Oil and Gas, Exploration for

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Exploration for oil and gas has evolved from a basic trial-and-error drilling to the application of sophisticated geophysical techniques to predict the best locations for drilling.


Oil and gas are usually associated with sedimentary rocks. The three basic types of sedimentary rocks are shales, sands, and carbonates. The shales are the sources of the hydrocarbons while the sands and carbonates act as the conduits and/or the containers.

Source Rocks

Shales often are deposited with some organic matter, for example, microscopic plant or animal matter, that become part of the rock. When the shales are squeezed under the pressure of overlying rocks and heated by the natural heat flowing from the earth, oil and gas may be formed depending on the type of organic matter involved and the temperature to which the source rock is raised. If a rock is capable of producing oil or gas, it is referred to as a source rock because it is a source for the hydrocarbons. An important element of modern exploration is making certain that a new area being explored has source rocks capable of generating hydrocarbons.

The petroleum industry relies on organic geochemists to analyze the source rocks in new exploration environments. The geochemists evaluate the potential of a source rock for producing oil and gas by determining the amount and type of organic matter as well as the amount of heating and pressure applied to the rock. The whole process of making hydrocarbons can be compared to cooking in the kitchen. The final product depends upon the ingredients and the temperature of the oven (or sedimentary basin in the case of a source rock). Geochemists perform studies of potential source rocks in order to evaluate both the thermal history and the basic ingredients.

The important ingredient in a source rock is the organic matter or kerogen (Figure 1). Kerogen originally meant "mother of oil" but is used to today to describe the organic component of sediment not solvable in common solvents. Kerogens consist of basic biochemicals including carbohydrates, proteins, polyphenols, and lipids. Oil and gas are derived from kerogens rich in lipids. These types of kerogens are often deposited in lakes or marine environments. Other types of kerogens derived primarily from land plants are more prone to producing only gas. The geochemist has to identify the type of kerogen in a source rock in order to predict the types of hydrocarbons generated.

As the source rocks are buried and their temperature increases, the individual kerogens undergo chemical changes that are referred to as maturation. When the temperature reaches around 60–70°C and the rocks are buried approximately 1000 m below the surface, hydrocarbons begin to be released from the kerogen. At first oil is produced from the rock if the kerogen is the right type. Next, "wet" gas (or a gas with many different components) and finally "dry" gas (or a gas made up primarily of methane) is produced. As the rock continues to cook beyond the dry gas stage, the residual kerogen is of little use for producing oil and gas. Just as in the kitchen, too much heating can spoil even the best of ingredients.

Geochemists try to determine where hydrocarbons begin to be liberated and how their quantity and composition may vary with increasing maturity. This is equivalent to evaluating the amount and type of kerogen present in the rocks as well as the maturity (or amount of cooking in the analogy used above) for the potential source rocks in a region being explored. In addition, geochemists try to estimate when and in what directions the hydrocarbons migrated. This helps with the exploration process because some traps may have been formed too late in order to hold hydrocarbons.

One important measurement made by geochemists is the Total Organic Carbon (TOC) measurement. The results are expressed as a weight percentage. When the TOC is less than 0.5 percent, the rock is considered unlikely to have enough kerogen to produce oil or gas.

Other measurements made by geochemists try to determine the state or level of maturity of a rock. Just as with cooking, the color and appearance of kerogen changes as the source rock matures. As a result, there are several schemes for using color changes to measure the maturity of a source rock. One example is called the vitrinite reflectivity. Vitrinite is a main component of coal and is also found dispersed in source rocks. The reflectance of light from the vitrinite is measured electronically under a microscope and is denoted R0 (the vitrinite reflectance). When R0 is less than 0.5 to 0.7 percent, the rock is immature and still in the diagenesis stage of maturing. For R0 greater than 0.5 to 0.7 percent to around 1.3 percent, the rock is mature and in the oil window of development. When R0 is greater than around 1.3 percent and less than 2 percent, this stage of maturity implies the source rock is producing condensate and wet gas. When R0 is greater than 2 percent and less than 4 percent methane is the primary hydrocarbon generated (dry gas zone). When the reflectance is greater than 4 percent, the source rock has been overcooked. Vitrinite reflectance R0 combined with the measurement of the TOC and a determination of the type of kerogen can then be used to predict the amount and type of hydrocarbons expected from a source rock. The type or kerogen in a source rock is determined using laboratory techniques to determine the relative quantities of hydrogen and oxygen in the kerogen. For example, if the atomic ratio of hydrodren to carbon of the kerogen is plotted on a graph against the atomic ratio of oxygen to carbon, different types of kerogens can be identified. Three categories of kerogen can be identified using this type of plot. Type I kerogen is rich in lipids and is an excellent source of oil. Type II is still a good source rock but is not as rich in lipids and not as oil prone at the Type I kerogen. Type III kerogen is primarily a gas prone kerogen. Armed with results of this type of study, the geochemist is able to make predictions regarding the quality of the source rocks in an exploration area and the expected products (oil, gas, or both) expected from them. In addition, geochemists work with geologists to predict the timing and the direction of flow of hydrocarbons as they are expelled from the source rocks. This information is then used in exploration to evaluate the relative timing between trap formation and the creation of the oil. A potential oil trap might be capable of holding a great deal of oil and still not have one drop of oil because the trap was formed after the oil had migrated past the trap.

