Roger N. Anderson, Lamont-Doherty Earth Observatory, Palisades, New York
Albert Boulanger, Lamont-Doherty Earth Observatory, Palisades, New York
Robin Bell, Lamont-Doherty Earth Observatory, Palisades, New York
Lincoln Pratson, University of Colorado, Boulder, Colorado
Industry estimates of the hydrocarbon reserve potential of the U.S. deep and ultra-deepwater Gulf of Mexico (GOM) alone are as high as 20 billion barrels crude oil equivalent. But the ultra-deepwaters of the world, extending from 4000 feet to water depths of 10,000 feet and greater, remain largely a geological and economic mystery. For example, in the GOM, much of the ultra-deepwater subsurface is obscured by the vast, horizontal, Sigsbee salt canopy (actually an amalgam of intermixed salt extrusion events) which covers fully 45% of the surface area of the ultra deep (Figure 1). This terrain is similar to a lunar surface, and geophysical imaging beneath it will be a supreme challenge.
Figure 1. View of the bathymetry of the Ultra-deepwater
Gulf of Mexico, looking from Brownsville, Texas toward New Orleans.
The "moonscape" is from the Sigsbee salt canopy that
forms a horizontal sheet across much of the viewpath. Sunken depressions
are minibasins of sediment that have formed in holes in the canopy.
The entire sheet is moving to the south at several cm/year velocities,
and the Sigsbee Escarpment at the right is a 800 m high "cliff"
of advancing salt.
Currently recognized opportunities in the ultra-deepwater GOM include compressional foldbelts and associated anticlines located under salt, with new plays of not only turbidite sands like in the deepwater, but also of carbonate reservoirs analogous to the prolific Golden Lane of Mexico (c.f. "Industry watches deep gulf test", AAPG Explorer, June 1996).
If the subsalt region between the Perdido and Mississippi Fan Foldbelts contains such anticlinal structures, which have yielded many billions of barrels of hydrocarbons in other parts of the world, this would represent a tremendous untested exploration opportunity. However, before exploration for ultra-deepwater reserves in the GOM, or elsewhere, can move forward, many technical hurdles must be overcome. Of key importance are assessments of reservoir producibility, hydrocarbon mix and quality and the ultimate recoverable reserves volumes.
Deepwater GOM reservoirs produce hydrocarbons from turbidite sands with production rates as high as 15,000+/- barrels per day, on par with some Middle East wells and several times the average daily production of shallow-water GOM wells. Golden Lane carbonate reservoirs, such as Pozo Rico, have flowed at the highest rates in the North American continent (>100,000 bbl/day in the early 20th century).
Even at high rates, a discovery containing volumes approaching
2 billion barrels crude oil equivalent (recoverable) is probably
required to support necessary development projects in the ultra-deepwater,
which could cost upwards of $2 Billion dollars. The deepest water
production currently obtained from GOM waters is from the Auger
field located in Garden Banks Block 426, approximately 214 miles
southwest of New Orleans, Louisiana. The Auger field went on production
in April of 1994 and is located in 2,860 feet of water. In comparison,
the deepest water gas and oil well currently producing in the
world today is Petrobras' Marlim 3-MRL-4 well located in 3,369
feet of water in the Campos basin, offshore Brazil. To be viable,
Ultra-deepwater production would have to double these world record
flow rates.
Yet the technologies do not exist to economically test for rates and recoverables in such water depths. Technologies needed to explore and scope hydrocarbons from ultra-deepwater depths include sub-salt imaging and regional structural and stratigraphic mapping beneath the salt canopy. Current pre-stack depth migration requires a "window" through the salt to calibrate the seismic ray-paths received through salt.
On the engineering side, slimhole drilling, logging and testing technologies must be developed because the costs for larger tubular techniques is likely too prohibitive. In fact, the costs to explore, and more importantly, develop the technologies to explore, require that industry funds be leveraged to the maximum possible extent. Below, we will take a look at some emerging new exploration technologies that are custom-made to assist in ultra-deepwater exploration and development problems.
Many "far-field" technologies will be needed by the oil industry to solve the ultra-deepwater exploration problem. For example, a new generation of potential field observations is required to map the base of salt in locales where a continuous canopy is present. Luckily, the end of the cold war has made such measurements available to the oil industry.
3D gravity gradiometry is a "stealth" technology developed by Bell Aerospace the U.S. Navy Trident submarine program. The gravity gradiometer (Figure 2) consists of three separate gravimeters measuring the differences in earth's gravity over one meter distance as the meters tumble in a "binnacle". The result is the world's most accurate measurement of not only gravity, but the full tensor of the gravity field or the 3-D changes in gravity with direction. Therefore, this wonderful "cold war" technology offers the possibility of imaging density contrasts beneath salt to much higher resolution and accuracy than previously possible.
Figure 2. The 3D Gravity Gradiometry system was developed
for the U.S. Navy Trident submarine program by Bell Aerospace.
As an excellent example of the Navy's "dual-use" strategy for the maintenance of critical technologies, the 3D Gravity Gradiometry system has been declassified, and a company licensed to make available these new measurements to the deepwater oil industry. Bell Geospace, Inc. has conducted three seasons of gravity gradiometry surveying in the deepwater GOM already aboard U.S. Navy vessels, and another program to acquire data far onto the salt canopy is currently being subscribed for the Fall of 1996.
In collaboration with eight major oil companies holding substantial property positions in the deepwater GOM, Bell Geospace has acquired gravity gradiometry over most of the deepwater discoveries to date (Figure 3) . Fields surveyed include Brutus, Bullwinkle, Diana, Fuji, Gemini, Jolliet, Luna, Marquette, Mars, Mickey, Popeye, Ram-Powell, and Vancouver.
