Coring and Core Analysis (Core Analysis Reports)

Core Analysis Reports

Core Analysis Report

Plug (Conventional) Analysis

Figure 1 (Conventional core analysis for the CAD No. 1, a Gulf Coast well) shows a computer-generated report of a conventional core analysis of a Gulf Coast well. Both saturations and fluorescences indicate that the zone is oil saturated from top to bottom. A plotted coregraph for the same well is illustrated in Figure 2 (Completion coregraph for the CAD No. 1, a Gulf Coast well). The low permeability zone from 6007 to 6013 ft shows low porosity, higher water, and low oil saturations. This is not an oil-water transition zone, but is the result of a decrease in rock quality accompanied by a decrease in hydrocarbon saturation in the reservoir — and hence in the core.

 

Figure 3   (Permeability and porosity histograms for a Gulf Coast well) offers us computer-generated porosity and permeability histograms for the same core. These provide visual documentation of frequency (percentage of total samples) distribution patterns and median values, as well as arithmetic average porosity and geometric average permeability values. The storage capacity (in porosity feet) and flow capacity (in millidarcy feet) are presented as cumulative curves. If you enter the porosity histogram with a porosity cut-off, for example, at 20%, you will find that 20% of the 35 ft recovered has a porosity of 20% or less. Therefore disregarding samples of 20% porosity or less will result in a loss of 15% of the total storage capacity of the reservoir. Similar information is available from the permeability histogram.

Figure 4 (Porosity versus permeability for a Gulf Coast well) gives us a plot of permeability versus porosity data for the same well. The normal trend is evident; that is, increasing permeability is accompanied by increasing porosity. This curve can be compared to curves from adjacent wells to see if relationships are essentially the same or vary across the field. If similar porosity versus permeability trends are observed, special core data generated in one well can be confidently applied to others. This plot, in conjunction with the histograms, serves as a basis for selection of a suite of cores to be subsequently tested by special core analysis. Certain rock properties trend as a function of permeability, while others trend with porosity; therefore, it is essential that the test suite cover observed ranges of both permeability and porosity.

 

Full Diameter Analysis

Figure 1 (Full diameter core analysis of a West Texas well) presents tabular core data for a full diameter core analysis of a heterogeneous carbonate (dolomite) formation. Two horizontal permeability measurements (maximum and 90 degree), plus vertical permeability and grain density, were run and are reported in this figure.

Figure 2 (Full diameter completion coregraph of a West Texas well) presents the core analysis data graphically for the total interval analyzed. A gamma ray analysis (Core-Gamma) was also run and is included in the results. The gamma ray results can be easily compared to porosity, permeability, and residual saturations, and are available for comparison with a down-hole log of the well for core versus log depth correlation.

The total interval shown is oil saturated. The presence of low permeability horizontal barriers is clearly seen, and the higher permeability and porosity zones to be perforated are easily identified. In thick carbonate reservoirs, failure to recognize the presence of low permeability lateral barriers can result in oil being left unrecovered behind the pipe (Shirer, Langston, and Strong 1978). The zones separated by the low permeability barriers will waterflood at different rates, depending upon the magnitude of permeability. This zonation must be accounted for in reservoir engineering studies.

 

Sidewall Core Analysis

Irregular intervals used for sidewall core sampling reduce the usefulness of a graphical presentation of the sidewall data. Because of this, tabular information, as shown in Figure 1 (Sidewall core analysis), is all that is normally presented. Because sidewall cores are most helpful in soft sandstones, which in turn are often separated by shale barriers, data from multiple zones are often seen in a single report.

Four separate zones of good porosity and permeability are illustrated in Figure 1 . The upper zone is interpreted to be oil productive, but to contain an oil-water contact between 8221 to 8225 ft. This is indicated by the loss of residual oil and increase in total water saturation below 8221 ft. No hydrocarbon odor and no fluorescence were observed in the zone interpreted to produce water.

The zone between 8484 to 8513 ft is interpreted to be gas condensate productive in the upper portion. This overlies an oil column, with an oil-water contact below 8508 ft.

The lower two zones are both interpreted to be water productive. This interpretation is based on the existence of low to zero oil saturation, high total water content, and no odor or fluorescence.

Several pieces of data unique to sidewall analysis are shown. The column "REC IN" refers to the length in inches of the sidewall sample recovered. "OIL % BULK" and "GAS % BULK" equal, respectively, the cubic centimeters of corrected oil and gas volumes in the analyzed sample, divided by the bulk volume of the sample. This fraction has been multiplied by 100 to yield the percent data shown. "GAS DET" is the result of a measurement to detect hydrocarbon vapors in the sidewall glass container. A reading greater than zero is a positive indicator of hydrocarbons. If at zero, it means only that vapors were not present at the time of testing. They may have escaped from the bottle; therefore a zero is not necessarily negative.

"CRIT WTR %" defines the maximum water saturation a sample with the measured permeability and porosity can retain and yet not produce water. This value is determined independently, using special core analysis data, and then correlated with basic core analysis permeability and porosity information. In subsequent wells, knowledge of permeability and porosity allows estimation of the critical water saturation.

The critical water value should be compared to the reservoir in-place water saturation that has been calculated from downhole electric logs. If the in-place water saturation does not exceed the critical value, the well will produce hydrocarbons. These data are particularly important in low permeability reservoirs whose critical water saturation can be as much as 60% or greater, but which will still produce only hydrocarbons. Without knowledge of the permeability and porosity from core data and the estimate of high critical water saturation, a well that has been evaluated on the basis of logs alone may not be tested further or may be abandoned on the basis of its high level of log-calculated water. This water, although present, is held in place by capillary forces and will not flow.

B.12. Special Core Analysis

Special Core Analysis

Special core analysis tests on homogeneous formations are normally made on 1 or 11/2 inch (2.5 to 3.8 cm) diameter cylindrical plugs approximately 1 to 3 inches (2.5 to 7.5 cm) long. Samples are selected to cover the permeability, porosity, and rock-type range. For heterogeneous formations, tests are made on full diameter cores. Certain measurements are made on fresh, preserved cores that are not extracted and leached prior to the laboratory tests. In other cases, samples are extracted, leached, and dried. After porosity and permeability are determined, the samples are restored to the desired saturation conditions.

The problem of not having suitable cores for special tests may arise because cores were taken for a conventional analysis without subsequent special work in mind. The remote location of some oil wells may make the use of a desired coring fluid and packaging technique impractical. Either way, the engineer or geologist must use the available rock in the state in which it exists.

Other than when storage of rock has caused deterioration, the primary factor that may affect the soundness of the results of special tests is rock wettability. It is complex in theory, but a simplified illustration of the concept of wettability as a function of contact angle is shown in Figure 1 (Contact angle as an indication of wettability). It appears that normally rocks in their initial state are water-wet. Many remain in this state, while others become neutral or oil-wet over geologic time when contacted by oil containing surface-active (polar) compounds that are adsorbed on the rock surfaces. This has been discussed in some detail by Denekas, Mattax, and Davis (1959).

Samples of given original reservoir wettability have been shown to change because of contact with coring fluids, temperature and pressure effects, core storage and packaging, core exposure, and core cleaning. In other instances, however, rocks were found to be virtually insensitive to these same factors, indicating that valid results can be obtained in many cases with less than optimum conditions prior to special analysis.

