Petroleum Engineering Handbook
Larry W. Lake, Editor-in-Chief
Volume V – Reservoir Engineering and Petrophysics
Edward D. Holstein, Editor
Copyright 2007, Society of Petroleum Engineers
Chapter 1 – Reservoir Geology
The efficient extraction of oil and gas requires that the reservoir be visualized in 3D space. Engineers need a conceptual model of reservoirs, an integral part of the decision-making process, whether it be selecting perforations or forecasting future production. However, most engineering measurements made on reservoirs have little or no spatial information. For example, a core measurement has no dimensional information, wireline logs and continuous core measurements are 1D, and production data and pressure information are volumetric but with unconstrained spatial information. Geologic information, on the other hand, contains valuable spatial information that can be used to visualize the reservoir in 3D space. Therefore, engineers should understand the geologic data that can improve their conceptual model of the reservoir and, thus, their engineering decisions.
The first and most important geologic information is the external geometry of the reservoir, which is defined by seals or flow barriers that inhibit the migration of hydrocarbons, forming a hydrocarbon trap. The buoyancy force produced by the difference in density between water and hydrocarbons drives migration. Migration will cease, and a hydrocarbon reservoir will form, only where hydrocarbons encounter a trap. Traps are composed of top, lateral, and bottom seals; the geometry of traps can have structural, sedimentary, or diagenetic origins.
The second most important geologic information is the internal reservoir architecture. A reservoir is composed of rock types of varying reservoir quality that are systematically stacked, according to stratigraphic and diagenetic principles. The lateral distribution of depositional textures is related to depositional environments, and the vertical stacking of textures is described by stratigraphy, which is the geological study of the form, arrangement, geographic distribution, chronologic succession, classification, and correlation of rock strata. Diagenesis, changes that happen to the sediment after deposition, can also control the lateral continuity and vertical stacking of reservoir rock types. This fact is most important in carbonate reservoirs, in which the conversion of limestone to dolostone and the dissolution of carbonate have a large effect on internal reservoir architecture.
The most basic concern for most engineers is the spatial distribution of petrophysical properties, such as porosity, permeability, water saturation, and relative permeability. To visualize the reservoir in petrophysical terms, the engineer must be able to equate measurements (log, core, or production) with geologic models because the measurements themselves do not contain spatial information. Linking engineering measurements with geologic descriptions is best done at the rock-fabric level because rock fabric controls pore-size distribution, which, in turn, controls porosity, permeability, and capillary properties. Rock fabrics can be tied directly to stratigraphic models and, thus, to 3D space.
External Geometry-Reservoir Traps
IntroductionHydrocarbons are formed by anaerobic decomposition of organic matter that accumulates from the deposition of plankton in deep ocean basins. Oil and gas are generated as the sediments are buried and the temperature rises. Oil is the first hydrocarbon to be generated, followed by wet gas, and lastly by dry gas. Once generated, oil and gas flow vertically and laterally through overlying sediments because of the density difference between hydrocarbons and formation water and they migrate through permeable formations until they encounter a reservoir trap in which oil and gas accumulate. Oil will fill the traps first because it is first to be generated. Higher temperatures resulting from continued burial cause gas to be generated. Migrating gas will displace oil from the traps because gas has a lower density. The displaced oil will migrate further updip and fill any trap encountered.
Traps filled with hydrocarbons are often referred to as pools. However, engineers normally use the term reservoir instead of pool for an oil and gas accumulation, and reservoir will be used throughout this chapter. A field is composed of one or more reservoirs in a single area. A trap is defined by the geometry of its seals, which are formations with very low permeability and very small pores that will impede or stop the flow of hydrocarbons. To trap migrating hydrocarbons, seals must contain flow in 3D: the seals must form a closure. In the simplest terms, a trap is similar to a box with its bottom removed. The box is the seal composed of top and lateral seals. A trap may also contain a bottom seal. Imagine a smaller box inserted into the base of the original box. The smaller box is also a seal and confines the reservoir to a layer within the larger box.
Seals may be in the form of impermeable lithologies or faults. The simplest traps are convex structures in which the sealing layer dips in all directions from a central structural high, forming domes or doubly dipping anticlines. More complex structural traps are formed when convex structures are truncated by faults or when faulting occurs around a piercement structure. Many traps are combinations of structural uplift, faulting, and stratigraphy, such as an updip pinchout of a sand body into an impermeable shale. A purely stratigraphic trap may form when deposition creates a topographic high that is encased by impermeable lithology, such as shale or salt.
The volume of oil and gas that can accumulate is defined partly by the height of the trap because any additional hydrocarbons will spill out the bottom. The base of the trap is therefore called the spill point (see Fig. 1.1). The trap may not be full because the height of the oil column will be controlled by the capacity of the seal to impede flow and the volume of oil that migrates to the trap. In addition, oil/water contacts need not be horizontal because subsurface fluids are rarely static, and the flow can cause the oil/water contact to tilt in the direction of flow.
Geologists commonly describe traps on the basis of their origin. Structural traps are closures formed by structural movements within the Earth, and stratigraphic traps are closures formed by sedimentation and diagenesis, without the need for structural movements. Structural/stratigraphic traps are closures formed by patterns of reservoir rock that impinge upon a structure. This organization will be used hereafter, even though new groupings based on sealing surfaces were suggested by Milton and Bertram.
Structural traps are formed most commonly by structural uplift and differential compaction. Typical structural traps are structural domes and doubly plunging anticlines (see Fig. 1.1). These traps have a structural high and quaquaversal dips (the seal dips away from a structural high in all directions). The bulk of the world’s oil is found in these four-way-closure traps, which were the first type to be exploited by surface mapping. Many major oil fields in the world were discovered by using surface mapping to locate domal structures.
A more complex method of forming a structural trap is by faulting and structural uplift (see Fig. 1.1). Faulted structures can vary from a simple faulted anticline to complex faulting around piercement structures and domal uplifts. Faulted structures are very common and form some of the most complex reservoirs known. Types of faults include normal, listric, reverse, and thrust, which are related to the stress fields generated during structural movement. Piercement traps (diapirs) are formed typically by salt moving up through a stack of sediment driven by the density difference between salt and quartz or carbonate. Closure is achieved by the uplift of sediments juxtaposed to the piercement dome, by the top seal being an overlying impervious bed and the lateral seals being formed by structural dip, by sealing faults, or by the piercement salt. Faulted reservoirs commonly have a bottom seal formed by the lower contact of sand with shale. The bottom seal, along with the oil/water contact within the sand body, forms the base of the reservoir.
