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Sampling and Analysis of Drilled Cuttings

Rotary Drilling and Cuttings Generation

Rotary Drilling and the Generation of Well Cuttings

While the environment and purpose of drilling will control the type, design, and capabilities of the rig used, the essential components used to "make hole" remain the same. All rotary rigs require hoisting, rotating, and circulating systems in order to locate and power the drilling tool on the bottom of the borehole.

Rotary drilling is accomplished by the rotation of a drill bit at the end of a rigid drillstem. The cooling of the drill bit and removal of rock cuttings is performed by the circulation of drilling mud down through the hollow drillstem and back to the surface. It is important for the present discussion to realize that although drilling fluid is commonly called "mud," it has, in fact, a complex and carefully controlled composition. The drilling fluid is required to:
have sufficient density to control subsurface pressures and prevent borehole collapse;
provide the carrying capacity to remove rock cuttings from the hole;
form a gel when circulation is halted in order to suspend the cuttings in place;
cool and lubricate the drill bit and drillstem;
line the borehole wall with an impermeable clay filter cake to protect exposed formations from contamination;
release the rock cuttings and debris readily at surface;
provide buoyancy to help support the weight of the drillstem when it is being lifted from the hole;
cause minimum pollution damage to the drilled formations and the surface environment;
minimize corrosion of and abrasion damage to the drilling equipment caused by downhole formation fluids.

In general, the drill bit is the most important component of the drillstem to the geologist not simply because it is the means of penetrating and exposing fresh formations, but because the process of penetration-the interaction between the drill bit and rock-yields important geological information. An understanding of this interaction allows the geologist to correlate the drill time, or rate-of-penetration log, with the cuttings recovered at surface to construct a lithological section with true boundaries and relationships.

Bit Type and Its Influence on Penetration

Drag Bit

The earliest type of rotary drill bit was the drag, or fishtail, Its simple scraping action is efficient at high rotational speeds in soft and plastic formations, and it is still sometimes used for this task, However, harder or more abrasive rocks produce rapid blade wear, even when the blades are hardfaced with tungsten carbide. Excessive rotary torque may subject such blades to "twist-off" failures; they also have a tendency to deviate from the vertical by following structural weaknesses, such as steeply dipping bedding planes or fault lines.

Tricone Bit

In 1934, the tricone rock bit was introduced; with subsequent refinements, it has remained the standard drilling tool. The tricone bit.

The cutting process of the tricone bit is the result of the crushing action of the teeth as they roll across the formation. Beyond a certain threshold weight per inch of bit diameter required to initiate rock failure, increasing the weight on bit will produce increased rate of penetration. However, a limiting weight on bit exists, beyond which further increase cannot induce increased crushing and may result in the bit becoming embedded and clogged in compacted debris.

The rate of penetration will also increase with increasing rotary speed up to a limiting maximum beyond which the buildup of crushed debris will again prevent further penetration. Additionally, both the use of excessive weight on the bit or of excessive rotary speed will result in accelerated wear and decreased bit life.

The key to optimum bit performance is to use suitable drilling fluid viscosity and flow rate so that cuttings can be removed effectively as they are created. Without this, increasing either the weight on the bit or the rotary speed will not only be ineffective in increasing rate of penetration, but will shorten the lifetime of and therefore the total footage drilled by the bit.

In order to maximize bit life, the teeth on bits designed for hard formations are short, broad, and closely spaced. This gives maximum tooth impact per bit revolution and reduces tooth wear and breakage. With this type of bit, rate of penetration will increase as rock strength decreases. In general, this indicates increasing porosity and decreasing cementation and rock cohesion. However, where rock matrix strength decreases, e.g., in clays, the soft material will clog the short, closely spaced teeth and prevent penetration. Thus in very soft formations, the hard formation bit will drill slowest!

By contrast, the teeth of soft formation bits are more widely spaced and are longer and more slender to allow better fluid circulation and removal of soft debris. Each tooth penetrates more deeply into the formation with a gouging action that removes a greater volume of formation per impact. Such bits will drill very quickly in soft lithologies, but the long teeth are easily broken when encountering a hard rock matrix or strong cementation. In this case, rates of penetration will decrease rapidly and the bit will soon be useless.

