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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 3A – Petrophysics
- 1 Introduction
- 1.1 Definitions
- 1.2 Choosing Tools
- 1.3 Determining Layer Thickness
- 1.4 Determining Lithology and Rock Type
- 1.5 Determination of Porosity
- 1.6 Oil, Gas, and Water Saturation
- 1.7 Fluid Identification and Characterization
- 1.8 Determination of Absolute Permeability
- 1.9 Fractional Flow
- 1.10 How To Put It Into Use
- 2 Nomenclature
- 3 References
- 4 SI Metric Conversion Factors
The term "petrophysics" was coined by G.E. Archie and J.H.M.A. Thomeer in a quiet bistro in The Hague. By their definition, petrophysics is the study of the physical and chemical properties of rocks and their contained fluids. It emphasizes those properties relating to the pore system and its fluid distribution and flow characteristics. These properties and their relationships are used to identify and evaluate hydrocarbon reservoirs, hydrocarbon sources, seals, and aquifers.
The petrophysicist or petrophysical engineer practices the science of petrophysics as a member of the reservoir management team (RMT). (See the chapter on reservoir management in this section of the Handbook.) The petrophysicist provides answer products needed and used by team members, as well as physical and chemical insights needed by other teammates. The reservoir and fluid characteristics to be determined are thickness (bed boundaries), lithology (rock type), porosity, fluid saturations and pressures, fluid identification and characterization, permeability (absolute), and fractional flow (oil, gas, water).
It is easy to define these characteristics and to appreciate their part in the assessment of reserves. The difficult part comes in determining their actual value at a level of certainty needed to make economic decisions leading to development and production. The seven characteristics listed are interdependent (i.e., to properly determine porosity from a wireline log, one must know the lithology, fluid saturations, and fluid types). The science of petrophysics is then used to unscramble the hidden world of rock and fluid properties in reservoirs from just below the Earth’s surface to ones more than four miles deep. The petrophysicist then takes on many characteristics of the fictional sleuth Sherlock Holmes to extrapolate, from the most meager of clues, the true picture of the subsurface reservoir using dogged determination to wrest all possible information from the available data, all the while enjoying the thrill of the hunt.
How does the petrophysicist solve this difficult problem? Archie’s general method is to subdivide the problem into smaller segments and iterate using all data until all data agree. One starting point is to determine rock types (petrofacies) wherein we identify pore type, pore size distribution, pore throat type, and pore throat distribution. When coupled with fluid type, one can establish a capillary pressure model that will lead to understanding in-situ fluid saturations and fluid flow. The discussion of the process is lengthy and is covered here and throughout the Handbook. However, the tools available to the petrophysicist are mud logging (solids, liquids, gasses, volumes, rates, concentrations, and temperature); measurements while drilling (MWD) and logging while drilling (LWD); wireline logging (open- and cased-hole); core sampling [(wireline (percussion and drilled) and whole] and core analysis; and fluid sampling (wireline and/or drillstem tests). This list is arranged in order of the usual acquisition sequence. The economics of a given evaluation may restrict the application of any of these tools.
These topics are discussed in further detail in this and other sections of the Handbook. These chapters explain how to make the necessary measurements and how to ensure that the resulting data are accurate enough. We will now demonstrate how to choose the appropriate tools to determine the required reservoir and fluid characteristics.
Choosing ToolsThe choices of tools for the evaluation program are usually made by the RMT with recommendations from the petrophysicist. Cost and accuracy are usually highly correlated; thus, the team’s choices quickly become one of finding the maximum allowable risk for the minimum cost (time and money) of the evaluation. Table 3A.1 summarizes the typical evaluation program choices and can be used as a reference during subsequent discussions on determination of various reservoir properties.
Determining Layer Thickness
Bed boundaries are usually the easiest of all reservoir properties to measure; however, there are some fatal traps that await the unwary. The geologist’s knowledge of the rock types in the play, in general (and in the well of interest, in particular) can be used. By convention, reservoir thickness is expressed in feet and is rounded to the nearest foot, even though most modern wireline logs are recorded digitally every 6 in. Many of the world’s reservoirs are logged in metric units, and thickness is expressed in meters. In this regime, thickness is rounded to the nearest 0.1 m.