Structural/stratigraphic traps are formed by a combination of structure, deposition, and diagenesis. The most common form, the updip pinchout of reservoir lithology into a sealing lithology (see Fig. 1.1), is found in the flanks of structures. The top and updip seal is normally an impervious rock type, and the lateral seals are formed by either structural dip or the lateral pinchout of reservoir rock into seal material. The base of the reservoir is defined by a bottom seal composed of impervious rock and by an oil/water contact. During relative sea-level fall, streams may erode deep valleys, thus forming lateral seals for fluvial sediments. Onlap of sand onto a paleotopographic high during relative sea-level rise can produce an updip seal for a sand body. Unconformity traps are formed by the truncation of dipping strata by overlying bedded sealing lithology. The reservoir rock may be found in the form of buried hills formed by erosion during the time of the unconformity. The oil/water contact forms the base of these reservoirs. A stratigraphic trap may be partly related to diagenetic processes; for example, the updip seal for the supergiant Coalinga field, California, is tar- and asphalt-filled sandstone and conglomerate. Many traps in the Permian reservoirs of west Texas, are formed by lateral changes related to stratigraphy from porous to dense dolomite in an updip direction.
Stratigraphic traps are formed by depositional processes that produce paleotopographic highs encased in impermeable material, such as evaporite or shale (Fig. 1.1). Closure occurs when there is contact between seal material and underlying sediment. The most common type is a carbonate buildup, usually erroneously called a "reef." Piles of sand deposited on the seafloor by density currents often form broad topographic highs that, in turn, form stratigraphic traps. Structure may also play a part in the geometry of stratigraphic traps, although the defining characteristic is that structure is not required to form the trap.
SealsA seal is a low-permeable to impermeable rock or immobile fluid, such as tar, with a capillary entry pressure large enough to dam up or trap hydrocarbons. Typical seals include top, bottom, lateral, and fault, as shown in Fig. 1.2. Faults may be sealing or nonsealing, depending on whether the sand offsets another sand (nonsealing) or shale (sealing). Any lithology can be a seal or flow barrier. The requirement is that the minimum capillary displacement pressure of the seal or flow-barrier material be greater than the buoyancy pressure of the hydrocarbons in the accumulation. The continuous, small, pore-throat sizes create a barrier to moving hydrocarbons, causing them to dam up or become trapped. Therefore, the size of the continuous pore throats and the density of the hydrocarbons and water are critical elements in evaluating a seal or flow barrier.
in which hc = the maximum hydrocarbon column held, pc = the capillary entry pressure, ρw = the density of water, and ρhc = the density of the hydrocarbon. The capillary pressure used is usually not the capillary entry pressure but the capillary pressure at a mercury saturation of between 5 and 10% because of closure effects.
Effective hydrocarbon seals for exploration plays and reservoirs must be laterally continuous. Some typical seal lithologies, illustrated in Fig. 1.3, have entry pressures ranging from 14 to 20,000 psi. With data from more than 3,000 seals, we can group the data into Classes A through E to categorize the typical lithologies listed in Fig. 1.3 from most to least ductile. Fig. 1.3 also illustrates the hydrocarbon column that can be held, assuming that the fluid is 35°API oil and saline water. Evaporite and kerogen-rich shale can hold the greatest oil column—from 1,000 to more than 5,000 ft. Clay-mineral-rich shale, silty shales, and dense mudstones can hold between 500 and 1,000 ft of oil column. Sandy shales are ranked next, with a 100- to 500-ft capacity, whereas very shaly siltstone and sandstone, anhydrite-filled dolostones, and cemented sandstone each have between 50 and 100 ft of capacity. In addition, immobile fluids, such as tar, bitumen, and asphalt, can be effective seals and barriers. For example, the updip seal for the supergiant Coalinga field, California, is tar- and asphalt-filled sandstone and conglomerate.
Fig. 1.3 – (a) Air/mercury capillary pressure curves of seal lithologies. The ordinate is a log scale. (b) Typical seal lithologies. (c) Sneider et al. classification of seals and flow barriers. The hyrdrocarbon column that can be held assumes that the fluids in the reservoirs are 35° API oil and saline water. Types are keyed to Figs. 3a and 3b. Figure courtesy of Sneider Exploration Inc.
Whereas structure and stratigraphy most often define the reservoir trap or top of the reservoir, factors controlling the base of a petroleum reservoir include seal capacity, spill point, capillary forces, and hydrodynamics. The reservoir base is defined as the zero capillary pressure level, also referred to as the free-water level. Reservoir height is determined by the height from seal to spill point, if seal capacity is large enough. If the height is less than that from seal to spill point, seal capacity or hydrocarbon charge will determine the position of the reservoir base.
Subsurface groundwater is seldom static. Differences in water density, structural tilting, tectonic forces, and other factors combine to create a difference in hydrodynamic potentials that result in the movement of fluids in the subsurface. Fluid movement is controlled by the fluid potential as defined by Hubbert and illustrated by the following formula:
in which Z = elevation relative to a datum (sea level), P = measured static pressure, and ρ = density of the fluid (water).
A potentiometric map is a map that connects points of equal fluid potential within an aquifer. If the potentiometric surface is not horizontal, the aquifer will flow in the direction of lowest potential. Calculating fluid potential requires accurate subsurface pressure measurements in the aquifer. The flow of water under a reservoir will cause the zero-capillary-pressure level to tilt, referred to as a tilted water table. The degree of tilt can be estimated from the following equation.
in which change in reservoir height for distance x (tilt in water table), ρw = density of water in aquifer, ρo = density of hydrocarbon, and change in potentiometric surface for distance x.
During primary development, the economic base of the reservoir is normally defined as the producing oil/water contact, or the level at which oil and water are first coproduced. This level is generally assumed to be at approximately 50% water saturation, according to relative permeability considerations. During tertiary development, the economic base of the reservoir may be defined as the level of zero oil saturation. However, because pore size can vary with stratigraphy, 50 or 100% water saturation may not occur at the same height throughout the reservoir. The economic base of the reservoir will not be horizontal.
Defining the base of a reservoir is often made difficult by the presence of residual-oil and tar zones below the producing oil/water contact. Residual-oil and tar zones can be as thick as 300 ft and are thought to form by a variety of processes, including biodegradation of hydrocarbons, flushing of part of the oil column as a result of hydrodynamic forces, and remigrating of hydrocarbons because of leaky seals and structural tilting. The presence of this material may indicate that the reservoir is in an imbibition rather than a drainage mode. Estimates of the original oil in place will depend on which capillary pressure model is assumed. An incorrect model can lead to large errors in estimates of the original oil in place.