The data presented by Luffel and Randall (1960) indicate that capillary pressure measurements, gas-oil relative permeability, and electrical property information can be reliably obtained on extracted cores. Although it was not specifically stated, it is likely that the reservoirs reported on were water-wet. Extracted samples are suitable for most tests not involving the simultaneous flow of water and oil.

Greater awareness now exists that many reservoirs trend toward either neutral wettability or a state of preferential oil-wetness. Treiber, Archer, and Owens (1972) have provided a laboratory evaluation of reservoir wettability. They found that large percentages of both carbonate and sandstone formations appear to be other than strongly water-wet. When the rock is neutral or oil-wet, the laboratory capillary pressure data are likely not to be suitable for calculation of reservoir water saturations.

Water-oil relative permeability can be measured on extracted cores from water-wet formations. Where the formation is believed to be intermediate or oil-wet in nature, these tests should be made on samples recovered with oil-base coring fluids (native state cores) to which no extraneous water has been added. The assumptions in this case are that the water saturation present in the sample in the laboratory is equal to that in the reservoir, that it is in the proper pore spaces, and that the wettability of the laboratory rock sample mirrors the reservoir wettability. When the formation is oil-wet, electrical properties may also need to be measured on native state core.

Capillary Pressure Tests

Water is retained in the reservoir pore space by capillary forces as hydrocarbons migrate and accumulate. This interstitial water, in water-wet reservoirs, adheres to sand or carbonate surfaces. Retentive forces are proportional to the water-hydrocarbon interfacial tension and the affinity of water for the rock (wetting preference), and inversely proportional to pore size. This implies that low permeability formations that are composed of very small pore spaces have high water retentive forces, and hence often contain high immobile water saturations.

The measurement of capillary pressure requires that core samples be selected so that the pore radii distribution of the sample represents that of the reservoir. The data obtained in the test are used to define initial water saturation distribution in the reservoir as a function of the height above the hydrocarbon-water contact, and to furnish pore throat size and distribution data that are helpful in identifying various rock types present in the formation.

 

Measurement Techniques

Three commonly utilized techniques for measuring capillary pressure data are:

· the restored state cell technique (Bruce and Welge 1947);

the centrifugal technique (Slobod, Chambers, and Prehn 1951);

the mercury injection technique (Purcell 1949).

All three techniques furnish multiple saturation values so as to define water saturation as a function of capillary pressure. The restored state technique has one advantage over the other two: water is present in the core samples, which allows electrical properties to be measured along with capillary pressure. The centrifugal technique is the most rapid and is the best for poorly consolidated rocks, provided they have been mounted in sleeves with screens over the sample ends. The mercury injection technique yields the maximum number of data points. It is the best one for obtaining pore throat distribution data, but the sample will be filled with mercury at the conclusion of the test and will have no further value.

Figure 1 (Schematic of restored state capillary pressure cell) is a schematic of the restored state capillary pressure cell. Clean, dry samples are weighed, evacuated, pressure-saturated with simulated formation brine, and again weighed. Multiple samples of varying permeability can be run in one cell. The nonwetting phase is introduced at a low and constant pressure. This low pressure injection, which acts as a driving force to remove the water, is counterbalanced by the capillary retentive forces. When no further water is moving from the core at the imposed pressure level, the sample is removed and weighed. The water saturation remaining in the core is then determined gravimetrically.

 

The pressure imposed on the sample in the laboratory is equivalent to the pressure difference that exists between the wetting and nonwetting fluid phases. This in turn is proportional to the pressure difference between the wetting and nonwetting phase in the reservoir, which is related to the height of a given saturation above the original water-oil level and the oil and water hydrostatic gradient. Figure 2 (Pressure differential (PC) between water and hydrocarbon versus height and water saturation) illustrates this concept. As the hydrocarbon column increases in height, the buoyant force of the hydrocarbon column increases. Water saturation is therefore pushed from the pore space and reduced to lower values as the height above the free water surface increases.

In Figure 3 (Capillary pressure curves representing different depositional environments) we see examples of capillary pressure data for rocks that represent three different depositional environments. Note that the higher permeability rocks have the lowest water saturation at any given capillary pressure, thus yielding a smaller transition zone. There are some suggestions, however, that this may hold true only at lower capillary pressures. The capillary pressure that yields a given water saturation is a function of the rock-wetting characteristics. Typically, this contact angle varies between the laboratory and the reservoir. Capillary pressure is also a function of the interfacial tension between the fluids in the test core at the time of testing, which differs from the reservoir value. One of the major uses of capillary pressure data is for defining the initial water saturation of the reservoir.

Water Saturation versus Height

Equations 9.1, 9.2 and 9.3 (below) may be used to correct the laboratory measured capillary pressure to an equivalent height above the free water level in the reservoir. The free water level is defined as the depth where the capillary pressure is zero; for practical purposes, it is the depth at which a high permeability and porosity reservoir rock would show no residual oil saturation as the zone of 100% water saturation is approached.

	System	Contact angle 	Cosine 	Interfacial Tension T	T x Cosine 
Laboratory	Air-water	0	1.0	72	72
	Oil-water	30	0.866	48	42
	Air-mercury	140	0.765	480	367
	Air-oil	0	1.0	24	24
Reservoir	Water-oil	30	0.866	30	26
	Water-gas	0	1.0	50*	50

*Pressure and temperature dependent. Reasonable value to depth of 5000 feet.

Table 1. Typical interfacial tension and contact angle values for a wafer-wet system

The equations require knowledge of the interfacial tension of the fluids, both in the laboratory and in the reservoir. Some estimate must also be made of the contact angle in the reservoir. For water-wet systems, the values reported in Table 1 may be used as an approximation for those two variables if no further information is available. Schowalter (1976) discusses the importance of capillary pressure and presents data that may be used for estimating the parameters required in the three equations. Examples of conversions of capillary pressure to reservoir height have also been presented by Keelan in the manual published by Core Laboratories, Inc., entitled Special
Core Analysis.

(1)

or

But

(2)

Therefore

(3)

Where:

h = height above free water table, ft or m

P_c = capillary pressure, psi or kPa

 = interfacial tension, dynes/cm

= contact angle, degrees

p_w = density of brine, g/cm³

p_h = density of hydrocarbon, g/cm³ g = gravity term used to convert density to fluid gradient

R = subscript used to indicate initial reservoir conditions

L = subscript used to indicate laboratory conditions

Pore Throat Distribution

Capillary pressure data obtained from mercury injection tests can be converted to equivalent pore radii, and Figure 4 (Cumulative pore throat distribution for different depositional environments) illustrates plots of pore entry radius developed from the capillary pressure curves of Figure 3 . These data have been helpful in rock typing and in selection of net pay (Jodry 1972; McKenzie 1975).

 

 

 

Electrical Properties

Electrical measurements made in the laboratory on cores define, for a given formation, the parameters that are used in electric log calculations of water saturation. The measured properties include the resistivity of the core at 100% water saturation (R_o), at other saturations (R_t), and the resistivity of the brine (R_w). The relationship between rock properties and water saturation is as follows:

(1)

(2)

or

(3)

Where:

S_w = formation brine saturation, fraction

R_w = formation brine resistivity, ohmmeters

R_t = true formation resistivity, ohmmeters

R_o = true resistivity of 100% brine-saturated rock, ohm-meters

F = formation resistivity factor R_o/R_w

 = measured porosity, fraction

a = intercept on F versus  plot

n = saturation exponent, slope of RI versus S_w plot

m = cementation exponent (slope of F versus  plot)

By using these equations we can refine log calculations and need no longer rely on estimates presented in the literature.

