Sampling and Analysis of Drilled Cuttings (Sample Description)

Sample Description

Rock Material

Sample Description

All sample descriptions should include mention of the characteristics mentioned below. A thorough discussion of sample description is beyond the scope of this resource; for this the reader is referred to the excellent and comprehensive Sample Examination Manual by R.G. Swanson, published and made available by the American Association of Petroleum Geologists.

Color

Color may be specific to individual grains, matrix, or cement in the rock, or it may be a combination of the colors of all grains in a fine-grained ground mass. Color, hue, and intensity will vary upon illumination and sample dryness. For consistency, color evaluations must be performed with the same microscope magnification (10-power is recommended), illumination, and sample wetness as is used for other descriptions. Where color is not evenly distributed, the description should explain distribution between grains, utilizing such terms as spotty, mottled, streaky, or variegated. Where superficial mineral or hydrocarbon staining is present on cuttings, this should be noted and, if possible, the colors of staining and unstained background described.

If a color reference is required, the Geological Society of America Rock-Color Chart is recommended. However, in most cases, general color terminology will suffice, e.g., dark gray-brown. Interior decorating nomenclature such as "brick red" or "chocolate brown" should be avoided. These "colors" vary widely in popular perception and rarely resemble the thing for which they were named.

Hardness

Hardness and induration are estimated both visually, by observing the amount and distribution of cement, and physically, by testing the well cutting's resistance to a probe. In addition to actual strength (loose, weak, friable, hard, etc.), the description should also include mode and surface texture of rock breakage, for example:

massive crumbly

blocky platy

laminated flaky

hackly splintery

fissile foliated

In general, this characteristic is often of more importance to the drilling engineer than the geologist, but this does not minimize its importance.

Grain Size

Grain size estimation from well cuttings requires the use of a Grain Size Comparison Chart that can be viewed beside the sample through the microscope. Such charts, either printed on translucent film, or consisting of actual sand grains cemented to a card, are available from geological supply houses or service companies. A good estimate should report the mean grain size within each cutting and within the sample as a whole. More than a single grain size population may occur within a single sample and should be reported separately, e.g., medium to medium-fine grained with occasional coarse grains.

Grain Shape

Grain shape is a critical factor in determining the sedimentary source and history of the rock (e.g., grain rounding increases with distance of transportation). Shape also has a large effect on reservoir porosity and permeability (e.g., increasing roundness allows better grain-to-grain contact and reduced porosity). The two characteristics of grain shape are roundness and sphericity ( Figure 1 ,Grain shape: roundness and sphericity ).

Roundness is a measure of the grain angularity or lack thereof. Sphericity is a measure of the equality of axial ratios of the grains. For example, an ideal cubic grain would be described as angular but subspherical; conversely, a sausage-shaped grain is well-rounded but elongate. The roundness and sphericity descriptors shown in Figure 1 may be supplemented by additional shape-descriptive terms, e.g., bladed, fibrous, acicular, platy, tabular, nodular, etc.

Sorting

Combining estimates of grain size and shape with their distribution will give a measure of the degree of grain sorting within the rock. A gross rule of sorting is given by:
Good -90% or more of 2 or less Wentworth sizes;

Fair-90% or more of 3 or 4 sizes;

Poor-90%% or more of 5 or more sizes.

For each sample, however, this rule needs to be refined to some extent, according to the total number of size distributions present. For example, 800/c of a rock may consist of fine, well I-rounded, spherical sand grains. This obviously represents excellent sorting. If the remaining 200/c is made up of scattered subangular to angular grains that range from coarse sand to granule size, the gross population can be described as fair or even poorly sorted four or more size and shape populations. Such a description would be misleading; a qualification is, therefore, required in order to describe the rock as having a well-sorted groundmass with poorly sorted accessory grains.

Luster

Luster is more than a characteristic of appearance. It is a reflection of the fine surface features of the rock grains or crystals. This microstructure may be more visible on dried cuttings than wet, or when the grains are coated with mineral oil, or are rotated relative to the light source.