Jet Bit

The introduction of the jet bit greatly increased drilling efficiency and rate of penetration. Instead of flowing freely between the cones, drilling fluid is forced through three narrow jet ports in the face of the bit. This helps penetration by improving the removal of cuttings and soft debris from the bottom of the hole while simultaneously cleaning the face of the bit. In very soft formations, jetting alone may result in penetration, even without the bit touching the bottom of the hole,

Tungsten carbide inserts for tricone bits provide little or no improvement over the performance of an equivalent steel tooth bit. They do, however, extend bit life substantially.

Observing the performance of a tricone rock bit can be useful to the geologist. The bit will provide small but identifiable cuttings at the shale shaker. Its efficiency naturally depends upon the formation strength and porosity; thus its rate-of-penetration log will show sharp changes at lithological boundaries and relatively uniform, characteristic rates of penetration for each lithological type. A note of caution must be observed, however. While a bit will show increasing rate of penetration with decreasing rock strength (increasing porosity) for the range of formations it is designed to drill, outside of that range its performance may be anomalous. For example, a short-toothed bit designed for hard formations will become clogged with debris when drilling a soft formation and cease to drill.

Diamond Bit

The cutting action of the diamond bit consists of a continuous crushing and scraping process as the diamonds move over the surface of the bottom of the hole. Because the diamonds are small (they do not individually penetrate very deep; therefore, only sufficient weight on bit to cause compressive failure of the rock is required. Extra weight cannot give further penetration or cuttings removal. Because of their construction, diamond bits are vulnerable to damage caused by jolts or metal debris. On the other hand, rate of penetration is a direct function of rotation, and this relationship holds up to very high rotary speeds. It is common to operate diamond bits in combination with down hole motors to give maximum rates of penetration. Such rates do not commonly exceed those possible with tricone bits, but the strength and simplicity of the cutting structure allows very long bit life. Diamond bits may drill for thousands of feet and hundreds of hours without appreciable wear or reduction in rate of penetration.

For the geologist, however, the diamond bit is a far from ideal drilling tool. The shallow penetrating, scraping action of the bit makes it insensitive to rock strength and porosity variations. Unlike a tricone bit, the diamond bit will drill all formations, hard or soft, at relatively uniform rates, making the recognition of formation boundaries difficult. The grinding action of the bit produces, at best, very fine cuttings, sometimes little better than unidentifiable rock flour. At high rotary speeds, with downhole motors, frictional heating on bottom further degrades the cuttings, yielding debris burnt to the point that it can be mistaken for metamorphosed sediments.

PDC Bit

The polycrystalline diamond compact (PDC) bit combines high rates of penetration with wear resistance and long bit life, adding, as positive side effects, lithologically responsive rates of penetration and undamaged, identifiable well cuttings samples.

The PDC bit cutters consist of a disk of cemented tungsten carbide faced with a layer of synthetic diamond. This "drill blank" is as wear-resistant as diamond, but less susceptible to shock-induced breakage. The cutters do not crush rock, like a tricone or diamond bit, but scrape material from the bottom of the hole in the same manner as a drag bit. With this action, the rock fails by shear, not compression. This allows a much greater volume of formation to be removed with each rotation of the bit, especially in formations that exhibit plastic deformation. PDC bits, like tricone bits, have jets to ensure efficient bit cleaning and cuttings removal, even at the high rotary speeds obtained using down hole motors.

Although comparable in price to diamond bits, PDC bits offer a reduction in cost per foot because of their increased rate of penetration; in addition, they extend bit life beyond that expected for a tricone bit. Although cuttings from a PDC bit are usually smaller than those normally seen from a tricone bit, they are usually large enough to show lithological character and, even in the case where downhole motors are used, they are never pulverized or burnt like those from a diamond bit.

Uses of Cores and Cuttings

At the wellsite, the first use of well cuttings is for the preparation of a geological sample log. The more crucial study of cuttings and core samples, however, begins after the well is drilled. Such study examines:

paleontology and palynology for geological dating and stratigraphic correlation;

geochemistry of rock mineralogy, oil, and source kerogen composition;

measurement of porosity, permeability, and other petrophysical properties;

sedimentological studies of grain texture and sedimentary structures for regional geology.