Reservoir Rocks

Once the potential for hydrocarbons has been verified in a region, explorationists look for reservoir rocks that potentially contain the hydrocarbons. Reservoir rocks are typically comprised of sands or carbonates that have space, called "porosity," for holding the oil. Sands are present at most beaches, so it is not surprising that a great deal of petroleum has been found in sands that were once part of an ancient beach. Other environments responsible for sandstones include rivers, river deltas, and submarine fans. An example of a carbonate environment is a coral reef, much like the reef located off the coast of Florida. The sediment deposited on reefs consists of the skeletons of tiny sea creatures made up primarily of calcium carbonate. The sandstone and carbonate rocks become a type of underground pipeline for transporting and holding the oil and gas expelled from the source rocks. These reservoir rocks have pore spaces (porosity) and the ability to transmit fluids (permeability). A rock with a high porosity and high permeability is considered a desirable reservoir rock because it can not only store more petroleum, but the petroleum will flow easily when being produced from the reservoir. Finding reservoir rocks is not always easy and much of the effort of exploration is devoted to locating them. One approach to looking for reservoir rocks is to make maps over a region based on data from wells (Figure 2). Geologists can use these maps to predict the range of distribution for the reservoir rocks. For example, if the reservoir rocks were deposited by a river system, the map can show a narrow patch of sand following the meander of an ancient river channel. Because the speed of sound in sands and carbonates (reservoir rocks) is usually faster than in the surrounding shales (usually the source rock), the difference can be used to identify reservoir rocks by the reflection character and strength on the seismic data. One popular seismic method for examining the strength of the reflection coefficient as a function of source-receiver separation (referred to as "offset") is called "amplitude-versus-offset" or "AVO." Another way to identify reservoir rocks is their anisotropy when compared to the anisotropy of shales. Anisotropy is used here to describe the directional dependence of a material property (the velocity in this case). Shales have a natural anisotropy that causes the speed of sound to travel faster horizontally than vertically. Reservoir rocks tend to have a different type of anisotropy caused by fractures or no anisotropy at all (they are said to be "isotropic" in this case). When searching for reservoir rocks, the key is to separate the type of anisotropy caused by shales from the anisotropy (or lack of it) due to the reservoir rocks that are present. This approach can be used to seismically evaluate the potential for reservoir rocks in a region. Still another seismic approach to predicting the presence of reservoir rocks is based on a geological interpretation of the seismic data called "seismic stratigraphy." All of the above methods are used to identify the presence of reservoir rocks in an area being explored.


Once the petroleum has been generated and squeezed from a source rock into a neighboring sand or carbonate, the petroleum is free to move through the porous and permeable formations until it reaches the surface or meets a place beyond which the petroleum can no longer flow. When the petroleum flows to the surface, the hydrocarbons are referred to as seeps. When the hydrocarbons are prevented from reaching the surface, they are "trapped" (see Figure 3). Traps are divided into two basic categories: structural and stratigraphic. Structural traps are caused by a deformation of the earth that shapes the strata of reservoir rocks into a geometry that allows the hydrocarbons to flow into the structure but prevents their easy escape. The deformation can be caused by thrust faults such as those responsible for mountain building or normal faults such as those found in subsiding sedimentary basins such as the Gulf of Mexico. Stratigraphic traps are the result of lateral variations in layered sedimentary rocks so that porous rocks grade into nonporous rocks, that will not allow the petroleum to move any further. The easiest traps to find have been structural traps, because deformation usually affects all adjacent layers or strata. This means that the effects are easier to see on seismic data. The stratigraphic traps are the most difficult to find because they occur without affecting much of the surrounding geology. Many reservoirs are constrained by both stratigraphic and structural trapping.


