechanism by which hydrocarbons migrate out of geopressure, and 2) Can we image active hydrocarbon migration well enough to locate wells within the migration pathways and produce these streams directly to the surface (the new play concept)?
As an Internet organization, GBRN is one of the first of a new generation to disregard "red brick walls" and connect needed expertise regardless of geographic location. Columbia University's Lamont-Doherty Earth Observatory is one of the network affiliates, supplying seismic, well logging, and reservoir engineering expertise; the project's organic geochemists are from Woods Hole Oceanographic Institution and Texas A&M's Geochemical and Environmental Research Group.
Visualization expertise comes from the Cornell National Supercomputer Facility, Louisiana State University, and Lamont-Doherty. Pennsylvania State University and the University of Colorado supply the sequence stratigraphy and structural expertise. Michigan Technological University and the University of California Santa Barbara supply the inorganic geochemical expertise; Cornell and LSU provide the modeling expertise.
GBRN has joined with 12 major oil companies and several service companies including Advanced Visual Systems, Computational Mechanics Corp., Engineering Animation Inc., Halliburton Geophysical Services, Hypermedia Database Management, Landmark Graphics Corp., and Sun Microsystems in the development of the new dynamic technologies for the exploitation of this new play concept.
DYNAMIC ER TECHNOLOGIES
How do we locate dynamic hydrocarbon migration that might be occurring today? Where are the pathways? How do we drill into these pathways? Could we deliver hydrocarbons from these "streams" to the surface?
The GBRN/DOE methodology is conceived first, to visualize an integrated volume of the merged datasets in 4-D (x, y, z, and time-lapse) of all available seismic, geophysical, and geochemical databases from a depobasin and second, to finite element model the fluid flow history required to reproduce these observations.
A unique feature of our collaboration with DOE is that for the first time an academic-based project is able to test our modeling and data visualization results directly with the drillbit. We are able to locate and drill wells specifically to test whether our codes are working, to verify that our data interpretations are correct, and to discover a mechanism to extract hydrocarbons from these migration "streams" efficiently.
Our first test well is to be spudded in mid-1993.
EUGENE ISLAND 330 FIELD
In search of a study area, we looked at basins around the world where the signal from migration would be the greatest.
We looked at Nigeria, Indonesia, and the North Sea and settled on the U.S. Gulf Coast because of the vast and available database. Also, there is no question that migration of hydrocarbons is occurring there today (see cover of this issue).
For example, there are active seeps at the sea floor, chemosynthetic animals that live off these seeps, and large methane plumes that can be measured within the waters above the seeps.
Oil is being produced in 400,000 year old reservoirs beneath these seeps. Since the organic matter forming the oil is 60-80 million years old, the migration must be occurring in the Pleistocene.
In fact, the entire depobasin in our study area, Eugene Island South Addition Block 330 field, about nine miles across by four miles long, is filled with Plio-Pleistocene rocks to a depth of at least 25,000 ft (cover image).
We also chose El 330 field because it is the world's most prolific Pleistocene oil field. More than 1 billion bbl of oil, gas, and condensate have come from the field since discovery in 1972.
Also, the field is rather simple structurally, with a large growth fault system (termed the Red fault zone) sliding down to the south as alternating sequences of sand and shale are being forced into deep water from the Mississippi delta. As the Red fault zone accommodates extension toward the deepwater Gulf of Mexico, the sediments in the depobasin form rollover anticlines that are full of oil.
TIME-LAPSE STUDIES
The GBRN dynamic technologies are very different from existing observations that petroleum geologists make in the subsurface. Our emphasis is on dynamic, time dependent phenomena. We are trying to see not only the changes in structure and stratigraphy over geologic time but also the physical and chemical influences of the fluids as they move through the rock matrix on a production time-scale. That is, we attempt to quantify changes in pressure, temperature, geochemistry, and in seismic amplitudes over time.
The dynamic importance of the thermal signal can be seen immediately by overlaying isotherms onto structure (Fig. 2). To say the least, it is unusual to have Pleistocene sediments that were at surface only 400,000 years ago to be currently 80 C. at a depth of only 6,000 ft.
That is at least four times as hot as these sediments should be. Extremely active, advective heat transfer must be involved.
Couple this thermal signal with significant overpressures, and something dynamic must be happening (Fig. 2). The pressure gradients bulge even more abruptly and at the same locations as the temperature anomalies, and both are centered on the major oil fields.