The results of such sample examination become important for:

facies analysis and reservoir characterization;

reservoir engineering, well stimulation, and production programs;

reference material for partners, government agencies, and trade.

The value of all of these studies is based entirely upon the quality of the original sample. Every effort should thus be made to adopt drilling practices that provide best sampling conditions. However, the practical demands of drilling often dictate the use of methods, tools, or materials that may produce suboptimal well cuttings.

C.2. Sample Collection and Handling

Collecting and Handling Rotary Cuttings

A good wellsite lithological log requires good samples. This involves the accurate determination of the depth a sample represents, selection of a practical sample interval, careful collection, combination, and processing. In most cases, the well-site geologist will be responsible for supervision of cuttings sampling. However, the actual task of sample collection will commonly be delegated to other wellsite personnel. The job is best performed by the mud logging contractor, who will provide wellsite personnel with some geological training (in the case of the major contractors they may be graduate geologists). These people should be fully briefed on the geological section anticipated, particular zones of interest, and problems requiring special attention. Given adequate preparation, a mudlogging crew can provide a reliable sample series, prepare an initial descriptive log, and set aside individual samples of particular interest.

At the opposite extreme is the situation where sampling is assigned to a member of the drilling crew- usually the most recently hired and least experienced. In this circumstance, some time spent explaining the importance of maintaining a regular sampling schedule may be of value, but the geologist should plan to be present at the wellsite whenever important horizons are to be drilled. The common result of using drilling crews to catch samples is the phenomenon known as "boilerhousing" or "doghousing." At some convenient time, when other duties permit (normally at the beginning or end of the shift), the "roughneck" will bag and store away large numbers of samples, giving him a sufficient quantity to fulfill present, and some future, requirements. That such samples are of little or no geological value is not surprising. Some geologists have dismissed the use of well cuttings altogether as a result of working with such meaningless samples. This, however, is a mistake. Actual rock samples often answer crucial geologic questions; any adequate drilling plan will guarantee, as much as possible, the collection of useful samples.

Sample Lag Time

Well cuttings must travel with the drilling fluid to surface from the depth at which they are cut. Even in shallow holes with high fluid flow rates, this may take many minutes. In deep wells, the lag time may be two hours or more. It is necessary to "lag" samples, so that sample descriptions correspond to the depth of the bit at the time the sample was cut (bit depth will, of course, be somewhat greater by the time the sample reaches surface). The simplest method for estimation of sample lag time is a calculation of the annular volume between the drillstem and the borehole wall, and the time necessary for the circulation system to displace it:
Va = Ch-(Cp + Dp) (1)

(2)

(3)

Where:
V_a = Annular volume (ft³/ft of hole)

C_h = Hole capacity (ft³/ft)

C_p = Pipe capacity (ft³/ft)

D_p = Pipe displacement (ft³/ft)

S_a = Annular velocity (ft³/ft)

O_c = Output of drilling fluid pump (ft³/min)

T₁ = Lag time (min)

D = Depth (ft)

Separate calculations must, of course, be made for individual sections of the drillstem with different sizes of pipe, collars, and the like.

Pipe capacity and displacement may be calculated from simple geometry, but books are available, such as the Halliburton Cementing Tables, or Baker Tech Facts, that provide tables for quick reference of pipe displacements and capacities.

This lag calculation assumes that the internal diameter of the borehole is constant and equal to the bit diameter. This will be true of a cased hole (a wellbore that has been lined with cemented steel pipe) or a borehole in extremely hard, well-consolidated rocks. However, in most sedimentary sections, the weaker, less-consolidated rocks in the borehole wall will cave or spall, resulting in an irregular, overgauge (larger than bit diameter) borehole. A typical borehole will, therefore, have a larger annular volume, hence a longer lag time, than will be calculated. The lag time calculation also assumes a constant pump output and does not take into account times when the pump may be turned off, as, for example, when making a connection.

A more representative lag can be obtained by use of a tracer introduced into the circulation system and detected on its return to surface. It is also advantageous to measure the transit of the tracer through the system not as elapsed time, but by counting the number of strokes of the constant displacement drilling fluid circulation pump. A pump stroke counter will add increments only when the pump is running; its rate thus reflects the true pumping rate.

