Recovering
dynamic Gulf of Mexico reserves and the U.S. energy future Recovering
dynamic Gulf of Mexico reserves and the U.S. energy future
As we all know, there has been a significant shift of resources, capital, and technologies overseas since the collapse of the U.S. oil industry in the late 1980's. As a consequence, crude oil output has been dropping at an alarming rate in the United States since 1986, and since U.S. production correlates directly with the number of wells drilled in the United States (which has also dropped precipitously),.the future supply left within our borders looks exceedingly tight (Figure 1).
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 U.S. internal needs ( which are projected to continue to climb (Figure 1). This flight of exploration is not just an economic problem, it is also a geological problem. The perception is that there are no more "Elephants"; 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 our predicament is the cost of discovering a new barrel of oil in the United States today. It is to the United States' economic advantage to produce much more oil than we import, even if it were to cost $20 a barrel to produce. However, it is not in any oil company's interest to produce oil at more than about $6 a barrel because their overhead and profit requirements make that a break-even point. No national oil company has to produce oil at such low costs (Saudi-Aramco, however, has costs that are fortuitously the lowest in the world, at less than a $1 a barrel). While Saudi-Aramco is a national oil company that is hugely profitable, there are many other national oil companies that come very close to losing money. (They may pay $18 to $22 a barrel to produce oil, and then sell it on the world market at $20 a barrel).
Somewhere in-between sits the government of the United States. We must occupy a significant upstream niche if we are to correct this collapse of U.S. production. Unless the U.S. becomes an even more active participant in booking new reserves within her boundaries, large volumes of hydrocarbons will go unexploited in the United States. Compounding this problem is the present economic disincentives favoring a shut-in of production, and when fields are shut-in, one is rarely able to bring back production at a later time.
Where does that leave the U.S.? Very likely without even marginally adequate petroleum resources remaining within its boundaries by the year 2010. We are close to being dependent upon imports (largely from OPEC) for more than 50% of our daily crude oil needs. If something new isn't discovered soon, (new Play concepts) all the major fields in the U.S. will be played-out very soon, including the North Slope of Alaska--on-shore and offshore-- and the Gulf Coast. Why? Because few companies, major or independent, are exploring for giants in the U.S. today, and it takes 20 years or more to bring a huge oil discovery fully on-line.
There is already a significant amount of money spent by the United States government on Fossil Fuel Research, principally by the Department of Energy. How much of an increase in "booked reserves" does this research currently result in? Not much yet, but things are changing. The government is beginning to develop mechanisms to influence the business of "booking new reserves" for the nation, and none too soon--because there might not be many reserves to produce from by the year 2010.
The project, run by the Global Basins Research Network (GBRN), was originally designed to produce new technologies for exploiting existing clastic reservoirs in the Gulf Coast. However, we made a wonderful discovery--reservoirs are being currently refilled with newly migrating hydrocarbons at rates that are close to the extraction rates! We are now concentrating on a Field Demonstration Well to attempt to enhance the flow from these "streams" feeding the more traditional, reservoired "ponds" from along a large growth fault system in the Eugene Island area of offshore Louisiana.
The GBRN is an electronic network designed to solve two very specific fluid-flow plumbing problems:
The GBRN is an Internet organization (Figure 2), one of the first to throw away the 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 the Woods Hole Oceanographic Institution and Texas A& M's Geochemical and Environmental Research Group; visualization expertise comes from the Cornell National Supercomputer Facility, as well as from LSU, and Lamont. Penn State supplies the sequence stratigraphy and structure, along with the University of Colorado; Michigan Tech and University of California at Santa Barbara supply the inorganic geochemistry expertise; and Cornell and LSU the modeling expertise.
Originally, the GBRN formed its industry/academic/government collaboration to try to enhance recovery from aging Pleistocene clastic oil fields in the Gulf of Mexico by attempting to understand the fluid flow regime in and around the Eugene Island 330 field. What we discovered, instead, are mechanisms by which one might identify hydrocarbons that are replenishing reservoirs from active, dynamic migration that is going on today from a much deeper "source". The new Play comes from the possibility of tapping these previously unreachable, deep, geopressured reserves.
The GBRN has partnered with several major oil companies and several service companies including Landmark Graphics, Advanced Visual Systems, Engineering Animation Inc., Computational Mechanics Corporation, Hypermedia Database Management, Sun Microsystems, and Halliburton Geophysical Services in the development of the new dynamic technologies for the exploitation of this new play. The economic result of success in finding ways to exploit such new discoveries might be to turn the GBRN into a national, non-profit, collaborative Play generating organization.
