Seismic Technology

Evolution of a Vital Tool for Reservoir Engineers

In the Duri field on the island of Sumatra, Caltex Pacific Indonesia is using four-dimensional (4D)—or three-dimensional (3D) time-lapse—seismic technology on a large scale to improve oil recovery and optimize energy use in the world’s largest steamflood. In the Ekofisk field in the North Sea, Phillips Petroleum has integrated borehole seismic images (also known as vertical seismic profiles) with 3D and 4D surface seismic data to monitor the reservoir and to position new wells more confidently to revitalize production. In the Kinsler field of southwestern Kansas, Amoco, Texaco, and Conoco have used crosswell seismic imaging to aid in drilling decisions and reservoir characterization. These accomplishments mark significant steps forward in the evolution of seismic technology beyond exploration to becoming a vital tool for field development and production. Similarly, these achievements exemplify the potential for turning untapped resources into recoverable reserves that can be realized when engineers and geoscientists work together in true multidisciplinary asset-management teams. Success in the oil field always has depended on minimizing risk and uncertainty. That, in turn, has driven the quest to acquire information about the subsurface and also to store, process, and manage that information to optimize production and minimize risk and cost. Petroleum seismic technology was used initially to generate structural images of subsurface targets. With the advent of 3D seismic and steady advances in acquisition, processing, and interpretation, seismic data now deliver not only more structural detail but also stratigraphic information and direct hydrocarbon indicators. When seismic data are integrated with well logs, core data, and other subsurface information, reservoir description and monitoring—and, thus, economics—are significantly enhanced.¹

In the Beginning

In 1924, the discovery of an oil field beneath the Nash salt dome in Brazoria County, Texas, was the first to be based on single-fold seismic data.² Before that, oilfield exploration was very much a guessing game based on surface signs. Stakes were high, and rewards could be tremendous, but losses from dry holes could be devastating. Then, engineers and geoscientists discovered that they could use low-frequency sound waves to map subsurface geologic structures and locate possible hydrocarbon traps.

Seismic instruments to record and measure movements of the ground during earthquakes were first developed during the middle of the 19th Century. John C. Karcher gave birth to the formula that is the basis of reflection seismology.³ This formula heralded a revolutionary change from refraction to reflection as the basis of oilfield seismology. In reflection seismology, subsurface formations are mapped by measuring the time it takes for acoustic pulses generated in the Earth to return to the surface after reflection from interfaces between geological formations with different physical properties.

In the early 1900s, Reginald Fessenden, chief physicist for the Submarine Signaling Co. of Boston, used sound waves to measure water depths and to detect icebergs. In 1913, seismic instruments he invented were used to record both refractions and reflections through Earth formations near Framingham, Massachusetts. In September 1917, the U.S. Patent Office issued a patent for “Method and Apparatus for Locating Ore Bodies.”⁴

During World War I, Ludger Mintrop invented a portable seismograph for the German army to use to locate Allied artillery. By recording Earth vibrations from positions opposite Allied bombardments, Mintrop could calculate gun locations so accurately that the first shot from a German gun often would make a direct hit.⁵ The Germans discovered that varying velocities among the geological formations through which their vibrations passed introduced errors into their distance calculations and that certain assumptions about geology had to be made to compute the distances. After the war, Mintrop reversed the process by measuring the distances and computing the geology from the Earth’s vibrations recorded on his portable seismograph and, in April 1923, was awarded a U.S. patent for the new process.

This was shortly after the 1921 Olahoma City tests conducted by Karcher, William Haseman, Irving Derrine, and William Kite that “proved the validity of the reflection seismograph as a useful tool in the search for oil.”⁶ In 1925, Karcher and DeGolyer persuaded Fessenden to sell his ore-bodies patent to Geophysical Research Corp. [On 16 May 1930, Karcher and Eugene McDermott, with the financial backing of DeGolyer, founded Geophysical Service Inc. (GSI).]

On 25 March 1925, Dabney Petty, Associate State Geologist for the Texas Bureau of Economic Geology, wrote to his brother, a structural engineer in Dallas, about application of Mintrop’s method by his company, Seismos, on the Texas gulf coast. In his return letter of 1 April, O. Scott Petty wrote of his idea to use the then-new vacuum tube to develop a seismograph that could operate without dynamite. “It occurs to me that if we had a seismograph that we could operate without using great quantities of dynamite—no dynamite at all, I mean—we would be able to put it all over these big companies,” Petty wrote. “Let’s try to invent a seismograph using a vacuum tube to detect the Earth vibrations so that it will be sensitive enough to register the vibrations made by simply dropping a heavy chunk of lead on the ground ….” This correspondence led to the invention and development of the first displacement-sensitive seismograph and also gave birth to the third of the pioneering geophysical firms, the Petty Cos.

