Western Atlas has developed a series of steps that determine the value of the bright spots
Dev GeorgeSince the early 1970s, bright spots have been the goal of explorationists. These high amplitude events on seismic records often indicate the presence of hydrocarbons, and, despite other improvements in seismic acquisition and interpretation, these indicators continue to be sought, even as data density and increased resolution vastly expand the volume of the data itself.
As a result, the geoscientist is confronted by a massive amount of data from which he must quickly derive an accurate evaluation of the area showing amplitude anomalies, its prospectivity, and economic viability.
Geophysicists Peter Kahn and Steve Hightower, both with Western Atlas E&P Services, have developed a process for making this evaluation. By establishing a series of steps and utilizing Western Atlas skills and tools, they have been able to determine the value of bright spots encountered in client data. Both rapid and proven, the work was completed with data from lease blocks in the Ship Shoal area, offshore Louisiana, and the results provided within four weeks.
The geoscientist begins the process by scanning large 3D data volumes for new and improved prospects. Anomalies that could represent potential hydrocarbons are quickly and efficiently found by employing powerful 3D visualization software.
The amplitude anomaly scan, spatially encompasses one lease block in the X and Y directions and 1 to 5 seconds in the vertical direction. The data's amplitude range is provided by system, but a subset range that correlates with anomalous peak and trough amplitudes is defined by the user.
With the anomalies processed and presented, and their inline, crossline, and time locations known, the most likely anomalies are selected for further investigation.
Well log stratigraphy
The lease area had seen nine wells drilled which produced three significant gas discoveries with some associated oil. Five of the wells were shut in, with minor production or gas shows, and one was a water wet well. Full wireline log suites and some horizon top information was provided by the client. Information regarding the presence and abundance of microfossils was also provided where log data were not available, which allowed the E&P geoscientist to date tops of formations.
Hydrocarbon pay is known to involve up to ten reservoir sands deposited in early Pliocene time (about 3.0-5.5 million years ago, in the study area. These potential pay zones span 12,000-17,000 ft. Overpressure was not encountered by any of the nine wells.
The signature seen on wireline curves is blocky in each of the sand units, an effect that increases as depth decreases. The type of signature encountered is typical of a shelf-margin shoreface-deltaic environment of deposition. The deltas were located in the northern part of the block under study when the sea level was low (lowstand), according to regional geological publications.
Adjacent deposition commenced with deposition of the "Tex" sands and concluded with an unconformity, a major break in the deposition, marked by the "Tex-1" surface. Reflections deformed as the sea level dropped, and this unconformity surface became a major boundary between beds with different depostional histories. Overlying Mid-Late Pliocene marine shales have acted as a regional seal.
Up to ten lowstand sand units have been identified on the logs, with each sand unit capped by muds-marine shales deposited in front of the deltas. These sand/shale bundles or parasequences, appear to extend over the length of well log cross sections. In fact, correlation of the log curves indicates that nearly all the potential reservoir sands are laterally continuous.
To calculate information needed for subsequent volumetric determinations, wireline logs were also used. Water saturation, porosity, ratio of net-to-gross sand thicknesses, and other reservoir characteristics data were then tabulated for each of the parasequences. Landmark's Stratworks and Western Atlas's eXpress software were used to overlay one wireline curve atop another and help to tie the wells for logs with unknown horizon picks. It was evident after this correlation work that some reservoir sections had been reduced or removed by erosion. Within any sand unit where gas columns were interpreted, water legs always appeared to be present, suggesting discrete reservoirs with water being the main drive mechanism.
Influences on trap genesis
In most of this area of the Gulf of Mexico, sediments from southwardly advancing deltas loaded and mobilized underlying salt, which flows both laterally and in the downdip (southerly) direction. The evacuating salt left a topographic low that trapped sediments from the deltas. During early Pliocene times in the Ship Shoal area, shelf-margin deltas prograded southwards across the evacuated low, setting up a number of growth fault-related rollover structures, which, in turn, rest on a deep-seated fault that may have been a conduit for the upward movement of hydrocarbons into trays. The faults break counter to regional dip, thus, amplitude anomalies near the deep-seated faults probably are hydrocarbon-bearing. As a matter of fact, wells in the Ship Shoal lease block known to be water wet also had obviously been drilled on the backside of a salt structure through which hydrocarbons were not likely to have migrated.
Timing the charging of a trap with hydrocarbons to trap formation can play a critical role in establishing the risk attached to prospects. For example, two wells drilled on relatively older growth fault structures encountered shows and noncommercial quantities of gas. In contrast, wells drilled on relatively late structures are significant discoveries.