The GBRN/DOE methodology is to solve the fluid flow problem of hydrocarbon migration first, by volume visualization of the immense, 4-D (x,y,z, and time-lapse) seismic, geophysical, and geochemical databases already available for such mature exploitation environments. There has been more than 100 billion dollars spent just in drilling wells in offshore Louisiana in the last 50 years. The universal product from all those wells, dry and producing alike, is geology. From the cores,logs, and the enormous volumes of fluid drawn out of these wells, combined with millions of miles of seismic profiling, we ought to be able to describe the physics and chemistry of hydrocarbon migration. The second methodology is the development of the capability to model predictively the fluid migration event. Finite Element Modeling in 4-Dimensions of the fluid flow with real-time visualization of code computations (non-batch job mode) is accomplished over Internet using the Cornell National Supercomputer Facilities. These computational solutions are difficult because the equations that describe the physics and chemical changes that occur during migration are tightly coupled to each other. That is, permeability, pressure ,temperature, and the flow characteristics of the hydrocarbons in the subsurface are coupled to the chemical changes in the liquids and solids that they flow in through and around. Only when we can demonstrate valid models do we understand the system through the equations of the model.
A unique feature of our collaboration with the Department of Energy is that for the first time, an academic-based project is able to test our modeling and data visualization results directly with the drill bit. We are able to locate and drill wells specifically to test whether our codes are working, to find out whether our data synthesis is correct, and whether a mechanism can be designed to extract hydrocarbons from the 'stream" efficiently.
The dynamic technologies are very different from existing observations that petroleum geologists make in the subsurface. Our emphasis is on the observation of dynamic, time-dependent phenomena. We are trying to see not only the changes in structure and stratigraphy over time, but also the physical and chemical influence of the fluids as they move through the rock matrix. We're trying to image changes in pressure, temperature, geochemistry, and in seismic amplitudes over time.
In fact, the entire depobasin in our study area, the Eugene Island 330 Field, which is about 9 miles across by 4 miles long, is filled with Plio-Pleistocene rocks to a depth of at least 25,000 feet (cover). We chose as a study area, the single most prolific Pleistocene oil field in the world. There have been more than a billion barrels of oil, gas and and condensate produced from this field since its discovery in 1972. The field is rather simple structurally, with a large, growth fault system sliding down to the south as sand and shale are being forced into deep water from the Mississippi Delta. As these faults move they form roll-over anticlines that are full of oil.
Couple this thermal signal with significant overpressures, and something clearly dynamic must be happening (Figure 3). The pressure gradient bulges even more abruptly and at the same locale (the oil fields) as the temperature anomaly. Modeling of the coupled pressure and temperature bulges requires a transient fluid burst that has occurred within the last 10,000 years or so. Some kind of a burst of fluids involving a pathway along the growth fault system is required.
The plot thickens significantly when you examine the production history of the Eugene Island 330 field. The whole field has been depleting unusually slowly (Figure 4). In about 15 years you could generally deplete most reservoirs in the Gulf Coast. In terms of fractal behavior, there is a different fractal dimension to the Eugene Island 330 fields compared to normal fields. The overproduction is easy to identify if you compare the initial production, (how many barrels per day that the reservoirs came onto production) versus the production decline rate, (the slope of the production decline per unit time).
Regardless whether Eugene Island 330 field reservoirs have high or low initial production, they have a very low decline rates. Consider block 314, for instance, where there is much more initial production of gas than oil, yet the decline of oil has been a little steeper than the decline of gas. Whereas in blocks 330 and 331, there is virtually no decline in the rate of oil or particularly gas being produced in that reservoir per year over the whole life of the field.
Something unusual is happening. Specifically, we believe the event that we are observing in the coupled pressure and temperature signatures is the same migration event that is causing the overproduction-- both are caused by new hydrocarbons that are coming into these reservoirs as they are being produced.
Strong amplitude anomaly "isosurfaces" are observed from the Red Fault Zone deep into these three "sourcing" depobasins of presumed turbidite sands. They, in turn are buried beneath the detached salt sheet, and extend well into geopressures, and are ponded among larger, vertical salt columns that themselves appear to have sourced the shallower salt sill (Cover).
The hydrocarbon-rich fluids seem to be sourcing from these synclinal turbidites. If so, they may contain huge hydrocarbon reservoirs that were filled when these sands were initially capped by shallow salt in a previous analogue to the present-day flexure trend, deep-water Play that has produced fields such as the newly announced Mars and Mickey discoveries. 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.