Sands and Shales. The term sand is used generically and can also refer to sandstone or other siliciclastic formations. The term shale is used generically and can also refer to mudrock or claystone. When the reservoir beds are mostly sand [typically low gamma ray (GR)] and shale (typically high GR), then the GR log can usually be used to select bed boundaries. The inflection point of the GR count rate expressed in American Petroleum Institute (API) units is selected as the bed boundary. (See examples in the chapter on nuclear logging in this section of the Handbook.) The choice of which bed thickness is to be determined is usually made by the geologist largely on the basis of pattern recognition skills developed during the play definition. Not all sand beds have low GR levels. If the sand bed contains sizable amounts of potassium feldspar, mica, or volcanic debris, the sands may be as radioactive as the shales and difficult to tell apart. In this case, the spontaneous potentials (SP) log is often used if the well is drilled in water-based mud. Again, the inflection point of the log is used to denote the bed boundary. (See examples in the chapter on resistivity and SP logging in this section of the Handbook.) However, in low-porosity and high-resistivity environments, the SP is suppressed and cannot be relied on as a bed boundary indicator.
Another tool that can be used to mark bed boundaries is the electric (resistivity or conductivity) log. This log is most useful when the shales are water-bearing and the sands are shale-free and hydrocarbon bearing. However, the bed boundary is no longer at the inflection point on the log, but is offset by one-half of the electrode spacing of the tool used to measure resistivity. Each service company has charts to aid the petrophysicist in determining the correct offset, while many wellsite computer products take this offset into account automatically. The finest resolution of all is afforded by electric or acoustic borehole image logs, but these logs are not routinely run because of their expensive acquisition and processing costs. The chapter on specialized logging topics in this section of the Handbook shows examples of borehole image logs. If the well is drilled in oil-based mud, then the SP log is not available and the density/neutron log can be used to define sand from shale. If the density/neutron log is a modern digitally sampled tool, then the inflection point can be used as the bed boundary. If, however, the density/neutron log is an older analog tool, the bed boundary can be offset because of drag settings. Vendor publications are available to aid the user in determining the offset. Acoustic borehole image logs are an option in small boreholes and lightweight oil-based muds. Nuclear magnetic resonance (NMR) logs are also useful in distinguishing zones that have movable fluids from those containing bound fluids (examples are shown in the chapter on NMR logging in this section of the Handbook).
Carbonates. When the reservoir beds are generally composed of carbonates (i.e., limestones and/or dolomites), bed definition becomes more complex. In this case, the presence and absence of porosity defines the reservoir from the seal; thus, the GR log may not be useful in demarking bed boundaries. Likewise, carbonates are generally in a higher resistivity regime, and the SP log is of little use. Thus, in this environment, one relies on a tool sensitive to porosity to delineate the bed boundaries, such as the density, neutron, or acoustic log. Borehole image logs are also useful when the borehole is relatively smooth. Large vugs and washouts invalidate readings from these tools. (The chapter on specialized logging topics in this section of the Handbook includes an example of a borehole image log in a carbonate formation.)
What To Count. Determining gross bed thickness is straightforward; however, determining what part of a given bed contains producible hydrocarbons is tricky. At present, there is no single standard sanctioned by SPE or API as to the definition of, or the method for determining, net pay. One of the more common complications is a result of the small thickness of layers containing hydrocarbons. Some common depositional environments can result in sands and shales being laid down into zones thinner than the resolving power of almost all wireline logs. One cannot count directly what one cannot see. In this case, we settle for thicker averages that mathematically equate to correct fluid volumes (i.e., calculate that from depth X to depth X+30 ft, the ratio of sand to shale is 0.5; thus, it contains 15 ft of reservoir-quality rock in layers too thin to individually resolve). Finally, one can cut a continuous core from the top through the bottom of the reservoir in question and, given the good fortune to recover 100% of the core at the surface, one can use sophisticated core-analysis techniques to determine the thickness of the layers with a precision and accuracy better than any other part of the reservoir remaining in the Earth. Because of the high cost of cutting and analyzing whole core, this method is seldom used, unless no other method can be proven to work.
Determining Lithology and Rock Type
The identification of a bed’s lithology is fundamental to all reservoir characterization because the physical and chemical properties of the rock that holds hydrocarbons and/or water affect the response of every tool used to measure formation properties.