Formation Factor versus Porosity

The formation factor (F) has been defined (Archie 1942) as the resistivity of a 100% water saturated rock (R_o) divided by the resistivity of the saturating brine (R_w). When the measured formation factor is plotted against measured porosity, the slope of the resulting line yields the cementation exponent (m). This is illustrated in Figure 1 (Plot of formation factor versus porosity, illustrating variation in intercept "a"), along with limits observed in laboratory tests.

 

 

 

Resistivity Index versus Water Saturation

As water saturation decreases in a given sample, the true resistivity rises. This occurs because less water and subsequently fewer ions are available to conduct electricity. The resistivity index (RI) is defined as the true resistivity (R_t) at any saturation divided by the resistivity at 100% saturation (R_o). Figure 2 (Plot of sesistivity index versus water saturation for range of measured values of the slope"n") shows a typical plot of the resistivity index versus water saturation over a range of laboratory measured data. Note that the saturation exponent (n) is the slope of the resistivity index versus water saturation line.

In rare cases, both m and n values exceed the limits illustrated on the figures. For example, if the rock matrix contains conductive matrix components, the n value often falls outside the illustrated limits. The calculation of water saturation is very sensitive to m as porosity decreases, and use of an incorrect m value will yield water saturation errors of 50% pore space.

 

 

 

Clay Effects

The presence of clay can suppress rock resistivity, and yield lower m and variable n values. The water saturation equation that was developed to accommodate the presence of clays that conduct electricity becomes more complex than that given in Equation 3. The saturation equation that incorporates measured cation exchange capacity effects caused by clays is given by the Waxman-Smits-Thomas equations (1968,1974):

(4)

Where:

F*= Fa (1 + R_wB Qv) (5)

(6)

Where, in addition to the definition of nomenclature given after Equation 4, the following apply:

F* = formation resistivity factor independent of clay conductivity = a*/m*

n* = saturation exponent independent of clay conductivity

B = specific counterion activity, 1/ohm-m/equiv/liter

Q_v = quantity of cation exchangeable clay present, meq/ml of pore space

CEC = cation exchange capacity, meq/100 gm

_ma= grain density of rock matrix, g/cm3

a = equation coefficient associated with m*

m* = cementation exponent (slope of F* vs  plot)

Neglecting the cation exchange capacity — that is, using Equation 4 rather than 5 — yields pessimistic estimates of hydrocarbons in place (see Koerperich 1975; Keelan and McGinley 1979). With the present extent of knowledge, the cation exchange capacity can only be reliably determined on rock samples from the formation being evaluated.

The Waxman-Smits-Thomas equation requires a trial and error solution, as the water saturation (S_w) appears on both sides of Equation 5. Programs for hand-held calculators have been published by Bush and Jenkins (1977) that allow the calculation to be made more easily. Keelan and McGinley (1979) have shown how the measured laboratory values of m and n may be modified to furnish the m* and n* values required for the Waxman-Smits-Thomas equations. Table 1., below, illustrates the differences in calculated water saturation that may occur when using m and n values for clean sand versus values developed for use in the Waxman-Smits-Thomas equations. Note the pessimistic estimate of hydrocarbons in place that will result if the clean sand rather than the latter equations for shaly sand are used.

Waxman-Smits-Thomas				Laboratory Data			Clean Sand
a=1.0		a* =1.0		a=1.0			a=1.0
m=1.63		m*=51.92		m=1.63			m=2.0
n=2.38		n*=2.87		n=2.38			n=2.0
			(1)		(2)	(3)
No.	Porosity		Sw: % PV		Sw: % PV	Sw: % PV
1	20.4		47.		55.	66.
2	17.8		56.		68.	87.
3	16.3		57.		72.	95.
4	20.1		54.		64.	79.
5	14.3		61.		80.	111.
6	25.2		59.		59.	69.
7	25.4		55.		51.	58.
8	27.3		57.		51.	57.
9	17.5		74.		73.	95.
10	20.0		60.		70.	88.
11	17.4		68.		75.	99.
12	14.4		74.		86.	119.

 
(1) Laboratory data correctly adjusted to *values (equation 2)

(2) Laboratory values used as reported

(3) Clean sand values assumed correct and ignoring clay and shale effects (equation 4)

Table 1. Comparative values of calculated water saturation, using clean sand and shaly sand equations, for a shaly formation (from Keelan and McGurley, 1979, reprinted by permission of SPWLA)

 

Relative Permeability

Definitions

Relative permeability is a dimensionless term that has importance when two or more fluids move through the pore spaces—for example, oil and water. Specific or absolute permeability is the permeability of a porous medium to one fluid at 100% saturation. Effective permeability is the permeability to a given phase when more than one phase saturates the porous medium. The effective permeability, then, is a function of saturation. Relative permeability to a given phase is defined as the ratio of effective permeability to the absolute or, in some cases, a base permeability. Relative permeability, then, is also a function of saturation.

In data that were generated prior to 1973, the specific permeability to air was often used as the base permeability. Since that time, the common base has been the hydrocarbon permeability in the presence of irreducible water. For an oil-water reservoir, this would mean the base permeability would be effective permeability to oil at irreducible water. For a gas reservoir, the base permeability would be that to gas in the presence of irreducible water.
Figure 1 (Gas-water relative permeability curves) illustrates gas-water relative permeability data when water displaces gas.

Imbibition versus Drainage

The terms imbibition and drainage are also employed when discussing relative permeability tests. Their meanings imply what is happening in the pore space to the wetting phase as relative permeability tests are measured. If the wetting phase is decreasing, that phase is draining and the curve is called a drainage curve. If the wetting phase is increasing or being imbibed during the test, the curve is referred to as an imbibition curve ( Figure 1 ).

For a water-wet reservoir, the drainage curves apply during the time that water is draining from the reservoir and hydrocarbons are accumulating. Once the reservoir rock or laboratory sample has attained an equilibrium water-saturation value and the water is subsequently increased by natural water influx or the introduction of coring or test fluids, the imbibition curves apply. (In oil-wet rock, a reduction in the oil phase by water flooding would be referred to as a drainage curve.) These data are required in many reservoir engineering calculations, and the laboratory tests that develop them should follow the same saturation history as that in the reservoir.

Laboratory Methods for Measuring Relative Permeability

Two major laboratory methods have evolved to measure relative permeability. These are referred to as the steady-state and nonsteady-state techniques.

STEADY STATE: The steady-state test, the older of the two methods, is made at low flow rates, and the test apparatus contains upstream and downstream mixer heads to remove capillary end effects. Most research groups prefer data obtained from this test. Two fluids are injected simultaneously into a core sample and the water saturation is increased slowly. This simulates the slow increase in water saturation that would occur in the formation between the injection and producing wells. Saturation increase is monitored by measuring the gain in weight occurring in the sample or by X-ray technique.

NONSTEADY STATE: The nonsteady-state technique uses a viscous oil and is normally made at a higher flow rate than that present in the reservoir. It is this higher rate that sometimes yields pessimistic estimates of recovery from rocks of intermediate wettability. Heaviside and Black (1983) have analyzed the two techniques and presented recommendations on the most appropriate way to measure water-oil relative permeability depending upon the wetting characteristics of the rock.