The organic geochemical signature of the reservoir oils and gases are equally persuasive that an injection event has occurred recently in the EI 330 field. Texas A&M's Geochemical and Environmental Research Group has conducted a four-part, Gulf of Mexico Oil Correlation Study. Phase 4 included the analyses of 33 oils from all the major reservoirs of EI 330. Among the conclusions: the oils are biodegraded in the shallow reservoirs; there is little biogenic gas present; and the biomarkers, heavy metals, and sulfur isotopes indicate a carbonate marine source of probable Cretaceous age.
Maturation indicators were calculated separately for the oils and gases from each reservoir. Methylphenanthrene ratios were measured on the C10+ fraction of the hydrocarbons. An equivalent vitrinite reflectance was then calculated for each ratio. The oils all have maturities in the 0.8-1.0 range, with an indication of decreasing maturity in the deeper reservoirs. Gas maturities were calculated from the empirical relations between vitrinite reflectance values and the ratios of Del C13 between methane and propane, and ethane. In contrast to the oils, the gases are nearly super-mature, with vitrinite reflectance estimated at between 1.3 and 1.5. Also, the gases show more maturity with increased depth. While estimates of maturity are much more inaccurate for oils than for gases, the large difference is believed to be significant. The gases may be forming from the present-day cracking of oils at considerable depth, certainly well within the geopressures and from beneath the detached salt sill. In contrast, the oils appear to be from a cooler, shallower depth (but still within the geopressures), and are being entrained with the gas-rich phase as the fluids exit the geopressures within the Red Fault Zone.
Combining the maturation and fractionation evidence, the organic geochemistry indicates the EI 330 hydrocarbons are derived from the first gas-rich, fluid discharges from mature oils presently cracking to gas and undergoing evaporative fractionation. The gas-saturated fluids, expelled from deep within the sub-basins, entrain less mature oils from shallower depths on their way up the synclinal turbidites to the distributary network buried within the Red Fault Zone. From there, the fluids lose their hydrocarbons preferentially to the first low pressure reservoirs encountered in the transition above geopressure. Some water, and accompanying methane makes it all the way to the surface, where seeps are active along the Red Fault Zone today.
The pressure, temperature, seismic and overproduction anomalies observed in the EI 330 field suggest the possibility that the oils produced in 1993 may not have been present in the 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 4 phases of the Texas A&M study offer a limited opportunity since many oils from EI 330 block wells were sampled in 1985 and again in 1988. One well was also sampled in 1973, and another in 1992.
Whole oil chromatograms were measured for oils from several wells producing from each reservoir in the EI 330 block, with 7 wells sampled at two different times, and two wells sampled at three times. Oils from the two shallow reservoirs (at 4200 feet and 5200 feet) that were heavily biodegraded in 1973, showed considerable variability in degree of biodegradation from 1985 to 1988. In all cases, the 1985 oils were less heavily biodegraded than either in 1973 or in 1988.
Another indication of mixing of different hydrocarbons comes from the gasoline concentrations in these same oils. Light gasoline contents were greater in 1988 than in either 1973 or1985. This same pattern was observed in non-biodegraded oils from the reservoir at 7600 feet.
While there are many variables to be eliminated before these observations are definitive (sampling irregularities, measurement equipment and technique changes, etc.), the need to monitor compositions of produced hydrocarbons over time in all blocks of the EI 330 field is obvious. GBRN scientists are in the process of resampling for 1993 right now.
The accumulation of observational and modeling results suggesting transient refilling in the EI 330 field led us to test whether the effects of fluid flow could be imaged using multiple 3-D seismic surveys conducted over a number of years (termed 4-D seismic here). Currently, we have 3-D surveys conducted in 1985 and 1988 over about a 4 square mile area at the intersection of EI 329, 330, 338, 339 (Figure 6). In 1993, we will expand the analyses to include a 3-D survey shot in 1992 with overlap coverage of approximately 20 square miles.
In the 1985/1988 overlap area, both 3-D seismic surveys clearly imaged the same geological features, the most prominent of which is a salt column which necks into a horizontal "mushroom-like" top, except that the sill has five distinct "points" (and is termed the star-structure"). One of the points and the root is imaged on both 3-D surveys (Figure 6). This feature can be seen by fitting isosurfaces to high amplitude regions after conversion of the seismic waveforms to reflection strengths. Horizontal producing reservoirs near the surface also are present in both surveys, as are the synclinal turbidite layers buried deep beneath the salt star. Mid-depth in both surveys, the seismic amplitudes are attenuated because of the presence of geopressures.
