USC Sec 2 USC SEC 2 Petroleum Geology Supplemental Notes

University of Southern California Department of Petroleum Engineering

Fall, 2011

PTE-461

Formation Evaluation

Section 2: Petroleum Geology Lite

Donald G. Hill, Ph.D.

California Registered Geophysicist 170 California Registered Geologist 6043

Kentucky Registered Professional Geologist 1624 Texas Licensed Professional Geophysicist 6289

Consulting Petrophysicist:

Petrophysics, Shallow Geophysics, Borehole Geophysics, and Subsurface Geology

Planning, Oversight, and Interpretation

1012 Hillendale Ct +(925) 437-5748 Business Walnut Creek, CA +(925) 437-5748 Cell USA 94596 +(309) 420-7354 FAX http://www.hillpetro.com [email protected]

USC PTE-461, Basic Petrophysics - Fall, 2011


Donald G. Hill, Ph.D., R.Gp, R.G., R.P.G., L.P.Gp. Page: 2-2

Table of Contents

Subject Page

Introduction 2-1 Minerals 2-2 Rocks 2-3 Igneous Rocks 2-3 Metamorphic Rocks 2-5 Sedimentary Rocks 2-7 Clastics 2-8 Fossils, Carbonates, and Diatomites 2-11 Evaporites 2-11 Reservoir Rock Types 2-12 Clastic Reservoirs 2-12 Carbonate Reservoirs 2-14 Unconventional Reservoirs 2-14 Coal Bed Methane 2-15 Shale Gas 2-17 Other Unconventional Reservoir Types 2-20 Oil Shales 2-20 Tar Sands 2-21 The Bakken Formation 2-21 Monterey Shale 2-22 Origin of Petroleum 2-22 Migration of Petroleum 2-26 What is Needed for a Petroleum Reservoir 2-27 Atlas of Reservoir Types and Traps 2-29 Anticlinal Trap 2-30 Breached Anticline 2-31 Faulted Anticlinal Trap 2-31 Anticline Crestal Keystone and Thrust Imbricate Faults 2-32 Growth Fault Anticlinal Trap 2-32 Piercement Salt and Mobile Shale Domes 2-35 Clastic Stratigraphic Trap 2-37 Transgressive Seas and On-Lap Traps 2-38 Carbonate Reservoirs 2-40 Bi-Modal Clastic Model 2-41 References 2-41 Useful Websites 2-55 Tables

Table 2-1: Structural-Stratigraphic Classification of Petroleum Reservoirs 2-24




Figures

Figure 2-1: Crystal Forms for Quartz 2-1 Figure 2-2: Quartz Crystals are Independent of Size 2-2 Figure 2-3: Vesicular Basal, showing Vesicular gas Bubble Tubes 2-4 Figure 2-4: Polished Granite Gneiss Containing Biotite, Quartz, Feldspar, And Muscovite 2-5 Figure 2-5: Comparison of Common Clastic Material Grain Size Scales 2-6 Figure 2-6: The Effects of Grain Size and Water Velocity on Erosion of

Loose Grains 2-7 Figure 2-7: Cubic and Rhombohedrally Packed Spheres, Showing the

Porosity Extremes Dependent Upon Packing, but independent Of Sphere Size 2-9 Figure 2-8: Sandstone Exhibiting Fine-Scale Bedding, and an Unconformity 2-9 Figure 2-9: Comparison of Pore-Throat Sizes in Common Sedimentary Rock with Fluid Molecule Sizes and Measurement Technique Resolution 2-10 Figure 2-10: Example of Shallow Channel Sands Coalescing and then

Dispersing into Distributary Sands 2-12 Figure 2-11: Visualization of Stacked Sand Reservoirs 2-13 Figure 2-12: Schematic Model of Supergiant Tengiz Platform Reef Field 2-14 Figure 2-13: US Coal Resources, With Major Basins Annotated 2-15 Figure 2-14: Common CBM Recovery Technique 2-16 Figure 2-15: US Shale Gas Play Map 2-17 Figure 2-16: Vertical vs. Horizontal Well Shale Gas Completion 2-17 Figure 2-17: Multi-Stage Horizontal Well Completion 2-18 Figure 2-18: Surface Activity for Typical Barnett Shale Fracture Operation 2-19 Figure 2-19: API Gravity vs. Depth for Tensleep Reservoirs in Wyoming 2-23 Figure 2-20: Idealized Anticlinal Structure 2-25 Figure 2-21: Santa Fe Springs Field, CA, Structure 2-26 Figure 2-22: Santa Fe Springs Field, CA, Structural Cross-Section AA' 2-27 Figure 2-23: Circle Ridge Anticline, WY, Photo Mosaic 2-28 Figure 2-24: Upper Circle Ridge Field, WY, Structure Contours on Top of Phosphoria Limestone 2-29 Figure 2-25: Upper Circle Ridge Field, WY, Structural Cross-Section Along Line AA' of Figure 2-24 2-30 Figure 2-26: Visualization of Thrust Faults with Secondary Keystone Faults 2-31 Figure 2-27: Schematic Representation of Growth Faults 2-32 Figure 2-28: Lewisburg Field, LA, Contour Map on Top of Frio Formation Showing Five Growth-Fault Created Reservoir Blocks 2-33 Figure 2-29: Visualization of a of Piercement Salt Domes 2-34 Figure 2-30: Three-Dimensional Renderings of Avery Island Salt Dome, LA 2-35




Figure 2-31: East Texas Field, TX, Map 2-36 Figure 2-32: East Texas Field Structural and Stratigraphic Cross-Section 2-37 Figure 2-33: Paul Valley, Oklahoma, Uplift Cross-Section, Showing on-Lap Sedimentation Against an Unconformity 2-37 Figure 2-34: Map of Horseshoe Atoll Fields, Texas, Including Kelley-Snyder Field 2-38 Figure 2-35: Kelly-Snyder Field, Texas, Field Outline and Structure Contoured on the Top Canyon Reservoir 2-39 Figure 2-36: Kelly-Snyder Field, TX, Cross-Section Along Line AA' 2-40 Figure 2-37: Sieve Analysis for a Recent Gulf Coast Sand Interval with Two

Dominant Grain Sizes 2-41 Figure 2-38: Comparison of Basketballs to BBs 2-42 Figure 2-39: Bi-Modal Particle Size Sediment Model 2-43 Figure 2-40: Sand Porosity vs. Depth, for a Gulf Coast Well 2-44 Figure 2-41: Shale Chip Porosity vs. Depth, for a Gulf Coast Well 2-45 Figure 2-42: Bi-Modal Clastic Model Total and Effective Porosity vs.

Grain Fraction 2-46

Introduction As petroleum engineers, you may be asked to assess and/or recover hydrocarbons

from subterranean reservoirs. The popular public impressions are often that these reservoirs are large underground lakes of the fluids just waiting to be produced. This impression, aided by the fact that some jurisdictions refer to oil and gas reservoirs as “Pools”, is not the case. While some vuggy carbonate reservoirs have vugs approaching caverns, in size, most reservoirs more closely resemble granular, or porous porcelain, filters than they do Carlsbad Caverns. Chemical engineers often deal with engineered filters and porous beds. In fact, much of reservoir simulation theory is based on concepts first developed for these engineered materials. Actual reservoirs, however, are usually much more heterogeneous and complex.

Fortunately, for reservoir engineers, subsurface, development, and/or reservoir geologists and geophysicists are available to provide descriptions of the reservoirs to be produced. Reservoir engineers, however, do need to know a little about geology and geologic terminology to be able to understand these geologic descriptions. Otherwise, the two disciplines cannot communicate.

Figure 2-1: Crystal Forms for Quartz (after Barry and Mason, 1959).




Minerals In chemistry, we learned that atoms are the building blocks of the universe (for now,

at least, we will leave the physicists to play with their sub-atomic particles). In geology, we learn that rocks are the building blocks of the earth and that minerals are the building blocks of rocks. We will start our discussion at the bottom, with minerals, and then work our way up through rocks, to end up with petroleum reservoirs and hydrocarbon traps.

Figure 2-2: Quartz Crystals are Independent of Size.

With few exceptions (e.g., agate and opal), Minerals are crystalline, with their constituent ions occupying specific positions in a geometric framework, called a crystal lattice. The net result of this geometric relationship is the formation of distinctly recognizable crystals, such as those of quartz, shown in Figures 2-1 and 2-2. Crystals can be microscopic to quite large, depending on the mineral type and the conditions under which they formed. For example, quartz crystals weighing several pounds and measuring several inches long have been formed under optimum conditions. The sizes of most, natural mineral crystals, however, are found in the microscopic to a few mm range. Some minerals, such as quartz (SiO2), calcite (CaCO3), and pyrite (FeS2), have specific chemical formulas. Others, such as biotite (K(Mg,Fe)3(AlSi3O10)(OH)2), Dolomite (CaMg(CO3)2), and plagioclase




((Na,Ca)(Al,Si)AlSi2O3) form solid substitution series for some of their elements (i.e., those separated by commas).

There are literally a few thousand minerals (some named after their discoverer or the discoverer's major professor). There are only a few minerals, however, commonly found in reservoir rocks. The most common reservoir rock minerals are: anhydrite, calcite, clay minerals, dolomite, feldspars, gypsum, halite, micas, pyrite, and quartz.

Each of the above minerals will have unique physical responses to the measurements used for formation evaluation (FE). Because the wireline and MWD measurements utilized for FE will be composite measurements, knowledge of the mineralogy involved will greatly assist interpretation.

Mineralogy can also affect drilling operations and borehole conditions. Clay minerals, particularly montmorillonite, are expansive minerals which will swell, causing stuck drill strings, and logging tools, as well as enlarged boreholes due to caving, during the drilling operations. Anhydrite and Halite are evaporites, which will dissolve in contact with water-based drilling muds, causing washed-out boreholes. Carbonates, containing high percentages of calcite and dolomite require different drill bits than shales, containing high percentages of clay minerals.

Being able to read and understand geologic reports will help drilling engineers plan more efficient drilling operations and avoid expensive fishing operations.

Rocks Rocks are composites of their constituent minerals. Rocks, not minerals, also form

petroleum reservoirs.

