SAMPLE EXAMINATION

2.2. ORDER OF CUTTINGS DESCRIPTION A standardised order of written descriptions is required. This ensures that all important rock properties are recorded, increases the uniformity of description among geologists (crucial on wells of long duration) and allows for ease of extracting information from a series of descriptions. Thus all changes in rock properties are easily identifiable. It is a requirement that cuttings descriptions be recorded in the Standard format presented below, to ensure consistency throughout the well between different geologists. Use CAPITALS as indicated by the abbreviations list. Where abbreviations do not already exist, use longhand. Where useful abbreviations could be introduced notify the local site office to obtain approval for adoption. The description will comprise a rock name with qualifier, colour, description of grains (m-c g sand, silt), a Dunham type textural statement, a description of cement and matrix, accessories, and porosity. It may even be necessary to follow the description with a note to clarify what you mean by a particular aspect of the description. Percentages of all new cuttings should be recorded in the cuttings register. Percentages of sample contaminants e.g. LCM should be recorded separately Where potential problem may exist e.g. excessive steel in the samples, advise the BP Rep. Use the following order:

GENERAL CARBONATES SILICICLASTIC Rock Type (Name of rock, qualifier)

e.g. LST dol; e.g SST qtz;

Colour

Texture Grain / crystal size, Grain type (skeletal/non skeletal), Grain / crystal shape, Sorting, Nature of framework, Dunham depositional texture e.g. skeletal wackestone

Grain size Roundness Sphericity Depositional texture Sorting

Cement, matrix type Matrix (micrite / micro-sparite / sparite), nature of residue e.g. siliciclastic, organic

Hardness

Fracture, break Check swelling props of clays Accessories

Fossils

Benthonic / planktonic, conodonts,macrofossils

Benthonic / planktonic, macrofossils

Structures

Porosity

Primary: intergranular, matrix, growth framework, chalky Secondary: intercrystal, vuggy, moldic, fracture

Shows

White light UV light

Example descriptions e.g SST qtz, wh lt gy grn, m - c g, well sort, subrnd-subang, sub sph - sph, grst tex, wk calc cmt, fria, glauc rr mica, gd vis por, patchy dk brn oil stn, wk yel dir fluor, bri yel cut fluor, instant blooming yel-wh crush cut fluor, dk brn cut col. e.g. LST; wh buff lt brn, m-c g, bioclastic grst, xln cmt, hd, ang brk, tr pyr, poor vis por

2.2.1. Rock Type - Siliciclastics Record the basic name in upper case e.g. SST (Figs. 2.1-2.4) followed by a compositional classifier e.g. SST lith.

Clay,mudstone or shale CL, MDST, SH Silt or siltstone SLT, SLTST Sand or sandstone SND, SST Gravel or conglomerate / breccia monogenetic v polygenetic

GRAV, CONG, BRECC

Tuff (lithic sandstone with >65% volcanic material)

TUFF

n.b Grain size is differentiated using a grain size comparator. Shale exhibits a well marked bedding plane fissility and does not form a plastic mass when wet, thus distinguishing it from

mudstone. 2.2.2. Rock Type - Carbonates Carbonate rocks comprise predominantly calcite and dolomite, the two principal rock types being limestone and dolomite/dolostone (Fig. 2.5).

% CaCO3 HCl Reaction in Test Tube Limestone LST 90 - 100 Instant, violent, specimen floats dissolving

within 5 min. Acid frothy

Dolomitic Limestone LST dol 90 - 50 Moderate and continuous Strong

Calcitic Dolomite DOL calc 50 - 10 Weak - accelerating after several minutes

reaction in warm

Dolomite / Dolostone DOL <10 Hesitating; beads form slowly, acid becomes milky

HCl

n.b. argillaceous, anhydritic and bituminous limestones react more slowly

Carbonate Stain Test

Red calcite - pure No stain dolomite - pure Mauve ferroan calcite Fe2+ poor Light blue ferroan dolomite Purple ferroan calcite Fe2+ rich Dark Blue ankerite

n.b. Reagent: 0.2%HCl + 0.2%Alizarin red S + 0.5% saturated K-ferricyanide 2.2.3. Rock Type - Evaporites