Superposition of the 1985 survey (green) onto the 1988 survey (red) shows that the form of these predominant amplitude isosurfaces are somewhat distinct. Of particular interest are the amplitudes within the producing reservoirs because we know of the precise fluid withdrawal and pressure changes induced by man between 1985 and 1988. A larger volumetric isosurface is to be expected in the 1985 (green) survey than the 1988 (red) survey, and indeed, such is observed. However, the deeper reservoirs are actually larger in the 1988 survey, implying some sort of inflation.
It should be emphasized, however, that the seismic technique does not image fluid movement directly, but only acoustic impedance contrasts. Fluid pressure changes rather than fluid flow itself is the most likely process that could substantially change the acoustic impedance for two 3-D seismic surveys that were shot only 3 year apart. The maximum resolution capability of oil industry seismic technologies is about 40 feet, too coarse to detect direct fluid flow movements. Pressure changes propagate much more rapidly throughout the subsurface, and should be detectable.
Time-dependent seismic amplitude gradient evaluation provides an accurate representation of such postulated pressure changes. Consider then the "similarity" image of the combined 1985 and 1988 datasets (Figure 6). Displayed in turquoise are isosurfaces around gradients that have not moved measurably between the two surveys. The reservoirs, salt structure, and general turbidite "sources" appear primarily as "similar", rigid bodies.
overlaid onto this rigid structure are isosurfaces around locations where the gradient of the 1985 survey is larger (in blue) and smaller (yellow) than that of the 1988 survey (Figure 6). Interestingly, the primary loss of gradients of amplitudes has occurred at the tops of the producing reservoirs (blue), implying that the removal of large volumes of hydrocarbons from these reservoirs has focused the reflectivity to insonification somewhat deeper into the producing reservoirs. This is in contrast to the simplistic concept that production occurs from the base to the top of a reservoir as the oil/water contact migrates up-dip. The deepest reservoirs appear to have been more efficiently drained than the shallower reservoirs (more blue). Increases in gradient from 1985 to 1988 (yellow) are primarily confined to the edges of the shallowest reservoirs, with hardly any increase observed in the deeper reservoirs.
There have been some movements associated with the edges of the salt structure, of particular interest because of the known propensity of large hydrocarbon accumulations to such salt edges. Specifically, there was a decrease in gradients on top of the salt star, and an increase beneath the star structure from 1985 to 1988. Also, there appears to have been an increase in amplitude gradients along the Growth Fault Zone beneath the salt star, whereas there was a decrease in amplitude gradients within the deepest turbidites themselves. This observation might portend a movement of fluids from the deep turbidites, up the fault to the base of the salt star; i.e., a further pooling at the top of geopressure.
It is time for an organized governmental, academic, industry program aimed at developing and exploiting many new Play concepts in other area of the the United States as well, with the expressed mission of increasing our booked reserves for use during the twenty-first century. Prime targets, in addition to the Gulf of Mexico are the multi-billion barrel fields exploited at the turn of the century in western Pennsylvania, in the diatomites of California, and i the Alaskan National Wildlife Refuge, as well. A concerted government, academic, industry effort to explore ANWR has the hope of allaying the great fears of exploitation by the environmentalists. Perhaps together we can do a better job than apart.
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,
Jeff Nunn, Louisiana State University,
Jim Wood, Michigan Technological University,
Peter Flemings, Pennsylvania State University,
Charles Kinnicutt, Texas A&M University,
Jean Whelan, Woods Hole Oceanographic Institution,
Ed Bagdonas, Advanced Visual Systems, Inc.,
Craig Warner, Ceram, Inc.,
Paul Manhardt, Computational Mechanics Corp.,
Jeff Trom, Engineering Animation, Inc.
Gary White, Halliburton Geophysical Services,
John Austin, Jack Leady, Deet Schumacher and Richard Woodhams, Pennzoil Exploration & Production Co.,
H. Roice Nelson, Jr., Walden 3-D, Inc.
Oil Industry Support from:
AGIP
AMOCO
ARCO
CHEVRON
CONOCO
ELF AQUATAINE
EXXON
MOBIL
PENNZOIL
SHELL
TEXACO
UNOCAL
Cover: Raised view of volumetric representation of 3-D seismic interpretation of the subsurface beneath 9 blocks centered on the Eugene Island 330 Field, offshore Louisiana. Each block is 3 miles on a side. Depth is in seismic travel time from 1.5 to 6.0 seconds. Salt is in white. Faults are in red. High seismic reflection strengths (amplitudes) are contained within the colored isosurface columns (such as the green in the foreground) thought to represent presently active migration pathways of oil and gas. See article by Anderson inside. Background is satellite view from Rocky Mountains to Gulf Coast from Lamont-Doherty Earth Observatory digital bathymetric/topographic database. Imaging is by Engineering Animation, Inc., Ames, Iowa.