The term lithology is used as a gross identification for a rock layer in the subsurface and uses familiar names such as sandstone (or sand), limestone, dolostone (or dolomite), claystone (or clay), chert, coal, shale (or mudrock), diatomite, halite, anhydrite, gypsum, and tuff. (The preceding list is not exhaustive. For detailed lists, see Deeson) The term rock type is a more detailed description than lithology because it reflects the natural groupings of pore systems that produce recognizable properties used to predict flow properties, volumes, and fluid saturations. Lithology focuses on grains, while rock type focuses on pores. The list of rock types contains more than 250 classifications. * (See the chapter on petroleum geology in this section of the Handbook.) Another term used in the literature is the Greek equivalent "petrofacies." (Another term that is finally dropping from use is the incorrectly named "electrofacies.")
Direct Determination. Obtaining a physical sample of the reservoir is the surest way to unambiguously determine lithology and rock type, but obtaining this physical sample is not always easy. Mud logs are the first choice in wildcat wells, but exact assignment of a rock fragment to a particular depth is not without error. The size of the individual rock sample examined at the surface is rather small because it is limited by the size of drill cuttings and rock strength. Weak rocks, ones without cement, are often reduced to original detrital grain size by the drilling process, making it difficult to determine rock type, but still possible to determine lithology. Once the well is drilled and logged and rock layers are marked for further study, rock samples can be obtained through the use of wireline core takers or sidewall core drills.
Recovery of sidewall samples is not always a sure thing, and we often fail to get rock samples from zones of interest. In a wildcat well with a zone of high interest identified with logs, rock samples, and fluid samples, we can plug back the well several hundred feet, set a whipstock, perform a parallel sidetrack (called a bypass hole), and then take a whole core across the zone of interest. Because the two holes are parallel, we know exactly at which depth to swap out the drill bit with a core barrel. The resulting whole core can be sampled, and sophisticated core analysis can be used to identify the rock type of each zone and determine petrophysical parameters, which are used to refine the formation evaluation from the log data.
Indirect Determination. If no direct rock sample is available in a given zone, log responses must be used alone to simultaneously determine lithology, porosity, and fluid saturations. Rock typing is much more involved and requires the use of commercially available catalogs of analog data or locally collected data to pinpoint petrophysical properties that can be used to refine porosity and fluid-saturation calculations. If, in a given wellbore, one is lucky enough to encounter parts of the desired reservoir below the free-water level, then fluid saturation is known and gross lithology can be determined from routine wireline logs such as density, neutron, and acoustic tools. All wireline service companies provide charts and answer products that convert wireline logging data into lithology; however, few beds are simple homogeneous layers. (See the chapter on Reservoir Geology in this section of the Handbook.) If some of the layers are beneath the resolving thickness of the tool, some average response of the layers, depending on bed and borehole geometry, can be observed. Single layers of salt (NaCl), anhydrite, gypsum, coal, or tuft are easily identified when several feet thick or thicker; however, salt-plugged sandstone can mimic gas-filled clean sandstone, or a very shaly rock type can hide the presence of gas.
Mica or potassium feldspar, when abundant in sandstones, can confuse lithology determination on the basis of the GR response. The more sophisticated GR spectroscopy tools can help to identify the chemical species in a given rock and often can lead to deducing its lithology. (See the chapter on nuclear logging in this section of the Handbook.) However, no single wireline log or set of logs can determine pore size distribution and pore throat size distribution. These data are used to establish rock type, resulting fluid flow characteristics, and other petrophysical parameters needed to determine fluid saturation. If every reservoir in our wildcat well is hydrocarbon filled, the problem of quantification becomes more difficult, particularly when formation water resistivity, Rw, is unknown. In difficult areas, a follow-up well and a whole core, drilled with oil-based mud that is taken high in the hydrocarbon column, must be drilled to guarantee no in-situ water displacement. Subsequent sophisticated core analysis can determine the value of in-situ water salinity. (See the chapter on petrophysical applications in this section of the Handbook). If coring is not an option, a well will have to make a significant amount of water to test. In pressure-depletion reservoirs that never produce much water, the accurate determination of water salinity may never happen if the reservoir is drilled with oil-based mud, negating the use of the SP log.
* Personal communication with R.M. Sneider, R.M. Sneider Exploration Inc., Houston (1990).
Determination of Porosity
The determination of porosity is paramount because it determines the ultimate volume of a rock type that can contain hydrocarbons. The value and distribution of porosity, along with permeability and saturation, are the parameters that dictate reservoir development and production plans. Determination of porosity from a wireline log is only part of the problem, because the values determined in one well must be upscaled into the space between wells. To extrapolate correctly, the team must identify depositional environments and rock types and then have access to analog data sets. Only then can the correct statistical distributions be extrapolated across the reservoir. (See the chapter on geostatistics in the Emerging and Peripheral Technology section of the Handbook.)