Modeling of the fluid flow required to produce the coupled pressure and temperature bulges requires a transient fluid burst up the large Red fault zone to have occurred within the last 10,000 years or so.
HISTORY, REFILLING
The plot thickens significantly when we examine the production history of EI 330 field. The whole field has been depleting unusually slowly (Fig. 3).
Within about 15 years most Gulf Coast reservoirs are largely depleted. However, there is a different character to the depletion of EI 330 field. Specifically, the field has depleted at a much slower decline rate (Fig. 3).
Whether EI 330 field reservoirs have high or low initial production, they are characterized by very slow decline rates. Consider blocks 330 and 331, for example, where there has been a very minor decline rate in the production of oil and particularly gas all through the field's life.
Something unusual is happening. Specifically, we believe we are observing overproduction caused by the migration of new hydrocarbons from a deeper source region into these shallow reservoirs even as they are being produced.
RED FAULT CONNECTION
The possibility of active hydrocarbon recharge is further reinforced by the observation of "trails" of seismic amplitude anomalies leading from the shallow reservoirs into the Red fault zone in the 3-D seismic surveys from the area.
There are clearly discernable amplitude anomaly "trails" from the 4,200 ft, 5,200 ft, and 6,200 ft reservoirs to the Red fault zone in Eugene Island Block 330 (Fig. 4). Deeper reservoirs from 6,800 ft to 7,800 ft are connected to a large antithetic fault that intersects the Red fault zone at depth.
Similar trails are found to the Red fault zone from the 4,700 ft and 5,200 ft producing sands of Eugene Island blocks 338 and 339, and the 5,200 ft and 6,200 ft sands of Eugene Island Block 331.
At least seven separate amplitude trails appear to delineate the hydrocarbon-filling pathways from the shallow reservoirs to the Red fault zone, then down-ward to deep, fluid "sources" (Fig. 5).
These migration pathways are intertwined into a complex, distributary network of high seismic amplitudes that branch from what appear to be three primary source areas of presumed turbiditic sands extending deep within the hard geopressures (Fig. 5).
The turbidites are ponded among larger, vertical salt columns that themselves appear to have sourced the shallower salt sills that are characteristic of this portion of the Pleistocene Gulf Coast.
The deep turbidites may contain huge hydrocarbon reservoirs that were filled when these sands were initially capped by shallow salt in a previous analog to the deepwater flexure trend. Three million years of recent deltaic sands have since buried these hydrocarbons deep into geopressures, and some have burst back toward the surface in the very recent past, if not the present. If we can develop new technologies to tap these migrating hydrocarbons, the GBRN will have identified a new play concept of enormous potential.
ACTIVE MIGRATION
The coupled temperature, pressure, overproduction, and seismic amplitude anomalies observed in EI 330 field suggest the possibility that some oils produced in 1993 may not have been present in the shallow reservoirs at the beginning of production in 1973.
Organic geochemical evidence for time-dependent variability in composition has rarely been examined in oil fields. However, the four phases of the Texas A&M Geochemical Study of Gulf Coast Oils offer a unique opportunity to examine just such time-dependent variability, since many wells from EI 330 were resampled several times over the history of the project.
Whole oil chromatograms were measured for oils from several reservoirs producing from seven wells in EI 330 that were sampled at two different times, and two wells sampled at three times.
Oils from the two shallow reservoirs (at 4,200 ft and 5,200 ft) were heavily biodegraded in 1972, but there were obvious changes in the degree of biodegradation observed in 1984 and 1988 (Schumacher, AAPG annual convention abstracts, 1993, Fig. 6). In all cases, the 1984 oils were less heavily biodegraded than either the 1972 or the 1988 oils from the same perforation depths in the same wells.
Another indication of time-dependent changes comes from the ratios of gasoline-peak concentrations in these same oil samples. Light gasoline ratios were found to have changed over time in all samples, with the 1972 gasoline ratios generally larger than in the 1984 oils, which in turn were smaller than in the 1988 oils (Fig. 6).
This same pattern of gasoline-grade enrichment was observed in oils from the deepest reservoirs at 7,600 ft, but these oils were not biodegraded. Ratios of specific gasoline peaks should not have been affected by gas/oil ratio (GOR) changes caused by reservoir pressure declines.