Internal Geometry-Reservoir Architecture
Information that defines the external reservoir geometry, including trap configuration, seal capacity, and the base of the reservoir, is of primary importance during exploration and initial development of a reservoir. As development continues, reservoir architecture becomes key to predicting the distribution of reservoir quality so that primary- and secondary-development programs can be planned. Reservoir architecture is important because it provides a basis for distributing petrophysical properties in 3D space. In most cases, this operation is done by relating lithofacies to petrophysical properties because lithofacies can be directly linked to depositional processes for prediction.
We commonly correlate lithofacies from one well to the next by assuming a degree of horizontality and continuity of similar facies. This approach leads to images with highly continuous lithofacies and porosity zones. Many depositional facies, however, are known to be highly discontinuous laterally and vertically, and correlating similar lithofacies from one well to the next can lead to unrealistic displays of reservoir architecture. Modern correlation methods rely more on the chronostratigraphic approach, one that uses time stratigraphy rather than lithostratigraphy to determine continuity between wells. This approach is referred to as sequence stratigraphy and provides a basis for correlating time surfaces between which lithofacies are distributed systematically in a predictable pattern.
Sequence StratigraphySequence stratigraphy is a chronostratigraphic method of correlation. It groups lithofacies into time-stratigraphic units between chronostratigraphic surfaces, which are sometimes defined by unconformities and facies shifts. A key premise is that the surfaces are formed in response to eustatic sea-level changes of various scales and periodicity (eustatic refers to worldwide sea-level changes affecting all oceans). It is thought that eustatic sea-level changes can be linked to climatic changes and to eccentricities in the Earth’s orbit. The Russian astronomer Milanovitch defined cyclic variation in the shape of the Earth’s orbit and in the tilt and wobble of the axis. These Earth cycles are precession (19,000 to 23,000 years), obliquity (41,000 years), and eccentricity (1,000,000 to 4,000,000 years) and are thought to cause changes in the Earth’s climate, resulting in more or less water trapped as ice at the poles. The trapping or release of water from the ice caps is thought to result in sea-level rise and fall, referred to as eustasy.
Sequence stratigraphy is important for reservoir modeling because a chronostratigraphic surface is present in every well in the reservoir. This fact provides geologists with a powerful tool for correlating packages of lithofacies between wells. A more realistic image of reservoir architecture can, therefore, be constructed by distributing lithofacies and petrophysical properties within a detailed sequence-stratigraphic framework.
The terminology of sequence stratigraphy, like most geologic terminology, is complex and constantly evolves as concepts and ideas change. It is the intent here to present a basic overview of the terminology to provide the reader with sufficient understanding to communicate with reservoir geologists. The classic Exxon model (see Fig. 1.4) shows the terminology used in siliciclastic stratigraphy. The terms used in carbonate stratigraphy, although similar, have important differences because carbonates are organic in origin and clastics are terrigenous in origin. The terminology used in carbonate stratigraphy is illustrated in Fig. 1.5.
Fig. 1.4 – Exxon idealized depositional-sequence cross-sectional model for siliciclastic sediments. Sequence boundary (SB), LST composed of basin-floor fan (bf), slope fan (sf), and lowstand prograding wedge (LSW), TST, HST, and shelf-margin wedge (SMW). Maximum flooding surface (mfs) separates the TST from the HST. Taken from Kerans and Tinker.
Fig. 1.5 – Hierarchy of carbonate sequence-stratigraphic terminology in a cross-sectional view. An HFC is composed of a flooding event (transgression) and a shallowing event (prograding). HFSs are composed of a retrogradational cycle set that makes up the TST and prograding cycle set that makes up the HST. Composite sequences are composed of a basal retrogradational set of HFSs and an upper set of progradational HFSs/ The dark shading indicates transgressive units, and the light shading indicates progradational units. See Kerans and Tinker.
Repeated eustatic sea-level cycles result in the vertical stacking of HFC. Cycles are stacked vertically into retrogradational cycles, aggradational cycles, and progradational cycles. Retrogradational cycles are formed when the eustatic sea-level rise for each cycle is much more than the fall. The shoreline will move farther landward with each successive cycle, a pattern described as back stepping or transgression. The sediments are said to be deposited in the transgressive system’s track (TST). Aggradational cycles are formed when eustatic rise and fall are equal, and the resulting facies will stack vertically. These cycles are defined as part of the highstand system’s tract (HST). Progradational cycles form when the eustatic fall for each cycle is greater that the rise. The shoreline for each successive cycle will move seaward, a pattern described as progradation or regression, and the sediments are said to be deposited in the HST. Sediments deposited when relative sea level is lowest are said to be deposited in the lowstand system’s track (LST). The sequence from TST to HST to LST defines a larger-scale sea-level signal referred to as a high-frequency sequence (HFS). The turnaround from transgression to aggradation and progradation is termed the maximum flooding surface (MFS). HFSs can be packaged into longer-term signals called composite sequences on the basis of the observation that they tend to stack vertically into transgressive, progradational, and lowstand sequences.
The terminology and duration of the cycle hierarchies estimated by Goldhammer are shown in Fig. 1.6. HFC, HFS, and composite sequences are commonly referred to as fifth-, fourth-, and third-order cycles, respectively, with characteristic durations ranging from 0.01 to 10 million years (m.y.). First- and second-order cycles, or supersequences, have much longer durations, from 10 to more than 100 m.y., and are related more to structural movements than to eustasy. These major sequences are useful not only for regional but also for worldwide correlations. The durations of all these cycles and sequences are approximate and are based on radiogenic dates extrapolated to the numbers of cycles and sequences of various scales.
Fig. 1.6 – Terminology of cycle hierarchies and order of cylicity from Goldhammer.
IntroductionA basic overview of carbonate-reservoir model construction was presented by Lucia, and much of what is presented herein is taken from that book. Carbonate sediments are commonly formed in shallow, warm oceans either by direct precipitation out of seawater or by biological extraction of calcium carbonate from seawater to form skeletal material. The result is sediment composed of particles with a wide range of sizes and shapes mixed together to form a multitude of depositional textures. The sediment may be bound together by encrusting organisms or, more commonly, deposited as loose sediment subject to transport by ocean currents.