Name/ Composition Remarks RHOB (g/cm3) Dt (ms/ft)

Anhydrite CaSO4

Tasteless, not scratched by fingernail, sinks in Bromoform

2.98 50

Halite NaCl

Salty, soluble 2.04 67

Polyhalite K2SO4.MgSO4.2CaSO4 .2H2O

Variable solubility. White precipitate with BaCl2

2.79 57.5

Sylvite KCl

Salty (bitter) 1.86 74

n.b. See Appendix 2.1 for detailed notes. Sulphate Test: dissolve sample in 10% HCl, add few drops BaCl2 - dense white precipitate indicates sulphate 2.2.4. Rock Type - Coal Classify according to constituents: Humic Coal - woody, plant tissue dominant (gas-prone source rock). Further divisible by rank i.e. on the decreasing proportion of volatile constituents (water) i.e. peat lignite - sub-bituminous - bituminous - semi-bituminous. Distinguished by appearance and texture - laminated, friable in part, jointed, fibrous, bright 'jet' like layers, variable lustre, hardness/brittleness.

Sapropelic Coal - non-woody, comprises spores, algae and macerated plant material (oil-prone source rock). Distinguished by massive unlaminated glassy appearance, conchoidal fracture, firm rather than hard. Check coals for fluorescence, cut and crush cut fluorescence. Extra geochemical and biostrat samples must be taken when drilling through coaly sequences. Coals are clearly definable on wireline logs, particularly density-neutron. Neutron porosity is high due to the high hydrogen content of coal.

r (g/cm3)

Dt (µsec/ft)

fN

Lignite 0.70 - 1.50 140 - 180 >50 Sapropelic Coal 0.90 - 1.25 >50 Bituminous Coal 1.24 - 1.50 110 - 140 >50 Anthracite 1.40 - 1.80 90 - 120 >50

2.2.5. Rock Type - Organic Rich Mudstone (Source Rock) There are no clear guidelines for identification from cuttings but most potential petroleum source rocks (siliciclastic and carbonate) can be identified at wellsite. Samples of all fine grained sequences (siliciclastic and carbonate) should be checked periodically for shows by crush in solvent under UV light. Wireline logs are useful because relative to clay or carbonate minerals kerogen has a • low density • low velocity • high neutron porosity • high resistivity Relative to non-source rock intervals of similar lithology, rich source rocks are characterised by • an increase in apparent porosity from density, sonic and neutron tools • enhanced resistivity particularly when mature • high radioactivity (organic complexes concentrate Uranium) 2.2.6. Rock Type - Igneous / Metamorphic Basement rocks are frequently modified by weathering processes to the point where they are indistinguishable from sedimentary rocks. Well TD is often called on the basis of basement penetration. Weathered granites and acid gneisses can easily be confused because they are characterised by abundant quartz grains, muscovite, accessory minerals and secondary clay, with the ferromagnesian portion e.g. hornblende and biotite being chloritised. The resulting ‘sediments’ often resemble immature / arkosic sands. Weathered basic igneous and metamorphic rocks are also easily confused as weathering usually results in a combination of iron oxide and clay minerals. Deep weathering results in all the essential minerals being destroyed, leaving a brown or red clay containing a high proportion of limonite. Pyroclastic rocks cover the complete basic - acid igneous range, and the complete range of grain/clast sizes. Realistically only the finer grained end is seen in cuttings being described as tuffs. Tuffs can be differentiated on the physical nature of their components, e.g. vitric, lithic, crystal, and are given chemical qualifiers, e.g. acid, basic. Tuffs provide excellent marker horizons which can often be correlated over large areas e.g. Balder Formation of the North Sea. 2.2.7. Colour Wet colour - refer to GSA rock colour chart. General terms suffice. Describe pattern and distribution of colours e.g. banding, streaking, variegation, mottling etc, hence attention to colour on initial description is very important. Cements and matrix materials often determine colour. Limonite and haematite are yellow, red and brown. Carbonaceous and phosphatic material, iron sulphide and manganese impart grey to black colours. Glauconite, ferrous iron, serpentine, chlorite, and epidote are green. Colour changes in mud dominated sections may be critical in picking formation tops and sequence boundaries where logs prove inconclusive. Surface appearance is also noteworthy e.g. chalky, dull, earthy, vitreous, greasy, soapy etc. 2.2.8. Grain / Particle / Crystal Size A key attribute, frequently having a direct bearing on porosity and permeability, and may reflect environment of deposition. A modified Wentworth scale of grain or particle size is used (Fig. 2.6). Size grades must always be referenced to a grain size comparator. Also useful is a photographic grid of half-millimeter squares which can be fixed to the bottom of the sample tray.

