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EEExxxppplllooorrraaattt iiiooonnn Land Acquisition The Petroleum Landman

Role and function The private ownership of land is permitted in many countries of the world. Some countries (e.g., USA, UK and Canada), allow the private ownership of oil and gas interests or rights. Typically, such rights predate an act of union (e.g., USA) or act of parliament. Invariably, governments control the leasing of most oil and gas interests on the continent (i.e. on-shore) and all of the interests off-shore. Therefore, an exploration company seeking both access to land and the right to explore/produce oil and or gas must determine who holds the rights and the steps necessary to acquire and maintain that lease. In North America, that person is the Landman. The role and function of the Landman may vary from company to company; however, all successful Landmen share the same professional attributes, they are knowledgeable and skillful negotiators. The Petroleum Landman may be involved in any one or all of the following activities (Tinkler, 1992), the acquisition of leases and drilling rights, the maintenance of leases, agreements, contracts and legal obligations, and ultimately the disposition of leases and termination of contracts.

Acquisition The acquisition of leases begins with the examination of public records to determine who holds oil and gas rights in a given area of interest. A review of previous lease sales in the area or adjoining area will be under taken and perhaps the past and present activity of other companies will be researched. The Landman must also determine the necessary terms to obtain a lease if privately owned, or the value of the lease, if the lease is awarded on the basis of a sealed-bid. If leases are awarded on a first-come-first-served basis, then appropriate steps must be undertaken. Fundamentally, the Landman must obtain the rights to explore and produce oil/gas. In addition to the acquisition of the oil and gas lease, there maybe permits to acquire and contracts (such as Farm-outs or Joint Operative Ventures) to negotiate and asset trades to deal with.

Maintenance Once a lease or an agreement has been attained there then follows a period of maintenance during which the administration of the lease must be maintained. For example, during this time the processing of payments or royalties must be maintained, land titles and leases may require curative work or maintenance and there will be a need to keep track of all lease and contractual obligations. It may also be necessary to enter into contractual negotiations with investors or outside parties who have an ongoing interest, or who have developed an interest, in the associated venture. This may lead to farm-outs and farm-in agreements, seismic options, bottom-hole contributions, etc.

Disposition Ultimately a decision will be made to trade, release or surrender the lease, and terminate contracts, or to permit them to expire. Therefore, the Landman will be involved in the possible Farm-out, sale, or disposal of oil and gas interests. Whatever transpires, company records must be maintained and the filing of all necessary documents with the appropriate government department or agency should be done in a timely manner.

Farm-out and Farm-in: If an oil and gas company holding a lease (hence known as the Farmor) agrees to assign a portion of that lease (called the farm-out-area) to another company (the Farmee), in consideration of the Farmee drilling a specified number of wells on that Farmed-out-area, then the Farmor has made a Farm-out and Farmee has made a Farm-in.

Joint Operating Agreements (JOA): A JOA, or operating agreement, occurs when two or more companies who share a working interest share the risk of drilling, developing and operating an oil or gas venture. Typically one of the companies acts as the operator for all the companies bound by the JOA. The JOA also specifies how the costs and revenue will be shared and how leases will be acquired, maintained and disposed of (Tinkler, 1992)

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Land description and Land Maps

Subdivision of land Legal property descriptions and oil and gas maps are the means through which a well is physically located and the subsurface geology portrayed. Geologists are familiar with various types of map, such as topographic maps, solid-geology maps, isopach maps, structural maps, etc, but land maps are planimetric maps that show the subdivision of land without reference to variations in ground elevation. Land maps consist of a grid system where land is divided into blocks that mat be subsequently subdivided into smaller blocks. The grid systems of many Land maps are typically tied to the major trending lines of latitude and the longitude. The legal description of property and well location is only one aspect of a Land map; land maps also typically include (Tinkler, 1992): The legal description of the well/property by township, range, section, block, survey or LSD1 The names of operators and / or leases Surface land ownership, and Mineral ownership (if different from the surface land owner) Lease status Pertinent well data, such as well name, well status, total depth The names of significant land marks, such as roads, streams, lakes. Legal property descriptions The inaccurate description of property or a well is the most common reason why land titles fail. In the United States the subdivision of land typically follows the Rectangular System of Surveys, or more commonly known as the Public Lands Survey, which was adopted by the U.S. Government for Alabama, Florida, Mississippi, all lands west of the Mississippi (except Texas) and all states north of the Ohio River (Figure 109). Those states not included in this system use a sectionalized system developed within each state. Through a system of land subdivision based on east-west and north-south lines, land subdivided according to the Public Lands Survey is divided into squares called townships, ranges and sections. All surveys have a reference point or Point of Beginning. This reference point is the intersection of an east-west baseline and a north-south meridian. For example, in Kansas this point is known as the Initial Point for the Sixth Principal Meridian. The Public Lands Survey divides the land into townships which are square parcels of land that are six miles on each side. The location of a given Township is by reference to the number of townships north or south of the baseline, and the number of Ranges, east or west of the reference meridian. Each township is further divided into 36 parts called

1 LSD: (Legal subdivision) a legally defined subdivision of land or territory: an area composed of subdivided lots

Figure 109. A representation of the Public Lands Survey system of land subdivision used by many states in the United States of America. For example, the legal description for well Y shown in the 40-acre subdivision above (D) would be Township 2 North, Range 2 West, nth Principle Meridian (T-2-N, R-2W, nthPM), Section nineteen (19), southwest quarter (SW/4) of the northwest quarter (NW/4), southeast corner (SE Cor.). Putting that together we would have: SE Cor., SW NW, Sec 19, T-2-N, R-2W,nthPM.