There are three major types of rocks: igneous, metamorphic, and sedimentary. The great majority of petroleum reservoirs are sedimentary rocks. We will briefly discuss all three types, however, because the materials, which form sedimentary rocks, can come from all three.

IGNEOUS ROCKS All igneous rocks were once high temperature liquid (molten) melts, with the same

current chemical composition. These molten rocks can currently be seen at active volcanoes. It is thought that even larger amounts of molten (or near molten) rocks lie at great depths, where their presence can only be inferred by changes in seismic velocities and refraction of seismic wave trains through them. Igneous rocks are most often seen, at the surface, as granitic mountain cores, such as the Sierra Nevada Batholith, in California, or as solidified lava flows, such as on the Island of Hawaii, and in Arizona, California, Idaho, Nevada, New Mexico, Oregon, and Washington.




There is no precursor to igneous rocks, except molten magma. The type of igneous rocks, which form from a magma is dependent upon the original chemical composition of the magma, the temperature at which it solidifies, the amount of water in the magma, and the pressure at which it solidifies. Igneous rocks that solidify at depth tend to have larger mineral crystals than those, which solidify on the surface. The largest crystals are found in pegmatites, which often form from high water content melts at the final stages of solidification. Volcanic glass (obsidian) solidifies so rapidly at the surface that there is no crystalline structure. Explosive volcanic eruptions discharge large volumes of fine-grained volcanic glass shards (ash) into the atmosphere where they can travel hundreds, to thousands, of miles before settling back to earth. These wide-spread volcanic ash beds are often used by subsurface geologists as "time markers" for correlation because of they represent a very short interval in geologic time.

Figure 2-3: Vesicular Basalt, showing Vesicular Gas Bubble Tubes.

Common igneous rocks are granite, gabbro, basalt (sometimes called black granite), and rhyolite. Granite, gabbro, and basalt are often cut in to slabs, polished, and used for counter tops, interior trim and building facing. Granite is also often used for tombstones.




Igneous rocks themselves, are generally not reservoir rocks. Exceptions to this rule-of-thumb occur in Vesicular Basalt flows of Indonesia and Japan (see Figure 2-3).

Weathered igneous rock products, however, often form source materials for the sedimentary rocks, which often do form reservoirs. The source of the sands, feldspars, and clay minerals filling the Central Valley of California, and building the Niger Delta are weathering products of the Sierra Nevada Batholith and the African Shield, respectively.

Figure 2-4: Polished Granite Gneiss Containing Biotite, Quartz, Feldspar and Muscovite.

METAMORPHIC ROCKS Metamorphic rocks have been altered (i.e., metamorphosed) from something else.

The precursor to a metamorphic rock can be igneous, sedimentary, or even metamorphic rocks. The oldest rocks on earth (radioactively dated at over 5.5 Billion yr.) are metamorphic, which means that the earth, itself, must be much older. One criterion of metamorphic rocks is that there needs to be some indication of their former state. For example, an early Pre-Cambrian (Archian) meta- (glacial) tillite, near Marquette, Michigan, shows the outlines of the glacial eratics on its weathered surfaces, but has no indication of this history on fresh fractured surfaces. Metamorphic rocks are found in regions where there have been high temperatures and chemically charged aqueous solutions, as well as great compression and/or shear forces at work, such as the Franciscan terrains of the Northern California Coast Ranges. Examples of metamorphic rocks are marble (metamorphosed limestone) and Verde Antique Marble (serpentinized basalt), and Granite Gneiss. All of these rocks are often used as building facings, interior trim, or for counter tops (see Figure 2-4).




Figure 2-5: Comparison of Common Clastic Material Grain Size Scales (after Griffiths, 1957; and

Pettijon, 1957).

Metamorphic rocks, themselves, are generally not reservoir rocks. Exceptions to this rule-of thumb occur in SW Texas as serpentinized volcanic rock oil reservoirs. Weathered metamorphic rock products, however, can form the source materials for sedimentary rocks, which often do form reservoirs.




SEDIMENTARY ROCKS Sedimentary rocks are formed from the weathered products of other rocks. The

source of these materials can be igneous, metamorphic, or even older sedimentary rocks. Weathered materials, from sediment sources, are transported by wind, ice, or water to places of deposition, where they can become lithified to form sedimentary rocks. Water transport can be either by dissolved salts, in solution, or granular materials, in suspension.

Rocks exposed to the atmosphere will weather (disintegrate due to extremes of wind water, and temperature, or by chemical reactions), either mechanically or chemically. Chemicals are leached from minerals in rocks by water in rainfall, lakes, and rivers. These chemicals then travel from the source to some deposition location in solution. Mechanical weathering removes portions of rock materials physically from their source. These liberated pieces of rock are then transported by gravity, wind, and/or water, to a deposition location. During transport, the rock fragments undergo further mechanical and chemical weathering. Transport mechanisms vary according to size of the rock fragments. Figure 2-5 compares several common particle size descriptions. The finer grain sizes (i.e., smaller than bolder-cobble size) are most useful for describing petroleum reservoirs.

Water expands, in volume, upon freezing. Water filled cracks, in temperate climates increase the rate of weathering, due to "frost heaving" when the water freezes and thaws.

Wind driven dust and sand, in arid regions, will erode rock surfaces, via abrasion, as another form of mechanical weathering.

Figure 2-6: The Effects of Grain Size and Water Velocity on Erosion of Loose Grains (after Blatt et al.,

1980).

High water stream flows, due to seasonal flooding, will erode the surfaces over which they flow, via abrasion by the suspended granular material. Water flow mechanical erosion is most successful in eroding grains, which are already loose. This characteristic is illustrated in Figure 2-6. Water velocity is on the vertical axis and grain size on the horizontal axis (fine




grains on the left and coarse grains on the right). Below the gray shaded region, there is no erosion. Above it, there is erosion, with grains suspended in the moving water. The gray region, itself, marks the data scatter, for the study, as well as the region of grain movement by salting and traction (skipping along the channel bed surface). The large scatter in the data for fine-grained particles reflects some of the unique properties of clay-sized particles and clay minerals, which will be discussed later.

A clear running stream, within its banks, has removed all grain sizes within the erosion region of Figure 2-3. The only grain movement is by salting and traction. At flood stage, however, that same stream will be flowing faster and overflow its banks. The higher water velocity will suspend grain sizes, which were below the erosion level, at normal stage flow. At flood stage, the water flowing outside the stream banks will encounter and suspend finer grain sizes than were present in the stream-bed. The net result is that flood stage stream flow is turbid, while normal stage flow is usually clear.

Chemical erosion can occur when rain-water dissolves acidic minerals (e.g., sulfides) in exposed rock, releasing acids, which react with other minerals in the rock. Carbon dioxide (CO2), in the atmosphere, can be dissolved in rainwater, forming a weak acid, which will react with (at least some) minerals in exposed rock surfaces. An example of artificially rapid chemical weathering is the deterioration of marble statuary, in the NE US and Eastern Canada, due to acid rain. Sulfur dioxide (SO2), carbon dioxide (CO2), and oxides of nitrogen (NOx) released by stationary (e.g., power plants, and other heavy industries) and mobile (e.g., automobiles, trucks, busses, train engines) sources into the atmosphere, where they can be carried by prevailing winds over great distances. Once airborne, these gases mix with water vapor in clouds, to form weak acids. Rainfall, from the acidified clouds, will react with minerals in building walls and statuary accelerating the effects of natural chemical weathering. Carbonates (limestone and marble), often used in limestone building walls, tombstones, and marble statuary, are particularly susceptible to the effects of acid rain.

Both chemical and mechanical erosion remove material from the source rock area and transport it downstream. Materials carried by waters (either as dissolved ions, or suspended grains) will eventually be deposited, as clastic (clays, sand, and gravels) or chemical (playa evaporite or carbonate reef) deposits.

Clastics Clastic deposit type descriptions depend upon grain size, grain density, and water

velocity, during deposition. When rivers and streams encounter flat land and/or open water, flow rates decrease and suspended sediment begins to settle out of the moving water. Settling patterns are the reverse of erosion patterns. Coarser grain-sizes and heavier minerals settle out first, with the grain sizes and densities still in suspension decreasing as the water flow velocity decreases. The last to settle out will be the clay-size particles and clay minerals. Coarser grained clastic deposits can become reservoir rock once lithified.




Figure 2-7: Cubic and Rhombohedrally Packed Spheres, Showing the Porosity Extremes, Dependent

Upon Packing, but Independent of Sphere Size (after Anon, 1992).

Porosity (relative void space) of rocks is a measure of the volume available for storing fluids, such as crude oil and natural gas, of interest to petroleum engineers. For clastic rocks, porosity is a function of grain size distribution, packing, cementation and compaction.

Figure 2-8: Sandstone Exhibiting Fine-Scale Bedding, and an Unconformity.




As stated above, grain size distribution will be a function of flow rate condition at the time of deposition of the clastic grains. Uniform flow will have a narrow range of grain sizes, while turbulent flow will have a greater diversity of grain sizes.

Figure 2-7 illustrates two extreme types of uniform sphere packing. Cubic packing (left hand side, of Figure 2-7) yields the greatest porosity (48%), while Rhombohedral packing (right hand side of Figure 2-7) yields the lowest (26%). The porosity relationships, shown in Figure 2-7 are independent of particle size, as long as the particle size is uniform (Anon, 1992). The porosity values of Figure 2-7 are extremes, which probably do not reflect real life situations. Beard and Weyl (1973) determined that well sorted “wet-packed” sands averaged about 42.4% porosity.

This particle size independence of porosity collapses, when there is a broad dispersion of particle sizes. Beard and Weyl (1973) average results for poorly sorted “wet-packed” sands was 27.9%.

Figure 2-9: Comparison of Pore-Throat Sizes in Common Sedimentary Rock with Fluid Molecule Sizes

and Measurement Technique Resolution (after Nelson, 2008).

Permeability, the ability for fluids to flow through a porous material is not independent of pore size. This is because of frictional effects between the walls of the pore




throats and the fluid passing through them. Larger grain sizes will result in larger pore throats, which will yield higher permeabilities. This is illustrated by Figure 2-9

The above discussion provides a foundation for the interface between geology and reservoir engineering. Real rocks, however, are much more complex than the idealized rocks described, above. Figure 2-8 is a photograph of a small sample of a reservoir quality sandstone. This small sample shows fine-scale bedding - alternating layers of fine and coarser grained particles, which probably also contain different minerals. This hand sample also shows an unconformity – an erosional surface where two different sets of bedding planes intersect.