Depositional textures are described using a classification developed by Dunham. The Dunham classification divides carbonates into organically bound and loose sediments (see Fig. 1.7). The loose sediment cannot be described in simple terms of grain size and sorting because shapes of carbonate grains can vary from spheroid ooids to flat-concave and high-spiral shells having internal pore space. The grain content of a grain-supported sediment composed of shells can be as little as 30% of the bulk volume because the shells occupy less space than spheroids. Loose sediment is, therefore, described on the basis of the concept of mud vs. grain support. Mud refers to mud-size carbonate particles, not to mud composed of clay minerals. Grain-supported textures are grainstone, which lacks carbonate mud, and packstone, which contains mud. Mud-supported textures are referred to as wackestone, which contains more than 10% grains, and mudstone, which contains less than 10% grains. To complete the description, generic names are modified according to grain type such as "fusulinid wackestone" or "ooid grainstone."
Enos and Sawatsky measured the porosity and permeability of modern carbonate sediments. The average porosity and permeability of grainstone are approximately 45% and 10 darcies, respectively, whereas the average porosity and permeability of a wackestone are approximately 65% and 200 md, respectively. The higher porosity in mud-supported sediments is caused by the needle shape of small aragonite crystals that make up the carbonate mud, and the decrease in permeability is caused by the small pore size found between mud-sized particles. An important observation based on this data is that all carbonate sediments have sufficient porosity and permeability to qualify as reservoir rocks.
With modifications, the Dunham approach can be used to characterize the petrophysical properties of carbonate rocks. The classification must be modified, however, because diagenesis significantly alters the depositional texture, and a rock-fabric classification that incorporates diagenetic overprints and that can be linked to petrophysical properties is required. The classification proposed by Lucia is designed for this purpose (see Fig. 1.8). All pore space is divided into interparticle (intergrain and intercrystal) and vuggy (pore space within grains/crystals and much larger than grains/crystals). Interparticle pore space is classified with the Dunham classification approach. Instead of grain support vs. mud support, however, grain- and mud-dominated are used as a basic division. Grain-dominated fabrics include grainstone and grain-dominated packstone. Mud-dominated fabrics include mud-dominated packstone, wackestone, and mudstone. The packstone class is divided into grain- and mud-dominated packstone because the petrophysical properties of grain-dominated packstone are according to grain size, whereas mud size controls the properties of mud-dominated packstone. Diagenetic reductions in porosity by cementation and compaction are reflected in the amount of interparticle porosity.
Fig. 1.8 - Lucia classification of carbonate pore space.
Dolostones are classified similarly if the precursor limestone fabric can be determined. The principal petrophysical difference between limestones and dolostones occurs in mud-dominated fabrics. Limestone-mud-dominated fabrics have mud-sized particles (< 20 μm) and very small pores. Dolomitized mud-dominated fabrics have crystal sizes ranging from 10 μm or less to more than 200 μm, with corresponding pore sizes. Dolomitization must, therefore, improve reservoir quality by increasing particle and pore size.
The classification of vuggy pore space is an important aspect of rock-fabric classification that is not found in the classification of depositional textures. Vuggy pore space is divided into two groups on the basis of how the pore space is connected. Separate vugs are connected to each other through interparticle pore space, and touching vugs are connected directly to one another. Selective dissolution of grains, such as ooids or skeletal material, and intrafossil porosity are types of separate vugs. Because separate-vug porosity is poorly connected, it contributes less to permeability than would be expected if the porosity were located between the particles. Touching vugs are commonly formed by mass dissolution and fracturing. These processes can form reservoir-scale vuggy pore systems that dominate the performance of carbonate reservoirs.
Depositional EnvironmentsCarbonate sediments accumulate in depositional environments that range from tidal flats to deepwater basins. Most carbonate sediments originate on a shallow-water platform, shelf, or ramp and are transported landward and basinward. "Platform" is a general term for the shallow-water environment, whereas "shelf" and "ramp" refer to topography—shelves with flat platform tops and steep foreslopes and ramps having gently dipping platform tops and slightly steeper foreslopes.
The lateral distribution of depositional environments reflects energy levels, topography, and organic activity. These changes can be related to the geometry of the carbonate platform. Ocean currents are produced by tides and waves and are concentrated at major topographic features, such as ramp and shelf margins, islands, and shorelines. Grainstones and boundstones are concentrated in the areas of highest energy, commonly at ramp and shelf margins. Sediment is transported from the shelf edge onto the shelf slope and into the basin environment. This transport occurs primarily during highstand and results in progradation of the shelf margin. Calcareous plankton is deposited in the basinal environment as well. Sediment is also transported landward onto the shoreline, creating tidal-flat deposits that prograde, primarily during regression. Transgressive sediments are generally wackestones and mudstones at all locations because rising sea level typically creates a low-energy depositional environment.
The combination of organic activity, ocean currents, topography, and eustasy produces a typical facies progression from land to basin during highstand: peritidal, middle ramp, ramp crest, ramp shelf or slope, and basin, as shown in Fig. 1.9. The peritidal facies, composed of tidal-flat-capped cycles, normally defines the most landward position of an HFC. The cycles are formed by filling accommodation space and depositing sediment above sea level by transporting carbonate sediment onto the mud flat with tidal and storm currents. Tidal-flat sediments are key indicator facies because they define sea level. The tidal-flat environment is divided into the intertidal zone overlain by the supratidal zone. Sediment in the intertidal zone is characterized by burrowed, pelleted, muddy sediment. Algal laminates are concentrated at the boundary between the intertidal and supratidal zones. The supratidal zone is easily identified by its characteristic irregular lamination, pisolites, mud cracks, intraclasts, and fenestral fabrics. The supratidal zone is sometimes called a "sabkha" environment, referring to the extensive evaporitic flats on the western shore of the Persian Gulf.
In arid climates, evaporite deposits may form by precipitation of gypsum (CaSO4 •2H2O) or anhydrite (CaSO4) from evaporation of seawater trapped on or in the supratidal zone. Halite (NaCl) is normally found in isolated basins similar to the Dead Sea. Sulfate minerals are found as deposits in hypersaline lakes and as beds and crystals within the peritidal sediments. Sulfates found within carbonate sediments are properly classified as diagenetic minerals and cannot be used to describe the depositional environment, but sulfate deposited out of a standing body of water, is properly classified as sediment and is characteristic of the depositional environment as well as the climate. For sulfate to precipitate from seawater, three conditions must be met:
- The body of seawater must be highly restricted from the ocean.
- The hypersaline water must be able to escape either by returning to the ocean or by seeping into the underlying sediment (seepage reflux), otherwise large volumes of Halite will precipitate forming a bed of salt.
- The climate must be sufficiently arid to allow the seawater to evaporate to at least one-third its original volume.
The middle-ramp facies is characterized by quiet-water deposits typically composed of skeletal wackestones and mudstones. Burrowing organisms churn the muddy sediment and produce fecal pellets that, together with skeletal material, comprise the grain fraction of the sediment. During highstand, accommodation space may be reduced and water depth lessened to the point at which wave and storm energy increase, lime mud is winnowed out, and a packstone texture is produced. The increase in grain content, possibly capped by packstone, is used to define sea-level changes in this environment.