Applying the seismic principles developed by these pioneers revolutionized the search for hydrocarbons and brought remarkable discoveries. Cecil Green, who was also a founder of Texas Instruments, once reminisced that geophysics was “a perfect combination of technology and people. … The high demands of science breed integrity, and modesty as well,” he said. “Show me a geologist, a geophysicst who’s brimming with ego, and I’ll show you a probable newcomer to the business. Mother Earth has a way of quickly showing you you’re always the upstart.”⁷

Transistors, Tape, and CDP

Following World War II, GSI acquired a license to build transistors that ultimately resulted in the birth of Texas Instruments, of which GSI then became a subsidiary. The move to transistorized equipment dramatically lightened the load for field crews.
Another advancement during the mid-1950s was the recording of seismic signals in variably magnetized tracks along the length of a magnetic tape. Changing from paper to taped records pointed the way to machine processing, development of the analog processor, and a total change in the way seismic data were collected and processed.

A third advancement in the 1950s was W. Harry Mayne’s invention of common-depth-point (CDP) data stacking. Mayne’s invention, also referred to as common midpoint or common reflection point, proved to be the main signal-to-noise-enhancing technique in seismic exploration and is still the basis from which novel techniques of economic continuous subsurface coverage depart.⁸ A fourth advancement, Conoco’s development of Vibroseis, made it possible to substitute manmade vibrations or waves for those caused by dynamite-generated explosions. Vibroseis relies on specially designed vibrating or weight-dropping equipment to create waves that penetrate the surface, strike underground formations, and reflect back to the seismograph in exactly the same manner as explosion-generated waves. The introduction of Vibroseis meant that the multiplicity of source points necessitated by CDP would be feasible without the associated increase in cost that was inevitable when dynamite was the only energy source

Digital Technology: The Second Revolution

According to Graebner, the second revolution in petroleum seismology occurred in the early 1960s with the arrival of digital technology. In a joint effort with Texas Instruments and several oil companies in 1961, GSI introduced the first digital field system and computer for seismic-data processing. Three years later, IBM introduced its 360 series of digital computers, and computers suddenly moved from novelty to commercial popularity. Geoscientists began moving data from bookshelves and file cabinets into computers, and processors had a heyday generating processing algorithms.

The evolution of modern petroleum seismic technology and the evolution of information technology (IT) are closely related. In fact, the two have developed in tandem, and the petroleum geophysical industry continually is one of the largest—and best—users of IT outside the high-tech industry itself.

With digital technology, signals detected by sensitive geophones could be read at millisecond intervals and recorded as binary digits across the width of a 1-in. format tape. Early well files mimicked the paper files from which they had descended. They contained primarily raw data. Seismic sections were correlated by hand to sonic logs to evaluate prospects. Computer filing quickly grew more sophisticated, however, and databases evolved. Complete digital gathering and processing systems were developed, systems approaches were adopted, and the amount of real subsurface information available improved dramatically.

Computing added a third dimension to reservoir modeling and increased the number of grids, which improved resolution. It also made it possible, for the first time, to model Earth properties with nonlinear characteristics.

Three-Dimensional Seismic: The Third Revolution

Graebner characterizes the move from two-dimensional (2D) to 3D seismic as the third major revolution in seismic technology. The concept of 3D-seismic surveying has existed since the earliest days of geophysics. However, the ability to implement that concept was restricted by the efficiency and accuracy of data acquisition and the cost and computing power necessary to condense, process, display, and help interpret data. All that changed in just over 1 decade and made 3D seismic a reliable and cost-effective method of optimizing field development and management.
By the early 1970s, the industry had developed a data-processing arsenal that contained, among other things, programs for single and multichannel processing, deconvolution, velocity filtering, automated statics, velocity analysis, migration, inversion, and noise reduction. These processing accomplishments and the accompanying improvements in data collection advanced seismic prospecting by levels of magnitude, but imaging methods were still 2D.⁹

The first 3D seismic survey was shot by Exxon over the Friendswood field near Houston in 1967. In 1972, GSI enlisted the support of six oil companies—Chevron, Amoco, Texaco, Mobil, Phillips, and Unocal—for a major research project to evaluate 3D seismic. The site selected for the experiment was the Bell Lake field in southeastern New Mexico.