Fossils, Carbonates, and Diatomites Marine animals, such as crustaceans, corals, mollusks, foraminifers and diatoms,

extract dissolved minerals from seawater to form their shells. When the animal dies, the shells sink to the sea bottom and eventually become incorporated into rocks. If shell collections are numerous enough, shell beds will form. Rocks formed, largely from the shells of diatoms are diatomaceous earth (kitty litter), diatomite, and chert.

In tropical seas, coral colonies and mollusks extract large amounts of calcium and carbonate ions from seawater to form large reef structures to protect their soft bodies. Both shell beds and coral reefs can become carbonate reservoir rocks after lithification. Diatomites can also become very low permeability petroleum reservoir rocks (e.g., the Monterey Formation, of California), providing a particularly vexing challenge to reservoir engineers charged with extracting petroleum from them.

Evaporites In arid environments, evaporation of standing water bodies often exceeds inflow from

streams. The net result is increased salinity of the standing waters. If the salinity becomes great enough, salts will crystallize and precipitate, forming evaporite deposits.

Currently, this chemical precipitation is occurring in closed basin, inland lakes, such as The Dead Sea, The Great Salt Lake and The Salton Sea. Extensive thick salt deposits in the Michigan Basin, Cape Breton Island, Southern Iran Desert, Oman, The Persian Gulf, The North Sea, The Permian Basin, The Gulf of Mexico, and The Congo Basin, indicate that, over geological time, very large, semi-isolated seas have existed.

Evaporites generally do not form reservoir rocks. They become plastic at relatively low temperatures and pressures (e.g., such that exist as shallow as 2,000 - 3,000 ft. depths) and are easily dissolved in contact with subsurface waters. Because of these characteristics, evaporites tend to heal any fractures and/or pore space, making them excellent reservoir seals.

If there is modest, shallow, wave motion, oölites can form. Aragonite (CaCO3) will begin to precipate on dust, or other very fine, particles. The gentle wave action keeps the




deposition centers in motion so that aragonite is added in concentric spherical shells about the oölite centers. When the oölites reach sand grain size, they can be carried by stronger waves into seabed bar like deposits. These oölitic sands can become very good petroleum reservoirs.

Reservoir Rock Types Reservoirs are rocks that can store hydrocarbons and deliver them to a borehole.

Hydrocarbons can only be stored in the void spaces (porosity, , see Section 1). Almost all

petroleum reservoirs are in sedimentary rocks. The three major types of sedimentary rocks are clastics (shales, sandstones, and conglomerates), carbonates (limestones and dolomites) and evaporites (anhydrates, dolomites, gypsums, anhydrites, and halites). Of those three, clastics and carbonates are the most common reservoir rock types.

Clastic Reservoirs

Clastic rocks consist of mineral grains, which have been weathered from their source rock and transported to a deposition location, by wind, water, or ice, compacted and/or cemented (lithified) into rock. Clastic rocks are identified by their dominant particle size (see Figure 2-5). The finest clastics are called clays. The "clay" classification, of Figure 2-5, is based on grain size, not mineral type. Most clay mineral grains in rocks, however, are also clay particle size. The coarsest particle sizes are classified as boulders. Between these two extremes are gravels, sands, and silts, with silt sized particles between those of clays and sands. After lithification, the clays become shales, the silts become siltstones, the sands

Figure 2-10: Example of Shallow Channel Sands Coalescing and then Dispersing into

Distributary Sands (after Hill and Qualheim, 1995)




Clastic rocks, consisting of individual solid particles have void space (porosity) between the grains. The amount of porosity depends upon sorting, grain packing, and cementation. Grafton and Frazer (1935) demonstrated that random packs of uniform spheres yielded porosity values between 26% and 47%, depending upon the packing. These results were the same, regardless of the size of the spheres used. Figure 2-7 illustrates the porosities for the extreme cases of cubic and rhombohedrally packed spheres. Figure 2-9 illustrates the pore throat size ranges in comparison to reservoir fluid molecular sizes and measurement technique resolution. Referring to the grain size chart of Figure 2-7, silt sized particle sediments become siltstone reservoirs, while sands become sandstones, and the boulders and gravels become conglomerates.

The ability of the reservoir rock to deliver hydrocarbons to a borehole, the permeability, is dependent upon pore throat size. Coarser grain packs will have larger pore throats and, consequently, higher permeability. This is why sands and gravels at a given depth will have much higher permeability than shales at that same depth, even though the porosities me be comparable, or the shales may even have higher porosity.

Figure 2-11: Visualization of Stacked Channel Sand Reservoirs (courtesy of John Perez Graphics &

Design, LLC).

Sandstone reservoirs are the most common form of petroleum reservoirs. Sands can be deposited as regional, or blanket, sands, braided stream sands, channel sands, distributary sands, bay-mouth, or barrier sands, and long shore sands. Examples of regional sands are the St. Peter Sandstone and The Dakota Sandstone, in the North American mid-continent. Petroleum reservoirs in these sands must have structural closure, such as domes, anticlinal folds, or up-dip faulting. The Bell Creek Field, Montana, is an example of a barrier sand reservoir. SW Louisiana has several examples of channel, distributary, bay-mouth, and long shore sand reservoirs. Figure 2-10 shows an example of channel sands coalescing and then




separating in a shallow alluvial fan deposit. Figure 2-11 shows a visualization of stacked channel sand reservoirs.

Carbonate Reservoirs Carbonate rocks are mostly limestones and dolomites, which form from muddy shell

beds and coral reefs. Unaltered carbonates usually have very low porosities and permeabilities. For carbonates to become reservoir rocks, porosity must be created by fracturing and/or solution leaching along fractures, clastic layers, or partings in the rocks. Another mechanism to create porosity and permeability in carbonates is via dolomitization. Dolomitization involves replacing some of the Ca

+2 ions in the calcite (CaCO3) crystal

lattice, with Mg+2

, creating dolomite (Ca,Mg(CO3)2). The dolomite crystal unit cell is smaller than that for calcite, so that dolomitization creates porosity and permeability. While there are not as many carbonate reservoirs as sandstone reservoirs, some of the world's largest and most prolific oil and gas fields, such as the North Gas Field (Qatar), South Pars Field (Iran), and Tengiz Field, Kazakhstan (see Figure 2-12), are carbonate reservoirs.

Figure 2-12: Schematic Model of Supergiant Tengiz Platform Reef Field (after Dehghani, et. al., 2008).

Unconventional Reservoirs Unconventional reservoir rocks include a wide range of rocks whose only common

characteristics is that they have such low permeability that until recently, at least, were not considered to be viable reservoir rocks. Their Total Organic Content (TOC) or Kerogen ranges from near 0%, for tight gas sands, to organic rich coals, with TOC near 100%. Somewhere in the middle are shales and oil shales (really organic rich marls) with 50% < TOC < 85%.




With the exception of tight gas sands, Unconventional reservoir rocks have long been acknowledged as source rocks, but their permeabilities were considered to be to low for commercial gas and/or oil development. While their porosities and permeabilities have not changed, these rock types now have a new designation as “Unconventional Reservoirs”, because of advances in drilling and completion technology, as well as declining major new discoveries.

Figure 2-13: US Coal Resources, With Major Basins Annotated (after: ALL Consulting, 2004).

Coal Bed Methane Figure 2-13 shows the most common version of US coal resources distribution. This

map is a little misleading as some of the areas designated as coal fields, such as the Michigan Basin and the mid-continent Cherokee-Forrest City Basins of Iowa Kansas, and Missouri contain only shallow, thin, low-grade lignite coal beds, which if developed at all were mined by crude surface mining methods, long ago. There are also questions regarding the reliability of the information used to compile these maps. Finally, Resources do not translate directly into Reserves as no consideration is made for economic viability of potential development in USGS Resource Assessments.

Methane is endemic to underground coal mines and a common poison and explosion hazard. Coal beds are also often source rocks for gas fields, as in the North Sea. In the late




1990’s and early 2000’s there was a drive to drill multiple closely spaced wells into recent, shallow lignite, bituminous, and sub-bituminous coals to produce methane, which collect in the coal cleats. These developments were concentrated, primarily, in the Black Warrior Basin of Alabama, Powder River Basin of Montana and Wyoming, San Juan Basin of Colorado and New Mexico and Uinta Basin of Colorado and Utah, and Wasatch Plateau, of Utah.

Figure 2-14: Common CBM Recovery Technique (after: ALL Consulting, 2004).

Figure 2-14 is a schematic representation of the most common CBM recovery technique. An outsized well is drilled into the coal bed of interest and water is allowed accumulate in the well sump. A submersible pump, in the sump, recovers the water from the coal bed, reducing the formation pressure and liberating methane attached to cleats in the coal, and dissolved in the water.

While considerable gas can be produced, with this technique, huge volumes of high salinity contaminated water are also produced, causing disposal problems, because of the high total dissolved solids (TDS) content of the water, and lowering the regional water table, effecting water supplies for livestock, homes, and irrigation. The water well damage, crop damage and stock die-offs accompanying heavy CBM development, in Wyoming, resulted in very strict environmental controls and large damage claim settlements. In the end;

• High costs associated with CBM development. • Low commodity (gas) prices. • High transmission costs. • Slow return on investment. • Environmental concerns and restrictions.

combined to slow CBM development. When other sources of gas became readily available, and the above problems remained, CBM development declined markedly.




Figure 2-15: US Shale Gas Play Map (after: Anon, 2008).

Shale Gas Organic rich shales are, by far, the most common oil and gas source rocks. Some,

like the Michigan Basin Antrim Shale, have been considered for surface mining and retorting as a source of crude oil. Figure 2-14 shows major shale gas plays of the Lower 48 US states, and their basins.

Figure 2-16: Vertical vs. Horizontal Well Shale Gas Completion (after: Brownell, 2008).




Because of the low permeability of shales, they need to be stimulated to produce gas at commercial rates. In all cases, the stimulation of choice has been fracturing: A completion technology where the completion liner is perforated at regular intervals, followed by high pressure (i.e., above the formation fracture pressure) fluids and natural (i.e., sand) or artificial granular proppant material is forced into the formation. This process expands the effective diameter of the well and exposes it to more of the formation. Initially, vertical wells were used. As directional drilling and drill bit guidance became more sophisticated, extended reach horizontal wells became more common. Figure 2-16 illustrates both vertical and horizontal well fracturing.