The ramp-crest facies is characterized by high-energy deposits, typically grainstones and packstones. The classic upward-shoaling succession of wackestone to packstone and grainstone typifies this environment. Typical high-energy deposits are as follows:
- Shelf-margin, tidal-bar, and marine-sand belts.
- Back-reef sands associated with landward transport of sediment for fringing reefs.
- Local middle-shelf deposits associated with gaps between islands or tidal inlets forming lobate tidal deltas.
Packstones are typically churned by burrowing organisms and show no evidence of current transport. Grainstones are commonly crossbedded, often in multiple directions, indicating deposition out of tidal currents. Reefs are also found in the ramp-crest facies. The term reef has been much misused in the petroleum industry. At one time, all carbonate reservoirs were referred to as reefs, and the term is commonly used today to describe any carbonate buildup. However, the term should be restricted to carbonate bodies composed of bindstone, bafflestone, and associated float- and rudstones.
The outer-ramp, or slope, facies is formed by transport of shelf-margin and inner-shelf sediment onto the shelf slope. Sediments are typically wackestones and mudstones, along with occasional packstones and grainstones, in channels associated with density flows into the basin. On steep slopes, sediments may be dominated by sedimentary breccias and debris flows produced by the collapse of a steep shelf margin. The basin facies is typically composed of thin-bedded, quiet-water lime muds that contain planktonic organisms. Wackestones are often punctuated by debris and grain flows. Classic turbidite textures and cycles are also found in basinal carbonate deposits.
Because all carbonate-reservoir rocks have undergone significant diagenesis, understanding their diagenetic history can be as important as understanding their depositional history. Modern carbonate sediments have sufficient porosity and permeability to qualify as reservoir rocks. Many ancient carbonates, however, lack the porosity and permeability needed to produce hydrocarbons economically. Loss of reservoir quality occurs when sediment changes after deposition. The processes that cause these changes are referred to as diagenetic processes, and the resulting fabric is often referred to as the diagenetic overprint.
Carbonate diagenetic processes include calcium-carbonate cementation; mechanical and chemical compaction; selective dissolution; dolomitization; evaporite mineralization; and massive dissolution, cavern collapse, and fracturing. Whereas sedimentation is a one-time event, diagenesis is a continuing process, and diagenetic processes interact with one another in time and space. Thus, a sequence of diagenetic events may be extremely complicated and the pattern of diagenetic products difficult to predict if they are not related to depositional patterns.
The process of diagenetic overprinting of depositional textures must be understood to predict the distribution of petrophysical properties in a carbonate reservoir. To this end, diagenetic processes are grouped according to their conformance to depositional patterns. Calcium-carbonate cementation, compaction, and selective dissolution form the first group. These processes have the highest conformance to depositional patterns. Reflux dolomitization and evaporite mineralization form the second group. Although these processes depend greatly on geochemical and hydrological considerations, they are often predictable because they can be related to tidal-flat and evaporite depositional environments. Massive dissolution, collapse brecciation and fracturing, and late dolomitization form the third group. These processes have the lowest conformance to depositional patterns, and their products are quite unpredictable.
Calcium-carbonate cementation, compaction, and selective dissolution can often be linked to depositional textures. Because calcium-carbonate cementation begins soon after deposition, it is often connected to the depositional environment. It continues as the sediment is buried, so the distribution of late cements is often unpredictable. Cementation fills pore space from the pore walls inward, reducing both pore size and porosity in proportion to the amount of cement. Compaction and associated cementation are a function of depositional texture and the time-overburden history. Compaction is both a physical and a chemical process resulting from increased overburden pressure caused by burial. Textural effects include porosity loss; pore-size reduction; grain penetration, breaking, and deformation; and microstylolites. Compaction does not require the addition of material from an outside source and is often related to depositional textures. Experiments and observations have shown that mud-supported sediments compact more readily than those that are grain-supported.
Selective dissolution occurs when one fabric element is selectively dissolved in preference to others. Carbonate sediments are composed of three varieties of calcium carbonate—low-magnesium calcite, high-magnesium calcite (magnesium substituted for some calcium in the crystal lattice), and aragonite. Aragonite, in particular, is an unstable form and is rarely found in carbonate rocks. Grains composed of aragonite tend to be dissolved, and the carbonate is deposited as calcite cement. This distribution of aragonite grains can be predicted on the basis of depositional models.
Dolostone (a rock composed of dolomite) is an important reservoir rock. The composition of dolomite is CaMg(CO3)2 , and it is formed by replacement of calcite and by occlusion of pore space. In the following dolomitization equation, x = the amount of carbonate added to the rock in excess of the amount in the sediment.
A main source of magnesium is thought to be modified seawater circulating through the sediment in response to various hydrodynamic forces, including density, elevation, and temperature differences. Many pore volumes of dolomitizing fluid are needed to convert a limestone to a dolostone. Therefore, the hydrologic system must be understood for the distribution of dolostone to be predicted. The hypersaline reflux model can be used to predict dolomite patterns because it can be linked to an evaporitic environment. In an arid climate, seawater is trapped in tidal-flat sediment and hypersaline lakes and is concentrated through evaporation, producing a dolomitizing fluid. A hydrodynamic potential is created because the evaporated fluid is denser than seawater or groundwater and the tidal flats are at a slightly higher elevation than sea level. As a result, the hypersaline fluid will reflux down through the underlying sediment, converting it to dolomite. The geometries of dolostone bodies formed by this mechanism can be predicted if the distribution of evaporitic tidal-flat facies is known.
The hypersaline reflux model also accounts for the addition of CaSO4, commonly an evaporite mineral in carbonate reservoirs. CaSO4 is most commonly formed near the Earth’s surface in its hydrous form, gypsum (CaSO4•2H2O). However, at higher temperatures, the stable form is anhydrite CaSO4, which is the form most commonly found in carbonate reservoirs. In some locations, tectonics has uplifted carbonate strata into a cooler temperature, and anhydrite has hydrated, forming gypsum.
Four types of anhydrite are commonly found in dolostone reservoirs. Pore-filling anhydrite is typically composed of large crystals filling interparticle and vuggy pore space. Poikilotopic anhydrite is found as large crystals with inclusions of dolomite scattered throughout the dolostone. They are both replacive and pore filling. Nodules of anhydrite are composed of microcrystalline anhydrite, often showing evidence of displacing sediment. They make up a small percentage of the bulk volume and have little effect on reservoir quality. Bedded anhydrite is found as beds composed of both coalesced nodules and laminations. Anhydrite beds are flow barriers and seals in reservoirs.