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sections. Each section contains 640 acres or one square mile. Because of the Earths curvature, corrections must be made ever 30 miles, which is every 5th Township line.

The subdivision of land in the Provinces of Alberta, Manitoba and Saskatchewan within Canada is similar, in that it uses imperial units of measurement, and is based upon a Township and Range planimetric grid system. However, because this system is based on the Torren System, the numbering of sections differs from that used within the Public Lands System of the USA, and note also that the subdivision of each section uses a grid of 16 40-acre blocks. The subdivision of land is represented in Figure 110. Adjacent to the western side of a meridian the subdivisions are of standard proportions, consisting of full quarters. To compensate for the curvature of the Earth, subdivisions are often irregular, consisting of partial or make-up quarters close to Provincial borders and along the eastern side of each meridian. The minimum spacing for a conventional well is 40 acres, gas well = 80 acres. Wells are located by the further subdivision of each LSD and then using Lat. and Long.

Offshore descriptions and subdivision In the United States, offshore areas that are subject to state control use the same system that was devised for land. However, areas of Federal interest utilize the Outer Continental Shelf Leasing Maps designated by the Mineral Management Services (1984). Such maps are subdivided into blocks that are 5760-acre blocks, except offshore Louisiana, which uses 5000-acre blocks. On the East Coast of Canada, such as the Scotian Shelf, a hierarchical system has been devised based upon regular subdivisions of longitude and latitude. The largest subdivisions are Grids, which in turn are subdivided into Sections and subsequently into Units (Figure 111). Further refinement is possible by subdividing each Unit into four 200 m2 quadrants known as Targets. The United Kingdom uses a well-registration numbering system that permits the identification of Country, the number, or letter of the quadrant in which the well is drilled and pertinent drilling information. UK quadrants are areas enclosed by one degree of latitude and longitude, and each UK Quadrant is divided into 30 blocks measuring 12 minutes of longitude by 10 minutes of latitude (Figure 112). The well-registration numbering system includes both Quadrant, the number of the block within the quadrant and a block-suffix, if the block is subdivided.

Figure 111. The Grid, Section and Unit system that is utilized off shore Nova Scotia, Canada.

Figure 110. A representation of the Torren Survey system of land subdivision used by some of the Provinces of Canada. For example, the well in the 40-acre LSD above (indicated by a ) is in Township 2, Range 2West of the X Meridian, Section thirty (30), LSD 13. Putting this all together we would have: 6-13, T2, R2WX.

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Figure 112. The Quadrant system of the United Kingdom (off-shore). The planimetric grid that subdivides offshore England and Scotland into numbered Quadrants is based upon lines of longitude and latitude. The inset diagram (blue border) illustrates the numbering and subdivision of each Quadrant. England and Scotland are shown in solid grey (modified from the U.K. Department of Trade and Industry, PON12, 2005; Crown copyright material is reproduced with the permission of the Controller of HMSO and Queen's Printer for Scotland ).

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Surface prospecting and remote sensing Seeps (oil and gas)

Introduction A visible oil or gas seep may be an important phenomenon in oil exploration, their presence is an indication of petroleum and or source rocks within the subsurface, since many seeps represent the tertiary migration of petroleum. Many oil fields have been discovered through the associated presence of an oil seep, including Baku (Russia), many fields within California, Oil creek (Pennsylvania), Golden lane, Mexico, Masjid-I-Sulaimin field, Iran and the Hombre Pintado field Venezuela, to name but a few. However, the concept of using seeps and other remote sensing techniques, as a prospecting tool, has fallen out of favor with many exploration companies, but not all! The existence of a surface seep is hard to ignore. But rather than simply indicate the presence of hydrocarbons within the subsurface, the presence of a surface seep may indicate something else, such as a deficient trap

Weathering and transformation of seeps Hydrocarbons associated with seeps do not remain in pristine condition for long. A transformation readily occurs depending upon: oxygen availability, temperature, the presence or absence of water and the presence or absence of bacteria. Changes initially involve a lowering of API gravity followed by pronounced changes in molecular composition, viscosity and solubility, the end product is a solid-like material known as pyrobitumen (Figure 113).

Classification of seeps Upon encountering a surface seep, the first step would be to characterize the seep material and determine if the seep is: active (i.e., live), inactive (often manifest by the presence of solid bitumen impsonite or grahamite), or a false seep such as those associated with landfill sites. Link (1952) offered a simple classification of seeps that was related to their geological mode of occurrence. Most seeps occur at basin margins and in sediments that have been either folded or faulted and eroded. The classification of Link (1952) is straightforward and relatively uncomplicated, consisting of:

1. Seeps emerging from homoclinal beds, the ends of which are exposed and the beds outcrop at the surface (e.g., Trenton Limestone, Canada).