Wettability Effects

The natural preference of a porous medium, which causes one fluid to adhere to its surfaces rather than another, is referred to as wettability. A water-wet porous medium causes water to adhere to its surfaces. The wettability of a rock has a dramatic influence on relative permeability curves. It is therefore necessary that the core samples tested in the laboratory reflect the actual formation wettability, and that initial water saturation in the test sample be of the same magnitude and have the same spatial location as it has in the reservoir. This need has led to the recovery of "native state" cores. These are cores taken with crude oil or with other oil-base fluids that do not alter the wettability or water saturation present in the recovered core.

 

Figure 2 (Effects of wettability on water-oil relative permeability: imbibition data for Torpedo sandstone) illustrates the effects of core wettability on water-oil relative permeability measurements (Owens and Archer 1971). These data indicate that as the rock becomes more oil-wet, the relative permeability to oil decreases and the relative permeability to water increases at any given saturation. This results in unfavorable recovery efficiency. It also indicates that the residual oil saturation in intermediate to oil-wet rocks is a function of the volume of water that flows through the core sample, and that the relative permeability to water existing at floodout will be much higher for the oil-wet formation. An interesting observation is that the reduction of capillary retentive forces in the oil-wet rock allows a lower residual oil saturation to be achieved in the oil-wet rock if economics would support continued water injection.

Wettability may be estimated from shapes of relative permeability curves; however, it should be remembered that a similar shift in the relative permeability curves can also be caused by changes in other rock properties. This was documented by Morgan and Gordon (1970).

Petrographic Studies

Sidewall and conventional cores, as well as cuttings recovered from wells, can be used for petrographic studies. Progress in instrumentation now allows us to look into the pore spaces and examine samples at magnifications of 40,000 times or greater. These various microscopic measurements are complementary in nature, and all may be made on a single sample that is representative of a given depth. Several such tests are detailed below.

Thin Section Analysis

In thin section analysis, samples are mounted on glass and ground to a uniform thickness of 0.03 mm. They are studied with a petrographic scope under normal and polarized light. The minerals that are present are identified, and the estimated porosity, median grain diameter, and degree of rounding and sorting are recorded. The accumulation of minerals can be ascertained, and the changes in composition, texture, and cement that have occurred after deposition can be determined. These studies use magnifications of up to 600 times normal size. Thin section analysis is a less successful method for identifying clays, but there may be cases where a particular clay is abundant enough to be seen and identified. Figure 1 (Thin section microscope display) shows a thin section sample; Table 1., below, depicts a core description made from this type of analysis.

Sample depth: 4640 feet	Grain size:
Color: Medium gray	Minimum: 0.06 mm
Name: Fine-grained sandstone	Maximum: 0.51 mm
Sorting: Well	Average: 0.24 mm
Lithification: Well	Angularity and shape: Angular to subrounded
Texture: Massive	Grain contacts: Concavo-convex

 

Detrital grains-%	Cements-%	Matrix-%	Visible porosity-%
Quartz: 69	Secondary	Detrital: 2	Intergranular: 5
Chert: 3	quartz	Authigenic: 4	Grain-moldic: 2
Feldspars (total): 2	overgrowths: 7		Dissolution: 1
	Feldspar		Microporosity: 1
Lithic fragments: 4	overgrowths: Trace	Fracture: -
	Calcite: -
	Pyrite: Trace

Measured porosity: 7.4%

Measured permeability: 38.3 md.

Table 1.
Thin section data

Scanning Electron Microscopy (SEM)

Scanning electron microscope photographs provide a three-dimensional view of a pore space with a magnification of up to approximately 40,000 times normal. Both distribution and morphology of clays within the pore space can be studied with this type of display. Normally, samples for analysis are first coated with a thin film of conductive material and then bombarded with electrons. This causes a secondary electron emission that yields a visual image such as that shown in Figure 2 (Electron microscope display) plus X-ray photons that are then available for elemental analysis. The latter assists in defining clay type and chemistry.

Clays influence core analysis analytical procedures, permeability and porosity magnitude, well-completion techniques, and response of the downhole logs. The ability to identify clay types, and to observe the microporosity present in both clay linings and in carbonates, are two of the most important uses of SEM information.

 

 

 

 

 

(Sample depth: 4640 ft.)

Mineral	Bulk sample	Net clay fraction (4.2% of bulk sample)
Quartz	91
Feldspars	5
Calcite	—
Kaolinite	3	70
Chlorite	—	—
Illite/Mica	1	30
Total	100%	100%

Table 2. X-ray diffraction data

X-ray Diffraction

All crystalline materials reflect X-rays from atomic planes within the Crystal that yield a unique diffraction pattern. This allows the identification of minerals, including those too small to be identified by thin section studies. Improved clay mineral identification results when clay-sized particles of four microns or less are separated from large sand grain particles and X-rayed as a unit. Table 2., above, is an example of such data.

Cathodoluminescence

Thin sections of rock that are placed within a vacuum chamber will glow with color when hit with electrons. If the electron emitter is mounted on a petrographic microscope, immediate comparison of samples by polarized light and luminescence is possible, and growth rings similar to those of trees may be observed in individual crystals. West (1978) suggests that these rings have proved to be correlatable over large distances, and that their color pattern reflects trace elements present in formation waters at various stages of the crystal history. The color pattern, then, offers insight into water temperature and chemistry during the history of the rocks.

 

 

Micropaleontology and Palynology

Micropaleontology is the study of fossils that are not identifiable with the naked eye. Both the petrographic microscope and scanning electron microscope are essential tools in these studies. Palynology is a specialized area of micropaleontology, that deals with acid-insoluble organic plant fossils. Included in this classification are plant spores and pollen, which are associated with terrestrial environments. LeRoy (1977) suggests that other microfossils are associated with the marine environment, and that still others, typical of fresh and brackish water, are found in transitional environments. These data, when observed in core samples and related to sedimentary structures, texture, and lithologic characteristics, aid in the classification of environments of deposition. Figure 1 (Terrestrial and marine microfossils) presents some examples of terrestrial and marine microfossils.

 

Trace Element Identification

Kukal (1971) indicates that trace elements present in shales have been used successfully as guides to major variations in water salinity, and hence serve to differentiate between fresh water and marine sediments. The presence of trace elements is related to the cation exchange capacity of clay minerals located within the shales. Clays have tremendous surface area and are often electrically imbalanced. Trace elements are adsorbed on clay surfaces, and many trace metals survive at these absorptions points. Boron, chromium, copper, nickel, vanadium, rubidium, and lithium are generally found in higher percentages in marine clay sediments deposited in salty water. Some studies have indicated lead associated with fresh water sediments.

Insoluble Residues

Tests for insoluble residues are conducted to determine the materials remaining after rock samples have been digested in hydrochloric, formic, or acetic acid. Ireland (1977) reports that quartz, chert, pyrite, and clay are common residues. The reporting of data may simply identify residues or may furnish their weight percentages as well. The techniques for such studies are also discussed by Swanson (1981). Residue identification helps to specify rock environment.

