Robert B. O'Connor Jr.
Wavetech Geophysical Inc.
Denver
Recent major discoveries by Conoco Inc. and Duncan Oil in the Lower Mississippian Lodgepole formation of the Williston basin show that finding major oil reserves is still possible in the U.S. and that 3D seismic methods have the capability to locate them.
The implications are profound for independent oil and gas producers, who traditionally concentrate their operations in the mature U.S. Like major companies, independents are profiting from use of 3D seismic methods.
The Williston basin successes show how independents might use 3D seismic methods to identify opportunities in a region once considered to be drilled up. Both the increasing use of these technologies by independents as well as the experiences major companies have had with them are well-documented.1 2
LODGEPOLE DISCOVERIES
A look at Williston basin geology shows why 3D seismic methods have become crucial to recent exploration.
The Williston basin is a cratonic basin that began forming in the early Paleozoic era and continued to develop at least until the end of the Mesozoic or early Cenozoic eras. Depositional periods of principal interest to the development of oil and gas in the basin are the Ordovician, Devonian, and Mississippian, although other periods have some potential as well.
Each of these periods is cyclical in character, and each contains numerous subcycles of terrigenous, biogenic,and evaporitic rocks deposited under generally low energy conditions (Fig. 1)(82412 bytes). The large-scale structure of the basin is very simple, with only the Nesson and Cedar Creek anticlines interrupting its roughly circular symmetry (Fig. 2)(59295 bytes).
Small-scale structure, on the other hand, is exceedingly complex and can be easily misinterpreted unless the observational sampling is quite dense. One particularly subtle but important structural feature of the basin is the widespread occurrence of wrench faults having little or no vertical displacement (Fig. 3)(63477 bytes). These manifest themselves on the surface as lineations and are difficult to interpret on 2D data. They are believed to be extremely important in the detailed hydrodynamics of the basin, which generally exhibits a southwest to northeast flow pattern.
This water flow has led to the differential dissolution of large areas of the Devonian, Mississippian, and Mesozoic salt formations in the basin (Fig. 4)(58176 bytes) and is probably the leading cause of the subtle and complex structural features mentioned above. Also, it undoubtedly has had a significant influence not only on the diagenesis of the basin's rocks but on its hydrocar- bon migration patterns as well.
Hydrocarbon source rocks in the basin are found throughout the sedimentary section, with the principal and most widespread ones being in the Ordovician Winnipeg group, the Devonian- Mississippian Bakken formation, the Mississippian Lodgepole formation, and the Pennsylvanian Tyler formation (Fig. 1)(82412 bytes). In terms of total organic content, the Bakken is by far the most significant, but some of the others, especially the Lodgepole, may be more important than earlier thought.
During all of Devonian time the Williston basin was connected to the open ocean via a northwest-southeast trending seaway through Canada. By the end of the Devonian, the basin had become greatly restricted, and anaerobic conditions led to preservation of the organic material in the Bakken shales.
As the Canadian seaway closed off, a new seaway opened to the west, the Montana Trough, and the Mississippi-an megacycle began with a major marine transgression. Sedimentation changed from fine-grained terrigenous clastics to calcareous marine shales in the central part of the basin with biogenic build-ups in shoal areas and along the basin margins.
It was during this time of transition that the Lodgepole formation was laid down. Fig. 5 (58873 bytes) shows the facies distribution of the lower part of the Lodgepole and possible trend of the Lodge- pole play.
The discoveries by Conoco and Duncan appear to be on biohermal build-ups that have developed massive vugular porosity. The geological model currently used to describe them is that of the Waulsortian mound, named after a bioherm type found in Belgium (Fig. 6)(119785 bytes). Examples of bioherms of this type have been found in outcrops to the west in Montana and to the east in the Illinois basin. They appear to grow in low energy shoal areas, but the origin of the shoaling, whether thixotropic mud slumpage or differential bathymetry due to salt dissolution (or other causes), is not known.
The Lodgepole discovery by Conoco appears to have been fortuitous since the principal objective of the discovery well was deeper. The Duncan discovery well, on the other hand, was based on 3D seismic mapping of the Lodgepole reflection characteristics. Numerous subsequent wells have since confirmed accuracy of the mapping; as a result, over the past several months, hundreds of square miles of new 3D seismic have been shot by Duncan and other companies in the general area of Dickinson. Before the play is completed, it is expected that hundreds, perhaps thousands, more square miles of 3D seismic will be shot along trend in both directions from Dickinson.