If one has access to an undamaged whole core from the reservoir in question, direct measurement of the porosity is possible, if care is taken. Some profess that all cores are damaged by the coring process, thus no accurate assessment of porosity is possible by coring. This author does not agree with that premise. X-ray computerized tomography scans, thin sections, and scanning electron microscope examination can verify that grain contacts are unmoved, authigenic pore linings are undamaged, and heavy-weight drilling fluids and/or particles are absent. Thus, given a satisfactory core, porosity can be determined accurately by several different methods specified in API RP 40.
There are a number of pitfalls to avoid. One pitfall is that cleaning the core of crude and brine must be both thorough and gentle. One must remove all the heavy ends of the crude (typically asphaltenes) but not damage the authigenic minerals. NaCl crystals left from the in-situ brine when the water is removed must also be removed, but the authigenic clay minerals must not be removed or disturbed. Tar must not be removed if it occurs naturally in situ, and NaCl pore linings must not be removed if it occurs naturally in situ. Gypsum, when present, must not be dehydrated during the determination of porosity, and hydroxyl water of clay minerals must not be removed and counted as part of the pore space. Pore space must not be created during the cleaning process by flowing large volumes of fluid through rocks with soluble grains, such as gypsum, anhydrite, limestone, or salt.
Another pitfall to avoid is that some rock samples are mechanically weak and uncompact when brought to the surface and freed from the overburden load. These rock samples must be returned to in-situ conditions of effective stress to return the rock sample to its in-situ value of porosity. Correct procedures to make these measurements have been published by several authors. Typically, stressed porosity measurements are more time consuming and more costly. If the core is subdivided into rock types, empirical correlations between stressed and unstressed measurements on a given rock type can be used to extrapolate to a larger data set.
An additional pitfall is that some sandstones contain fibrous pore-bridging clay minerals. These clay types are fragile and are damaged by most routine methods used to clean the core before porosity determination. When this type of clay is determined to be present, all subsequent core cleaning must be done using critical point drying methods. In addition to the methods defined in API RP 40, NMR spectroscopy methods can be used to determine porosity on small core samples, When care is taken to ensure that the core sample is 100% saturated with water and or liquid hydrocarbon, the NMR method yields an accurate value of porosity. The NMR method for porosity determination can also be used in the borehole using wireline NMR tools with excellent results. The chapter on NMR logging in this section of the Handbook shows examples.
Indirect Determination. Direct determination of porosity by core analysis is the "gold standard" and is used where available to calibrate all indirect measurements. Indirect methods allow leveraging of limited core data to provide more information on areal and vertical variations in porosity when coring is too expensive and/or only partial cores are recovered.
Sands. Patchett and Coalson determined that the density log is the most accurate method to determine porosity when one has knowledge of grain density and fluid density. While this method is standard in production wells, these parameters are often unknown for wildcats. Grain density can change rapidly along the borehole as lithology changes. Fluid types and saturations change more slowly, except at fluid contacts. Thus, we have four unknowns: porosity, grain density, hydrocarbon saturation, and water saturation, and one measurement: bulk density. A statistical method would be used to combine the environmentally corrected log readings from the density, neutron, acoustic, and GR to solve for the four unknowns. Often, a shallow resistivity log is included in the mix, and the acoustic log is dropped. Every logging vendor provides an answer product that uses this type of method, and most larger oil companies have published their own method. If we are certain that we are below the free water level and if we assume that we know the rock type is sand with a grain density of 2.65 g/cm3, the measured density log reading of bulk density can be converted into porosity, as the chapter on nuclear logging in this section of the Handbook shows.
Heterogeneity. Another simplified method is to use the density-neutron crossplot provided by each of the logging vendors. Patchett and Coalson found no benefit to using the density-neutron crossplot over a density log if one used known and variable grain density. The novice often uses a simple method with little regard for changes in rock type, fluid type, or borehole conditions, and the result is considerable error in the determination of porosity. The density log can be quite accurate when logged in ideal to semi-ideal borehole conditions. However, in rugose boreholes, extremely thick mudcakes, or unusual weighting materials in the mudcake (e.g., hematite), the bulk density readings seen on the log will no longer reflect those of the borehole wall, and these readings must be discarded and the value of porosity determined by other methods. The borehole caliper and density correction curves are used to validate the quality of the bulk density readings.