Physical abrasion and chemical corrosion of grains are common causes of surface texture. The most often seen textures and their resultant lusters are-
For a clear, shiny, broken grain or euhedrall well-formed crystal

vitreous (glassy)

faceted

conchoidal

For a lightly worked, abraded surface

silky

pearly

polished

For a deeply etched, or scoured, translucent surface

frosted

dull

etched

For a surface showing signs of pinpoint impact, or solution pits and grooves

pitted

striated

grooved

Another cause of luster is external coatings and stains thick enough to modify the grain surface texture and color, but not so great as to cover it. Such coatings may be dull, sooty, or earthy in appearance, or they may be more reflective, giving a waxy, soapy, or slick luster. (The term "oily," because of its implication of actual petroleum, should never be used to describe the luster of a solid coating or stain.)

Cementation

The mineralogy and distribution of cement in a rock is critical to its strength, porosity, and permeability-and hence its capacity to hold and produce hydrocarbons-both in its original state and after stimulation (fracturing or acid treatment). The most common cementing materials are calcite, silica, and clay, but other carbonates, oxides, and sulfides may also be present in smaller quantities. In general, the difference between cement and matrix is one of relative amount. For example, as shown in Figure 2
(Cementation and matrix in clastic rocks ) and Figure 3 (Primary porosity in clastic sedimentary rocks ), where substantial grain-to-grain contact exists, the bonding material between grains is cement, regardless of whether that material is from a secondary source, or is derived from solution of the grains themselves.

Where minor quantities of detrital or secondary minerals are present within the matrix or between grains (but without any appreciable cementing strength), these minerals are described as accessories or inclusions. Similarly, microfossils or macrofossil fragments that do not constitute the bulk of the rock are also accessories, i.e., of no importance to the physical strength or characteristics of the rock, but of major interest in determining its source, and its pre- and post-depositional history.

Porosity

Porosity, commonly expressed as a percentage, is the ratio of the pore volume to total volume of the rock. Permeability is a measure of the ability of a porous rock to transmit a flowing fluid. Microscopic examination can only allow a qualitative estimate of these. Accurate determination requires core analysis.

Primary, intergranular porosity is readily visible and is commonly classified as follows:
Good-15% or more;

Fair 10% to 15%;

Poor 5% to 10%;

Trace-2% to 5%;

Tight 2% or less.

Permeability is governed by porosity and cementation, and is also relatively easy to estimate visually (in a qualitative sense). If the blender gas analysis test is performed, then this test also provides a guide to the permeability of the rock. A high gas reading from the disaggregated sample indicates that low permeability has prevented the escape of gas from the cuttings during their transit to surface. In this case, only after disintegration in the blender will the sample release the entrapped gas.

Secondary porosity is commonly diagenetic in origin and on a large scale relative to the size of cuttings or even cores. Joints, fractures, solution structures such as vugs and caverns, and shrinkage voids resulting from recrystallization are common forms of secondary porosity. The volume of pore space created by such structures is on a scale too large, or too irregularly distributed, to be reliably estimated from well cuttings.

Secondary porosity is often particularly important in carbonate rocks, Ii me-stones, and dolomites. Figure 4 (Carbonate porosity can occur on many scales ) displays the various types of carbonate porosity commonly found in reservoirs. Note that complex combinations of these can characterize a single reservoir. It is usually significant in sandstones only when they are well cemented and indurated-in other words, when most of the primary porosity has been destroyed by diagenesis.

Although secondary porosity cannot be reliably estimated in cuttings, its presence should be recognized and reported. Solution voids can be seen as concave surfaces on cuttings. Both these voids and fractures are often marked by solution pitting, striations, or, alternatively, by secondary mineralization, infill, or mineral staining. While large scale secondary porosity cannot be seen directly, its presence should be detected by these signs and reported.

Rock Type

Finally, after thoroughly describing all visible features of the sample, it is necessary to identify the mineralogy in order to determine a rock "name." For the geologist, this should be a relatively routine task. The following brief guide is provided for the engineer who may be required to perform limited wellsite geological surveillance.