The Bell Lake field was a structural play with nine producers and several dry holes. It also had sufficient borehole data to ensure that 3D seismic could be correlated to subsurface geology. The acquisition phase took only about 1 month, but processing the half million input traces required another 2 years, and producing migrated time maps without workstations or any other form of 3D interpretation aid was also a lengthy process. Nonetheless, the project was a defining event in seismic history because the resulting maps confirmed the field’s nine producers, condemned its three dry holes, and revealed several new drilling locations in a mature field. The development of 3D seismic was one of the most important technological breakthroughs in an industry in which profitability is closely tied to innovation and technology. Finally, the subsurface could be depicted on a rectangular grid that provided the interpreter with detailed information about the full 3D subsurface volume. The images produced from 3D data provided clearer and more accurate information than those from 2D data. Any desired cross section could be extracted from the volume for display and analysis, including vertical sections along any desired zigzag path.

Lateral detail also was enhanced by the dense spatial coverage in 3D surveys. Slicing the data volume horizontally at fixed reflection times yielded comprehensive overviews of subsurface structural features, particularly faulting. Attributes could be mapped and displayed along curved reflector surfaces. The accurate positioning of events made possible through 3D migration also improved subsurface imaging of flatter-lying stratigraphic targets. The result was an extension of the value of seismic data for exploration and production functions.

Modern 3D Seismic Technology

Today, 3D-seismic technology is applied to solve problems and reduce uncertainties across the entire range of exploration, development, and production operations. Surveys are used to characterize and model reservoirs, to plan and execute enhanced-oil-recovery strategies, and to monitor fluid movement in reservoirs as they are developed and produced. These capabilities have been made possible by advancements in data acquisition, processing, and interpretation that have both improved accuracy and reduced turnaround time.

Acquisition. Reduction in 3D data-acquisition time has reduced the price of 3D data and dramatically increased the amount of data available. Better and more reliable instrumentation, better and more streamers per swath, improved and faster navigation processing, and onboard quality control and data processing have dramatically reduced downtime. Today, marine seismic vessels used for 3D acquisition have, on average, four or five streamers, although some supersized vessels can tow up to 16 streamers simultaneously.¹⁰ Another dramatic improvement in acquisition technology has come about through ocean-bottom-cable (OBC) surveying methods. Once considered a specialized technique, OBC acquisition has become competitive with streamer operations in water depths of up to 650 ft. With the OBC method, cables connected to stationary receiver stations are deployed on the ocean bottom, and a marine vessel towing an array of air guns serves as the energy source. This makes it possible to survey congested areas safely and uniformly.¹¹ Additionally, resolution is higher because the quality of measurements is less affected by noise and other disruptions and because control of actual positioning makes repeated surveys more reliable. Processing. Commercialization of 3D depth migration, the process by which geophysical-time measurements are processed into depth readings, owes itself to parallel computing. In places where lateral changes in the Earth take place quickly, time images of the subsurface are distorted by those changes. When these data are processed into depth, a substantially more accurate picture of the Earth’s subsurface is yielded if velocities of the rocks are known. Today, 3D depth migration is emerging as a truly interpretive data-processing method that is closing the communications gap between geologists, geophysicists, and reservoir engineers.

Interpretation. Maturation of 3D interactive workstations has played a key role in the widespread acceptance of 3D-seismic data. The amount of raw data to be interpreted per survey has increased by a factor of more than 5,000 over the past 15 years, placing a premium on efficiency in the interpretive process.¹²

One of the most exciting advancements in 3D interpretation is 3D visualization. Humans perceive the 3D world through a variety of visual cues that include perspective, lighting and shading, depth of focus, depth cueing, transparency and obscuration, stereopsis, and peripheral vision. With the addition of each visual cue, 3D-seismic interpretation has become more efficient, accurate, and complete. Large amounts of data have been integrated into easily understood displays, and communication between the various members of asset and management teams has improved.