2. Seeps associated with source rocks that have become fractured or exposed to the Earths surface (e.g., Green River Fm, Uinta Basin, USA).

3. Seeps from large hydrocarbon accumulations that have been exposed by the erosion of faulted or folded reservoir rock (e.g., Masjid-I-Sulaimin field, Iran, or the Hombre Pintado field, Venezuela).

4. Seeps along the outcropping of an unconformity (e.g., Athabasca oil sands, Canada). 5. Seeps associated with igneous intrusions, salt diapirs, or other local sources of extraneous heat that may mobilize

a small portion of a reservoir (e.g., Golden lane, Mexico).

Gas or condensate seeps and geochemical prospecting Terrestrial seeps Gas and condensate are difficult to detect as seeps, unless under water. Light hydrocarbons typically evaporate or are easily dissipated at the Earths surface and, therefore, cannot be detected directly. However, gas and condensate seeps have been detected, for example, in Louisiana, Texas and the Gulf of Mexico, indirectly through the occurrence and

Figure 113. The sequential transformation of crude oil due to weathering. Physical and chemical changes are summarized (above) and the end product, a sample of Pyrobitumen from Western Canada, is shown right. The Pyrobitumen displays a characteristic optical texture (indicated by the arrows) due to an increase in molecular order when examined in cross polarized reflected white light. The image is approximately 150m across. (image courtesy of L. Stasiuk).

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association of paraffin dirt. Paraffin dirt is typically yellow, behaves elastically and resembles natural gums and resins in appearance. However, paraffin dirt does not contain hydrocarbons of thermogenic origin. It is composed almost entirely of microbial cells and bacteria (including methane-, ethane-, propane-, and butane-metabolizing bacteria), and metabolic by-products.

Underwater seeps Live or active seeps have been found on the continental shelf off the coast of California, such as those associated with the Ventura field, California. Underwater oil seeps have been identified visually, since gas bubbles are amenable to visual detection. The unambiguous detection of a thermogenic gas seep requires the use of sophisticated gas sniffers. Such devices are sensitive detectors with claimed detection limits of 0.5 ppb. However, like all techniques, the user must be aware of certain limitations. It must be determined if the gas is biogenic or thermogenic, the latter implies the presence of an active source rock and migration system. Whereas biogenic gas is the by-product of the microbial decay of buried organic matter and may not be linked to an economic accumulation of petroleum! The presence of propane and ethane (plus others) is often taken as an indicator of thermogenic gas, but should be confirmed by isotope analysis. Offshore gas sniffing is also difficult to interpret in areas frequently used by shipping, or in coastal areas adjacent to cities or industrial centers. Surface prospecting techniques, such as all exploration (i.e., prospecting) techniques may or may not work with equal success in all areas. Each area must be evaluated on its own merit!

Geophysical exploration Introduction With costs rising, no one would seriously consider drilling a well using any of the reconnaissance techniques prevalent in the nineteenth century. Business decisions require data and a detailed prognosis of the play to be explored. Acquiring subsurface data by drilling a borehole is expensive and while it provides a great deal of geological data, the reliability of that data, beyond the confines of the borehole is unknown. Fortunately, there are techniques that can be used to provide information of an area of interest and/or help relate one borehole to another.

Analysis of outcrop and surface topography give vital clues to the geological style of an area or basin (Video 7) that can supplement the information provided by geophysical surveys (Video 8). Geophysical surveys provide a cost-effect means of acquiring geological information of an area of interest; information that can help reduce exploration risk. There are three types of geophysical survey frequently used in the petroleum industry:

magnetic anomaly surveys gravity surveys seismic surveying

Both magnetic and gravity survey techniques are reconnaissance type surveys, often conducted from the air to facilitate speed and permit the surveying of large tracts of the Earths crust. In contrast, seismic surveys, provide a greater degree of subsurface detail, but require physical contact with the ground.

Video 8. Geophysical techniques, from The Making of Oil (copyright Schlumberger, Ltd. Used with permission).

Video 7. Surface techniques, from The Making of Oil (copyright Schlumberger, Ltd. Used with permission).

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Magnetic anomaly surveys Magnetic surveying investigates anomalies in the Earths magnetic field due to the magnetic properties of rocks within the subsurface (Figure 114). Magnetic surveys can be conducted from the air, over land or water as an airborne survey. Such surveys typically cost 40% less than ground-based surveys and can be conducted over relatively inaccessible terrain. Aeromagnetic surveys usually have the sensor suspended or towed from an aircraft, whereas marine surveys can be conducted from a sensor towed some distance behind a ship. Therefore, magnetic surveys are well suited as a reconnaissance tool, providing geological information over a very large and extensive region, such as a continental shelf (Keary and Brooks, 1991). In the absence of magnetic minerals within rocks of a sedimentary basin, a magnetic survey can provide information on structures and the composition of the underlying crystalline basement. Magnetic surveys provide an overall assessment or geological impression of basement topography, possibly indicating the basin depocenter (Figure 114). In areas where it is believed that overlying sediments are controlled by the crystalline basement, magnetic surveys can be used to help delineate areas of exploration potential. Therefore, a magnetic survey is primarily regarded by the oil industry as a reconnaissance tool! However, they are incapable of locating small structures, such as reefs. Many national geological surveys conduct magnetic surveys as a matter of course. However, more companies are running their own high resolution magnetic surveys, recognizing that lineaments, faults and basement highs typically leave a geological imprint on the overlying strata with the potential to influence migration fairways and plays.