Figure 3. Location of 3D gravity gradiometry surveys already
completed by the U.S. Navy for Bell geospace, and available for
purchase by the oil industry.
Consider the gravity gradiometry results around Mars, for example.
The "easting" tensor, or the difference in gravity measured
by two gravimeters when lined up exactly in the east-west orientation
(Figure 4), shows the boundary of the Mars basin with its sediments
lapping onto the Antares (to the north) and Venus (to the south)
salt canopies. In addition, there is an interesting density boundary
observed downdip in the center of the basin itself, that, coincidentally
or otherwise, corresponds in general location to the seismic oil/water
contact. It will remain for new surveys to establish whether the
density contrast from the drainage of oil from this basin will
be large enough to allow repeated "4D" gravity gradiometry
surveys to track the movement of hydrocarbons as production proceeds.
Figure 4. (top) easting gravity gradiometry tensor, or the change in gravity with distance in the east direction. Red is change from high to the west to low to the east, blue is change from low to the west to high to the east. Notice the change in density in the middle of the Mars basin.
(bottom) North-South seismic profile across the Mars basin showing
the Antares and Venus salt massifs and the location of the Mars
discovery well.
The seismic reflections from below the salt canopy in the deepwater GOM are not well imaged with conventional, horizontally-acquired, 3D seismic methods. Again, the U.S. Navy has injected some new technology into the industry through the efforts of Texaco. This time, it is vertical-cable seismic arrays (Figure 5). Acquisition of vertical cable seismic data differs from conventional seismic acquisition (towed horizontal cables) in that vertical cables are moored to the seafloor, and the only connection with the source boat is a radio link. This allows much greater freedom in source/receiver geometry and allows out-of-plane, or "true 3D" multi-azimuthal shot records.
Figure 5. The business driver toward deepwater exploration
and production will be instrumented seafloor and water column
seismic cables, surface shooting boats, gravity gradiometry, and
satellite and microwave connectivity to virtual command-and-control
centers on land
In addition, vertical cable technology allows far offset recording
out to 25 kilometers. These aerial shot records can then be efficiently
pre-stack depth migrated so that the seismic reflections are correctly
located before stack. This provides for the potential of much
better sub-salt imaging. Ocean bottom seismometers are also being
investigated as "anchors" for the vertical arrays.
Multi-component, multiple receiver Vertical Seismic Profiling (VSP) and Seismic-While-Drilling (SWD) must be developed and tested for ultra-deepwater use. VSP has become an integral component of any rank wildcat exploration well, and provides the vital link between seismic data and well logs. VSP also is used to distinguish multiples and reverberations on surface seismic surveys, and to estimate reflectivity at the borehole. In addition, the wavefield produced by the drill bit will be a critical new technology to identify where within the geologic section the drillbit is at all times in high-risk, ultra-deepwater wells.
However, SWD and VSP techniques must contend with two new conditions in ultra-deepwater exploration wells. First, the deepwater itself is a problem with its strong and variable currents. Previous SWD and most VSP surveys were in less than 4,000 ft of water, and hydrophones were deployed on the ocean bottom. Although ocean-bottom deployment is an option, suspended streamers are more likely to be useful (maybe even the same vertical arrays discussed above).
Techniques for the deployment and positioning of suspended streamers are immature, but options are again available from the world's most experienced user, the U.S. Navy. Widely used techniques not yet introduced into the oil industry include "self locating arrays" that determine their own locations to accuracies of up to 1 mm from ambient ocean noise, as well as bottom sources (c.f. "A vision of the technology rich oil field of the future", American Oil and Gas Reporter, July, 1996).
In addition, positioning thrusters on drillships themselves are
a problem for listening arrays deployed from non-fixed platforms.
Experience operating hydrophone arrays from drillships has shown
that allowances must be made both for the acoustic noise from
the thrusters, and the possibility that hydrophone cables may
be wrapped around the riser as thrusters continually reposition
the drillship.
Where in the deep and ultra-deepwater provinces of the world are the most prospective reservoirs? Do large accumulations of gas and oil reside in the subsurface below ultra-deepwaters? And if so, are these reservoirs adequate in size, configuration, and quality to warrant the multi-billion dollar outlays necessary for field development?
Answers to these questions will not be realized without the introduction of new exploration as well as production technologies. However, the magnitude of the risks and associated costs of the ultra-deepwater make the development of such technologies beyond the capability of any single commercial entity.
The planning and operation of the comprehensive DeepStar production research program has been exemplary in leading the industry into just such collaborative efforts, but on the production side of the problem. Texaco has led this extraordinary consortium of 19 oil and gas companies, 47 service companies, and 14 engineering firms. This coordinated, multi-disciplinary research effort might need to be duplicated for exploration technologies. We also need a new generation of low cost technologies for exploration in deep and ultra-deepwaters. Leading-edge technologies as described above, and many more will be required before the key profitability questions can be answered.
The "system approach" to deepwater production technology
development is one of DeepStar's core strengths. The resources
of any single organization are adequate to develop only individual
components of a deepwater system, but typically are insufficient
for the evolution of an entirely new system. The system perspective
not only includes hardware and science issues, but also recognizes
the necessity of pairing industry's manufacturing and service
capabilities with the perceived needs of the end user market,
the oil and gas producers. This interactive relationship between
the commercial market and the service producer is key to validation
and acceptance of the system as a whole, as well as the individual
components. A similar effort is needed for exploration technologies.
Otherwise, the incredible promise of the ultra-deepwater will
remain forever unrealized.