Practically speaking, there are only two classes and five subclasses of sedimentary rocks with significant occurrence in petroleum exploration geology ( Figure 5 , Classicfication system for sediments and rocks encountered in petroleum exploration ). These are-
Detrital rocks: derived from the physical and chemical weathering, transport, and deposition of previously existing rocks. These are divided into two subclasses.
Arenites: rocks having grains that are visible to the naked eye or hand lens. Commonly consisting of quartz or feldspar fragments, they may be further subdivided into sandstones (grains visible to the naked eye), and silts tones (grains visible with the hand lens only).

Argillites: rocks having grains that cannot be distinguished even under low-power magnification. These may be further subdivided into three types: shales (those having a strongly developed fissility or foliate texture), claystones (lacking fissility, but known to consist primarily of clay minerals), and muds tones (lacking fissility, but containing significant amounts of some identifiable or unknown mineral other than clays).

· Chemical rocks: precipitated from sea or lakewater by organisms (formation of shells, etc.), extensive evaporation in restricted basins, or solution and reprecipitation by subsurface ground-waters. Of this type, the most significant subclasses are-
Marine Carbonates: rocks formed from the accumulation of the shell and skeletal debris and from the chemical solution, recrystallization, and alteration of calcium carbonate in the form of aragonite and calcite minerals.

Evaporites: salts precipitated as water evaporates in restricted lake or marine basins. These commonly consist of coarse crystalline halite, gypsumlanhydrite, calcite, dolomite, and "bittern" salts.

Diagenetic precipitants: crystalline deposits formed by the deposition of minerals from ground waters. Lime-stones and dolomite rocks commonly result from the recrystallization of marine carbonates. Chert sometimes forms in thin beds and nodules due to the precipitation of amorphous quartz from ground water.

Microscopic examination, in conjunction with a few, simple chemical tests, will usually identify which members of this basic classification are present.
· Fresh water
Clay minerals and claystones will soften, expand, or disperse when immersed in fresh water.

Evaporitic salts will rapidly dissolve in fresh water.

Dilute hydrochloric acid
Calcite and limestone will rapidly dissolve with effervescence because of the release of carbon dioxide.

Dolomite will dissolve extremely slowly. The reaction, however, may be stimulated by heating.

· Silver nitrate solution
Chlorides (halite or bittern salts) will give a white precipitate of silver chloride.

· Barium chloride solution
Sulfates (anhydrite or gypsum will give a white precipitate of barium sulfate.

· Steel blade
Feldspar and calcite crystals can be scratched or crushed by a steel blade or needle. Quartz grains cannot.

Quartz silt grains in mudstone will scratch a steel blade. Carbonate and clay minerals in limestones and claystones will not.

Descriptions of rock type can have either one or two parts: the first is always the principal lithology and is underlined (e.g., LS, Sh, Sst); the second, if used, is a textural adjective term of general significance (e.g., packstone, lithic).

The geologist will be familiar with more comprehensive rock classification systems, such as that shown in Figure 5 . Carbonate rocks are especially variable in occurrence. Several specialized classification systems have been published.

Hydrocarbon Evaluation

Inspection for oil should begin with the unwashed sample. Sample processing and microscopic examination should be followed by a systematic oil evaluation procedure.

First, the tray of washed sample should be viewed under the microscope. Cuttings that have an apparent oil stain (oily luster, yellow, or brownish discoloration) should be selected from the tray and placed on a clean spot plate (only one cutting per spot!). Next, these cuttings should be inspected under ultraviolet light. Crude oil will fluoresce with a color and intensity characteristic of its density. Low density, high gravity oils are light yellow to gold in color and have bright gold, white, or blue-white fluorescence. Heavy, low gravity oils are dark brown, green, or black in color and have dull yellow or brown fluorescence. Comparison of the oil stain color with its fluorescence will confirm the type of crude oil present, or indicate the presence of a contaminant. For example, diesel oil has a yellow-gold stain, but negligible dull brown fluorescence.