Gravity surveying The gravity method is also used as a reconnaissance tool. However, gravity surveys are capable of suggesting the presence of small scale structures, such as salt domes and reefs. Gravity surveys are feasible because global and regional variations in gravity exist due to crustal heterogeneity and differences in rock density. The unit of gravity measurement is the Gal, named in honor of Galileo, which is divisible into mGal and Gal. 1.0 Gal is equal to 1 cm sec2. Generally gravity decreases with increasing distance from the center of the Earth; either as a function of the Earths shape (as an oblate spheroid) or due to changes in elevation or with changes in mass! The presence of a rock unit of differing density from the surrounding rocks will cause a local perturbation in the Earths gravitational field, generating what is commonly known as a gravity anomaly. Once corrections for surface effects, latitude, elevation, tide and instrument drift have been made, the presence of bodies of varying mass result in variations in gravity, or anomalies (Figure 115). A gravity anomaly can be expressed by differences in rock density:

p = P1 - P2 (8) where, P1 is the density of a body of rock, surrounded by rock of density (P2) and p represents the difference in density.

Figure 114. Two imaginary transects, depicting a simplified geology and their respective gravity (G) and magnetic (M) responses.

Figure 115. This illustration shows the relative effect of a small body of high mass and a larger body of lower mass against corrected background gravity, note that ground elevation has no effect upon the gravity survey device.

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Table 9. Compressional wave velocities (Vp) for selected geological materials.

Material Vp (km s-1)

Sand (wet) 1.5 2.0 Clay 1.0 2.5 Sandstone Tertiary 2.0 2.5 Carboniferous 4.0 4.5 Limestone Cret. chalk 2.0 2.5 Carbonif. lms 3.0 4.0 Dolomite 2.5 6.0 Salt 4.5 5.0 Anhydrite 4.5 6.5

Video 9. A short movie featuring a Vibrator truck, from The Making of Oil (Copyright Schlumberger, Ltd. Used with permission).

If the density difference is negative then the gravity anomaly will be negative. The principal reason for variations in rock density in sedimentary rock is rock porosity; hence, densities increase within rocks of low porosity or increasing depth. Some example densities are given in Table 8 for common sedimentary rocks. Gravity anomalies range from the small scale, such as a buried valley or reef, to larger anomalies, such as a salt dome and regionally extensive anomalies, typical of igneous plutons. However, it is generally recognized that it is difficult to distinguish between small bodies of high mass and large bodies of low mass. Bouguer anomaly maps can help delineate areas of differing density; low-density sediment appearing as negative anomalies, and rocks of relatively higher density appear as positive anomalies.

Seismic surveying

Introduction Seismic waves are parcels of elastic strain energy that propagate outwards from a seismic source (e.g., explosion). The velocity of a seismic wave is determined by the physical properties of the rock(s) transmitting the wave. If the rock properties are homogeneous (i.e., isotropic) then the wave front travels at the same speed in all directions and the locus of the wave front would define a sphere, rather like ripples on water (Figure 116). Physical properties, such as mineral composition, grain size, shape and sorting, porosity and pore fluids type combine to determine the density and elastic modulus for a given rock unit, and, therefore, seismic velocity. Compressional wave velocities (Vp) vary from 0.5 to 1.0 km s-1 for dry sand up to 2.0 to 6.5 km s-1 for anhydrite (Table 9). In general Vp increases with depth of burial, due to the combined effects of increased confining pressure, compaction and cementation, although frequency decreases. The presence of gas also reduces shear wave velocity (Vs) (Keary and Brooks, 1991).

Energy sources Land: Vibroseis or Vibrator truck has rapidly become the most common non-explosive method utilized on land. These truck-mounted pad vibrators (Figure 117; Video 9)) are capable of creating a sweep signal from 10 to 80 Hz for extended periods of time. Vibroseis units can also be used as linked units by phase-linking each unit, thereby permitting deep seismic penetration of the crust. Because such units require good contact between pad and ground they work best on firm ground, and unlike dynamite they are urban environment friendly. Land-based recording devices are called geophones (Short, 1992).

Figure 117. A seismic energy source; the vibrator truck.

Table 8. Ranges in rock density for common sedimentary rocks (after Keary and Brooks, 1991)

Lithology Density (Mg m-3)

Clay 1.63 2.60 Shale 2.06 2.66 Sandstone (Cretaceous) 2.05 2.35 Sandstone (Tertiary) 2.25 2.30 Sandstone (Carboniferous) 2.35 2.55 Chalk 1.90 2.90 Limestone 2.60 2.88 Dolomite 2.28 2.90 Halite 2.10 2.40

Figure 116. The relationship between a ray path to an associated wave front in an homogeneous rock unit (after Keary & Brooks, 1991).