The foregoing discussion on sands provides an answer for porosity that is correct, but it reflects the average porosity over the depth of resolution of the tools (i.e., approximately 3 ft). Sophisticated digital processing can increase the resolution to approximately 1 ft. Thus, when the reservoir is heterogeneous on a scale smaller than 1 ft, one must use other methods to deconvolve the resulting averages into values that reflect the true porosity of the individual rock types. One of the most common heterogeneous reservoirs is the laminated sand-shale sequence, in which the shale layers are often less than 1 in. thick. One published method used to determine the porosity of the sand layers free of the unresolved shale layers is the Thomas-Stieber method. In a sand-shale reservoir in which the shale laminations have a porosity lower than the sand layers, one will consistently understate the value of reservoir porosity if the unresolved shale laminations are not properly accounted for. Furthermore, if one is using porosity-to-permeability transforms, the value of permeability will be underpredicted.
Carbonates. Determination of porosity in carbonates is generally straightforward unless the rock type is one with large vugs (i.e., fist-sized or larger) or fractures. Density-neutron and neutron-acoustic crossplot have been historically useful and accurate when calibrated to core measurements. When the rock types become complex and numerous, then statistical, multiple-log methods that match the number of unknowns to independent log measurements are required. Every logging vendor provides an answer product to produce a reasonable value of porosity when all logs are environmentally corrected and validated. Large vugs can be spotted with borehole image logs (see the chapter on specialized logging topics in this section of the Handbook) and with large diameter cores (see the chapter on relative permeability and capillary pressure in the General Engineering section of the Handbook). With appropriate sampling, the borehole readings can be corrected for the effects of large vugs. Logging tools that investigate larger volumes are given higher weights in the analysis.
Fractured Reservoirs. The dual-porosity system that exists in a fractured matrix reservoir provides a challenge in the opposite direction in that often the overall value of porosity is quite low (2 to 3%). Because most wireline porosity logs have random statistical error of 1 to 2%, the error is as big as the value being measured. Under these conditions, reservoir simulation and history match is the most reliable method to determine storage capacity and reserves, and porosity becomes moot. Borehole image logs are used to locate the fractures and provide probable production intervals.
Oil, Gas, and Water Saturation
The determination of in-situ saturations relies on interpretations of logging devices that read far from the borehole and away from any fluid alterations caused by invasion during drilling.
The workhorse tools are the deep induction and deep laterolog. All other tools such as density, neutron, acoustic, NMR, shallow laterologs, and GR provide readings from the flushed zone that has altered saturations. The most important transform that converts resistivity readings into water saturation is the well-known Archie relationship, which is discussed in the chapter on resistivity and SP logging in this section of the Handbook. The Archie relationship has many unknowns [i.e., porosity (which may have three or four unknowns itself), Rw (resistivity of the in-situ water), m (an empirical fitting parameter between porosity and resistivity, often called Archie’s cementation exponent), and n (an empirical fitting parameter between water saturation and resistivity often called Archie’s saturation exponent)], and one measured parameter, the formation resistivity, often called the true resistivity. Thus, we have six or seven unknowns and one measurement, which is why a standard is needed (but a standard is rarely available).
In most cases, the saturations in a core have been flushed by the mud filtrate and are not representative of the in-situ reservoir value. Only when we drill with oil-based mud and core high in the oil column where the relative permeability to water is quite low (practically zero) do we recover a core with a value of water saturation at in-situ conditions, after we correct for blowdown from dissolved gas and stress effects on the pore volume of the core sample. The result is an accurate value of in-situ water saturation for zones with less than Sw=50%. Even under these ideal conditions, we have to make empirical corrections to our gold standard. The other case that can be used to calibrate Archie’s relationship is when heavy crude or tar does not move when we core. These cores usually have little or no blowdown because there is little or no dissolved gas. The only correction that is needed is for a stress correction to the pore volume; the result is an accurate value of in-situ oil saturation.
Calibration. Because the Archie method relies on so many adjustable and often unknown parameters, a calibration step is required to ensure that saturation values are accurate. The method of choice is calibration to a capillary model, which uses multiple core samples for each rock type to provide statistical precision. For a given rock type, several capillary pressure curves are averaged to provide a capillary pressure vs. saturation relation. With some information about the type of hydrocarbon in the reservoir, this relation can be converted into saturation vs. height above the free water level relation. With this model, we can predict, for a given rock type, the hydrocarbon saturation at any elevation in the reservoir and compare it with that computed from the Archie method. Discrepancies between the methods must be resolved by further study, but typically they result in adjustment to one of the many parameters in the Archie method.