While there are many variables to be eliminated before these geochemical observations are considered definitive evidence for refilling (sampling irregularities, measurement contamination, analysis technique changes, etc.), we consider these observations to be a "smoking gun," and GBRN geochemists are resampling fluids from the EI 330 field in 1993.
4-D SEISMIC IMAGING
The accumulation of observational and modeling results suggesting present-day hydrocarbon migration into the EI 330 field led us to test whether the effects of such active fluid flow could be imaged using multiple vintages of 3-D seismic surveys (termed 4-D seismic).
Currently, we have 3-D surveys conducted in 1985 and 1988 over a 4 sq mile area within the field (Fig. 7A). In 1993, we will expand the analyses to include an additional 3-D survey recorded in 1992, which has overlapping coverage of approximately 60 sq miles of the 1985 and 1988 surveys.
After normalization of both frequency content and amplitude spectra, the overlapping 3-D seismic surveys display the same geological features, the most prominent of which is a salt column which necks into a horizontal, "mushroom-like" top (cover, Fig. 5).
Both surveys image part of the salt overhang at its intersection with the Red fault zone, which continues downward and separates the salt from deep, "sourcing" turbidites (Fig. 7 A). Shallow, producing reservoirs are evident on both surveys. Above the salt overhang, seismic amplitudes are attenuated because of the presence of geopressures.
A hypothesized hydrocarbon migration pathway is imaged by fitting isosurfaces to high amplitude seismic reflection strength regions of the 4-D dataset. The oil column extends from the deep turbidites, up along the Red fault zone, under, then around the salt overhang and up into the shallower producing reservoirs (Fig. 7A).
Superposition of the 1988 survey (red) onto the 1985 survey (green) shows that the forms of these high seismic amplitude isosurfaces are somewhat different between the two surveys. Of particular interest are the amplitudes within the shallow producing reservoirs because we know of the precise fluid withdrawal volume and pressure changes induced by man between 1985 and 1988.
A larger isosurface volume is to be expected for each reservoir in the 1985 (green) survey than the 1988 (red) survey because of this production, and indeed, such is observed. It should be emphasized, however, that the seismic amplitude isosurface technique does not image fluid movement directly, but rather acoustic impedance contrasts.
Fluid pressure change rather than fluid flow is the most likely process that could substantially change the acoustic impedance for two 3-D seismic surveys that were shot only three years apart. The maximum resolution of oil industry seismic technologies is currently about 40 ft, too coarse to detect direct fluid flow movements over such a short time-lapse. However, pressure changes propagate much more rapidly throughout the subsurface, and should be detectable.
Time-dependent seismic amplitude movements provide a possible record of such pressure changes. Consider the "similarity," image of the combined 1985 and 1988 datasets (Fig. 7-B). Displayed in aqua are isosurfaces around high amplitude regions that have not moved measurably between the two surveys. The reservoirs, salt structure, and deep turbidite "sources" appear primarily as "similar," fixed bodies.
Overlain upon this rigid structure, however, are isosurfaces surrounding locations where the amplitude maxima of the 1988 survey are larger (in yellow) and smaller (in blue) than those of the 1988 survey (Fig. 7-B).
We have identified some changes in amplitude isosurfaces around the edges of the salt structure, of particular interest because of the known propensity of large hydrocarbon accumulations to such salt boundaries.
Specifically, there was an increase in amplitudes beneath a mushroom structure from 1985 to 1988. Also, there appears to have been a decrease along the Red fault zone beneath the salt overhang, whereas there was an increase in amplitudes within the deep turbidites themselves (Fig. 7-B).
This observation might represent pressure changes accompanying movement of hydrocarbon-charged fluids from the deep turbidites, up the Red fault zone, around the base of the salt overhang, and into the shallower, producing reservoirs.
EFFECT ON U.S. RESERVES
How extensive are these deep, as vet undiscovered hydrocarbon columns buried within geopressured turbidites in the Gulf of Mexico?
Current shallow production appears to be concentrated in the areas of maximum horizontal changes in the top-of-geopressure surface. That is, areas with known excessive production correlate strongly with areas of maximum horizontal pressure gradient at the transition depths from hydrostatic to geopressured sediments.