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Marine: There are many seismic source options for use off-shore that are typically chosen for a specific depth of penetration and resolution. The most commonly used include the air gun, water gun, sparkers, pingers and boomers. Air guns (Video 10) are capable of deep penetration whereas water guns can achieve high resolution because there is no bounce back, a phenomenon associated with pneumatic devices. Sparkers are electrical devices that can achieve high resolution but are best suited to shallow depths. Marine recording devices (Video 11) are called hydrophones (Dessler, 1992).

Seismic wave paths As mentioned above, reflection seismic surveying utilizes the reflection and refraction of compressional waves that travel from a seismic source back to the surface (Video 11), permitting us to interpret the subsurface. Since wave properties are predominantly a function of the elastic modulus and density of the transmitting and propagating media (i.e., rock plus pore fluids) when seismic waves (wavelets) pass from one lithology to another, those wavelets undergo a change in velocity, amplitude and direction. To help explain the complex behavior of seismic waves it is useful to introduce their behavior as analogous to light waves, because compressional waves have amplitude, wavelength and frequency, rather like light (Figure 118). The interface between two lithologies of differing density is known as a velocity interface. The analogy of the light ray is useful because it illustrates that the transmission of seismic waves, through strata of differing density, results in both reflection and refraction at each velocity interface, according to Snells law2. Since we are primarily concerned with reflection seismology, the arrival time of reflected wavelets to a given geophone/hydrophone is given as a two-way travel time. However, in reality seismic waves are not simple vectors, but travel as spherical wave fronts (Figure 119) that radiate from the energy source. Because multiple geophones are used during a seismic survey (e.g., 12 to 1064 arranged as an array), two-way travel times for reflected seismic waves increase with increasing distance from the mid-point or source (Figure 120) which creates a velocity hyperbola, known as diffraction. Raw, unprocessed seismic data is of little use for geological interpretation. Processing raw data involves a number of possible steps, such as, stepout correction, stacking, seismic migration, convolution and deconvolution. 2 Which relates the angle of incidence and refraction to the propagation velocity within the two media.

Figure 118. A seismic ray as analogous to a light ray. In this example, the seismic wave travels through lithology 1 with uniform velocity, amplitude and frequency. When the seismic wave encounters a change in lithology with differing density, noted by the velocity interface, the seismic wave is both reflected and refracted. where: v1 = velocity of lithology 1 v2 = velocity of lithology 2

v2 = velocity of lithology 2 and (a) = Reflected wave (b) = Refracted wave

Video 11. An animation of the seismic wave propagation process in a marine setting, from The Making of Oil (Copyright Schlumberger, Ltd. Used with permission).

Video 10. Seismic and data acquisition, from The Making of Oil (Copyright Schlumberger, Ltd. Used with permission).

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Figure 119. A graphical representation of seismic wave offset, in which a planar surface generates an apparent surface of curvature (velocity hyperbola).

Seismic data processing Stepout and stacking The horizontal distance from the seismic source to receiver (e.g., geophone) is termed offset. When using multiple geophones, two-way travel times between the surface and a given velocity interface increase as the distance between shot point and each geophone (i.e., offset) increases. This creates a delay, known as moveout, in the arrival time of reflected waves creating a velocity hyperbola (Figure 119). Stepout correction involves correcting for seismic moveout (vertical wave offset) otherwise planar surfaces will not appear planar. Moveout correction for horizontal and planar surfaces is known as normal moveout correction (NMO), dip moveout correction (DMO) is a correction applied to dipping reflectors (Keary and Brooks, 1991; Duncan 1992). When using multiple energy sources, and several arrays of geophone/hydrophone, velocity hyperbola are combined, or stacked to eliminate random background noise and create continuous seismic sections; typically represented as a wiggle trace in conventional seismic sections.

CMP, CDP and migration The common midpoint (CMP) is the midpoint, at the Earths surface, between source and receiver (Figures 120a and 120b). If the reflector is a horizontal plane, the common midpoint lies vertically (Figure 120a) above the common depth point (CDP), which is also the common reflection point (Keary and Brooks, 1991; Larner and Hale, 1992). Common depth point profiling has become the standard method used in two-dimensional (2D) multi-channel seismic surveying because traces from different source-receiver pairs that share a common midpoint can be corrected to remove the effects of different source-receiver offsets, and stacked to improve the signal-to-noise ratio (Keary and Brooks, 1991; Larner and Hale, 1992). However, sediments and sedimentary rocks are not always horizontal layers. Dipping reflectors do not have a common depth point because the reflection point for each successive source-receiver pair will be displaced updip (Figure 120b). Migration is a form of seismic processing that repositions reflection events (e.g., the dipping surface in Figure 120b) to their correct surface locations and at a corrected vertical reflection time (Keary and Brooks, 1991).

Figure 120. Common depth point (CDP) reflection profiling. (a) The seismic reflector is a horizontal surface. The commonmidpoint (CMP) directly overlies a common depth point (CDP) which is common to all source-detector pairs. (S1 to S3; D1 to D3respectively); (b) For a sloping reflector there is no common depth point and the reflection point differs for ray pairs S1-D1, S2-D2and S3-D3 (after Duncan, 1992).