Figure 2-17: Multi-Stage Horizontal Well Completion (after: Themig, 2011).

The big technical break-through, for shale gas development was multi-stage completion. This technology, which allows multiple completion intervals for a single fracture job, without intervening clean-out wiper trips, greatly reduces completion costs for shale gas wells. The technique can be used for either vertical or horizontal well, but has the largest financial impact for extended reach horizontal wells. Figure 2-17 is a schematic illustration of multi-stage completion for an extended reach horizontal well.

The first (intentional) shale gas well was the C. W. Slay No. 1, drilled in Wise County, Texas (NW of Fort Worth), during the 1981 gas boom by Mitchell Energy. Initial shale gas wells had very slow production rates and, consequently long pay-out periods. Because of this and a mid 1980’s gas price slump, development was slow, but “cut and try” research with drilling and completion technology, as well as with regional geologic studies continued. With increasing gas prices in the late 1990’s and early 2000’s, development pace picked up, sparking a land rush by several Independents, followed by some multinationals. A drop in gas prices in the late 2000’s with few open land parcels left, shifted activities to




other potential shale gas plays, such as the Woodford, Haynesville, Fayetteville, Antrim, and Marcellus.

Figure 2-18: Surface Activity for Typical Barnett Shale Fracture Operation (after: Brackett, 2008).

Shale Gas plays require thick organic rich shales with a high methane content. The pay intervals also need to be deep enough that they can be safely fractured, without break through to the surface. Wells must be cased and securely cemented to the surface, so that there will be no leakage of completion fluids and/or gas into shallower aquifers or to the surface. Completion fluids must be recovered and safely treated prior to disposal and/or re-use. While several extended horizontal wells can be drilled from a single drilling pad, the surface area required to stage a modern shale gas well fracture job can be extensive (see Figure 2-18).

Many shale gas plays have moved into urban and other areas not (recently, at least) exposed to extensive petroleum E&P development. Consequently, concerns have arisen about noise, air, and water pollution, as well as safety, fueled by drilling and completion accidents, and improper procedures. Some states have reacted with drilling moratoriums pending environmental studies and legislation, while others have applied strict conditions on drilling permits. All of these aspects of shale gas development have greatly increased the costs of development. Even with drilling and completion technology advancements, productions rates are low, resulting in long pay-out times for new development. Since about 2008, the well-head price of natural gas has been marginal, particularly for those resources far from large urban markets. In late 2009 – 2010, multinational companies who had been




setting on the sidelines began to acquire some of the land-poor independents that had over-extended themselves during the various land rushes. The rationale for this is unclear, but may have something to do with the face that shale gas reserves will stay on company books longer than conventional oil and gas reserves, because of the low production rates. For a large company having difficulty replacing conventional reserves, acquiring shale gas reserves cushion the loss of more easily produced reserves.like CBM, Shale gas development has to fight;

• High costs associated with shale gas development.

• Low commodity prices.

• High transportation costs.

• Slow return on investment.

• Environmental concerns and restrictions.

Other Unconventional Reservoir Types Shale gas and CBM are, currently, the most prominent, but not the only, examples of

unconventional reservoir types. Three other types are briefly discussed below.

Oil Shales Oil shales are immature organic (Kerogen) rich marls, such as the Green River Shale

(misnomer) of Colorado and Utah, and the Kimmeridgian Chalk, of the North Sea. Both of these extensive and thick formations are considered to be source rocks for conventional reservoirs in their respective basins. While the Kimmeridgian is primarily located under the hostile North Sea environment, the green River formation is located on the Colorado plateau, which is easily accessible. Consequently, it has been the target for innovative extraction technology evaluation by the US Department of Energy (US DOE), The Cleveland Cliffs Mining Co. (CCI), Shell Oil Co., TOSCO, and UNOCAL. CCI and TOSCO evaluated surface mining and retorting. Shell evaluated in-situ Fire Floods. The US DOE set off two underground nuclear explosions in an effort to in-situ retort the Kerogen and establish fracture permeability systems. This last effort was a technical success, in that an extensive fracture network was established and mature crude oil was obtained. Unfortunately, the resulting crudes and gases were highly radioactive and the site is not off limits for entry.

Oil Shales continue to remain a fuel source of the future.

Tight Gas Sands Tight gas sands are very low (<0.1 mD) permeability sands with very low to no

Kerogen content. During the 2000 – 2008 US gas price boom, there was considerable activity to develop these resources, particularly in the Colorado Plateau of Wyoming, Colorado, Utah, and New Mexico. When the US gas marked collapsed in 2008, development




essentially ceased. Tight Gas Sands are a resource extremely dependent upon commodity prices.

Tar Sands Tar Sands are sandstones (often with very high permeabilities), with pore spaces

plugged with very viscous (<8° API gravity) asphaltic bitumen, which must be either heated or diluted to flow at room temperature. They occur from surface outcrops to depth of a few thousand feet. Often tar sands have been used directly (after heating and mixing) as road surface materials as asphalt concrete substitute. Until recently, Tar Sands have been considered to be too costly to extract and process, for crude oil as refinery stock input. With continuing high (> U$S 70.00/Bbl) crude oil prices, several companies (e.g., Oil Sands Quest, Syncrude) and multinational oil companies (e.g., BP, Chevron, CONOCO-Phillips, EXXON-Mobil, Occidental, Shell, TOTAL) have become very active in Canadian Tar Sand development.

Tar Sand development is not without its environmental tool. Surface mining and processing have turned several Northern Alberta lakes, including parts of Lake Athabasca, into toxic sumps. Steam Assisted Gravity Drainage (SAGD), uses enormous amounts of oil and natural gas to drive the supporting steam generators and emits corresponding amounts of greenhouse gases. Some US states have enacted legislation banning imports of Tar Sand crudes and refined products.

Like other unconventional hydrocarbon resources, Tar Sand development remains viable only as long as there exists a shortage of conventional crude oil sources.

The Bakken Formation The Bakken formation is an extensive Upper Devonian – Lower Mississippian age

clastic formation in the Williston Basin of Western North Dakota, Eastern Montana, Southern Saskatchewan , and SW Manitoba. The most promising oil development areas to date have been in North Dakota.

Vertically, the North Dakota section is broken into three members: The upper and lower members are slightly to highly organic rich shales which serve as both source rocks and reservoir seals for the middle member.

The middle member consists of highly variable porosity and permeability interbedded siltstones, and sandstones, with lesser amounts of shale, dolostones, and limestones. Middle Member porosities vary from 1 to 16% with an average of about 5 %. Permeabilities vary from 0 to 20 mD, with an average value of 0.04 mD. The highest porosities and permeabilities appear to be localized and due to secondary porosity and fractures. Exploration consists of locating those localized high porosity and permeability intervals. Development is most successful with extended reach horizontal wells, intersecting vertical fractures, and multi-stage completions.




Bakken recoverable reserves estimates have ranged from optimistic to ridiculous. E&P remains high risk, because of the ephemeral nature of the reservoirs and the lack of significant structural closure. As a result most of the E&P work has been done by independents with venture funding from investors and large companies.

Monterey Shale The Monterey Shale (misnomer) is part of Miocene (6 – 17.6 million years old) age

Pacific Rim ocean bottom sediments. Far from being a “classic shale”, it is a (both laterally and vertically) heterogonous mixture of organic and phosphatic rich siltstones, diatomite, dolomite, chert, and porcelanite, with very little clay minerals. It is the source rock for nearly all of the California oil fields. It has also been the reservoir rock for oil fields from the early 1900’s.

Diatoms probably formed the bulk of the Monterey type original sediments, but easily dissolve and re-precipitate as chert and or porcelanite, over time. Both the chert and dolomite rich Monterey tend to shatter under tectonic stress and make the best reservoirs.

Monterey formation rock is characterized by very low matrix permeability, with most of the production coming from natural or induced fractures. Production has occurred from essentially from all of the various facies, but in no consistent fashion. The most consistent reservoir has been fractured dolomite. Some operators have been quite successful using regional fracture trend and detailed facies studies. Under-balanced drilling techniques have proven to be more successful than induced fracturing after the fact.

Monterey E&P continues to be a high risk operation, which only larger firms with considerable deep pockets can afford to do.

Origin of Petroleum Petroleum consists of simple (e.g., methane: CH4) to very complex organic molecular

chains and rings. There have been two competing theories on the origin of petroleum, almost from the beginning.

Astronomers, some inorganic chemists, physicists, and Russian scientists, including Dimitri Mendele'ev, father of the periodic table, have argued for inorganic origins to petroleum. The arguments for inorganic petroleum origin are:

• There is some laboratory evidence that hydrocarbons can be formed from volcanic gases.

• There are some igneous and metamorphic hydrocarbon reservoirs.

Morton’s (2000) description of Thomas Gold’s ideas on inorganic hydrocarbon origin provides an example of these arguments. Websites listed at the end of this section offer other arguments.




Figure 2-19: API Gravity vs. depth for Tensleep reservoirs of Wyoming (after Russell, 1960).

Most western and modern Russian (e.g., Kontorovich, 2004) geoscientists and petroleum scientists, however, have accepted an organic origin for petroleum. The compelling arguments for organic petroleum origin are:

• Major petroleum accumulations are found only in sedimentary rocks. • Major petroleum accumulations are found in unmatamorphosed, marine and

continental sediments.




• Major petroleum accumulations are found in porous sediments, isolated from shallower porous sediments.

• Petroleum hydrocarbons and related compounds occur in many living organisms, such as fish and microscopic marine life (e.g., plankton, diatoms, foraminifera, and radiolaria).

• Organic rich shales, some, like the Nonesuch Shale, of Northern Michigan, as old as Pre-Cambrian in age, contain petroleum hydrocarbons.

• Soluble liquid hydrocarbons, similar to heavier crude molecules, are found in most shales.

• Soluble asphalts similar to those found in asphaltic crudes, are found in most shales.

• Insoluble Kerogen, similar to that found in paraphenic crudes is found in most shales.