Any material may be used as a tracer that can be safely introduced at the top of the drillstem and can survive in a recognizable form that can be detected on return to surface. Rice, oats, other grains, or strips of colored cellophane, will pass safely through the jets of a drill bit and can be readily distinguished from cuttings on the shale shaker.

Use of visual tracers has one important disadvantage-someone must wait at the shale shaker for the first arrival to be seen. A better method is available if a mudlogging unit is being used. This unit is equipped with a digital pump stroke counter, as well as various gas detectors that draw samples from the returning drilling fluid (one of the main functions of mudlogging is the analysis of hydrocarbon gases in the drilling mud). A gas that does not naturally occur in the sedimentary section may be used as a tracer and its arrival automatically detected at the mud logging unit.

The most commonly used tracer is calcium carbide, a crystalline solid that can be conveniently introduced at the top of the drillpipe when a connection is made. Inside the drillstem it reacts with water to produce acetylene, a hydrocarbon gas that does not occur naturally.

A gas lag is acceptable for solid samples because the density and gel strength of drilling fluid prevent gas from rising and cuttings from settling in the annulus. Gas and cuttings lags are therefore synchronous when the drilling fluid is in good condition.

Sample Interval Selection

A representative sample log requires sampling at uniform intervals throughout the section. However, the sample interval must be governed by the rate of penetration. A sample depth interval should be selected that allows the personnel to collect and process samples properly while carrying out what other duties they may be assigned. Attempting to reduce the time available for sample catching and preparation will result in degradation of the quality of all samples.

Commonly, a sample interval of 30 ft is suitable in quickly drilled, shallow formations. As the borehole is deepened and the rate of penetration slows, the interval may be reduced, commonly to 10 ft. However, formation boundaries and thin zones of interest cannot be guaranteed to coincide with a fixed sample interval. Special samples should be caught when changes in the rate, or character, of penetration occur. This may be a "drilling break" (a sharp increase in rate of penetration indicating greater porosity), a reverse break (a sharp decrease), or a change in the way a certain rate of penetration varies over a short time (uniform or irregular), reflecting formation consistency and cohesion. The driller's rotary torque gauge is also a good indicator of changes in formation fabric.

When formation boundaries do occur, even if the lag time is accurately known, samples should be taken slightly earlier and slightly later than the expected arrival time. No matter how sharp a drilling break, lithology changes seen in well cuttings will always appear to be transitional. This is due to the small amount of sorting of cuttings by size, shape, and density that occurs in transit to surface. By "bracketing" the drilling break with samples, it is possible to obtain a true picture of the change taking place. Individual samples may be misleading, but a formation boundary can be recognized by the first appearance of a new lithology type, even if it represents only a small proportion of the total sample.

Sample Collection

The sorting by shape and density of cuttings occurs to a much greater extent in the drilling fluid conditioning equipment that removes solid material: the shale shaker, desander, desilter, and centrifuge. A totally representative sample requires the compilation of material from each of these. However, the desilter and centrifuge are only used intermittently to remove extremely fine solids. Such material, commonly known as drilling solids, consists of insoluble drilling fluid additives and finely abraded and unidentifiable cuttings debris. Sampling this material is rarely useful. The shale shaker and desander must be sampled and the samples combined at every selected sample point.

A geologist must always know what type of shale shaker is in use, when screens are changed, and the mesh size of the screen or screens used. He or she should also regularly check operation of the desander and request adjustment or replacement of the liner when required. If a desander is performing correctly, it will exhaust a stream of clean water and fine solids. If the exhaust is discolored with drilling fluid, repair or adjustment of flow rates is required.

If a conventional "rhumba" shale shaker is used, the screen nearest to the drilling fluid return flow line will have a greater proportion of large-sized cuttings. The second and third screens will have progressively smaller cuttings. Samples should be taken from all three screens and combined. On a modern double-decker shale shaker screens should be combined.