Invaded Zone Saturations. The near-wellbore environment is usually altered by the drilling process in several ways, one of which is mud filtrate invasion as a result of overbalance and/or imbibition. The size of the invaded zone depends on many parameters. Some are overbalance magnitude, mud-fluid-loss parameters, mudcake permeability, formation porosity, formation permeability, and in-situ fluid viscosity. The exact shape of the invaded zone is unknown but is assumed to be cylindrical. (This cylindrical assumption is not as robust when the borehole encounters dipping beds or is drilled as a deviated hole.)
The radial extent of this invaded zone can be determined with multiple-spaced resistivity tools if the invasion process has altered resistivity, unless the depth of invasion is beyond the zone of investigation of the resistivity tool. If one is comfortable that the shallow-reading resistivity device responds solely from the invaded zone, then one can use the Archie relationship to compute water saturation, as discussed previously. One must take care to determine if the n parameter has changed because the invaded zone is on the imbibition cycle, rather than the drainage cycle usually observed deep within the reservoir. NMR is another method that can be used to determine the invaded zone saturation. Wireline NMR tools do not see deeply into the formation and usually read invaded zone values. The chapter on NMR logging in this section of the Handbook shows examples of these responses. Generally, filtrate invasion results from the use of either water-based or oil-based mud. Filtrate invasion from water-based mud into the water leg of a reservoir makes no change in Sw. It remains at 100%.
Water-based mud filtrate invasion into the hydrocarbon leg of the reservoir can dramatically decrease the hydrocarbon saturation caused by imbibition, viscous stripping, and gas dissolution. The measured value of fluid saturations in the invaded zone should not be used to predict the residual hydrocarbon saturation by water displacement within the body of the reservoir because the dynamics of displacement are too different.
In the case of oil-based mud filtrate invasion, water saturation will remain immobile if Sw is less than 50% and mild surfactants are used in the mud. There will be no change in oil saturation in the invaded zone when compared with that deeper in the reservoir, unless extreme overbalance is being used. Shallow resistivity logs and NMR logs can be used to determine oil saturation in the invaded zone. These values can then be extrapolated to similar rock types throughout the reservoir.
Fluid Identification and Characterization
Detection of a change in fluid type in the rocks while drilling is usually straightforward with the use of gas and chromatographic measurements. The chapter on mud logging in this section of the Handbook discusses these methods. Gas shows and oil shows while drilling are time-honored indicators of zones that need further investigation through logs, testers, and cores. In the rare case of gas-bearing, high-permeability rock drilled with high overbalance, gas will be flushed from the rock ahead of the bit, will not be circulated to the surface in the mud, and will not produce a gas show.
Water-Based Drilling Mud. Because hydrocarbons are not always part of a water-based-mud formulation, sophisticated analytical chemical techniques can be used on the oil and gas samples circulated to the surface and captured to determine the properties of hydrocarbons in a given zone penetrated by the drill bit. Occasionally, small amounts of hydrocarbons are added to water-based mud to reduce friction on the drillpipe. This hydrocarbon response must be accounted for in any analysis. Sidewall samples will contain some remaining hydrocarbons when brought to the surface. If promptly wrapped, frozen, and analyzed, the crude remaining in the core can be used to characterize density, gas/oil ratio, viscosity, and other fluid properties. Companion sidewall samples can be analyzed at the wellsite for odor, color, fluorescence, and cut-fluorescence, which can be used to distinguish oil/water and gas/oil contacts. If one is uncomfortable predicting reservoir fluid properties from such a small sample, the zone in question can be sampled with a wireline formation tester or ultimately subjected to a drillstem test. Wireline formation testers are often unsuccessful in obtaining a hydrocarbon sample because of the extent of the invaded zone. The low oil saturation in the invaded zone has a low relative permeability resulting in little oil production and little, if any, movement while being sampled by a wireline tester tool until all of the invaded, water-based fluid has been removed.