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If the survey line is at some angle to the dip of the reflector (e.g., along the strike) in a 2D-seismic survey, the reflection point is displaced out of the plane of section, i.e., cross-dip (Keary and Brooks, 1991). Cross-dip cannot easily be resolved with two-dimensional (2-D) seismic surveys and represents a problem and limitation regarding 2D seismic data. However, the problem is easily resolved using three-dimensional (3-D) seismic surveys, since reflection points can be migrated in any azimuthal direction.

Convolution and deconvolution During the seismic reflection process, seismic energy is naturally filtered by the Earth. Wavelets change as they propagate through layers of differing sediment. As stated above, the interface between two lithologies of differing density is known as a velocity interface; as wavelets encounter a velocity interface, each reflecting velocity interface reflects the whole wavelet but a reduced amount of the original energy. Convolution is a process of filtering the propagation of seismic energy within the Earth is a natural filtering process. Convolution can be used to model the filtering of seismic energy by the various rock layers in the Earth. Deconvolution is used in seismic processing to counteract the adverse affects of filtering, or convolution that occurs naturally as seismic energy is naturally filtered by the Earth, or the removal of the frequency-dependent response of the seismic source and recording device and instrument (Duncan, 1992). Examples of seismic trace processing are given in figures 121 and 122.

Figure 121. Example seismic traces showing the result of various types of seismic processing. (a) The shot-to-receiver offset is zero at the center and increases to 2000 m at either end. Note the presence of offset related hyberbola due to normal moveout. (b) After the application of normal moveout correction (NMO) the horizons are flat. (c) A seismic section is produced by combining and stacking six adjacent shots (Duncan, 1992; images courtesy of Landmark Graphics Corporation).

(a) (b) (c)

Figure 122. Seismic data from the Santa Barbara Channel, offshore California, USA. (a) A CMP stacked data showing multiple crossing reflections, (b) Correcting for the mispositioning of dipping reflectors and collapsing diffraction curves, migration reveals a series of tightly folded anticlines and synclines (Larner and Hale, 1992).

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Bright spot seismicity Bright spot seismicity is the recognition of hydrocarbon (i.e., gas) charged reservoirs. This is due to significant changes in density between water saturated rocks over- and under-lying a porous rock (e.g., sandstone) that is relatively depleted in water due to the high saturation of gas (e.g., Sw less than 20%). As seismic waves encounter a velocity interface, reflection and refraction occurs, where significant changes in density occur, reflectors will be prominent. Therefore, the reflector associated with the gas-charged reservoir will appear as a strong reflector on the wiggle trace, due to the enhanced amplitude of each wiggle (Keary and Brooks, 1991). Notice in Figure 123 that in this example the enhancement of amplitude is greatest at the base of the gas-charged reservoir; this is due to the migration of some gas into the overlying shale (or as an alternative interpretation the downward migration of gas). As discussed above, this will generate a bright spot on the seismic trace (Figure 123).

3D and 4D Seismic Geologists are comfortable working with cross sections and so are comfortable with 2-D seismic sections. However, for reasons outlined above, 2-D seismic does have some limitations particularly relating to the optimal orientation of the section and during signal processing (e.g., migration). Furthermore, since traps are three dimensional entities a two dimensional seismic line may not present the optimal subsurface image (Hart, 2000). 3-D seismic surveying overcomes many of those concerns. Marine 3-D seismic surveys utilize a series of closely spaced parallel lines (line shooting) whereas on land receiver lines are arranged parallel to one another with the shot points positioned in a perpendicular direction (swath shooting) (Yilmaz, 1992; Hart, 2000). The distance between lines in 3-D seismic surveying is typically 50 m or less, compared to 2-D seismic surveying which may be 1 km or more. As a consequence hundreds of thousand to hundreds of millions of traces are collected during a 3-D seismic survey, generating gigabytes and terabytes of data. 3-D seismic data is available as vertical sections along the in-line or cross-line orientation (Figure 124a) and as horizontal sections (time slices) (Figure 124b). Multilayer time slices permit the generation of contour maps (e.g., isochron) or the identification of subtle types of trap, such as a meandering stream that otherwise would be problematic with a 2-D survey (Brown, 1988). Time lapse seismic surveying (Video 12), often referred to as 4D seismic, is the sequential surveying of a producing reservoir over a set period of time. Time lapse seismic surveying seeks to ascertain changes within a reservoir due to the withdrawal of petroleum, in which areas within the reservoir containing untapped oil will show little to no change. Time lapse seismic surveying has been used with great success in many producing fields in the North Sea.

Figure 123. A seismic line for Shell's Mars play, Gulf of Mexico, a "bright spot" play that became a 700 million barrel discovery (Forest, 2000).

Figure 124. Examples of 3-D seismic showing (a) data volume around a salt diapir depicting vertical sections in both in-line and cross-line orientation, and as time slices (image courtesy of Hunt Oil Company); (b) a time slice showing a meandering stream (used by permission of Sunoco, Inc.).