When drilling is slow, or when drilling is done with a small diameter bit, only a small volume of cuttings will be present on the shale shaker screen at any time. It will be necessary to make several visits to the shaker in order to accumulate sufficient material for a single sample. Remember that a single sample point must represent the formations cut between that depth and the previous sample point. A bucket or board placed beneath the shale shaker screens can be used to accumulate well cuttings between sample points. This is not a substitute for regular sample collection, but an acceptable alternative if a busy schedule requires it. If a catching bucket or board is used, then the geologist should instruct the drilling crew that the board or bucket is to be washed clean immediately after a sample is caught and at no other time!

The desander should be sampled by placing a sieve under the solids discharge

Sample Processing

After the well cuttings have been caught and accumulated for a sample interval, the cuttings must be split and prepared into several separate samples.

Unwashed Sample

Samples for paleontologic or geochemical analysis should be sealed in plastic bags or metal cans exactly as they come from the shale shaker, without any washing or other treatment (sometimes they may require the addition of a bactericide to the container before sealing). Geochemistry samples may need the combination of a drilling fluid sample with the cuttings sample, or a separate sample of each.

Containers for these and other samples should be clearly marked in waterproof ink with:

Oil company name;

Well name;

Well location and coordinates;

Sample depth interval (from/to).

On a "tight hole"(a high security exploration well), it may be necessary to report some or all of this information using a prearranged substitution code.

Archival samples are collected in labeled cloth sample sacks, about one pint in each. These may be shipped untreated, or may be lightly rinsed, to remove drilling fluid, and hung out to air dry. At least one set of archival samples is required on all wells for future reference and analyses. Extra sets may be necessary for partners in the well, for trade with other oil companies, or for government agencies (Geological Survey, Ministry of Petroleum, National Oil Company, and so forth). When numerous archival sample sets are required, collecting them can be close to a full-time job. Remember that members of the drilling crew cannot be relied upon for this. The mudlogging crew can collect one or two sets of archival samples as part of their normal duties, but if larger numbers are needed, they must take time from their other, more important work-gas, oil, and cuttings analyses. In such circumstances, additional temporary personnel whose only duty is the catching and bagging of samples under the direction of the geologist, or mudlogger, should be provided.

Washed and Dried Samples

At each sample point, approximately one pint of well cuttings (in addition to that required for archival samples) should be caught at the shale shaker, along with one quart of drilling fluid from the flow line, and about one minute's worth of desander effluent caught in a 170-mesh sieve (the actual volume of solids caught will depend upon the concentration of unconsolidated material in the drilling fluid).

The desander sample is lightly rinsed and set to one side for later examination. If the desander is operating correctly, this material should already be cleaned of drilling fluid.

The procedure for washing well cuttings samples should be agreed upon before the well is drilled so that later misunderstanding can be avoided. When drilling through an unconsolidated clay section, a lightly rinsed sample, after drying, will result in a geologically useless clay "brick." On the other hand, a sample that has been vigorously washed to remove all clay may later be misinterpreted as representing 100% of what are, in fact, only trace constituents. This is a common cause of disagreement between wellsite and laboratory personnel. The following procedure is intended as a guideline to avoid such problems.

The cuttings sample should be placed in the top of a sieve stack (8-mesh over 80-mesh over 170-mesh is usually adequate) and lightly rinsed to remove drilling fluid only. Contents of the 8-mesh sieve will be predominantly cavings from the borehole wall and can be set aside for later inspection. If the sample contains unconsolidated clay, a portion should also be set aside at this time before further washing.

From the material in the 80-mesh sieve, take about 100 cc and disaggregate it by blending with 600 cc of water. After blending, inspect the water surface for oil droplets, sheen, or petroleum odor (a mud logger will also take a gas sample from the blender jar). Decant the water and set aside the solid residue for later inspection.

If oil indications are seen, then repeat the blender test with 400 cc of drilling fluid and 300 cc of water. Small portions of unwashed cuttings and drilling fluid should also be checked under ultraviolet light for oil fluorescence (if none is immediately seen, try stirring the sample with a little fresh water). Record any oil observations; these will be included with the results of later oil tests.

If a "rinsed only," dried sample is required, remove sufficient material from the 80-mesh sieve for drying.