Massive dissolution, collapse brecciation and fracturing, and late dolomitization are the most unpredictable diagenetic processes. Massive dissolution refers to nonfabric selective dissolution, including cavern formation at any scale, collapse brecciation and fracturing, solution enlargement of fractures, and dissolution of bedded evaporites. This process is thought to be most commonly related to the flow of near-surface groundwater, referred to as meteoric diagenesis but often included under the general heading of karst. The products of this diagenetic environment are controlled by precursor diagenetic events, tectonic fracturing, and groundwater flow and show little relationship to depositional environments. Reservoirs of this type are, therefore, difficult to model.
IntroductionSiliciclastic rocks are composed of terrigenous material formed by the weathering of pre-existing rocks, whereas carbonate rocks are composed principally of sediment formed from seawater by organic activity. Clastic sediments are composed of grains and clay minerals, and siliciclastic sediments are first classified according to grain type. The three basic grain types are quartz, feldspar, and rock fragments, and the end members are quartz sandstone, arkosic sandstone, and lithic sandstone, as shown in Fig. 1.10a. Second, siliciclastics are described in terms of grain size (Fig. 1.10b). Grain-size classes include gravels (boulder size to 2 mm in diameter), sands (2 to 0.0625 mm), and mud, which includes silts (0.0625 to 0.004 mm) and clay (< 0.004 mm). Mixtures are described with a modifying term for a less-abundant size, such as clayey sandstone, sandy siltstone, or muddy sandstone (Fig. 1.10c). Mudstone, composed of clay and silt, is not to be confused with carbonate mudstone. In this classification, mud and clay are terms used to indicate size, not mineralogy.
The type, amount, and habit of clay minerals in siliciclastic rocks are important characteristics (see Fig. 1.11). Clay minerals are sheet-structure silicates that have a profound impact on the petrophysical and production properties of sandstones. They can be deposited as muddy sediment or formed during burial by diagenetic processes (sometimes referred to as authigenic clay). Common clay minerals are kaolinite [Al2Si2O5(OH)4], illite [KAl3Si3O10(OH)2], chlorite [(Al, Mg, Fe)Si4O10(OH)2], and smectite or montmorillonite [(Al, Mg)Si4O10(OH)2].
The mineralogy of the clay minerals has a great effect on pore size and petrophysical properties. For example, kaolinite-cemented sandstones are more permeable than are illite-cemented sandstones because kaolinite tends to form boolets that reduce pore size and porosity, whereas illite tends to form thin threads that reduce pore size with little effect on porosity. Clay minerals are also known to hinder inflow into the wellbore. Smectite, for example, tends to swell, reducing permeability when in contact with fresh water. Kaolinite is known to get dislodged by high-velocity flow and plug pore throats near the wellbore, reducing permeability. The iron in chlorite is commonly released during acid treatments, plugging perforations.
Depositional EnvironmentsThe following discussion is taken primarily from Galloway and Hobday. Grain type, size, and sorting, as well as other characteristics of siliciclastic reservoirs are most commonly controlled by the depositional environment. Many siliciclastic reservoirs are geologically young, and the sediment has undergone only moderate compaction and cementation. Therefore, diagenesis is not a major factor, and petrophysical properties can be predicted on the basis of sedimentology.
Siliciclastic sediments are transported and deposited by wind and flowing water. On land, clastics are deposited by wind and stream flow. In the marine environment, they are transported by tidal, wave, ocean, and density currents. Land-based environments are grouped into alluvial-fan, fluvial, and eolian systems. Ocean-center environments include delta systems and barrier bars, which are transitional between land and marine environments, and shelf, slope, and basinal systems, which are marine (see Fig. 1.12).
Fig. 1.12 – Range of sandstone depositional systems that typically host hydrocarbon resources.
Alluvial fans are conical, lobate, or arcuate accumulations of predominately coarse-grained clastics extending from a mountain front or escarpment across an adjacent lowland. Some fans terminate directly in lakes or ocean basins as fan deltas, which generally show some degree of distal modification by currents or waves. Most sediment is deposited by stream and debris flow. Stream flow is commonly confined to one or two channels but may spread across the fan as sheet-flow. Debris flows result when clay and water provide a low-viscosity medium of high yield strength capable of transporting larger particles under gravity. Wave and tidal currents modify the distal terminations of fans that build into lakes or the ocean, improving sorting and reservoir quality.
Eolian deposits are typically fine- to medium-grained, well-sorted, quartzose sand with pronounced crossbedding. The sand is transported and deposited by wind currents, which are the most effective agents for sorting clastic particles. Hot, arid regions are the most favored locales for eolian accumulation. Eolian environments can be divided into dune and interdune facies. Dunes are large bed forms that come in an array of forms. Barchans, barchanoid ridges, and transverse dunes form in response to essentially unidirectional winds. Longitudinal dunes arise from varying wind directions. Draas comprise large stellate rosettes with a high central peak and radiating arms and form in response to intense, multidirectional wind systems. The interdune environment is generally a broad, featureless plain covered by lag gravels resulting from deflation (erosion). Deposition in the interdune area results from rainfall in desert highlands, promoting ephemeral streams that deposit sediment in streambeds and small alluvial fans. Flooding may produce interdune braided-stream deposits. Ponding of water between dunes can create lakes that can precipitate evaporite minerals if the groundwater is sufficiently saline.
Fluvial systems are a collection of stream channels and their floodplains. The channels are sinuous (meandering), with the degree of sinuosity increasing seaward. Braided streams are the result of sand-rich channels. Channel deposits are composed of sand bars and lag deposits. The point bar, a major feature of a high-sinuosity channel, forms by lateral accretion of sediment in the lower-energy, leeward side of a meander. Deposition normally occurs during the ebbing phase of a flood. The highest energy, found in the channel proper, erodes the channel bank, causing the channel to shift constantly; lag deposits are characteristic of the channel. Abandoned channels are commonly clay filled.
Floodplain deposits are deposited as levees, crevasse splays, and flood-basin sediments. Levee deposits are fine sand, silt, and clay deposited along the margins of the channels, when decelerating water rich in suspended sediment spills over the banks during flood stage. Crevasse splays are formed when local breaches in the levees funnel floodwater into near-channel parts of the flood plain. These sediments tend to be highly heterogeneous, composed of sand of variable size, plant debris, and mud clasts. Flood-basin deposits are broad, clay-rich sediments that have been reworked by burrowing animals, plant growth, and pedogenic (soil-forming) processes.