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Cross-sections and subsurface maps Introduction Geological maps and cross sections are created to help resolve complexities in subsurface data, to provide a visual synthesis of geological features and to communicate our geological interpretations to others. They are both versatile and an indispensable tool. Even with the increased usage of 3-D seismic, the geologist still has need for cross-sections. For example, they permit the geologist to extrapolate stratigraphic equivalence between units, using seismic data, wire-line data and or lithostratigraphic information between wells or proposed wells. Cross-sections also permit a synthesis of structural attitudes of strata in relation to sea level or some other datum with data derived from seismic, or borehole data. The petroleum geologist will also construct many different types of map, including maps of the subsurface, topographic location maps, land usage maps (Weissenburger, 1992). For a given area and or zone of interest, it maybe necessary to construct a suite of maps. In this section, our examination of maps will be restricted to subsurface maps, in particular maps that contour a subsurface feature (e.g., isopach, isochore, isochron, net pay) or depict relationships, e.g., fault planes, facies change, or changes in porosity (Figures 125 and 126).

Figure 125. Example subsurface map (after Weissenburger, 1992).

Figure 126. Isopach map of the South Glenrock oil field, USA, showing an ancient (i.e. buried) meander belt (Curry and Curry, 1994).

Video 12. An animation showing the use and possible sequence of events when conducting time-lapse seismic, from The Making of Oil (Copyright Schlumberger, Ltd. Used with permission)

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Cross-sections Cross-sections are graphical representations of slices through the earths crust that are commonly used by the petroleum geologist to clarify or help interpret geological relationships (Boak, 1992). There are three basic type of cross section: correlation, structural, and stratigraphic cross-sections.

Correlation cross-sections Such cross sections may be the first to be drawn and are often based upon seismic data. Such sections also evolve, modified, updated and refined as data becomes available. Correlation cross-sections are often large scale and do not permit the extrapolation of high-resolution stratigraphic equivalence between wells or proposed wells. Although, it was in dealing with seismic data and the construction of cross-sections that prompted Vail et al., (1977) to devise the concept of sequence stratigraphy.

Structural cross-sections The structural attitude of strata, or any geological feature of interest, is typically drawn from seismic, or using seismic and borehole data (Figure 127). Such cross-sections are drawn in relation to sea level, or some other datum. Structural cross-sections are particularly effective when interpreting the location and nature of faults.

Stratigraphic cross-sections The detailed correlation of strata between wells is typically performed via the construction of stratigraphic cross-sections in which a given stratum is selected as the datum horizon, and all others 'hung' from that horizon. The data is often derived from wire-line data or from a composite log consisting of wire-line data and drill cuttings, core or paleontological data. Such sections may reveal features or used to identify subsurface sequence boundaries (Vail et al., 1977); typically deduced from wireline log responses, supplemented by core and/or drill cuttings. Cross-sections are a powerful visual, interpretative, tool; even more so if combined with a base map as a fence diagram (Figure 128). A fence diagram or panel diagram accommodates a number of interlinked cross-sections within a single three-dimensional diagram. Using a perspective view, each panel or fence is projected below a surface grid (the datum) and linked to one another. They can be an effective means of deriving a solution when data is limited.

Maps Basic requirements of a map What ever map is used it must be as accurate as possible. Errors and inaccuracy on subsurface a map may be more misleading, since the map represents a visual summation of data and is mostly responsible for molding our interpretations of a given data set or subsurface feature and the basis upon which exploration decisions hinge (Weissenburger, 1992). There is also trade-off between the inclusion of complex data and simplicity, and because each of us has individual thresholds of comprehension and confusion, the usefulness of a map should be gauged by the ease by which others can comprehend the data, or interpretation. Furthermore, all maps for a given basin, field or play should conform to one another; not only in scale, but also in style, concept and possibly interpretation. This is often

Figure 128. A partially completed fence diagram (panel diagram) with a 'base-map' projection.

Figure 127. A simplified structural cross-section through Hibernia, East coast Canada (Arthur et. al., 1992).

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difficult, or impossible when a basin straddles a political boundary where differences in nomenclature, units or geological resolution may occur. However, resolving differences or anomalies may yield insight.

Contouring There is an increasing reliance upon computers to construct a subsurface map. However, it should always be remembered that subsurface maps, more than topographic maps, require interpretative skills and that an interpretation is controlled by a variety of factors of which the relative abundance of data and well control is perhaps the most critical. The creation of bulls eye contouring by computer should always be questioned, since mapping software still lacks the ability to apply geological intuition. When dealing with a limited data set, contour in keeping with the structural style of the region; for example, don't invoke block faulting if simple folding is thought to dominate the structural style of a region. With a limited data set, remember a number of interpretations are possible, increasing the data set will eventually narrow the options and number of interpretations.

Isopach maps Isopach maps record the thickness of a given formation. Such maps can be local or regional. Note that with such maps, formation thickness does not always coincide with basin subsidence: carbonates or sand bodies are often thickest on the margins of basins, and local or regional truncation may result in formation thickness! An Isochore map is a specific type of isopach, depicting the thickness of an interval between the oil-water contact and the cap rock. Similarly, net pay can be depicted using a ratio of gross pay to net pay within a reservoir.