• Gas Chromatography/ Mass Spectrometry (GC/MS) has, at least, in some cases been able to tie hydrocarbons in specific organic rich shales to specific petroleum reservoirs.

Table 1: Structural-Stratigraphic Classification of Petroleum Reservoirs (after Russell, 1960).




There appears to be a residence time, temperature, and depth of burial relationship in the origin of petroleum. Methane is common in swamps (swamp gas) at the surface, due to the decay of animal and vegetable tissue. Methane is also a common product at wastewater treatment plants (sewer gas). Methane is common in very shallow, recent petroleum reservoirs. Methane also is the only hydrocarbon in some of the deepest and hottest petroleum reservoirs. Deeper and even hotter reservoirs contain carbon dioxide (CO2), but no methane.

Liquid hydrocarbons, however, appear to go from complex, heavy molecules (low API Gravity) to lighter and simpler (higher API Gravity) molecules with depth, as shown in Figure 2-19. This would suggest that liquid hydrocarbons form first as the more complex, heavy oil (low API gravity) hydrocarbon chains and rings. With time, increased depth of burial, and high temperatures, the more complex hydrocarbon molecules break down into simpler (higher API Gravity) light crude molecules. The occurrence of methane and then only CO2, in the deepest and hottest reservoirs suggests that this process continues until there is no hydrogen left.

Figure 2-20: Idealized Anticlinal Structure (after Bateman, 1959).




Migration of Petroleum Petroleum gases and most crudes are less dense than water. They are also largely

insoluble in water. All else being equal, petroleum should occupy the uppermost reaches of a petroleum reservoir containing water, which is the case. The problem is that many petroleum reservoirs are obviously not also source rocks. There needs to be some mechanism of transporting the petroleum from the source rocks to the reservoir, where it can then be produced. Petroleum migration theories are often entwined with theories of the origin of petroleum. Some of the websites, listed at the end of the Section 2 supplemental notes discuss the migration issue, in great detail.

Are the precursors of petroleum cooked to full-blown petroleum molecules, in the source rocks, where they are then expelled to find their way to reservoirs? This theory faces permeability and relative permeability problems. There are not always high permeability pathways between petroleum reservoirs and their apparent source rocks. Source rocks, themselves, are often fine-grained, which translates to very small pore throats, for fluid movement. Also, most of the rocks forming suspected migration pathways are preferentially water wet, further restricting the size of the pore throats through which the hydrocarbons must pass. At first glance, all of this seems to be low probability.

Figure 2-21: Santa Fe Springs Field, CA, Structure (after Russell, 1960).




An alternative to the above migration theory is that the source rocks release intermediate products, such as ligands, ammines, and esters which are usually simpler molecules than hydrocarbon molecules and/or soluble in water. According to this theory, the intermediate products migrate, in aqueous solution from the source rocks to the reservoir rocks, avoiding the immiscible fluid problems. Once in the reservoir rocks the maturation to petroleum crude oils and gasses then continues.

The wild card, for both of these theories, is that movement/maturation takes place over geologic time scales on the order of millions of years. While many aspects of petroleum maturation and migration can be scaled, in laboratory experiments, time scaling is very difficult to do. It is possible that either one, or both, of these scenarios is what actually happens.

Figure 2-22: Santa Fe Springs Field, CA, Structural Cross Section AA' (after Russell, 1960).

What is Needed for a Petroleum Reservoir A petroleum reservoir needs the following conditions:

• A reservoir rock with porosity to store hydrocarbons.




• A reservoir rock with permeability to deliver the stored hydrocarbons to a borehole.

• A very low permeability formation overlaying the reservoir rock (seal). • Structural closure, or trap, such that hydrocarbons cannot escape from the

reservoir to shallower formations. • A source of hydrocarbons, with communication (at least in the past) to the

reservoir.

The following conditions are also desirable, for commercial petroleum reservoirs:

• A thick hydrocarbon column. • A source of reservoir energy (compaction drive, water drive, dissolved gas drive,

and/or gas cap drive). • High gravity crude or gas.

Essential all petroleum reservoirs satisfy the first set of conditions. The best performing reservoirs also satisfy the second.

Figure 2-23: Circle Ridge Anticline, WY, Photo Mosaic (after Landes, 1970).




Atlas of Reservoir Types and Traps While all of the above first group conditions are necessary, without some type of

trapping mechanism to stop migration, there would be no petroleum reservoir. Petroleum reservoir traps come in many varieties, as shown in Table 1.

Petroleum reservoirs and traps can occur in a variety of forms. The next section reviews some of the more common reservoir types and traps. A trap involves a very low permeability rock over the reservoir, which will prevent migration of hydrocarbon molecules, in some type of geometrical shape, which will collect them. Geologists and Geophysicists usually depict reservoirs via footprint and structural contour maps, structural and stratigraphic cross-sections, or three-dimensional isometric projections.

Figure 2-24: Upper Circle Ridge, WY, Field Structure contours on top of Phosphoria Limestone (after

Landes, 1970).




ANTICLINAL TRAP One of the simplest types of structural trap is the anticline (see Figure 2-19). This

structure usually forms as a result of compression, resulting in a convex fold, with its axis at right angles to the direction of maximum stress, and parallel to the direction of intermediate stress (the direction of minimum stress, is assumed to be vertical).

Figure 2-21 shows a structural contour map (on the top of a gas reservoir), for the Santa Fe Springs Field, located in the Los Angeles (LA) Basin, of California. The "lazy S" shape of the anticlinal axis reflects the complex stress regimes in the LA Basin.

Figure 2-25: Upper Circle Ridge, WY, Field Structural Cross-Section along line AA', of Figure 2-24,

Showing the NE Limb (hanging wall) Thrust Over the SW (foot wall) Limb, Forming Two Separate

Reservoir Blocks (after Landes, 1970).

Figure 2-22 shows a structural cross-section along the AA' line, of Figure 2-21. The various geological formations, which were deposited as horizontal beds, have been bowed up to form gentle arches. Figure 2-22 also shows that the Santa Fe Springs Field has multiple "pay zones", or reservoirs. Each of these pay zones is separated from those above and below by low permeability shales, limiting or even stopping communications between pay zones. There is a "gas zone" at the top of these "stacked Pays", with 21 separate pay sands below. Those pay zones with common oil water (O/W) contacts are probably in communication with one another (out of the plain of the cross-section). Those (18) pay zones, which have distinct O/W contacts, are not in communication with other pay zones.




BREACHED ANTICLINE Deep folds tend to flatten as you approach the surface. As a result, the Santa Fe

Springs Anticline may have had little, if any surface expression, because of its depth and mild folding. Shallow, strongly folded anticlines, however, may exhibit a doming of the surface. Once hills are formed in this fashion, they are subject to erosion. In time, erosion can cause a "breached anticline", exposing several of the upper most dipping beds. Figure 2-23 is a mosaic of air photos, over the Circle Ridge Anticline, WY. The kidney-shaped ridges are the erosional outlines of successive formations, proceeding from youngest to oldest, from the outside to the center.

Figure 2-26: Visualization of Thrust Faults with Secondary Keystone Faults (courtesy of John Perez

Graphics & Design, LLC).

FAULTED ANTICLINAL TRAP As horizontal stresses, increase, anticlinal folding steepens until failure takes place.

When this happens, a thrust, or reverse, fault occurs and one side of the fault (hanging wall) over rides the other (footwall), forming a faulted anticline. If the fault movement is large enough that pay zones are no longer in communication across the fault; separate reservoirs




can often be found in both the hanging wall and footwall, depending upon the relative timing of faulting and hydrocarbon migration.

Figure 2-23 shows a structural contour map, on the top of the Permian Phosphoria Limestone, for the Upper Circle Ridge Field, Wyoming. Note that the western and SW edges of the field are bounded by a thrust fault. Also note that the shapes of the Figure 2-24 contours are similar to the outlines of the ridges in Figure 2-23. Figure 2-25 shows a structural cross-section along the line AA', of Figure 2-24. This structural cross-section shows the asymmetric to overturned Circle Ridge Anticline, the thrust fault, and the offset of pay zone(s) along the thrust fault.

ANTICLINE CRESTAL KEYSTONE AND THRUST IMBRIGATE FAULTS The stress regimes, at the crests of anticlines, are tensional prior to thrust faulting.

Under these circumstances, Normal Faults (hanging wall drops, relative to foot wall), forming Keystone Grabins (German for graves), at the crest. If horizontal compression results in thrust faulting, Imbricate (or secondary keystone) Faults can occur (see Figure 2-26).

Figure 2-27: Schematic Representation of Growth Faults (after Landes, 1970).

GROWTH FAULT ANTICLINAL TRAP Much of the US Gulf Coast, from Texas through the western Florida Panhandle, is

underlain by the extensive and thick Jurassic age Louann Salt. This evaporite deposition was followed by a deepening of the Gulf of Mexico Trough, or Geosyncline (large, concave, or down warped fold), accompanied with extensive infill of clastic sediments.

As the weight of the heavy sediment load built up, the underlying Louann Salt began to flow, forming thins and ridges under the overlying sediments. To accommodate the salt movement, a series of normal (hanging wall shifted down, relative to the footwall) faults formed ringing the landward side of the Gulf Coast Salt Basin. The heavy influx of sediment




continued during the faulting, so that deposition continued contemporaneously with movement on the normal faults. The resulting structures called, "Growth Faults" (Figure 2-27) in the US Gulf Coast are also found in other recent sedimentary regimes, such as the Niger Delta.

Figure 2-28: Lewisberg Field, LA, Contour Map on Top Frio Formation, Showing Five Growth Fault

Created Reservoir Blocks (after Landes, 1970).

Growth fault fields have the following characteristics:

• A series of normal faults and down-dip closures (see Figure 20-28).

• Listric (decreasing fault dip with depth) normal faults.




• Significant stratigraphic thickening across the fault (i.e., hanging wall thickness several times that on the foot wall.

• Reversal of regional dip into the fault (Rollover), creating anticlinal structures in the hanging wall (see Figure 2-27 and 28).

• Petroleum reservoirs in the hanging wall, adjacent to the growth fault (see Figure 2-27 and 28).

fault.

Figure 2-29: Visualization of a Piercement Salt Dome (courtesy of John Perez Graphics Design, LLC).