Computer-Assisted Tomography (CAT) Scanning

A computer-assisted tomography, or CAT scan, produces an image of the internal structure of a cross-sectional slice through an object by reconstructing a matrix of x-ray attenuation coefficients. CAT scanning is a non-destructive x-ray technology that is most familiar through its use in medicine, but which has been found to have oil industry applications as well. Applications relating to core analysis include (1) visualizing the extent of mud invasion, (2) detecting fractures, (3) characterizing the lithology of cores contained in opaque preservation material, rubber-sleeve core barrels and stainless-steel pressure vessels, (4) screening cores prior to flow tests and (5) correlating scan data to porosity, permeability and lithology (Hunt et al., 1988).

Nuclear Magnetic Resonance (NMR) Logging

The NMR logging tool has been used for a number of years to measure in situ rock properties such as porosity, permeability and residual oil saturation. More recently, nuclear magnetic resonance technology has been applied as a tool for core analysis (Edelstein et al., 1988). NMR imaging enables the analyst to visualize fluids in a porous medium in dimensions, on a sub-millimeter scale and thus to study porosity and fluid saturation distributions, along with fractures and drilling mud invasion. NMR images only mobile fluids within the pore structure.

Exercise 1.

Given:

· Original oil formation volume factor (FVF_o) of 1.5 reservoir bbl/stock tank bbl.

Reservoir oil gradient of 0.33 psi/ft @ reservoir conditions.

Reservoir water gradient of 0.44 psi/ft @ reservoir conditions.

Free water-oil level of 6000 ft (corresponding to zero capillary pressure).

Figure 1 and core analysis data.

 

Core analysis data (water base):

Depth	k		So(% PV)	So(% PV)
5950	350	28.4	20	55
5951	6.4	18.8	15	58
5952	350	28.4	21	55
5953	16	21.0	18	57
5954	100	25.0	20	54

Calculate the saturation versus height profile for the reservoir and the oil-in-place per unit volume of reservoir.

1. Convert capillary pressure to height above free water level.

2. Calculate height above free water level at which each core analysis sample exists.

3. Knowing height and permeability of each core sample, go to capillary pressure curves and read reservoir water saturation for each sample.

4. Compute average porosity .

5. Compute arithmetic average permeability 

6. Compute average water saturation in the core .

7. Compute average oil saturation in the core .

8. Computer average reservoir water saturation using capillary pressure data (Sw res).

9. Compute average reservoir oil saturation (S_o res).

10. Compute oil-in-place in the reservoir.

Where  and  are fractional and averages of the zone.

The following equations and worksheet will be helpful:

 

Sample depth	Height above free water level	k	Sw	1 - Sw
5950	____________	350	________	________
5951	____________	6.4	________	________
5952	____________	350	________	________
5953	____________	16	________	________
5954	____________	100	________	________
Avg		= ______	% = ________	fractional
Avg arithmetic		= _______	md
Avg Sw in core		= _______	%
Avg  in core		= _______	%
Avg  res		= _______	% =_______	fractional
Avg res		= _______	%
Oil in place*		= _______	bbl/acre ft

where and  are fractional.

Exercise 2.

Given the following data, calculate the cementation exponent "m" and the intercept "a" used in the equation:

R_w
= 0.21 ohm - meters @ 76°Figure

Sample	Porosity	Formation factor
1	14	37.2
2	18.8	24.0
3	21	19.7
4	25	14.5
5	28.4	11.9

Solution 2:

1. Construct log-log plot of Formation Factor vs. Porosity.

2. Compute slope of line to yield "m" = 1.69

3. Extrapolate data to intercept where 4) = 1.0 to find intercept "a" = 1.4

Exercise 3.

Given:

k₈ = 3180 md

k_o @ irreducible water saturation = 2540 md

Irreducible water saturation = 28.0%

k_rw = k_w/k_base

k_ro = k_o/k_base

k_base = 2540 md

Porosity = 28.0%

With the given relative permeability curves ( Figure 1 ) compute the effective permeability in millidarcies to water and to oil when the reservoir water saturation equals 50% pore space.

 

Solution 3:

@ S_w
= 50%

k_ro = 0.28

k_rw
= 0.027

k_o
= (0.28) (2540) = 711 md

k_w = (0.027) (2540) = 68.6 md

B.13. References and Additional Information

References

American Petroleum Institute, API RP27, Recommended Practice for Determining Permeability of Porous Media.

American Petroleum Institute, API RP40, Recommended Practice for Core Analysis Procedures.

Archie, G.E., 1942, The Electrical Resistivity Log as an Aid in Determining Some Reservoir Characteristics, Trans., AIME, v. 146, p. 54-67.

Bilhirtz, H.C. and G.S. Charlson, 1978, Coring for ln Situ Saturations in the Willard Unit CO2 Flood Minitest, SPE paper 7050, Fifth Symposium Improved Methods for Oil Recovery, Tulsa OK (April 16-19,1978).

Bruce, W.A. and H.J. Welge, 1947, The Restored State Method for Determination of Oil in Place and Connate Water, Drill. and Prod. Prac., API, p. 166.

Bush, D.C. and R.E. Jenkins, 1970, Proper Hydration of Clays for Rock Property Determinations, J Pet. Tech. (July), p. 800-804.

———, Shaly Sand Log Analysis Using Cation Exchange Capacity Data, Trans., CWL (October 1977).

Collins, R.E., 1952, Determination of the Traverse Permeabilities of Large Core Samples from Petroleum Reservoirs, J Applied Physics, v. 23, p.681.

Denekas, M.O., C.C. Mattax, and G.T. Davis, 1959, Effect of Crude Components on Rock Wettability, Trans., AIME, v. 216, p. 330-333.

Edelstein, W.A., H.J. Vinegar, P.N. Tutunjian, P.B. Roemer and O.M. Mueller, 1988, NMR Imaging for Core Analysis, SPE 18272, presented at the 63rd SPE Annual Meeting, Houston, TX, (October 2-5). Richardson, TX: Society of Petroleum Engineers.

Freeman, D.L. and D.C. Bush, 1983, Low Permeability Laboratory Measurements by Nonsteady-State and Conventional Methods, J Pet. Tech. (December 1983), p. 928-936.

Hagerdorn, A.R. and R.J. Blackwell, 1972, Summary of Experience with Pressure Coring, AIME Technical Paper SPE 3962 SPE-AIME Annual Fall Meeting, San Antonio (October 1972).

Harris J.D. and D.K. Keelan, 1976, Core Analysis Techniques, Case Histories, and Interpretation of Data for the Rocky Mt. Region, SPE paper 5905, May 11-12,1976.

Hayes, J.R., 1977, Grain Size Analysis and Application, Subsurface Geology, L.W. LeRoy, D.O. LeRoy, and J.W. Raese (eds.), Colorado School of Mines, Golden, CO, p. 61-74.

Heaviside, John and C.J.S. Black, 1983, Fundamentals of Relative Permeability: Experimental and Theoretical Considerations, Paper 12173, 58th Annual meeting of SPE of AIME, San Francisco.

Hensel, W.M, Jr., 1980, Summation-of-Fluids Porosity Technique, SPE paper 9376, 55th Annual Meeting of SPE, Dallas (September 21-24,1980).

———,1984, Improved Formation Evaluation from Pressure and Conventional Cores Taken with Stable Foam: Bennett Ranch Unit, Wasson Field, SPE Paper 13095, 59th Annual Meeting of SPE, Houston (September 16- 1 9, 1984).