Exploration success in finding other new fields in the Lodgepole or other objective formations will require, among other things, sufficiently large 3D seismic coverage to enable interpreters to discriminate between regional backgrounds and potential reservoirs. It will require the ability to map the wrench faults accurately and to relate their timings to hydrocarbon migration. It will also require the abilities to derive the locally complex 3D velocity functions needed to interpret the subtle salt solution features and to map interval velocity or acoustic impedance changes within the various objective formations with sufficient accuracy to infer potential reservoir conditions. Finally, it will require the ability to tie and calibrate the seismic at all levels to existing well control.
U.S. REJUVENATION
Important as the new developments in the Williston basin are, they are only precursors of a much larger rejuvenation of onshore oil and gas exploration in the United States that can be expected to develop. The most significant factor behind this rejuvenation is 3D seismic.
The technology is not new; in fact, the first experimental 3D surveys in the industry were carried out at least by the late 1950s. It was not until the 1980s, however, that field instrumen- tation, transport equipment, and processing power had developed enough to make 3D seismic economically viable.
Because of its more consistent shooting conditions and fewer land problems, the marine environment has seen the most development so that, today, most marine surveys are 3D. Land 3D seismic developments have lagged, partly because of the more- varied surface problems, but mainly because of the vastly more complex landownership conditions.
With developments in the Williston basin, on the Gulf Coast, and elsewhere, however, it is becoming evident that the technical benefits, as judged by the industry, are beginning to outweigh the increased costs and leasing complexity.
STRATIGRAPHIC INFORMATION
Initially, it was believed that the main benefit of 3D seismic would be in resolution of complex structure: for example, in salt dome and thrust provinces. Indeed, this is where it has been used the most. Typically, in order to save costs, 2D seismic profiling has been used to locate anomalous structural areas and has then been followed by 3D seismic to resolve them.
Now, it is beginning to appear that 3D seismic may be even more useful in resolving problems of stratigraphy, which explains its application in the Williston basin. The only twist here is that there is almost no way of effectively using 2D seismic work to localize to the centers of interest; the structure and stratigraphy are usually too subtle or complex for it to provide sufficiently unambiguous data for proper analysis and interpretation.
The result is that massive 3D seismic coverage is required from the start, a requirement that implies additional up-front capital investments in an industry that can barely stand exploratory drilling costs as they are. An economic assessment, however, must take place in the context of 3D seismic's technical implications.
In the seismic method, by one means or another, waves are induced in the ground and then recorded at the surface as a function of time. With 2D seismic, recordings are made along widely spaced (in terms of wavelengths) and discretely sampled lines, despite the fact that wave propagation in the ground is three-dimensional and continuous. It is the job of processing and interpretation to take this very sparse sampling of the three- dimensional wavefields and make geologic sense out of them.
In rigorous terms there is no solution, and a lot of geological intuition and guesswork must be introduced even to arrive at a very approximate interpretation. The largest part of the problem lies in the fact that the recordings are restricted to lines instead of being distributed a really over the surface. For example, seismic migration perpendicular to the line of recording cannot be done. In seismic jargon, the wavefields are aliased before the processing and interpretation are ever begun.
Independent sampling of the wave-fields over an area, as is done in 3D seismic work, permits much of this aliasing to be removed-but at the expense of squaring the number of independent observations. The additional data, however, provide for a much less-ambiguous imaging and inversion to the acoustic impedance distribution of the earth to be done, and a significantly better geologic interpretation to be made thereafter.
Most of these benefits are obvious in structural provinces, but they are less obvious in stratigraphic provinces. In a Stratigraphic province, such as the Williston basin, there are very few structural features having bedding plane dips of more than a few degrees; however, lateral facies changes abound and are crucial in the detection of potential reservoirs.
Scattered seismic energy from these facies changes must be migrated and inverted to acoustic impedance form, just as the specular reflections from dipping interfaces have to be migrated and inverted. Unless this is done, proper imaging of subsurface facies and accurate identification of potential reservoirs are not likely.
THE ECONOMIC DIMENSION
In view of the importance of 3D acquisition to petroleum exploration and production and the length of time its potential has been recognized, it is clear that unfavorable economics have dampened its application. Some of the perceived economic limitations have been valid, others not.