Delta systems form when a river transporting sediment enters a standing body of water, commonly an ocean or a lake, and consist of both fluvial and marine sediments. The depositional architecture of a delta system is characteristically progradational and may fill a small basin. The combination of fluvial and marine processes creates a unique facies assemblage and reservoir architecture. Deltaic sediments are deposited as channel fills, channel-mouth sands, crevasse splays, and delta-margin sand sheets. Together, these facies compose a delta lobe, which is a fundamental building block of a delta system. Delta systems are divided into fluvial-, wave-, and tidal-dominated deltas according to major energy type. Each system has a unique depositional architecture.
Shore-zone systems, excluding deltas, compose a narrow transitional environment that extends from wave base (≈50 ft of water) to the seaward edge of the alluvial coastal plain. They include shoreface, beach, barrier, lagoon, and tidal-flat facies. These systems are supplied principally by onshore transport of river-derived and shelf sediments. Sands are concentrated in barrier-island complexes and tidal sand bodies, with finer sediment landward. Accretion of beach ridges seaward can form a sheetlike sand body referred to as a strandplain sand. The "shoreface facies" refers to that part of the shore zone that is below the zone of wave swash. It is commonly divided into lower-, middle-, and upper-shoreface deposits partly on the basis of water depth and associated energy levels, the highest energy level being the surf zone (upper shoreface). Beach facies includes wave swash and dune zone, all deposited above mean tide. The barrier is formed by aggradation or by progradation of shoreface sands seaward. The lagoon facies, located behind the barrier, is generally composed of clay and fine sand. The barrier may be breached during storms, allowing tidal currents to transport coarser sediment from the ocean into the lagoon, forming tidal deltas.
Shelf systems are broad, deepwater platforms covered by terrigenous sediment. Sediment distribution is controlled by ocean currents, including tidal, wave, storm surge, and density. Facies are defined by bed form and include sand ribbon, wave, ridge, storm, and mud.
Slope and basin systems are found in the relatively deep water beyond the shelf break. Deposition is characterized by the dominance of sediment transport by gravity and density flow, although pelagic settling also occurs. The upper slope is typically a zone of sand remobilization and bypass, with characteristic erosion and channel cutting; the lower slope and basin floor are sites of deposition. Regionally, grain size is the coarsest in the upper slope and decreases in the basin-floor direction. Slope and basin systems are typically distinguished from other systems by their fining-upward-graded bedding, which results from grain settling from a suspended sediment load. Submarine fans are typical slope and basin-floor deposits. Fed from point sources, such as river mouths or submarine canyons, they receive the bulk of their sediments from turbidity currents, a density current produced by sediment-rich water. The upper-fan environment is characterized by feeder channels or canyons that serve as sediment conduits, and sediments are typically coarse gravels. The midfan is characterized by a series of bifurcating, distributary, or braided channels that accumulate massive and pebbly sands showing lenticular bedding, and the lower fan is a smooth, gently sloping surface that received slowly deposited, suspended sediment punctuated by pulses of fine-grained to silt-sized sand. The resulting graded beds are thin, laterally persistent, and monotonously repetitive, commonly through a considerable thickness.
Sandstones are less susceptible to diagenetic change than carbonates. Common diagenetic processes in sandstones are quartz overgrowth cement, carbonate (calcite and dolomite) cement, compaction, grain dissolution and associated formation of clay minerals, and alteration of sedimentary clay minerals. Many of these products can be related to the burial history. Pore space is reduced by mechanical and chemical compaction, resulting in more closely spaced grains and smaller pores, and by quartz overgrowths, which are commonly sourced from chemical dissolution of quartz grains during burial. Carbonate cements are formed by dissolution and precipitation of indigenous carbonate shell material and by importation of carbonate from a more distant source. Iron-rich, pore-filling dolomite is not uncommon.
Feldspar minerals found in rock fragments are commonly unstable in the burial environment and are susceptible to dissolution, forming grain molds similar to those in carbonate rocks. Clay minerals (commonly chlorite) are deposited in the intergrain spaces associated with this dissolution process. Chlorite linings of pore space are thought to inhibit burial cementation and compaction and preserve porosity at depth. Clay minerals are altered during burial diagenesis, and authigenic (diagenetic) clay minerals are formed. Clay-mineral diagenesis causes large increases in surface area and microporosity that, in turn, have large effects on reservoir performance and log analysis.
Reservoir ModelsReservoir models are constructed by distributing petrophysical properties in 3D space with geologic models as a template. Geologic models are constructed by distributing facies within a sequence stratigraphic framework using the systematic distribution of facies within a depositional model as a guide. There are many types of facies, and facies selection is normally based on the question asked. Water depth and changes in sea level are key questions when building a sequence stratigraphic model, and fossil and other grain types together with depositional textures are keys to estimating water depth. Thus, numerous "depositional" facies are commonly described from core material. Once a sequence model is built, however, the problem is to convert the geologic model into a reservoir model by populating the geologic model with petrophysical data. This problem is best resolved by linking petrophysical measurements to rock fabric or texture, and the number of "rock-fabric" facies needed to quantify the geologic model is generally much lower than depositional facies.
Examples of carbonate rock-fabric facies include grain-dominated packstone, medium crystalline dolowackestone, and moldic grainstone. In carbonate reservoirs, rock fabrics include diagenetic overprints as well as depositional textures because diagenesis plays an important role in forming most carbonate pore space. An example of how rock-fabric facies relate to porosity and permeability is illustrated in Fig. 1.13. Particle size, sorting, interparticle porosity, and vuggy porosity are used to characterize pore-size distribution. Petrophysical quantification of a carbonate stratigraphic model is accomplished by mapping rock-fabric facies and interparticle porosity and calculating permeability and initial water saturation from rock-fabric-specific relationships to porosity. An example of a rock-fabric reservoir model is illustrated in Fig. 1.14.
Fig. 1.13 – Relationship between carbonate rock-fabric facies, porosity, and permeability. (a) Crossplot of interparticle porosity and permeability showing rock-fabric fields. (b) Crossplot of total porosity and permeability showing effect of separate-vug (Svug) porosity on permeability of grainstone.
Fig. 1.15 – Relationship between siliciclastic texture, porosity, and permeability in unconsolidated sediments. (a) Porosity varies with sorting and not with grain size. (b) Permeability varies with grain size and sorting.
Fig. 1.16 – Depositional facies model in a basin-floor fan showing grain size, average porosity, and average-permeability data.