Hunt, P.K., P. Engler and C.J. Bajsarowicx, 1988, Computed Tomography as a Core Analysis Tool: Applications, Instrument Evaluation and Image Improvement Techniques. SPE 16952 JPT (September).

Hurd, B.G. and J.L. Fitch, 1959, The Effect of Gypsum on Core Analysis Results, Trans., AIME, v.216, p. 221.

Ireland, H.A., 1977, Insoluble Residues, Subsurface Geology, L.W. LeRoy, D.O. LeRoy, and J.W. Raese (eds), Colorado School of Mines, Golden, CO, p. 53-59.

Jodry, R.L., 1972, Pore Geometry of Carbonate Rocks (Basic Geologic Concepts), Oil and Gas Production from Carbonate Rocks, Elsevier Publishing Co., p. 35-82.

Jones, F.O. and W.W. Owens, 1979, A Laboratory Study of Low Permeability Gas Sands, AIME Technical Paper SPE 7551, Denver (May 1979).

Keelan, Dare K., 1972, A Critical Review of Core Analysis Techniques, J. Canadian Pet. Tech. (April-June 1972), II, 2, p. 42-55.

———,1982a, Core Analysis for Aid in Reservoir Description (Dist. Author Series, SPE 10011), J Pet. Tech. (November 1982), v. 34, p. 2483-2491.

———,1982b, Special Core Analysis, company publication, Core Laboratories, Inc.

Keelan, Dare K. and D.C. McGinley, 1979, Application of Cation Exchange Capacity in a Study of the Shannon Sand of Wyoming, Trans., SPWLA (June 1979), 1, Paper W.

Klinkenberg, L.J., 1941, The Permeability of Porous Media to Liquids and Gases, Drill. and Prod. Prac., API, p. 200.

Koepf, E.H. and R.J. Granberry, 1960, The Use of Sidewall Core Analysis in Formation Evaluation, J. Pet. Tech. (October 1960).

Koerperich, E.A., 1975, Utilization of Waxman-Smits Equations for Determining Oil Saturation in Low-Salinity, Shaly Sand Reservoir, J. Pet. Tech., v. 27, p. 1204-1208.

Kukal, Zdenek, 1971. Geology of Recent Sediments: Academic Press, New York, p. 421-426.

LeRoy, D.O., 1977, Economic Microbiostratigraphy Subsurface Geology, L.W. LeRoy, D.O. LeRoy, and J.W. Raese (eds.), Colorado School of mines, Golden, CO, p. 212-233.

Luffel, D.L. and R.V. Randall, 1960, Core Handling and Measurement Techniques for Obtaining Reliable Reservoir Characteristics, Formation Evaluation Symposium Jointly Sponsored by Gulf Coast Section, AIME, University of Houston Student Chapter, AIME, and University of Houston Dept. of Pet. Eng. (November 21-22,1960), I, p. 21-37.

Maness, Mabre, 1983, Cores, Drilling Samples Essential for Reservoir Evaluation, Michigan Oil and Gas News (October 28, 1983), p. 28-32.

Maness, Mabre, J.G.W. Price, and P.D. Ching, 1977, Well Formation Characterization by Residual Hydrocarbon Analysis, SPE Paper 6660, SPE 52nd Annual Technical Conference and Exhibition, Denver (October 9-12, 1977).

McKenzie, W.T., 1975, Petrophysical Study of the Cardium Sand in the Pembina Field, SPE paper 5541, 50th Annual meeting of SPE, Houston, 1975.

McLatchie, A.S., R.A. Hemstock and J.W. Young 1958, The Effective Compressibility of Reservoir Rock and Its Effects on Permeability. Trans., AIME, v. 213, p. 386.

Morgan, J.T. and D.T. Gordon, 1970, Influence of Pore Geometry on Water-Oil Relative Permeability, Soc. Pet. Eng. J. (October 1970), p. 1179.

Owens, W.W. and D.L. Archer, 1971, The Effect of Rock Wettability on Oil-Water Relative Permeability Relationships, J. Pet. Tech. (July 1971), p. 873-878.

Purcell, W.R., 1949, Capillary Pressures-Their Measurement Using Mercury and the Calculation of Permeabilities Therefrom, Trans., AIME, v. 186, p. 39.

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Rathmell, J.J., P.H. Braun, and T.K. Perkins, 1972 Reservoir Waterflood Residual Oil Saturations from Laboratory Tests, SPE paper 3785, Improved Oil Recovery Symposium, Tulsa, OK, (April 16-19).

Reitzel, G.A. and G.O. Callow, 1977, Pool Description and Performance Analysis Leads to Understanding and Golden Spike's Miscible Flood, J. of Pet. Tech. (July 1977), p. 867-872.

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Nomenclature

A = sample cross-sectional area, cm2

a * = equation coefficient associated with m*

B = specific counter ion activity, 1/ohm-m/equiv liter

BD = bulk density, g/cm3 (assumed or measured)

BV = bulk volume

CEC = cation exchange capacity, meq/100 gm of sample

GD = grain density, g/cm3 (from downhole log)

GV = grain volume

F = formation resistivity factor independent of clay conductivity, Ro/Rw

F* = formation resistivity factor independent of clay conductivity, a*/

FD = fluid density, g/cm3 (assumed)

g = gravity term used to convert density to fluid gradient

h = height above free water table, ft or m

k = permeability, md

k1 = Klinkenberg permeability value, md

ka = air permeability, md

I = sample length, cm2

L = subscript used to indicate laboratory conditions

m* = cementation exponent (slope of F* vs  plot)

n = saturation exponent, slope of RI (Resistivity Index) versus Sw plot

n* = saturation exponent independent of clay conductivity

PV = pore volume, fraction or percent

pc = capillary pressure, psi of kPa

p1 = upstream pressure, atmospheres absolute

p2 = downstream pressure, atmospheres absolute

pa = atmospheric pressure, atmospheres absolute

Qv = quantity of cation exchangeable clay present, meq ml of pore space

q = liquid flow rate, cc/sec

qa = gas flow rate at atmospheric pressure, cc/sec

R = subscript used to indicate initial reservoir conditions

Ro = true resistivity of 100% brine-saturated rock, ohms

Rt = true formation resistivity, ohm-meters

Rw = formation brine resistivity, ohm-meters

Sw = formation brine saturation, fraction

Vb = bulk volume of sample used to determine unoccupied pore space, corrected based on retort sample weight, cm3

Vg = grain volume, cm3

Vo = volume of oil collected, cm3 (corrected for vapor losses, coking, etc.2)

Vu = volume of unoccupied pore space, corrected based on retort sample weight, cm3

Vw = volume of water collected, cm3

W1 = weight of crushed rock in retort less weight of contained fluids

W2 = weight of crushed rock in retort, g

= contact angle, degrees

µ = viscosity of fluid flowing, centipoise

= fluid gradient, psi/ft

= rock grain density, g/cm3

= grain density of rock solids, g/cm3

= oil density, g/cm2

= water density, g/cm2 (assumed 1.00 for water collected)

= interfacial tension, dynes/cm

= porosity

Standard Abbreviations for Lithologic Descriptions

Note: Abbreviations for nouns always begin with a capital letter.