Methods for 3D visualization have evolved from a lighted 3D horizon surface to desktop visualization to the current immersive environments that engage peripheral vision. In 1997 Arco, Texaco, and Norsk Hydro each installed large immersive visualization environments. The Texaco facilities are visionariums—that is, 8- to 10-ft-tall screens that curve horizontally through approximately 160°, with data projected by use of three projectors that each covers one-third of the screen. Arco and Norsk Hydro use immersive visualization rooms based on the virtual reality interface CAVE, invented at the U. of Illinois at Chicago. In a CAVE, three walls and the floor are used as projection surfaces, and the images on the walls are backprojected, while the image on the floor is projected from the top down. In these environments, the data not only surround the interpreters but actually appear to fill the room. Members of the asset team literally can walk through the data and discuss the reservoir with one another. With a 3D pointer, a new production well can be planned from inside the reservoir and the effects of any changes experienced immediately.¹³

Four-Dimensional Seismic

Time-lapse, or 4D, seismic, consists of a series of 3D-seismic surveys repeated over time to monitor how reservoir properties (such as fluids, temperature, and pressure) change throughout the productive life. Consequently, fluid movements can be anticipated before they affect production. Similarly, placement of extraction and injector wells can be fine tuned, bypassed oil and gas can be recovered, and production rates can be accelerated.¹⁴

For example, in the Duri steamflood project in Sumatra, which produces approximately 300,000 B/D of high-viscosity oil, placing injector wells with the aid of 4D seismic is expected to help operator Caltex (a Chevron and Texaco affiliate) raise recovery efficiency in a complex reservoir from 8% primary recovery to nearly 60%. A 4D-seismic pilot was conducted in the field with a baseline survey and six monitor surveys recorded at various intervals over 31 months. The pilot, which consisted of a central steam-injection well surrounded by six production wells, demonstrated that the horizontal and vertical distribution of steam could be tracked over time. On the basis of the quality and detail of reservoir information from the pilot study, a multidisciplinary asset team assessed the economic feasibility of large-scale 4D monitoring of the Duri field. The assessment took into account the benefits of time-lapse seismic as well as the cost of seismic data and the risk probability of various outcomes. Benefits included shutting off injection in swept zones; putting steam into cold zones; and locating observation wells in the right places, possibly eventually reducing the need for them. When these benefits were weighed vs. seismic-data cost and risk factors and compared with other operating scenarios for the field, the conclusion was that the largest net present value could be obtained by aggressively managing the steamflood with 4D seismic.¹⁵ Four-dimensional reservoir-monitoring projects are also being conducted in numerous other parts of the world, including the North Sea, Southeast Asia, and the Gulf of Mexico.

Crosswell Seismic Technologies

Detailed understanding of reservoir flow and barrier architecture is crucial to optimizing hydrocarbon recovery. Crosswell seismology—that is, using seismic sources in a wellbore and recording the wave propagation in another wellbore—is the only spatially continuous, very-high-resolution method that can image such features as faults, stratigraphic boundaries, unconformities, sequence porosity, fracturing, and additional untapped reservoir bodies away from the well. Crosswell data currently are expensive to acquire, and processing the data through topographic inversion and migration requires considerable expertise. However, the fact that answers to many of the most challenging geophysical problems reside within this high-resolution, wide-azimuth illumination of rocks on a macroscale is driving the technology to become a viable and regularly used tool.¹⁶

Looking Ahead

Integration, miniaturization, and production are likely to be operative words in describing seismic technology in the 21st Century. With most, if not all, of the world’s more obvious reservoirs already discovered and in production, and given the likelihood that unstable oil prices are here to stay, emphasis in the oil field will focus on integrating technologies and disciplines to optimize recovery in existing fields and develop new fields quickly. All this means that seismic technology will become more and more a tool for production rather than exploration work. It also means that geoscientists and reservoir engineers will work together more closely and cooperatively.

Full-Vector Wavefield Imaging: The Fourth Revolution. According to Graebner, a fourth revolution in seismic technology, full-vector wavefield (or multicomponent) imaging, which includes both shear and compressional waves (S- and P-waves, respectively) to capture rock properties between wells, will add further value to seismic as a production tool.

P-waves, the traditional waves of seismic exploration, are influenced not only by rock frame properties but also by the nature of the fluid in the rock pores. S-waves, on the other hand, are insensitive to the type of fluid in sediments. Full-vector wavefield imaging makes it possible, among other things, to “see” through gas chimneys that plague economically important areas, such as the North Sea. These chimneys, which are caused by free gas in the sediments, destroy P-wave continuity but hardly affect S-wave reflections. Combining P- and S-waves also helps asset-team members discriminate among sands and shales and is valuable in helping detect fractures.¹⁷ Using multicomponent imaging to detect fractures and stratigraphic traps will bring engineers and geoscientists closer together. They will learn one another’s jargon and paradigms both on the job and in university education. They will monitor reservoirs routinely with time-lapse seismic and process data both in the field and in their offices essentially in real time, thanks to cost-effective, high-bandwidth satellite communication. Finally, of course, they will continue to search for even better and faster ways of improving success ratios and reducing risk in the oil field.

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