Wash the sample remaining in the 80-mesh sieve, manipulating it with the fingers in order to evaluate the clay content and consistency. Set aside a portion of the sieve contents for examination. Dry and bag the remainder of the sample for later reference.

Finally, rinse the material remaining in the 170-mesh sieve and decant any solids contained in the rinse water.

At the end of this process, several separate samples will be available for microscopic examination and evaluation (not all of them will always be required):

unwashed cuttings;

drilling fluid;

unwashed cuttings and drilling fluid diluted with fresh water;

8-mesh cavings;

80-mesh lightly rinsed cuttings;

80-mesh well washed cuttings;

170-mesh well washed cuttings;

170-mesh decanted washings;

desander effluent;

blender-decanted residue.

Cuttings Sample Examination: General Requirements

Evaluation of the prepared sample may be as sophisticated a procedure as available time and equipment allow. For routine wellsite sample description, the following is the minimum equipment required:

binocular microscope and illuminator;

ultraviolet light inspection enclosure;

sample inspection and drying trays;

sample reference trays;

tweezers;

steel probe or blade;

porcelain spot plate;

syringes or dropping bottles;

grain size comparison chart or graticule;

10% hydrochloric acid;

chlorothene (or other safe organic solvent);

phenol phthalein solution;

barium chloride solution;

silver nitrate solution.

Microscopic Examination: An Overview

At the microscope, the various samples should be arrayed in a single sample tray as shown in Figure 1 (Samples for microscopic examination ) , with a small quantity of each available to the microscope. A reference fray containing 80-mesh fractions from the previous 50 or 100 ft of drilling should be kept beside the microscope to assist the recognition of progressive changes in rock texture or color.

Thick layers of sample in the tray will cause focusing problems when the microscope is used to track across the sample. They also complicate the selection and testing of individual cuttings by tweezers or sample probe.

Initial cuttings evaluation should include the following characteristics:

rock type;

color;

hardness or induration;

grain size;

grain shape;

grain sorting;

luster;

cementation or matrix;

porosity (amount and type) and oil shows;

fossils, accessories, and inclusions.

These are commonly described in the order shown, although the last two may be reversed. Although "rock type" is the first item on this list, it should be the last determination and is, in fact, among the least important. The first and most important responsibility of the wellsite evaluator is to provide a complete and graphic description of the sample in terms that are detailed and comprehensive enough to allow their recognition and correlation when the same rocks are encountered in other drilled wells. The following are two sample descriptions:

Sst: bu.-wh., wI. ind., med.-crs., wI. rndd., wI. srt., sill. cmt., gd. intgran. por., gd.

Stn., gd. cut Fluor.

Ls: Pkst., brn., crs., fr. intpar. por., fr. cut Fluor:, sli. crinal., arg.

Abbreviations such as these are commonly used for on-site evaluation. Properly written out these descriptions would read:

Sandstone: buff-white, well indurated, medium-coarse grained, well rounded, well sorted, silica cement, good inter-granular porosity, good stain, good cut and fluorescence.

Limestone: packstone, brown, coarse grained, fair interparticle porosity, fair cut and fluorescence, slightly crinoidal, argillaceous.

Following the sample description, the wellsite evaluator must identify the stratigraphic unit of which a single sample represents only a small part. Also, it should be remembered that formation boundaries, no matter how sharp in reality, will appear transitional in well cuttings, due to the sorting of cuttings in the return annulus. It is necessary to review several samples before a valid decision can be made regarding the rock type and the true boundaries of a section. For example, a series of samples that, taken individually, might be described as silt-stones and argillaceous sandstones, might, when considered together and with reference to changes in rate of penetration and rotary torque, be interpreted to represent a uniform, massive shale with thin, clean sandstone intercalations.

Finally, in naming rock type, the wellsite geologist should beware of being too specific, possibly to the extent of implying mineralogical components or variations that are indeterminate at the well-site. An unjustified conclusion that is later disproved may result in doubt being cast on the whole sample log. A detailed and graphic description of a nonspecific "mudstone" or an unidentified "accessory mineral" will provide sufficient information and will draw the attention of specialist personnel during postdrillling studies, while avoiding unnecessary errors.

C.3. 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.

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. 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.. 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 .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.