Structural contour maps This type of map is often the simplest and perhaps the most important subsurface map (Figure 129). This map is a representation of contours for any subsurface horizon with respect to some stated datum, which could be sea level, RKB3 or some other subsurface horizon. Subsurface structural maps can also be local or regional. The information used could be based upon seismic, well control, or preferentially both. Structural maps delineate traps and are essential for reserve calculations. Most structural maps utilize sea level with all deep horizons below sea level, and larger contour values are negative and therefore represent greater depths. The contour intervals should be clear, the map must have a scale and legend, and faults clearly marked.

Reserve Calculations Estimates Estimates of recoverable reserves must be made when conducting an appraisal of a reservoir, pool or field and updated whenever new data or information becomes available. There are several parameters that should be known, calculated or estimated including, for example, reservoir volume, reservoir porosity, water saturation (Sw), a recovery factor, and an estimation of the formation volume factor (i.e., stock-tank shrinkage). The estimation of reserves may also include other assumptions; such as, the presence/absence of a gas cap, the geometry of the oil/water interface and that the reservoir is regular and divisible into units to facilitate volumetric calculations. Calculated figures should never be regarded as absolute; they are estimations because our knowledge of the reservoir is not perfect and is always subject to change or revision. However, even as estimations, those calculations should be as accurate as possible since they form the basis for a number of business decisions regarding the possible outcome of a reservoir, pool or field.

Rough estimate: Roil = Vb f (9) where: Roil = the amount of recoverable oil (in bbl or m3) Vb = bulk volume of the reservoir rock f = recoverable oil 3 RKB: the rotary kelly bushing, depth measurements are commonly referenced to the kelly bushing.

Figure 129. Structural contour map (Jorgensen, 1994).

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This method has some assumptions, the method uses typical recovery values and porosity estimates (e.g., 30% for sandstone, 10 to 20% for carbonates).

Reservoir volume There are various other formulae by which it is possible to estimate recoverable reserves using actual data. Most however, utilize a formula that calculates a tabular volume, such as the area of a pyramid or a hemisphere (Dahlberg, 1979). An isopach map is often the starting point for most reservoir volumetric calculations (Figure 130). The basal area for each contour interval is then derived using a planimeter, or by dividing the area into a square grid or by using some other means of measuring area. The cumulative area occupied by the reservoir is derived using the contour interval (h) plus values for the base of each area, using the following formula (Dahlberg, 1979):

V = (A0+A1) + (A1+A2)...+ residual above the last plane (10) Or

where: V = rock unit volume h = the contour interval of the isopach map (i.e. height) A0 = the basal area above the oil/water contact A1 = the basal area of the first contour A2 = the basal area of the second contour An etc = the basal area of the nth contour

Recoverable oil Only a small volume of the area calculated is actual pore volume, therefore, V must be reduced to accurately represent the pore volume of the reservoir. This is achieved by multiplying the calculated volume by a porosity value in decimal form (e.g., 0.17). Porosity is typically derived from core analysis or estimated from petrophysical logs. Furthermore, the volume of the reservoir that holds oil or gas must be further reduced because of varying amounts of water and oil. The amount of water present within a reservoir is expressed as the water saturation (Sw) and, therefore, must be factored into such calculations, e.g., V = [1.0 - Sw]. Furthermore, the amount of hydrocarbon that can be produced from a reservoir maybe less than 100% due to the volumetric shrinkage of oil, because dissolved gas will come out of solution, leading to an effective volumetric shrinkage in oil. The shrinkage factor is calculated from the temperature, pressure and GOR (gas-to-oil ratio) of the oil and can be as much as 10 to 30 percent. Therefore, the formation volume factor (FVF) will range from 1.1 for gas-free oil to 2.0 for a high gas-oil. Hence, the equation for estimating recoverable oil is (Dahlberg, 1979):

Recoverable oil = V (1 - Sw) R (12) FVF where: V = reservoir volume (in cubic meters, barrels or cubic feet) = average porosity (as a decimal) Sw = average water saturation R = estimated recovery factor, as a decimal equivalent FVF = formation volume factor

Figure 130. A simplified isopach map and cross-section illustrating the basis for estimating volume

(11)

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If it is required to express the results as barrels of oil, the reserves should be converted from cubic meters by dividing V by 0.159, or dividing V by 5.615 when working in cubic feet.

Utilizing the pore volume equation

(STB) = V N/G Shc R 6.29 (13) FVF where: V = reservoir volume N/G = net or gross ratio of the reservoir rock body making up V 6.29 = oil field conversion factor (m3 to bbl) = average porosity Shc = average hydrocarbon sat. R = estimated recovery factor FVF = formation volume factor STB = Stock tank barrels, bbl. of oil at 60 deg F and 14.7 psi.

Short-cuts Spherical or ellipsoidal reservoir Many short-cuts and quick-look methods exist, depending upon the approximate geometry of the trap; we will examine one method that assumes a hemispherical (dome) shape. The volume of the top of a sphere can be approximated by the following quick method. area of the base max. thickness (i.e., height of reservoir) (14) For a hemispherical or near hemispherical reservoir this 'approximation' will be within 6%. The error will increase, as the shape becomes more ellipsoidal, such as a fault-bounded trap. The volume can be approximated by determining the area corresponding to the mid-distance between the reservoir base and top.

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