Figure 2-30: Three-Dimensional Renderings of Avery Island, LA (after Landes, 1970).

PIERCEMENT SALT AND MOBILE SHALE DOMES A very significant class of hydrocarbon reserves in the US Gulf Coast, as well as

elsewhere are structural traps created by the movement of salt and high water content clays. With continuing sedimentary loading, some of the salt ridges, responsible for growth faulting, find pressure relief by sending salt piercements (plugs) through loci of weakness, into the overlying sediments, as shown in Figure 2-29. The formation of these piercemednt domes warped up the overlying sediments and dragged the pierced sentiments up with them. Petroleum reservoirs can be found in the sands domed above the salt plug, solution features within the cap rock of the dome, and/or in the sands dragged up by the piercement action (see Figure 2-29). Similar structures formed by high water content mobile shales are found in the Niger Delta.




Figure 2-31: East Texas Field Map, (after Landes, 1970).




One such salt dome, Spindletop Dome, near Beaumont, Texas, was responsible for launching TEXACO, GULF, AMOCO, and ARCO, as well as many smaller oil companies. Many of these domes have significant surface topography (from 10 to over 100 ft). Some have operating salt mines in their core, as well as oil and gas fields along their flanks. Figure 2-30 shows a three-dimensional rendering of the Avery Island Dome, in SW Louisiana.

Figure 2-32: East Texas Field structural and Stratigraphic Cross-Section (after Landes, 1970).

CLASTIC STRATIGRAPHIC TRAP The previous examples all had some type of structural closure of the reservoir, with

overlying low permeability shales. In the absence of structural closure clastic reservoirs can also be formed by up-dip facies changes from sands to shales. Figure 2-31 is a map of the East Texas Field, one of the largest fields in North America (note that the map scale is in miles). Figure 2-32 is a west to east structural and stratigraphic cross-section, showing the pinch-out and facies change in the Woodbine Group, which resulted in the oil entrapment.

Figure 2-33: Paul Valley, Oklahoma, Uplift Cross-Section, Showing On-Lap Sedimentation Against an

Unconformity (after Landes, 1970).




This super giant field launched the carriers of the Hunt family, their oil companies, and, possibly, served as the inspiration for the television series, Dallas.

TRANSGRESSIVE SEAS AND ON-LAP TRAPS Large-scale climatic changes are not a new phenomenon. There have been several

large-scale climatic changes, throughout geologic time.

Periods of colder temperatures have been accompanied by the growth of polar ice caps, as well as increased alpine, and continental glaciation, with accompanying lowering of worldwide sea levels. The most extreme of these periods are called “Ice Ages”, the most recent being the Pleistocene Ice Age.

Periods of warmer temperatures have been accompanied by the complete loss of continental glaciers (except, possibly, at the poles), along with melting of polar ice caps and alpine glaciers. We are currently experiencing one of these inter-glacial periods, with rising sea levels.

Figure 2-34: Map of Horseshoe Atoll Fields, Texas, Including Kelly-Snyder Field (after Landes, 1970).




Tectonic events (mountain building) can also cause local changes in sea levels. The west coast of the US is currently emerging, with the land rising relative to sea level. The California Coastline, north of San Francisco, shows evidence of former wave cut benches, now several tens of feet above sea level. The East coast of North America and SW Louisiana are in a submerging state, with increased flooding of coastal lowlands.

Near-shore sedimentation is controlled by water depth and wave movement. Rising sea levels move sedimentation zones toward the shore, resulting in what is called “on-lap” sedimentary sequences. Falling sea levels move sedimentation zones away from the shore, resulting in what is called “off-lap” sedimentary sequences.

Figure 2-33 shows a cross-section through the Paul Valley, Oklahoma, Uplift. Successively more recent sediments are deposited higher and higher along the (weathered surface) unconformity. Low permeability shales overlying the third and fourth Deese Sand Zones form reservoir seals, and traps at their up dip termination (sub-crop) against the unconformity.

Figure 2-35: Kelly-Snyder Field, Texas, Field Outline and Structure Contoured on the Top Canyon

Reservoir (after Landes, 1970).




CARBONATE RESERVOIRS The large preponderance of petroleum reservoirs are in clastic rocks. Some of the

largest and most prolific fields in the world, however, are in carbonate rocks. For carbonate reservoirs to form secondary porosity must form after the limy muds, shell beds and coral reefs have been converted to limestones. This is done by recrystalization (conversion from calcite to dolomite) and/or solution features due to movement of waters within permeable portions of the carbonates.

Figure 2-36: Kelly-Snyder Field, Texas, Section along AA' in Figure 2-22 (after Landes, 1970).

Figure 2-34 shows the location of Horseshoe Atoll, A Pennsylvanian age carbonate reef, in West Texas. The largest field in this former reef is the Kelly-Snyder Field, shown in




Figure 2-35. Figure 2-36 is a structural and stratigraphic cross-section along line AA', of Figure 2-35. Similar Super Giant Carbonate fields are located in Iran, Kazakhstan, Kuwait, Saudi Arabia, Qatar, Yemen, and The UAE, as well as elsewhere in the West Texas - SE New Mexico Permian Basin.

Figure 2-37: Sieve Analysis for a Recent Gulf Coast Shaly-Sand Interval, with Two Dominant Grain

Sizes (after Griffin, 1991)

Bi-Modal Clastic Rock Model One of the more interesting problems faced by petrophysicists involves estimation of

volumetrics ( and Sw) for clastic reservoirs containing significant volumes of clays and clay

minerals. While this situation describes a sand containing clay sized particles and clay minerals, the reservoirs are universally called "Shaly-Sands".

Over time, petrophysical shaly sand models have become very complex, as investigators have attempted to accommodate additional properties. For purposes of the current discussion, however, we will consider a rather simplified model. In spite of its simplicity, this model also satisfies many field observations. Its simplicity allows insight, which might be more difficult for more complex models.




Figure 2-38: Comparison of Basketballs and BBs.

Consider, if you will, a sediment model consisting of only two sizes of particles: coarse- and fine-grained, such as the bi-modal grain size distribution in the sieve analysis of Figure 2-37. For the purposes of this model, we would like the coarse grained particles to be at least 50 - 100 times larger than the fine-grained particles (visualize the diameters of BBs and basketballs, as shown in Figure 2-38). This is the case, for the sieve analysis, of Figure




2-37. Figure 2-5 (Seevers and Hill, 1970), shows that this condition is also satisfied for sand and clay sized particles, using common particle size scales.

Figure 2-39: Bi-modal Particle Size Sediment Model (after Seevers and Hill, 1970).

Now, consider that the sediment model consists of a structural matrix of the coarse grained particles, with the fine-grained particles only in the spaces between the coarse grains. This model, shown in Figure 2-38, has been utilized by Stephenson (1970, 1971, 1974a, 1974b, and 1977), Seevers (1977), Seevers and Hill, (1971), Thomas and Stieber (1975), and Hill (1978), to develop “Shaly-Sand” petrophysical relationships.

If we start with a coarse-grained matrix of porosity, c, and fill in the pore spaces with fine-grained material of porosity, fn, we would like to know what the porosity of this mixture, T, would be. Define the coarse-grain fraction, Xc, of this composite as the ratio of the volume of the coarse-grains over the volume of the total matrix. With no fine-grained material in the mixture, Xc = 1. As fine-grained material is inserted into the coarse-grained pore spaces, the total porosity will be reduced by the volume of the fine-grained material that has been inserted into the pores of the composite. At some point, in this exercise, we would have completely filled the coarse-grain pore spaces with the fine-grained material. At that point, the total porosity of the composite, 'T, will be:

' T = c fn . 2-1)




Figure 2-40: Sand Porosity vs. Depth, for a Gulf Coast Well (after Pardo and Kurtak, 1965).

The grain fraction where this occurs, X'c, can be determined, using a little intuitive geometry and a lot of algebra, to be:

X' c =1 c

1 c fn

. 2-2)

For the range: X'c < Xc < 1, the total porosity follows the model:

T =1(1 c)

Xc=

c X fn

1 X fn

, 2-3)




where: Xfn = 1 - Xc.

Figure 2-41: Shale Chip Porosity vs. Depth for a Gulf Coast Well (after Stephenson, 1970)

If we start with a fine-grained matrix of porosity, fn, and insert the coarse-grained material until we have achieved a coarse grained framework, with a coarse-grained porosity,

c, we would like to know what the porosity of this mixture, T, would be. In this case, we would be replacing both the fine-grained material and its porosity, with each coarse-grain we insert. With no coarse-grained material in the mixture, Xc = 0 and the T = fn. As coarse- grained material is inserted into the composite, the total porosity will be reduced in a more




complex manner, than before, because we are now replacing both matrix and pore space. The porosity minimum, however, will still be given by Equation 2-1and the grain fraction for

that minimum will still be given by Equation 2-2. For the range: 0 < Xc < X'c, the total porosity is given by:

T =(1 Xc ) fn

1 Xc fn

. 2-4)

Equations 2-1 -2-4 indicate that we can estimate the porosity of a bi-model mixture, for any Xc, using only c and fn, the coarse-grained and fine-grained end point porosities. We can now use these equations and assumed values of c and fn to show the relationship, at deposition.

Figure 2-42: Bi-Model Clastic Model Total and Effective Porosity vs. Grain Fraction.

Grafton and Frazer (1935) demonstrated that random packs of uniform spheres yielded porosity values between 26% and 47%, depending upon the packing. The question is where do we start. Beard and Weyl (1973) demonstrated that well sorted “wet-packed” sands averaged 42.4% porosity, regardless of the grain size mode. Athy (1930) demonstrated that porosity compaction appears to follow the form:

= Ae bz, 2-5)




where: A and b are arbitrary constants, determined by the data and z is the depth below ground surface. Equation 2-5 indicates that porosity/depth plots on semi-logarithmic grids will be a straight line, with a slope of -b and a z = 0 intercept of A.

Figure 2-40 shows a porosity/depth plot for sands from a Gulf Coast well. The data, for this well, do follow the model of Equation 2-5, quite well, with a surface porosity intercept of ~43%, which is close to that predicted by the models of Beard and Weyl (1973). Figure 2-41 shows a similar porosity/depth plot for shale chips from a gulf coast well. This shale data also follows the model of Equation 2-5 well, with a surface porosity of ~ 42%, which also agrees with the model of Beard and Weyl (1973).