Geologists can be thought of as the historians of the earth. History is important to exploration success. When a well is drilled, a number of devices are lowered down the well to log or identify the different formations that have been penetrated. The geologist uses the logs from many different wells to put together an interpretation of the geology between wells. A part of the interpretation process involves making structure maps of the depth of sedimentary rock formations beneath the surface of Earth. In addition, geologists try to predict stratigraphic variations between wells using other mapping techniques. Besides being historians, geologists must solve geometric puzzles because they use the bits and pieces of information about rock layers observed from the well logs in order to form a complete picture of the earth. They can, for example compare well logs from two adjacent wells and determine if a fault cuts through one of the bore holes. The interpretation for modern geologists has been more challenging because many oil and gas wells purposely deviate from the vertical. Modem geologists employ numerous geometric tricks of the trade to assemble complicated 3-D interpretations of the earth and to identify where the reservoir rocks are located.


Geophysical methods are used to obtain information on the geology away from the wells where the location of oil- and gas-producing formations is known. In the early 1900s, the use of geophysics to find structural traps was accomplished by employing gravity and seismic methods. Gravity methods were the earliest geophysical method used for oil and gas exploration. The torsion balance gravimeter that was originally invented by Roland von Eotvos of Hungary (1890) later became an exploration tool. The first discovery by any geophysical method in the United States was made using a torsion balance in January 1924. Nash Dome was discovered in Brazoria County, Texas, by Rycade Oil Company, a subsidiary of Amerada. Sensitive gravity instruments measure the changes in the pull of Earth's gravity at different locations. The gravitational pull varies due to density variations in the different types of rocks. Because salt is lighter than most sedimentary rocks, gravity measurements were a popular approach to finding reservoirs associated with salt domes.

Sounding methods for spotting enemy artillery that were developed during World War I led to the major seismic exploration methods. On the German side, Ludger Mintrop developed the refraction exploration method that was most useful for early exploration of salt domes. Although Robert Mallet shot the first refraction survey in 1845, Mintrop recognized the commercial value of refraction surveying. He was able to verify the refraction method as an exploration tool by finding two salt domes in Germany in the period 1920–1921. In June 1924, shortly after the first torsion balance discovery, a Mintrop refraction crew (a company named "Seismos") discovered Orchard Dome in Fort Bend County, Texas. A patent filed in the United States in January 1917 by Reginald Fessenden, a Canadian by birth, laid down the fundamental ideas of using sound waves for exploration. The title of Fessenden's patent was "Methods and Apparatus for Locating Ore Bodies." In addition, the French, British, and U.S. wartime sound ranging efforts (for artillery) laid some of the foundation for the development of early seismic instrumentation and thinking developed by John Clarence Karcher. In 1921, Karcher used seismic reflections to map the depth to the top of the Viola limestone in Oklahoma. In 1927, Geophysical Research Corporation made the first seismic reflection discovery near Potawattamie County, Oklahoma. The successful well was drilled September 13, 1928. John Clarence Karcher and Everette Lee DeGolyer were the major contributors to this new exploration tool. Today the seismic reflection method is the dominant form of exploration. The depth to the top of the oil and gas formations can be mapped with this technique, so the seismic reflection method can be used to directly identify structural traps.

Many other geophysical methods were attempted, but the gravity and seismic methods have survived the test of time. Gravity and seismic methods are often used in tandem because they give complementary information. This is helpful when exploring beneath salt or volcanic lava flows where seismic methods suffer difficulties. Some early work on magnetic measurements were accomplished, but magnetic surveys did not become popular until more sophisticated magnetometers were developed after World War II. When Conrad and Marcel Schlumberger joined forces with Henri Doll in the 1920s, they achieved the first geophysical logging of wells. The electric logs and other logs they developed played a major role in the early history of oil and gas exploration. The company they formed, Schlumberger Limited, has been an active contributor to numerous technological advances.


In the 1950s the petroleum industry experienced an explosion of technology, a trend that continues today. One of the contributors in this effort was Harry Mayne, who developed common depth-point stacking, a method of adding seismic signals. The resulting stacked signals were then plotted in the form of a picture called a seismic section. The seismic sections, that appear as cross-sections of the earth, were initially used to find structural traps. The creation of the stacked sections benefited from digital recording that could be used to accurately record the amplitudes of seismic signals. True amplitude recording led to the discovery that the presence of hydrocarbons, especially gas, caused high-amplitude seismic reflections. These reflections, that appeared as bright spots on the seismic sections, enabled researchers to distinguish hydrocarbons from the surrounding rocks. Thus, in the 1970s bright-spot technology was developed by the petroleum industry to directly detect hydrocarbons from the surface. Shell Oil Company was the first company to use this new technology in the offshore region of the Gulf of Mexico, lowering the risk of falsely identifying oil and gas reservoirs. Unfortunately, other geological circumstances can create bright reflectors and some of these locations have been drilled.