Word Abbreviation

about	abt
above	ab
absent	abs
abundant	abd
acicular	acic
agglomerate	Aglm
aggregate	Agg
algae, algal	Alg, alg
allochem	Allo
altered	alt
alternating	altg
ammonite	Amm
amorphous	amor
amount	amt
and	&
angular	ang
anhedral	ahd
anhydrite (-ic)	Anhy, anhy
anthracite	Anthr
aphanitic	aph
appears	ap
approximate	apprx
aragonite	Arag
arenaceous	aren
argillaceous	arg
arkose (-ic)	Ark, ark
as above	a.a..
asphalt (-ic)	Asph, asph
assemblage	Assem
associated	assoc
at	@
authigenic	authg
average	Av, av
band (-ed)	Bnd, bnd
basalt (-ic)	Bas, bas
basement	Bm
become (-ing)	bcm
bed (-ed)	Bd, bd
bedding	Bdg
bentonite (-ic)	Bent, bent
bitumen (-inous)	Bit, bit
bioclastic	biocl
bioherm (-al)	Bioh, bioh
biomicrite	Biomi
biosparite	Biosp
biostrom (-al)	Biost, biost
biotite	Biot
birdseye	Bdeye
black (-ish)	blk, blksh
blade (-ed)	Bid, bid
blocky	blky
blue (-ish)	bl, blsh
bore (-ed, -ing)	Bor, bor
bottom	Btm
botryoid (-al)	Bot, bot
boulder	Bid
boundstone	Bdst
brachiopod	Brach
brackish	brak
branching	brhg
break	Brk, brk
breccia (-ted)	Brec, brec
bright	brt
brittle	brit
brown.	brn
bryozoa	Bry
bubble	Bubl
buff	bu
burrow (-ed)	Bur, bur
calcarenite	Clcar
calcilutite	Clclt
calcirudite	Clcrd
calcisiltite	Clslt
calcisphere	Clcsp
calcite (-ic)	Calc, calctc
calcareous	calc
caliche	cche
carbonaceous	carb
carbonized	cb
cavern (-ous)	Cav, cav
caving	Cvg
cement (-ed, ing)	Cmt, cmt
cephalopod	Ceph
chalcedony (-ic)	Chal, chal
chalk (-y)	Chk, chky
charophyte	Char
chert (-y)	Cht, cht
chitin (-ous)	Chit, chit
chlorite (-ic)	Chlor, chlor
chocolate	choc
circulate (-ion)	circ, Circ
clastic	clas
clay (-ey)	Cl, cl
claystone	Clst
clean	cln
clear	clr
cleavage	Clvg
cluster	Clus
coal	C
coarse	crs
coated (-ing)	cotd, cotg, Cotg
coated grains	cotd gn
cobble	Cbl
color (-ed)	Col, col
common	com
compact	cpct
compare	cf
concentric	cncn
conchoidal	conch
concretion (-ary)	Conc, conc
conglomerate (-ic)	Cgl, cgl
conodont	Cono
considerable	cons
consolidated	consol
conspicuous	conspic
contact	Ctc
contamination (-ed)	Contam, contam
content	Cont
contorted	cntrt
coquina (-oid)	Coq, coqid
coral, coralline	Cor, corln
core	c,
cove red	cov
cream	crm
crenulated	cren
crinkled	crnk
crinoid (-al)	Crin, crinal
cross	x
cross-bedded	x-bd
cross-laminated	x-lam
cross-stratified	x-strat
crumpled	crpld
crystocrystalline	crpxln
crystal (-line)	Xi, xln
cube, cubic	Cub, cub
cuttings	Ctgs
dark (-er)	dk, dkr
dead	dd
debris	Deb
decrease (-ing)	Decr, decr
dense	dns
depauperate	depau
description	Descr
detrital	detl
devitrified	devit
diabase	Db
diagenesis (-etic)	Diagn, diagn
diameter	Dia
disseminated	dissem
distillate	Dist
ditto	"or do
dolomite (-ic)	Dol, dol
dominant (-ly)	dom
drilling	drlg
drilistem test	DST
drusy	dru
earthy	ea
east	E
echinoid	Ech
elevation	Elev
elongate	elong
embedded	embd
equant	eqnt
equivalent	Equiv
euhedral	euhd
euxinic	eux
evaporite (-itic)	Evap, evap
excellent	ex
exposed	exp
extraclast (-ic)	Exclas, exclas
extremely	extr
extrusive rock, extrusive	Exv, exv
facet (-ed)	Fac, fac
faint	fnt
fair	fr
fault (-ed)	Fit, fit
fauna	Fau
feet	Ft
feldspar (-athic)	Fspr, fspr
fenestra (-al)	Fen, ten
ferruginous	ferr
fibrous	fibr
tine (-ly)	t, fnly
fissile	fis
flaggy	fIg
flake, flaky	FIk, flk
fiat	ti
floating	fltg
flora	Flo
fluorescence (-ent)	Fluor, fluor
foliated	fol
toot	Ft
foraminefera (-al)	Foram, foram
formation	Fm
fossil (-iferous)	Foss, toss
fracture(-d)	Frac, frac
fragment (al)	Frag, frag
frequent	freq
fresh	frs
friable	fri
fringe (-ing)	Frg, frg
frosted	fros
frosted quartz grains	F.Q.G.
fucoid (-al)	Fuc, fuc
fusulinid	Fus
gabbro	Gab
gastropod	Gast
gas	G
generally	gen
geopetal	gept
gilsonite	Gil
glass (-y)	Glas, glas
glauconite (-itic)	Glauc, glauc
Globigerina (-inal)	Glob, glob
gloss (-y)	Glos, glos
gneiss (-ic)	Gns, gns
good	gd
grading	grad
grain (-s, -ed)	Gr, gr
grainstone	Grst
granite	Grt
granite wash	G.W.
granule (-ar)	Gran, gran
grapestone	grapst
graptolite	Grap
gravel	Grv
gray, grey (-ish)	gry, grysh
graywacke	Gwke
greasy	gsy
green (-ish)	gn, gnsh
grit (-ty)	Gt, gt
gypsum (-iferous)	Gyp, gyp
hackly	hkl
halite (-iferous)	Hal, hal
hard	hd
heavy	hvy
hematite (-ic)	Hem, hem
Heterostegina	Het
heterogeneous	hetr
high (-ly)	hi
homogeneous	hom
horizontal	hor
hydrocarbon	Hydc
igneous rock (igneous)	Ig, ig
impression	imp
inch	in
inclusion (ded)	Incl, incl
increasing	incr
indistinct	indst
indurated	ind
Inoceramus	Inoc
in part	I.P.
insoluble	insl
interbedded	intbd
intercalated	intercal
intercrystalline	intxln
intergranular	intgran
intergrown	intgn
interlaminated	intrlam
interparticle	intpar
intersticies (-itial)	Intst, intst
intraclast (-ic)	Intclas, intclas
intraparticle	intrapar
intrusive rock, intrusive	Intr, intr
invertebrate	Invtb
iridescent	irid
ironstone	Fe-st
irregular (-ly)	irr
isopachous	iso
jasper	Jasp
joint (-ed, -ing)	Jt, jt
kaolin (-itic)	Kao, kao
lacustrine	lac
lamina (-tions, -ated)	Lam, lam
large	lge
late rite (-itic)	Lat, lat
lavender	lav
layer	Lyr
leached	lchd
lens, lenticular	Len, lent
light	it
lignite (-itic)	Lig, lig