Perhaps the most misunderstood aspect of the economics has been the tendency to view 3D seismic solely as a method to minimize dry hole costs, which, of course, it can do. In fact, the savings, which can sometimes be quite accurately measured after the development of a field, are frequently only marginal.
The crucial factor that is often over-looked is the cost to a company of missing a potential field that would have been found if a 3D seismic survey had been run. From an economics viewpoint, this represents by far the greatest cost. But, since it is the most difficult to analyze, it is usually omitted.
How much more does 3D coverage cost than 2D at current levels of instrumentation, equipment, and processing capabilities? Obviously, this varies greatly depending upon surface and culture conditions, permitting costs, and processing and interpretation complexity.
An estimate for the North Dakota portion of the Williston basin is that 2D coverage at quarter-mile spacing of lines in two orthogonal directions is roughly equivalent in cost to full 3D coverage over the same area. In a stratigraphic play, quarter- mile spacing of lines is not unusual so that the absolute cost rates for 3D seismic coverage are not much greater than some companies are willing to accept with 2D seismic.
In this era of short investment time horizons, strategic or broad regional acquisition exploration, except for the largest companies, is a thing of the past. This has an immediate impact on 3D seismic and is related to seismic acquisition cost per acre under lease in onshore plays. Traditionally, individual companies have conducted 2D seismic programs over their own lease holdings and not much beyond. In terms of cost per acre under lease, the efficiency of such acquisition is reasonably good, but this has not been the case with 3D seismic in areas of divided lease holdings.
Especially in stratigraphic mapping, it is very important to acquire enough data to be able to identify what is anomalous and what is not. This means 3D acquisition, which must be carried out over broad areas, inevitably results in a low cost efficiency per acre under lease unless surrounding lease holders are willing to share costs in proportion to their holdings, something they are frequently unwilling to do.
For the full technical potential of 3D to be realized, costs of acquisition will have to be shared more than they are now. Basically, there are two traditional approaches: group surveys, where several companies with interests in a given area join together to share the costs of a single large survey; and nonexclusive surveys, which are conducted by a third party on a pre-subscription or speculative basis with the intent of subsequently selling the data, piece by piece, to anyone inter- ested in buying it.
The first approach is often plagued with management problems and in some cases runs the risk of violating antitrust laws. The second is probably the cleanest but may cost more because of the necessary fee to the third party managing it.
THE IMPLICATIONS
What are the implications of onshore 3D seismic work in the United States, based upon developments like the Williston basin Lodgepole play?
If the history of oil and gas exploration provides any criteria, it is likely that they will be profound. Based on experience over the past 40 years or so, we should expect another round of domestic oil and gas exploration.
Since World War II, important geophysical developments have brought about significant extensions to the life of the oil and gas industry. One of the first was the transition from the use of optically recorded paper records to the use of variable area or density profiles in interpretation. This converted the seismic method from a primarily one-dimensional analytical technology practiced by a relatively few specialized seismologists to a more visually intuitive, two-dimensional technology intelligible to most explorationists. It made possible better, more geologically reasonable interpretations and, for at least a decade, stimulated further exploration in the United States.
About the time it seemed that the economic finding of domestic oil and gas was drawing to a close, the common depth point (CDP) method came on the scene with its added moveout dimension and improved signal-to-noise characteristics, and another round of domestic exploration began.
Developments in 3D seismic are no different in fundamental character from these earlier developments. Each, in its turn, has increased the dimensionality of the data upon which the interpretation of the subsurface could be made, and the advent of 3D seismic with its added spatial dimension of observations can be expected to extend the life of the domestic oil and gas industry at least another decade or two before its full economic return is realized.
For 3D seismic to be economically viable over a wide range of conditions onshore, it is likely that nonexclusive surveys will be the form in which much future work will be carried out. This may run counter to the competitive preferences of the industry, but present-day economics will probably force the approach. There is much historical precedence for this kind of change, as transitions from company seismic crews to contractor seismic crews, from company seismic processing to contractor seismic processing, to name two, attest.
There is little doubt that 3D seismic methods have led not only to considerably better exploration success rates but also to exploration that would not have been economically justifiable with 2D methods. The Williston basin is a good example of this. The impact on United States oil and gas reserves will probably also be substantial both in the discovery of bypassed reserves in older fields and, especially, in the development of new reserves in provinces where stratigraphic trapping is the dominant style. Altogether, the coming of age of massive onshore 3D seismic in the Williston basin bodes well for the domestic oil and gas industry of the United States.
REFERENCES
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