The other fluid in the rock of interest is water. The value of the water resistivity in the virgin reservoir is needed to interpret the deep-reading resistivity tools. However, the water-based mud filtrate dilutes the in-situ water, making its characterization problematic. Some authors have proposed a method to tag the mud filtrate with radioactive tritium while coring the reservoir. The resulting core is sampled, its water extracted and analyzed for tritium. The measured concentration of tritium is used with the measured porosity to compensate the fluid properties for the effect of dilution from mud filtrate. Other methods use an uncommon anion as the tagged material to avoid radiation-based methods. The formation tester tool can also be used to obtain a water sample in the water leg of the reservoir. Although the zone is invaded with mud filtrate, we can use the pump-out feature available on all vendors’ tools to pump fluid from the invaded zone into the wellbore until the entire invasion has been removed. At this point, a water sample can be taken. The tester tool has an onboard water resistivity cell that is used to monitor the change in resistivity as the invasion fluid is pumped. When this value no longer changes, we switch over and take a water sample for analysis.
Oil-Based Drilling Mud. The overwhelming presence of oil in this type of mud dilutes the hydrocarbon in the invaded zone to such a point that analysis of the hydrocarbon in sidewall samples can no longer be used to predict hydrocarbon fluid properties. On the other hand, the water phase is now intact and can be sampled and analyzed with usual methods.
To determine hydrocarbon properties, wireline formation testers must be used. Two methods are useful. One method requires that many judiciously placed pressure tests be taken in the wellbore. This will permit the determination of the fluid-pressure gradient and density, which can be used to identify gas, oil, or water. Another method requires the use of the pump-out feature available on all wireline vendor tester tools to pump invaded zone fluid into the wellbore until the invading fluid has been reduced to a sufficiently low value, and then switches the pump to capture fluids in a removable, transportable fluid chamber. The feature of these tester tools that makes this possible is onboard spectrometers that have the ability to discern oil-based mud filtrate from in-situ hydrocarbons that guide the changeover from pumping into the wellbore to the sample chamber. Pressure/volume/temperature laboratories for the required fluid properties can then analyze these fluids. The operation of wireline formation testers is neither cheap nor without risk of tool sticking; thus, some operators choose not to run these wireline tools and opt instead for a drillstem test. All wireline tester tools can be used to take a water sample in the water leg, and this practice is encouraged. Not only are errors in water resistivity reduced, but possible incompatibilities between in-situ water and completion fluids are discovered before completion attempts.
Determination of Absolute Permeability
The "gold" standard for permeability is to make measurements on core samples and to determine permeability with the methods outlined in API RP 40. All other techniques are calibrated back to core measurements. However, because core measurements sample such a minute part of the reservoir, we must rely on techniques that can be applied in a widespread fashion across the reservoir. These methods rely on measurements on sidewall samples, correlation to wireline logging responses, interpretation of NMR logs, wireline formation tester pressure responses, and drillstem tests.
Sidewall Samples. This technique is valid for slightly to unconsolidated sandstone rock types. Carbonate rock types are generally too heterogeneous for small samples to provide any meaningful reservoir-wide value for permeability. Sidewall samples of sandstone rock types are inherently contaminated with drilling mud particles and are of little use for direct measurement of permeability. However, we can inspect the rock sample with a binocular microscope to estimate median grain size, sorting, and degree of consolidation, and to characterize pore fills. With these data, we can develop correlations to permeability on the basis of whole core measurements. An alternative is to disaggregate the sample and determine a grain size analysis with laser light scattering, which can then be correlated to permeability on the basis of whole core analysis.
Wireline Logging Correlations. Permeabilities measured in cores can be correlated to wireline measurements taken in the cored borehole. At various times and places, almost every wireline log has been used to correlate to permeability. The porosity-permeability crossplot is, perhaps, the most used; however, it is subject to considerable error. In select basins, the GR log response can be used to correlate to permeability while, in other basins, the neutron log or acoustic log seems to provide the correlation with least statistical scatter.
NMR Logs. Interpretation of NMR logging responses provides a volumetric distribution of pore sizes. If the pores are assumed to be spherical in shape, a value for permeability can be computed. These size-dependent data have been coupled with NMR pore volumes and NMR fluid saturations to produce an NMR permeability log. The chapter on NMR logging in this section of the Handbook shows examples of these techniques.
Wireline Formation Testers. All wireline tester vendors provide answer products that take the drawdown and buildup pressure vs. time responses and compute mobility. Mobility can be converted into permeability if a value of fluid viscosity is assumed. This permeability must be used with some caution. First, the pressure measurements are made on the borehole wall that has suffered possible drilling damage and pore throat plugging from mud solids. Second, one must take note if the measurement is in an invaded zone with two phases and, hence, the permeability determined is an effective permeability, not an absolute permeability. Depending on rock type and fluid saturations, the effective permeability may be an order of magnitude too small. The chapter on fluid sampling in the General Engineering section of this Handbook presents examples of wireline formation tester responses and derived permeability and the use of these pressure measurements to determine fluid gradients.