limestone	Es
limonite (-itic)	Lim, lim
limy	lmy
lithic	lit
lithographic	lithgr
lithology (-ic)	Lith, lith
little	Ltl
littoral	litt
local	loc
long	lg
loose	lse
lower	l
lustre	Lstr
lutite	Lut
macrofossil	Macrofos
magnetite magnetic	Mag, mag
manganese,
manganiferous	Mn, mn
marble	Mbl
marl (-y)	Mrl, mrl
marlstone	Mrlst
marine	marn
maroon	mar
massive	mass
material	Mat
matrix	Mtrx
maximum	max
medium	m or med.
member	Mbr
meniscus	men
metamorphic rock,	Meta
metamorphic (-osed)	meta, metaph
mica (-ceous)	Mic, mic
micrite (-ic)	Micr, micr
microcrystalline	microxln
microfossil (-iferous)	Microfos, microfos
micrograined	micgr
micro-oolite	Microol
micropore (-osity)	Micropor, micropor
microspar	Microspr
microstylolite	Microstyl
middle	Mid
miliolid	Milid
milky	mky
mineral (-ized)	Min, min
minor	mnr
moderate	mod
mold (-ic)	Mol, mol
mollusc	Moil
mosaic	mos
mottled	mott
mud (-dy)	md, mdy
mudstone	Mdst
muscovite	Musc
nacreous	nac
nodules (-ar)	Nod, nod
north	N
no sample	n.s.
no show	n/s
novaculite	Novac
no visible porosity	n.v.p..
numerous	num
occasional	occ
ochre	och
oil	O
oil source rock	OSR
olive	olv
ooid (-al)	OO, oo
oolicast (-ic)	Ooc, ooc
oolite (-itic)	Ool, ool
oomold (-ic)	Oomol, oomol
oncolite (-oidal)	Onc, onc
opaque	op
orange (-ish)	or, orsh
Orbitolina	Orbit
organic	org
orthoclase	Orth
orthoquartzite	O-Otz
Ostracod	Ostr
overgrowth	ovgth
oxidized	ox
oyster	Cyst
packstone	Pkst
paper (-y)	Pap, pap
part (-ly)	Pt, pt
particle	Par, par
parting	Ptg
parts per million	PPM
patch (-y)	Pch, pch
pebble (-ly)	PbI, pbl
pelecypod	Pelec
pellet (-al)	Pel, pel
pelletoid (-al)	Peld, peld
pendular (-ous)	Pend, pend
permeability (-able)	Perm, k, perm
petroleum, petroliferous	Pet, pet
phlogopite	Phlog
phosphate (-atic)	Phos, phos
phyllite, phyllitic	Phyl, phyl
phreatic	phr
pink	pk
pinkish	pkish
pin-point (porosity)	p.p.
pisoid (-al)	Piso, piso
pisolite, pisolitic	Pisol, pisol
pitted	pit
plagioclase	Plag
plant	Plt
plastic	plas
platy	pity
polish, polished	Pol, pol
pollen	Poln
polygonal	poly
porcelaneous	porcel
porosity, porous	Por, , por
possible (-ly)	poss
predominant (-ly)	pred
preserved	pres
primary	prim
probable (-ly)	prob
production	Prod
prominent	prom
pseudo-	ps
pseudo oolite (-ic)	Psool, psool
pumice-stone	Pst
purple	purp
pyrite (-itized, -itic)	Pyr, pyr
pyrobitumen	Pybit
pyroclastic	pyrcl
quartz (-ose)	Qtz, qtz
quartzite (-ic)	Qtzt, qtzt
radial (-ating)	Rad, rad
radiaxial	Radax
range	rng
rare	r
recemented	recem
recovery (-ered)	Rec, rec
recrystallized	rexlzd
red (-ish)	rd, rdsh
reef (-old)	Rf, rf
remains	Rem
replaced (-ment)	rep, Repl
residue (-ual)	Res, res
resinous	rsns
rhomb (-ic)	Rhb, rhb
ripple	Rpl
rock	Rk
round (-ed)	rnd, rndd
rounded, frosted, pitted	r.f.p.
rubble (-bly)	Rbl, rbl
rudist	Rud
saccharoidal	sacc
salt (-y)	SA, sa
salt and pepper	s & p
salt water	S.W.
same as above	a.a
sample	Spl
sand (-y)	Sd, sdy
sandstone	Sst
saturation (-ated)	Sat, sat
scarce	scs
scattered	scat
schist (-ose)	Sch, sch
scolecodont	Scol
secondary	sec
sediment (-ary)	Sed, sed
selenite	Sel
shale (-ly)	Sh, sh
shell	Shl
shelter porosity	Shlt por
show	Shw
siderite (-itic)	Sid, sid
sidewall core	S.W.C.
silica (-iceous)	Sil, sil
silky	slky
silt (-y)	Sit, sit
siltstone	Sltst
similar	sim
skeletal	skel
slabby	sib
slate (-y)	Sl, sl
slickenside (-d)	Slick, slick
slight (-ly)	sli, slily
small	sml
smooth	sm
soft	sft
solution, soluble	Sol, sol
somewhat	smwt
sorted (-ing)	srt, srtg
south	S
spar (-ry)	Spr, spr
sparse (-ly)	sps, spsly
speck (-led)	Spk, spkld
sphalerite	Sphal
spherule (-itic)	Spher, spher
spicule (-ar)	Spic, spic
splintery	splin
sponge	Spg
spore	Spo
spotted (-y)	sptd, spty
stain (-ed, ing)	Stn, stn
stalactitic	stal
strata (-ified)	Strat, strat
streak (-ed)	Strk, strk
striae (-ted)	Stri, stri
stringer	strgr
stromatolite (-itic)	Stromlt, stromlt
stromatoporoid	Strom
structure	Str
stylolite (-itic)	Styl, styl
subangular	sbang
sublithic	sblit
subrounded	sbrndd
sucrosic	suc
sulphur, sulphurous	Su, su
superficial oolite (-ic)	Spfool, spfool
surface	Surf
syntaxial	syn
tabular (-ate)	tab
tan	tn
terriginous	ter
texture (-d)	Tex, tex
thick	thk
thin	thn
thin-bedded	t.b.
thin section	T.S.
throughout	thru
tight	ti
top	Tp
tough	tgh
trace	Tr
translucent	trnsl
transparent	trnsp
trilobite	Tril
tripoli (-itic)	Trip, trip
tube (-ular)	Tub, tub
tuff (-aceous)	Tf, tf
type (ical)	Typ, typ
unconformity	Unconf
unconsolidated	uncons
underclay	Uc
underlying	undly
uniform	uni
upper	u
vadose	Vad, vad
variation (-able)	Var, var
varicolored	varic
variegated	vgt
varved	vrvd
vein (-ing, -ed)	Vn, vn
veinlet	Vnlet
vermillion	verm
vertebrate	vrtb
vertical	vert
very	v
very poor sample	V.P.S
vesicular	ves
violet	vi
visible	vis
vitreous (-ified)	vit
volatile	volat
volcanic rock, volcanic	volc, Volc
vug (-gy)	Vug, vug
wackestone	Wkst
washed residue	W.R
water	Wtr
wavy	wvy
waxy	wxy
weak	wk
weathered	wthd
well	WI, wi
west	w
white	wh
with	wi
without	w/o
wood	Wd
yellow (-ish)	yel, yelsh,
zircon	Zr
zone	Zn

From Swanson, 1981, reprinted by permission of AAPG.