Conservative estimates of undiscovered hydrocarbons in the Pleistocene Gulf of Mexico balloon to at least 20 billion bbl when the deep hydrocarbon columns are considered. A concerted, collaborative, national exploration campaign searching for similar new plays in the deepwater flexure trend might explode the total hydrocarbon reserves "booked" for the U.S. Gulf of Mexico to greater than 50 billion bbl of yet unrecovered hydrocarbons.
In addition, the application of the new dynamic technologies worldwide can surely discover enormous additional reserves in basins with active present-day hydrocarbon migration, such as Nigeria, Indonesia, the North Sea, and the Caspian Sea.
SUMMARY
The gloomy projections of future reserves assume no new technological breakthroughs and no concerted efforts to improve the situation.
The GBRN/DOE/oil industry project is just one example of the possibilities of the payout potential of collaborative applications of new technologies to the exploration for new reserves in the U.S. It is essential that much larger governmental, academic, industry programs be aimed immediately at exploring for and exploiting new play concepts in other areas of the U.S. as well as internationally.
The expressed mission of such collaborations should be to increase booked reserves for use during the 21st century.
Prime targets in the U.S., in addition to the deepwater Gulf of Mexico, are the multibillion barrel fields discovered at the turn of the century in western Pennsylvania (where new technologies have hardly been used), in the diatomites of California (where new hydraulic fracturing technologies promise enormous increases in production capability), and in the Arctic National Wildlife Refuge (ANWR), as well.
For example, a concerted government, academic, industry effort to explore ANWR has the hope of allaying the great fears of exploitation by the environmentalists and at the same time of scoping just how much oil and gas are located beneath the subsurface of ANWR, an evaluation that the government desperately needs.
The Environmental Protection Agency might be brought into the team from the start, along with the U.S. Geological Survey, DOE, oil companies, and academia. Perhaps together we can do a better job of exploration for new plays, because the U.S. will quickly need these new reserves, and eventually, so will the world.
ACKNOWLEDGMENTS
Members of the Global Basins Research Network are Joy Allen, Lana Billeaud, Wei He, Ulisses Mello, Lincoln Pratson, Robin Reynolds, David Roach, Mark Spiegelman, and Craig Wilkinson, Lamont-Doherty Earth Observatory of Columbia University; Laurel Alexander, William Bohrer, Lawrence Cathles III, Bruce Land, and Steven Losh, Cornell University; James Boles, University of California Santa Barbara; Paul Weimer, University of Colorado; Jeffrey Nunn, Louisiana State University; James Wood and Jacqueline Huntoon, Michigan Technological University; Peter Flemings, Pennsylvania State University; Mahlon Kennicutt, Texas A&M University; Jean Whelan, Woods Hole Oceanographic Institution; Edward Bagdonas, Advanced Visual Systems Inc.; Paul Manhardt, Computational Mechanics Corp.; Francis Cipriani, Elf Acquitaine; Jeffrey Trom, Engineering Animation Inc.; Gary White and John Anderson, Halliburton Geophysical Services; Charles Rego, Hypermedia Inc.; David Chandler, Landmark Graphics Corp.; John Austin, Jack Leady, Deet Schumacher, and Richard Woodhams, Pennzoil Exploration & Production Co.; Daniel Wexler, Sun Microsystems Inc.; and H. Roice Nelson Jr., Walden 3-D Inc.
Oil industry support comes from Agip, Amoco, ARCO, Chevron, Conoco, Elf Aquitaine, Exxon, Mobil, Pennzoil, Shell, Texaco, and Unocal.
This article and two previous articles (see bibliography) are accompanied by 10 min VHS videotapes available for the $10 shipping and reproduction costs, payable to Trustees of Columbia University, from David Roach, Lamont-Doherty Earth Observatory, One Torrey Cliffs Rd., Palisades, N.Y. 10964.
BIBLIOGRAPHY
Anderson, Roger N., He, Wei, Hobart, Michael A., Wilkinson, Craig R., and Nelson, H. Roice Jr., Active fluid flow in the Eugene Island area, offshore Louisiana, Geophysics: The Leading Edge, Vol. 10, No. 4, April 1991, pp. 12-17.
Anderson, Roger N., Cathles, Lawrence M. III, and Nelson, H. Roice Jr., 'Data cube' depicting fluid flow history in Gulf Coast sediments, OGJ, Nov. 4, 1991, p. 60.
Copyright 1993 Oil & Gas Journal. All Rights Reserved.