Using c = fn ± 40%, figure 2-42 shows the complete bi-modal porosity-grain fraction relationship. The dashed line in Figure 2-42 shows the T -Xc relationship. Note that both Xc = 0, = fn, and for Xc=1, = c. At Xc = Xc’ 72% T = c fn =16%.

Up to this point, we have not required anything from the coarse and fine grains, except that they be about 2 orders of magnitude different in size. If we now require that the fine-grains be clays and that the coarse-grains be quartz, we can draw another very useful inference.

Define the effective porosity, e, to be that porosity which will deliver significant volumes of fluids to a borehole. Remember that in the discussion of clastic sediments, it was stated that clays and shales may have quite high porosity but the sizes of the pore spaces in clays and shales are so small that they generally cannot deliver fluids to a borehole. The effective porosity of clays and shales is then 0.

The porosity on the left-hand side (LHS) of Figure 2-42 involves only fine-grained, or shale porosity. The effective porosity, for the entire LHS, where 0 < Xc < X'c is 0. The effective porosity for the right hand side (RHS) of Figure 2-42, where X'c < Xc < 1, is reduced by the volume of the fine-grained material, and its porosity, inserted into the coarse-grained matrix. The effective porosity for the RHS of Figure 2-36 is given by:

e = T

1 Xc

1 Xc fn

. 2-6)

These relationships are shown by the solid line in Figure 2-42.

Now that we have established the bi-model clastic model, we can see just what the effects of clays really are. For the model of Figure 2-42, where c = fn= 40%, X'c is approximately 72%. This means that only 28% clays, in the matrix, for this clastic model eliminates all effective porosity. Because the last few e % are not really that significant, this rock is not a viable reservoir with even less than 28% clays. Depending upon the c and fn, this cut off can be as low as 9% clays.

The bi-modal clastic model is greatly simplified, as you will see later in the course. Many of the inferences from this simple conceptual model, however, will provide valuable insight for more complex sedimentary models and/or the responses of various logging tools.




References

Allan, D. A., Ayoub, J., Borai, A. M., Brown, R. J. S., Cannon, D., Cheung, P., Dussan, E. B., Herron, M., Kleinberg, R., Dennis, B., Denoo, S., Everett, W., Rasmus, J., and Watfa, M., 1988, “Probing for Permeability: An Introduction to Measurements”, The Technical Review, v. 36, No. 1 (January), pp. 6 - 20.

Almon, W. R, 1979, “A Geologic Appreciation of Shaly Sands”, 20th

Annual Logging Symposium,

SPWLA, Paper WW.

Amaefule, J. O., and Altunbay, M., 1993, "Enhanced Reservoir Description: Using Core and Log Data to Identify Hydraulic (Flow) Units and Predict Permeability in Uncored Intervals/Wells", SPE-26436, Society of Petroleum Engineers.

Amaefule, J. O., Kersey, D. G., Marschall, D. M., Powell, J. D., Valencia, L. E., and Keelan, D. K., 1988, "Reservoir Description: A Practical Synergistic Engineering and Geological Approach Based on Analysis of Core Data", SPE-18167, Society of Petroleum Engineers.

Amaefule, J. O., Kersey, D. G., Ohen, H. A., Njoku, F., and Salter, G., 1991, "Role of Integrated Rock and Fluid Property Data in Reserves and Production Enhancement in Nigerian Reservoirs", 15th Annual SPE (Nigeria Council) International Conference and Exhibitions, Society of Petroleum Engineers.

Anon., 1980, Field Geologist's Training Guide, Applications & Training Section, Exploration Logging, Inc., Sacramento.

Anon., 1980 (?), Formation Evaluation Data Handbook, Wireline Services, Gearhart Industries, Inc. Fort Worth.

Anon., 1992, Introduction to Well Log Analysis, Western Atlas, International, Houston.

Anon., 2004, Coal Bed Methane Primer, ALL Consulting, Tulsa.

Anon., 2008, US Shale Gas Play Map, US Energy Information Administration.

Anon., 2011, North American Shale Play Map, US Energy Information Administration.

Arthur, J. D., Langus, B., and Alleman, D., 2008, An Overview of Modern Shale Gas

Development in the United States, ALL Consulting, Tulsa.

Athy, L. F., 1930, “Density, Porosity, and Composition of Sedimentary Rocks”, Bull. AAPG, v. 14, pp. 1 – 24.

Atkins, E. R., and Smith, G. H., 1961, "the Significance of Particle Shape in Formation Resistivity Factor-Porosity Relationships", Jour. Pet. Tech., v. 13, No. 3 (March), pp. 295 - 285, & 1057 (discussion).

Araktingi, U. G., and Bashore, W. M., 1992, "Effects of Properties in Seismic Data on Reservoir Characterization and Consequent Fluid-Flow Predictions when Integrated with Well Logs", SPE-24752, Society of Petroleum Engineers.




Archie, G. E., 1942, “The Electrical Resistivity Log as an Aid to Determining Some Reservoir Characteristics”, Bull., AAPG, v. 146, pp. 54 – 62.

Archie, G. E., 1950, “Introduction to Petrophysics of Reservoir Rock”, Trans., AIME, v. 34, pp. 943 – 961.

Athy, L. F., 1930, “Density, Porosity, and Composition of Sedimentary Rocks”, Bull. AAPG, v. 14, pp. 1 – 24.

Barry, L. G., and Mason, B., 1959, Mineralogy, W. H. Freeman and Company, San Francisco.

Bashore, W. M., and Araktingi, U. G., 1993, "The Importance of the Geological Model for Reservoir Characterization Using Geostatistical Techniques and the Impact on Subsequent Fluid Flow", SPE-2647, Society of Petroleum Engineers.

Bassiouni, Z., 1994, Theory, Measurement and Interpretation of Well Logs, Society of Petroleum Engineers, Richardson, TX.

Bateman, A. M., 1959, Economic Mineral Deposits, John Wiley & Sons, New York.

Beard, D. C., and Weyl, P.K., 1973, “Influence of Texture on Porosity and Permeability of Unconsolidated Sand”, Bull., AAPG, vol. 57, No. 2 (February) pp. 349 – 369.

Berman, A. E., and Pittinger, L., 2011, “US Shale Gas Reserves May be Over Stated at Least 100 Percent”, Think Progress website.

Blake, R. G., Maley, M. P., and Noyes, C. M., 1995, "Hydrostratigraphic Analysis - The Key to Cost Effective Ground Water Cleanup at Lawrence Livermore National Laboratory", UCRL-JC-120614, Lawrence Livermore National Laboratory.

Blatt, H., Middleton, G., and Murry, R., 1980, Origin of Sedimentary Rocks, Prentice-Hall, Englewood Cliffs.

Brown, A. A., 1984, “Electrical Properties of Shaly-Sands”, Standard Oil Company of

California Intermediate Formation Evaluation Seminar, Chevron Oil Field Research Co., LN84000590.

Brownell, M., 2008, “Well Drilling and Development: Marcellus Shale”, Susquehanna River Basin Commission.

Carman, P. C., 1937, “Fluid Flow Through Granular Beds”, Trans., Inst. Chem. Engr., v. 15, pp. 150 – 166.

Carman, P. C., 1938, “Fundamental Principles of Industrial Filtration (A Critical Review of Present Knowledge”, Trans., Inst. Chem. Engr., v. 16, pp. 168 – 188.

Clark., J. A., and Holbouty, M. T., 1952, Spindletop, Random House, New York.




Croft, G. D., 2009, “Resource Limits and Conversion Efficiency with Implications for Climate Change and California’s Energy Supply”,Ph.D., Dissertation, The University of California, Berkeley.

Croft, G. D., 2011, “Cal and the Peak of World Carbon Emissions”, Sacramento Petroleum Society.

Damsleth, E., and Tjølsen, C. B., 1994, "Scale Consistency from Cores to Geologic Description", SPE Formation Evaluation, v. 9, No. 4 (December), pp. 295 - 299.

Daniels, J. J., Scott, J. H., Blackmon, P. D., and Starkey, H. S., 1977, "Borehole Geophysical Investigations in the South Texas Uranium District", Jour., Research, U. S. Geol. Survey, v. 5, No. 3 (May - June), pp 343 - 357.

Dehghani, K., Jenkins, S., Fischer, D. J., and Skalinski, M., 2008, “Application of Integrated Reservoir Studies and Techniques to Estimate oil volumes and Recovery – Tengiz Field, Republic of Kazakhstan”, SPE Reservoir Evaluation & Engineering, V. 11, No. 2 (April, pp. 362 – 378.

Doveton, J. H., 1994, Geologic Log Analysis Using Computer Methods, AAPG, Tulsa.

Doveton, J. H., Ke-An, Z., and Davis, J. C., 1984, "Three-Dimensional Trend Mapping Using Gamma-Ray Well Logs: Simpson Group, South-Central Kansas", Bull., AAPG, v. 68, No. 6 (June), pp. 690 - 703.

Economides, M., and Ologney, R., 2000, The Color of Oil, Round Oak Publishing, Katy, TX.

Fara, H. D., and Scheidegger, A. E., 1961, "Statistical Geometry of Porous Media", Journal of Geophysical Research, v 66, No. 10 (October), pp. 3279 - 3284.

Gill, D., 1970, "Application of a Statistical Zonation Method to Reservoir Evaluation and Digitized-Log Analysis", Bull., AAPG, V. 54, No. 5 (May), pp. 719 - 729.

Gill, D., Shomrony, A., and Fligelman, H., 1993, "Numerical Zonation of Log Suites and Logfacies Recognition by Multivariate Clustering", Bull., AAPG., v. 77., No. 10 (October), pp. 1781 - 1791.

Graton, L. D., and Fraser, H. J., “Systematic Packing of Spheres, with Particular Relation to Porosity and Permeability”, Jour., Geology, v. 43, 785 – 909.

Griffin, T. J., 1991, Personal Correspondence from Ted J. Griffin, Core Petrophysics, to Donald G. Hill, Chevron Overseas Petroleum, Inc.

Griffiths, J. C., 1967, Scientific Method in Analysis of Sediments, McGraw-Hill Book Company, New York.