As a result of these limitations in identifying stratigraphic traps, the industry sought a better understanding of stratigraphy. An important contribution to this understanding was the development of improved seismic methods to map stratigraphy. This improved method shaped the waveform leaving a seismic source into a shorter duration signal (the wave form is said to have been deconvolved). Enders Robinson, who had been a part of radar research efforts at MIT during World War II, introduced the deconvolution methods to the industry. Robinson applied some of the same radar technology to compress the seismic wavelets so that small changes in the stratigraphy could be mapped.

Seismic stratigraphy, originally developed by Peter Vail and his associates at Exxon, was another important contribution to the industry's ability to unravel the stratigraphy of the earth. As the industry pushed to find even more information about stratigraphic variations, methods were developed to use information about the shear-wave properties of rock as well as the compressional-wave velocities that had been the primary tool for seismic exploration. Shear waves or shear-related methods of exploration, such as AVO are used by the industry to identify changes in lithology (e.g., from sandstones to shales). These methods can also be used to evaluate bright spots or other types of reflection amplitude anomalies. For example, AVO methods are used to find rocks that have been fractured, thus making them into better reservoir rocks. In the early 1970s Jon Claerbout at Stanford University introduced an important seismic imaging principle that is still used today migrate seismic data accurately. "Migration" is a process used by geophysicists to plot seismic reflections in their true spatial positions. Today, many companies are using more sophisticated seismic imaging and analysis techniques called "inversion".

An important part of interpreting surface seismic data is the identification of the oil- and gas-bearing zones on the seismic data. Vertical seismic profile (VSPs) data are often recorded with a source on the surface and with receivers down the well to accomplish this task. In this way, the travel time to the reservoir can be measured along with other information relating the well data to the surface seismic data.

Another type of technology that has influenced oil and gas exploration is the acquisition of 3-D surface seismic data. This technology produces so much information that modern interpreters have been forced to give up looking at paper sections and use computers just to view their data. The 3-D seismic surveys are very much like a solid section of the earth. An interpreter can sit at a workstation and literally slice through the data viewing the seismic picture of the earth in almost every way possible. Some companies have assembled virtual reality rooms where the interpreter actually feels as if he or she is walking inside the earth to make the interpretation. Maps that might have taken months to produce in the early days of seismic mapping can now be accomplished in minutes. Computers are used not only for seismic processing and interpretation but for geological modeling and more accurate reservoir modeling. Integrated teams of scientists consisting of geologists, geophysicists, and petroleum engineers are pooling their talents to construct detailed 3-D models of reservoirs.


If the area being explored is a new one, the company has to make an assessment of the source rock potential. Next, they look for the reservoir rock and the trap. Sophisticated seismic methods including 3-D seismic surveys and VSPs are used to create a picture of where the oil and gas traps are located. They can also be used to determine when the traps were formed as well as the amount of oil and/or gas they contain. Seismic methods are often integrated with other geophysical measurements such as gravity, and magnetic or magnetotelluric measurements. In this way, the complementary data can be used to give a more complete picture of the geology.


Because financial risk is a major element of exploration, putting together a map that indicates where to drill is only part of the exploration process. Someone has to be convinced to put money into the effort to drill. Large companies go through multiple computer runs to evaluate the risks of drilling at a prospective site. Smaller companies tend to use a formula in which they multiply the probability of success times the current value of the oil that will be obtained if the well is successful. Next, they subtract from this product the probability of failure times the cost of drilling a dry well. The difference is called the "Expected Monetary Value" (EMV). If the EMV is a positive number, the well is judged to be a potentially profitable investment. Geophysical methods act to raise the probability of success for finding an economically successful well. However, the geophysical methods raise the cost of a dry well. Modern methods of geophysical exploration have raised the probability of success by as much as 30 percent in some instances over the original methods implemented in the 1920s. However, the question remains as to when the modern technology, such as 3-D seismic data, should be employed because it is more expensive. In offshore areas such as the North Sea, the deepwater Gulf of Mexico, and offshore Africa, there is the potential of finding large reserves. There is no question that 3-D data should be applied in these areas. The probability of drilling a successful well in these deep ocean areas is approximately the same as the shallow offshore areas, but what is driving deep ocean basin exploration is the potentially greater size of the reservoirs that remain to be found.

Raymon L. Brown

See also: Fossil Fuels; Oil and Gas, Drilling for; Oil and Gas, Production of.


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