Amplitude anomalies, traps
The geoscientist begins evaluation by loading 3D seismic data, well log curves, synthetic seismograms, and lithology columns into OASIIS software. The phase of the data is determined from extracted wavelets and data dephasing - a process that eliminates some differences in the appearance of reflected wavelets - applied as necessary. Synthetic seismograms generated from well logs were overlaid on the sismic section and tied to known tops of subsurface horizons. With the well log data tied into the seismic data, the geoscientist can begin to develop horizon picks for the target sand units.
"Previous work led us to expect a Type 1 wavelet response, a reflection wavelet that is a dominant leading trough followed by a dominant peak," said Kahn and Hightower. "A wavelet that has this appearance can be an indication of potential hydrocarbon accumulation."
Integral to the identification of the bright spot amplitudes that ought to be investigated further was the structural framework that was created at the same time from the interpretation of faults as seen on the seismic and log data.
"In the Ship Shoal area," said Kkahn and Hightower, "the major, deep-seated faults are considered to have helped provide migration pathways for hydrocarbons, while shallower secondary faults account for reservoir boundaries and trap seals. In the manner just described, Western's geoscientists produced a detailed time structural interpretation of the block that included fault plane maps, horizon maps, and well tie traverses. Integrating this seismic data with the geological model for trap formation allowed interpreters to high-grade the amplitude anomalies and to focus only on those bright spots that were in close proximity to the major fault features. These faults are part of a tectonic extorsional system of beds that pulled apart and developed episodically as underlying salt evacuated the area and moved in a southward direction. The timing of structural trap formation appears to have played an important role in the accumulation of significant amounts of commercial hydrocarbons."
As it applied to the Ship Shoal lease block, the selection process produced three top contender amplitude anomalies that necessitated additional analysis. An isochron or map of the thickness above each reservoir was achieved by interpretation of the top and base of each anomaly.
It is imprtant to understand tuning effects and the related thickness resolution inherent in the data. Frequently, bright spot anomalies feature a thin top-to-bottom thickness isochron, and there is a clash between reflections emanating from the top and bottom of hydrocarbon-bearing beds which produce characteristic signatures on seismic data. That is tuning, and it is important that the geophysicist produce a tuning model for the data that can act as a guide for determining which reservoir sector lies below the thickness resolution established by the tuning interference.
Amplitude maps were also produced to indicate the spatial distribution within the reservoir of possible hydrocarbons. Western Atlas's E&P Srvices' geophysicists used OASIIS software to extract an amplitude attribute along the interpreted top and base horizon, and an average amplitude between the two horizons, and these were mapped to further demonstrate the areal extent of potential hydrocarbons and to provide parameters for generating net pay maps.
The geoscientist is able to take avantage of the relationship between well properties and seismic amplitude attributes in those areas where both amplitude anomalies and well control is present. Using the SigmaView geostatistical software, the geoscientist can determine the correlation between reservoir thickness and an extracted amplitude attribute at sample points on the well location. Thereafter, a reservoir map is produced for points between them, using seismic data as a guide.
A different correlation approach was taken in the Ship Shoal block, however, since the target bright spots were untested. At first, the geophysicists spotted the gross thickness of known pay zones on the seismic data and computed the isochron thicknesses by analyzing all available well logs. With the SigmaView software, the pay zone data was then crossplotted and a regression function through the data points was computed. (The slope of the regression line represents a velocity in ft/msec that was used to convert the isochron time thickness map to an isopach depth thickness.)
How much hydrocarbons
Reservoir engineers worked very closely from the very beginning with the geologists to determine well-log properties that were appropriate for recovery factor calculations, such as porosity, permeability, water saturation, and reservoir parameters such as bottomhole temperature, pressure/temperature gradientism, and mud weights. Each of these provided key data for reserve estimations.
Such volumetric calculations can also include a number of area-determining tools factor in structural geometries and oil-water contacts and provide area and acre/ft data. Although these calculations are constrained by how much of the hydrocarbons held in a trap can realistically be recovered, they define the raw data needed for reserve estimates and produce a net pay map.
What will development cost?
Concurrent with geological and geophysical data interpretion and integration, E&P Services engineers were also constructing a risked value for each of the prospects by evaluating relevant data such as production histories and pressure data from analogous feields, which they relayed to the geoscientists. Thus, by incorporating information on infrastructure, drilling costs, economics, etc., the engineers helped to produce a development plan for exploiting the prospects. Although none of the amplitude anomaly prospects that were defined have been drilled to date, the staged process of evaluation has been applied successfully to accurately predict known results.
For operators, this total process is a cost-effective and rapid means of establishing the economic value of bright spots. In the case of the Ship Shoal lease blocks, from 16 bright spots mapped on seismic data, four were high-graded and risked. Of the four, two are deemed highly prospective. As a generic economic evaluation, the success of this process of combining and building on engineering, geological, and geophysical strengths can be highly effective.