Haldorsen, H. H., and Lake, L. W., 1984, "A New Approach to Shale Management in Field-Scale Models", SPE Journal, V. 29, No 8 (August), pp. 447 - 457.




Hill, D. G., 1978, “Bi-Modal Shaly Sand Rock Model Petrophysical Relationships”, Technical Memorandum, TM78000300, Chevron Oil Field Research Company.

Hill, D. G., and Qualheim, B, 1995, "Modified Scintillation Detectors to Improve Slim-Hole Gamma Ray Log Repeatability in Low Radioactivity Materials", Proceedings, Sixth International Symposium on Borehole Geophysics for Minerals, Geotechnical and Groundwater Applications, Minerals and Geotechnical Logging Society.

Hurt, H., 1981, Texas Rich, Orbis Publishing, London.

Kontorovich, 2004, “Evolution of Oil Generation in the Earth’s History”, Gologiya I Geofizika, Siberian Branch of the Russian Academy of Sciences, vol. 45, No. 7, pp. 738 – 754.

Krumbein, W. C., 1938, "Size Frequency Distribution of Sediments and the Normal Phi Curve", Journal of Sedimentary petrology, v. 8, pp. 84 - 90.

Krumbein, W. C., 1957, "Application of Moments to Vertical Variability Maps of Stratigraphic Units", Bull., AAPG, v. 41, No. 2 (February), pp. 197 - 211.

Landes, K. K., 1970, Petroleum Geology of the United States, Wyley-Interscience, New York.

LaTorraca, G. A., and Wissler, T, M., 1990, "Effects of Rock Fabric on Petrophysical Properties", Internally published memorandum, LN82000005, Chevron Oil Field Research Co., La Habra, CA.

Matlack, K. S., Houseknecht, D. W., and Applin, K. R., 1989, “Emplacement of Clay into Sand by Infiltration”, Jour., Sed. Pet., v. 59, No. 1 (January), pp. 77 – 87.

Merkel, R. H., and Head, W. J., 1977, "The use of Computerized Log Analysis to Determine In Situ Lithologic Characteristics Pertinent to Secondary Recovery", Bull., Canadian Petroleum Geology, v. 25, No. 2 (May), pp. 291 - 304.

Moore, j. A., and Schultz, R. A., 1999, “Process of Faulting in Jointed Rocks of Canyonlands National Park, Utah”, Geological Society of America, Bulletin, v. 111, No. 6 (June), pp. 808 – 822.

Morin, R. H., and Urish, D. W., 1994, "Hydrostratigraphic Characterization of a Coastal Aquifer by Geophysical Log Analysis, Cape Cod National Seashore, Massachusetts", American Geophysical Union, Fall 1993, Meetings, San Francisco.

Morton, O., 2000, “Fuel’s Paradise”, Wired, v. 8, No. 7 (July), pp. 160 -169.

Murphy, R. E., 1980, “Formation Evaluation of Sandstones”, Basic Formation Evaluation School, Chevron USA, Eastern Region.

Myers, T., 2005, “Coal Bed Methane Development”, Western Mining Action Network.

Neasham, J. W., 1977, “The Morphology of Dispersed Clay in Sandstones and its Effect on Sandstone Shaliness, Pore Space and Fluid Flow Properties’, SPE Paper No. 6858.




Nelson, P. H., 2008, Personal Communication from P. H. Nelson, USGS, to D. G. Hill.

Nuccio, V., 2000, “Coal Bed Methane: Potential and Concerns”, USGS Open File Report

Pallatt, N., Wilson, J., and McHardy, W., 1984, "The Relationship Between Permeability and the Morphology of Diagenetic Illite in Reservoir Rocks", Jour. Pet., Tech., v. 15, No. 27, pp. 2225 - 2227.

Pardo, G., and Kurtak, A., 1965, “Effects of Overburden on Gulf Coast Sediment Properties”, Report 4208DC67, Gulf Research and Development Co.

Perez, J., 2008, Personal communication from John Perez, President, John Perez Graphics & Design, to D. G. Hill.

Pettijohn, F. J., 1957, Sedimentary Rocks, Harper & Brothers, New York.

Pirson, S. Y., 1970, Geologic Well Log Analysis, Gulf Publishing, Houston.

Poupon, A., Clavier, C., Dumanoir, J., Gaymard, R., and Misk, A., 1970, “Log analysis of Sand-Shale Sequences –A Systematic Approach”, Jour. Pet. Tech., v. 22, No. 7 (July), pp. 867 – 881.

Poupon, A., and Gaymard, R., 1970, “The Evaluation of Clay Content from Logs”, The Log Analyst, v. 11, No. 6 (November – December), pp. 18 – 25.

Russell, W. L., 1960, Principles of Petroleum Geology, McGraw-Hill Book Co., New York.

Scholle, P. A., and Spearing, D., 1982, Sandstone Depositional Environments, AAPG, Tulsa.

Seevers, D. O., 1977, “Bimodal Model and Permeability”, Presented to: Oil Field Research Committee, Standard Oil Company, of California (Transcribed by W. J. Plumley).

Seevers, D. O., and Hill, D. G., 1971, “An Alternative Model for SARABAND”, Formation Evaluation Committee Meeting Minutes - Supplement, Standard Oil Company, of California.

Serra, O., 1985, Sedimentary Environments from Wireline Logs, Etudes et Productions Schlumberger, Paris.

Serra, O., and Abbott, H. T., 1980, "The Contribution of Logging Data to Sedimentology and Stratigraphy", SPE-9270, Society of Petroleum Engineers.

Serra, O., and Sulpice, L., 1975, "Sedimentological analysis of Shale-Sand Series from Well Logs", Trans., SPWLA, v. 16, paper W.

Shepherd, R. G., 1989, “Correlations of Permeability and Grain Size”, Ground Water, v. 27, No. 4 (September-October), pp. 633 – 637.

Sinclair, U., 1926, Oil, Grosset & Dunlap, New York




Snodgrass, J. J., 1982, "A New Sonic Velocity-Logging Technique and Results in Near-Surface Sediments of Northeastern New Mexico", Technical Progress Report 117, Bureau of Mines Minerals Environmental Technology Program.

Stephenson, L. P., 1970, Lecture Notes on the Geological Interpretation of Seismic Velocities in Sedimentary Rocks, Chevron Oil Field Research Company,

Stephenson, L. P., 1971, “The Texture of Clastic Sediments and their Cation Exchange Capacity per Unit Pore Volume”, Technical Memorandum TM71000294, Chevron Oil field Research Co.

Stephenson, L. P., 1974a, “The Relationship Between Two Definitions of Grain Fraction”, Technical Memorandum, Chevron Oil field Research Co.

Stephenson, L. P., 1974b, “Porosity vs. Cement Ratio: A Quantitative Indicator of Diagenetic History”, Technical Memorandum TM74000474, Chevron Oil field Research Co.

Stephenson, L. P., 1977, “The distribution of Pore-Filling Clays and Cements in Reservoir Rocks”, Technical Memorandum TM77000753, Chevron Oil field Research Co.

Themig, D., 2011, “New Technologies Enhance Efficiency of Horizontal, Multistage Fracturing”, Jour., Petro. Tech., v. 63, No. 34 (April), pp. 26 – 231.

Thomas, E. C., and Haley, R. A., 1977, “Log Derived Shale Derived Shale Distribution in Sandstone and Its Effect on Porosity, Water Saturation and Permeability”, 6

th Formation Evaluation

Symposium, Canadian Well Logging Society, Paper M, Calgary.

Thomas, E. C., and Stieber, S. J., 1975, “The Distribution of Shale in Sandstones and its Effect on Porosity”, 16

th Annual Logging Symposium, SPWLA, Paper T.

Ti, G., Ogbe, D. O., Munly, W., and Hatzignatiou, D. G., 1995, Use of Flow Units as a Tool for Reservoir Description: A Case Study", SPE Formation Evaluation, v. 10, No. 2 (June), pp. 122 - 128.

Tyler, K. J., Svanes, T., and Omdal, S., 1993, "Faster History Matching and Uncertainty in Predicted Production Profiles with Stochastic Modeling", SPE-26420, Society of Petroleum Engineers.

Tyler, K. J., 1994, Heterogeneities: Challenges in Reservoir Management, Ph. D. Thesis, Aalborg University, Høgskolen i Stavanger.

Vermeer, P. L., and Alkemade, J. A. H., 1992, "Multiscale Segmentation of Well Logs", Mathematical Geology, v. 24, No. 1, pp. 27 - 43.

Winchester, S., 2001, The Map that Changed the World, HarperCollins Publishers, New York.




Wilson, M. D., and Pittman, E. D., 1977, “Authigenic Clays in Sandstones: Recognition and Influence on Reservoir Properties and Paleoenvironmental Analysis”, Jour., Sed. Petrology, v. 47, No. 3 (March), pp.137 –165.




Useful Websites:

http://www.clas.ufl.edu/users/jmartin/petroleum_geology/origin.html

http://amazingworld.5u.com/photo4.html

http://www.ce.berkeley.edu/~alvcohen/

http://www.searchanddiscovery.com/documents/Animator/klemme2.htm

http://www.geotimes.org/nov02/NN_oil.html

http://www.geotimes.org/oct05/feature_abiogenicoil.html

http://www.searchanddiscovery.net/documents/abstracts/2005research_calgary/abstracts/exte

nded/keith/keith.htm

http://www.homepages.indiana.edu/011405/text/hydrocarbons.shtml

http://www.geoart.com/

http://petroleumgeology.org/

http://www.google.com/images?client=safari&rls=en&q=Petroleum+Geology&oe=UTF-

8&um=1&ie=UTF-

8&source=univ&ei=PplgTIiABZTQsAOvn_iaCA&sa=X&oi=image_result_group&ct=title

&resnum=4&ved=0CDsQsAQwAw&biw=1202&bih=746

http://www.geologyshop.co.uk/oil&ga~1.htm

http://www.geomore.com/

http://www.cspg.org/

http://www.priweb.org/ed/pgws/backyard/sections/southcentral/southcentral1.html

http://www.geology.ar.gov/fossil_fuels/oil_geol_prodarea.htm

USC Sec 2 USC SEC 2 Petroleum Geology Supplemental Notes

Documents

Transcript of USC Sec 2 USC SEC 2 Petroleum Geology Supplemental Notes