Drillpipe thread grease (pipe dope) is heavy and has a dark brown or black natural color, but extremely bright, blue-white fluorescence color. Inconsistency between the natural and fluorescent colors is a conclusive sign of contamination.

A second tray of washed 80-mesh sample should be prepared and viewed directly under ultraviolet light (
Figure 1 , Testing cuttings for oil stain and fluorescence ). This provides an estimate of the overall amount and distribution of fluorescence throughout the sample. From this tray, representative fluorescent cuttings should be transferred to a clean spot plate (one cutting per spot!). These cuttings are then examined under the microscope and the color of any oil staining observed. This "double blind" test method ensures that only true crude oil shows (selected on the basis of both natural and fluorescent color, and appearance) are evaluated and contaminants are recognized.

Finally, cuttings in the spot plate are tested for solvent "cut." This involves adding chlorothene (or another safe organic solvent) to the cutting and observing the process of oil solution under ultraviolet light. Notation is made of the speed and manner with which fluorescence spreads into the solvent, of the color of the fluorescence, and of the natural color of the oil liberated from the cutting.

Light oil will almost instantaneously dissolve in solvent; heavier oils will dissolve more slowly and the intensity of the color of the fluorescence will gradually increase in the solvent. Heavy, residual (immovable) tarry oils will dissolve extremely slowly and have a very dull fluorescence.

The cut test is also a qualitative indicator of permeability in the rock. Even light oil cannot dissolve in the solvent if low permeability prevents the latter from entering the pores, or oil from leaving. If low permeability exists, solvent fluorescence will be bright, but unevenly distributed, spreading out from the cutting in swirls or streams.

A streaming cut may sometimes occur when oil mobility is impeded by a high wax content. This wax reduces permeability when the sample is brought up out of its original environment to cooler surface temperatures. This can be confirmed by repeating the cut test on cuttings that have been treated with hot water. This will improve the cut speed of waxy oils by lowering their viscosity, but will have no effect if the original cut was streaming as a result of low natural permeability. Conversely, crushing the cutting or treating it with acid will remove cement and enhance permeability, thus giving a faster cut for light oils. For waxy oils this permeability enhancement may improve the uniformity of the cut, but the cut will still remain slow.

In addition to oil, there are some minerals that fluoresce under ultraviolet light. The most common of these are calcite and pyrite. Mineral fluorescence tends to be less intense but more uniformly distributed than oil fluorescence. It will not respond to a solvent cut test, and hence is unlikely ever to be confused with oil fluorescence.

Problems in Evaluation

Well cuttings collected at the surface will be contaminated with previously drilled material, drilling fluid additives, and other debris. Some of these contaminants cannot be easily distinguished from fresh cuttings and may cause false, or erroneous, sample descriptions.

Cavings

The most common form of contamination is cavings-material that has collapsed or sloughed from the borehole wall. Often, cavings are much larger than cuttings, and may be conveniently removed by rinsing the sample through an 8-mesh sieve. However, some cavings may produce fragments small enough to pass through the sieve. Even these are usually larger than cuttings, and, since they have not been ground by the drill bit, will usually have a more angular, sharper edged, "fresher" appearance than cuttings.

Gumbo

In the worst circumstance, caving may occur in shallow, unconsolidated beds. These may be sandstones, siltstones, or, worst of all, soft, wet clays. These clays become further hydrated by the drilling fluid, reaching a semifluid state in which they swell viscously into the borehole. This problem necessitates the use of very high drilling fluid circulation rates in order to prevent the borehole from collapsing altogether and trapping the drillstring. On surface, drilling fluid, cuttings, and caved clays arrive at the shale shaker in a thick, sticky, hydrated mass that drilling crews call "gumbo." This material will plug the flow line, block the shale shaker screen, and prevent the geologist from drawing any reasonable conclusions about formations encountered below such clays. The only solution is to set casing, thus isolating the weak, shallow formations.