Drillstem Tests. These measurements are covered in the chapter on data acquisition and interpretation in the Drilling section of this Handbook.
To predict the fractional flow from a given zone in a wellbore, the absolute and relative permeability of the rock types open to flow in the wellbore must be characterized. Determining the complete relative permeability function vs. fluid saturations measured on cores maintained at reservoir conditions of temperature, pressure, and the use of live reservoir crude is a daunting task. Most reservoirs never have these measurements performed on them. Usually, we take small snippets of these curves and attempt to characterize their entire response with various models. Proof of success is often taken to be a successful history match; others prefer to look for agreement between future predictions and future performance.
Regardless of our ability to measure these parameters in the laboratory, the scaleup to a heterogeneous, faulted reservoir is a challenge of immense proportions. These subjects are covered in the chapter on reservoir simulation in this section and the chapter on relative permeability and capillary pressure in the General Engineering section of this Handbook.
How To Put It Into Use
This chapter is designed to show the reader how to use petrophysics in a general sense—how the many facets of petrophysics are tied together and how they relate to other elements of petroleum engineering. However, there is nothing like examples to show new practitioners how petrophysics really works and how they may put it to use themselves. The chapter on petrophysical applications provides these examples.
|m||=||Archie’s cementation exponent|
|n||=||Archie’s saturation exponent|
|Rw||=||resistivity of the in-situ water, ohm m2/m|
|Sw||=||water saturation, fraction of pore volume|
|X||=||a specific depth|
- Thomas, E.C. 1992. 50th Anniversary of the Archie Equation: Archie Left More Than Just an Equation. The Log Analyst (May–June) 199.
- Deeson, A.F.L. 1973. The Collector’s Encyclopedia of Rocks & Minerals. New York City: Clarkson N. Potter Inc.
- A Catalog of Petrophysical and Geological Properties of Typical Reservoir Rocks. 1995. Houston: Shell Oil Co.
- The World Wide Rock Catalog. 1990. Houston: Reservoirs Inc.
- API RP 40, Recommended Practices for Core Analysis, second edition. 1998. Washington, DC: API.
- Swanson, B.F. and Thomas, E.C. 1980. The Measurement of Petrophysical Properties of Unconsolidated Sand Cores. The Log Analyst (September–October): 22.
- Wei, K.K., Morrow, N.R., and Brower, K.R. 1986. Effect of Fluid, Confining Pressure, and Temperature on Absolute Permeabilities of Low- Permeability Sandstones. SPE Form Eval 1 (4): 413-423. SPE-13093-PA. http://dx.doi.org/10.2118/13093-PA.
- Wawak, B.E. and Campbell, W.L. 1986. Characterization of Clay Fabric Using Critical Point Drying to Preserve Clay Texture and Morphology. Scanning Electron Microscopy 4: 1323.
- Patchett, J.G. and Coalson, E.B. 1982. The Determination of Porosity in Sandstone: Part Two, Effects of Complex Mineralogy and Hydrocarbons. Paper T presented at the 1982 Annual Soc. of Professional Well Log Analysts Symposium, Corpus Christi, Texas, 6–9 July.
- Peeters, M. and Visser, R. 1991. A Comparison of Petrophysical Evaluation Packages: LOGIC, FLAME, ELAN, OPTIMA and ULTRA. The Log Analyst 32 (4): 350.
- Thomas, E.C. and Stieber, S.J. 1975. The Distribution of Shale in Sandstones and Its Effect on Porosity. Paper presented at the 1975 Annual Soc. of Professional Well Log Analysts Symposium, New Orleans, 4–7 June.
- Richardson, J.G., Holstein, E.D., Rathmell, J.J. et al. 1997. Validation of As-Received Oil-Based-Core Water Saturations From Prudhoe Bay. SPE Res Eng 12 (1): 31-36. SPE-28592-PA. http://dx.doi.org/10.2118/28592-PA.
- Holstein, E.D. and Warner, J., H. R. 1994. Overview of Water Saturation Determination For the Ivishak (Sadlerochit) Reservoir, Prudhoe Bay Field. Presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 25-28 September 1994. SPE-28573-MS. http://dx.doi.org/10.2118/28573-MS.
SI Metric Conversion Factors
|bbl||×||1.589873||E − 01||=||m3|
|ft||×||3.048*||E − 01||=||m|
Conversion factor is exact.