Fracture porosity can have a large influence on performance of a carbonate or siliciclastic reservoir. Characterizing and modeling fracture porosity is difficult and is beyond the scope of this discussion. The book on fractured reservoirs by Aguilera is suggested as a good general overview of the problem.
|g||=||acceleration of gravity, ft/sec2|
|hc||=||maximum hydrocarbon column, ft|
|H||=||fluid potential, ft|
|P||=||measured static pressure, psia|
|pc||=||capillary entry pressure, psia|
|x||=||horizontal distance, ft|
|Z||=||elevation relative to a datum, sea level, ft|
|θ||=||angle between horizontal and dip of water table, degrees|
|ρw||=||density of water, g/cm3|
|ρhc||=||density of the hydrocarbon, g/cm3|
|ρo||=||density of oil, g/cm3|
- Hunt, J.M. 1979. Petroleum Geochemistry and Geology, 617. San Francisco: W.H. Freeman and Co.
- Milton, N.J. and Bertram, G.T. 1992. Trap Styles—A New Classification Based on Sealing Surfaces. AAPG Bull. 76 (7): 983-999. http://aapgbull.geoscienceworld.org/content/76/7/983.citation.
- Demaison, G. and Huizinga, B.J. 1991. Genetic Classification of Petroleum Systems. AAPG Bull. 75 (10): 1626-1643. http://aapgbull.geoscienceworld.org/content/75/10/1626.citation.
- Sneider, R.M. et al. 1997. Comparison of Seal Capacity Determinations: Conventional Cores Versus Cuttings. Seals, Traps, and the Petroleum System, R.C. Surdam ed., 12. AAPG Memoir 67. http://archives.datapages.com/data/specpubs/mem67/ch01/ch01.htm.
- Smith, D.A. 1966. Theoretical Considerations of Sealing and Non-Sealing Faults. AAPG Bull. 50 (2): 363-374. http://archives.datapages.com/data/bulletns/1965-67/data/pg/0050/0002/0350/0363.htm.
- Hubbert, M.K.L. 1953. Entrapment of Petroleum under Hydrodynamic Conditions. AAPG Bull. 37 (8): 1954-2026. http://archives.datapages.com/data/bulletns/1953-56/data/pg/0037/0008/1950/1954.htm.
- Schowater, T.T. 1979. Mechanics of Secondary Hydrocarbon Migration and Entrapment. AAPG Bull. 63 (5): 723-760 http://aapgbull.geoscienceworld.org/content/63/5/723.citation.
- North, F.K. 1985. Petroleum Geology, 631. Boston, Massachusetts: Unwin Hyman Inc.
- Von Wagoner, J.C. 1995. Overview of Sequence Stratigraphy of Foreland Basin Deposits: Terminology, Summary of Papers, and Glossary of Sequence Stratigraphy. In AAPG Memoir 64--Sequence Stratigraphy of Foreland Basin Deposits; Outcrop and Subsurface Examples from the Cretaceous of North America, J.C. Van Wagoner and G.T. Bertram ed. http://archives.datapages.com/data/specpubs/memoir64/front/000i.htm.
- Kerans, C. and Tinker, S.W. 1997. Sequence Stratigraphy and Characterization of Carbonate Reservoirs. SEPM Short Course Notes No. 40, 130.
- Goldhammer, R.K. 1991. Hierarchy of Stratigraphic Forcing: Example from Middle Pennsylvanian Shelf Carbonates of the Paradox Basin. Sedimentary Modeling: Computer Simulations and Methods for Improved Parameter Definition, E.K. Franseen, et al., eds. Kansas Geological Survey Bull. 233, 361.
- Lucia, F.J. 1999. Carbonate Reservoir Characterization, 226. New York: Springer.
- Dunham, R.J. 1962. Classification of Carbonate Rocks According to Depositional Texture. in Classification of Carbonate Rocks—A Symposium, W.E. Ham ed., 108. AAPG Memoir No. 1. http://archives.datapages.com/data/specpubs/carbona2/data/a038/a038/0001/0100/0108.htm.
- Embry, A.J. and Klovan, R.E. 1971. A Late Devonian Reef Tract of Northeastern Banks Island, N.W.T. Bulletin of Canadian Petroleum Geology 19 (4): 730-781. http://bcpg.geoscienceworld.org/content/19/4/730.abstract.
- Enos, P. and Sawatsky, L.H. 1981. Pore networks in Holocene carbonate sediments. J. of Sedimentary Petrology 51 (3): 961-985. http://dx.doi.org/10.1306/212F7DF1-2B24-11D7-8648000102C1865D.
- Lucia, F.J. 1995. Rock-Fabric/Petrophysical Classification of Carbonate Pore Space for Reservoir Characterization. AAPG Bull. 79 (9): 1275-1300. http://aapgbull.geoscienceworld.org/content/79/9/1275.citation.
- Beard, D.C. and Weyl, P.K. 1973. Influence of Texture on Porosity and Permeability of Unconsolidated Sand. AAPG Bull. 57 (2): 349-369. http://aapgbull.geoscienceworld.org/content/57/2/349.citation.
- Neasham, J.W. 1977. The Morphology of Dispersed Clay in Sandstone Reservoirs and Its Effect on Sandstone Shaliness, Pore Space and Fluid Flow Properties. Presented at the SPE Annual Fall Technical Conference and Exhibition, Denver, Colorado, 9-12 October 1977. SPE-6858-MS. http://dx.doi.org/10.2118/6858-MS.
- Galloway, W.E. and Hobday, D.K. 1983. Terrigenous Clastic Depositional Systems; Applications to Petroleum, Coal, and Uranium Exploration, 423. New York: Springer-Verlag.
- Galloway, W.E. et al. 1983. Atlas of Major Texas Oil Reservoirs, 139. U. of Texas at Austin, Bureau of Economic Geology.
- Dutton, S.P., Barton, M.D., Asquith, G.B., Malik, M.A., Cole, A.G., Gogas, J., Guzman, J.I., and Clift, S.J. 1999. Geologic and Engineering Characterization of Turbidite Reservoirs, Ford Geraldine Unit, Bell Canyon Formation, West Texas, The U. of Texas at Austin, Bureau of Economic Geology Report of Investigations No. 255, 88.
- Aguilera, R. 1995. Naturally Fractured Reservoirs. Tulsa, Oklahoma: PennWell Publishing Co.fckLR
SI Metric Conversion Factors
|°API||141.5/(131.5 + °API)||=||g/cm3|
|ft||×||3.048*||E − 01||=||m|
|g/cm3||×||1.0*||E + 03||=||kg/m3|
|mm||×||2.54*||E + 01||=||in.|
|psi||×||6.894 757||E + 00||=||kPa|
Conversion factor is exact.