2.2.9. Texture - Siliciclastics Texture refers to size, shape, and arrangement of rock components which make up the rock fabric (Figures 2.7 - 2.9). Texture of siliciclastics can be classified using the concepts of the Dunham approach developed for carbonates.

Mud supported

Grain supported

<10% grains

MUDSTONE

>10% grains

WACKESTONE

>30%* intergranular volume is mud filled

PACKSTONE

<30%* intergranular volume is mud filled

GRAINSTONE

*note percentages modified for clastics Sorting A measure of dispersion of the size frequency distribution of grains in a sediment or rock. It is determined by size, shape, roundness, specific gravity and mineral composition. Refer to sorting comparators on the BP grain size card.

Standard Deviation (sorting)

Verbal Description Standard Abbreviations

0.00 - 0.35 f very well sorted v well sort 0.35 - 0.50 f well sorted well sort 0.50 - 0.71 f moderately well sorted mod well sort 0.71- 1.00 f moderately sorted mod sort 1.00 - 2.00 f poorly sorted poor sort 2.00 - 4.00 f very poorly sorted v poor sort 4.00+ f extremely poorly sorted ext poor sort

bimodal may be used as an additional qualitative description Roundness & Sphericity Reference is best made to comparators. 2.2.10. Texture - Carbonates A modified Dunham scheme is preferred which incorporates Embry and Klovan's additional terms for depositional textures seen in reef facies - Fig 2.5.

Mudstone mdst < 10% particles, mud supported Wackestone wkst > 10% particles, mud supported Packstone pkst grain supported. Groundmass of mud Grainstone grst grain supported. Groundmass lacks mud. Sparite may be present Boundstone bdst components bound together during deposition by organisms that are

largely 'horizontal' e.g reef builders Bafflestone

bafflst bound during deposition by stalked organisms which trap sediment

Framestone framst bound during deposition by organisms which build a rigid framework Floatstone floatst >10% of the particles >2mm diameter, mud/matrix supported Rudstone rudst >10% of the particles >2mm diameter & clast supported

Carbonate sedimentary grains are susceptible to early post - depositional diagenesis. The main components are allochems (skeletal and non-skeletal grains), mud (which generally recrystallises to micrite), cement and terrigenous grains. Allochems are organised carbonate aggregates that may/may not have undergone transportation. Four types are important: intraclasts, pellets or peloids, oöids and skeletal fragments (bioclasts). Lime mud is derived mainly from biogenic degradation of skeletal and other grains and also from chemical precipitation. Micrite consists of crystals 1-4µm diameter occuring as the matrix to other particles which generally represents lithified lime mud. Sparite cement consists of clean calcite crystals, generally longer than micrite, forming pore filling cement between grains and within cavities. Textures in some carbonates can be clearly seen with the aid of special wetting agents such as mineral oil, glycerine or clove oil. 2.2.11. Cement, Matrix Type Cement is a chemical precipitate deposited around the grains and within the interstices of the sediment. Matrix comprises fine grained material deposited with the larger grains, and can also develop authigenically. Rock strength (cohesion) is a function of cement/matrix type. Note type of cement/matrix, hardness and amount; effect on porosity (is it occluding?)

2.2.12. Visual Estimate of Percentages Refer Fig. 2.10 2.2.13. Hardness The cohesive strength should refer to individual cuttings or chips and not to individual grains.

loose lse grains fall apart in dry conditions friable fria grains may be detached using fingernail, rock crumbles between fingers moderately hard mod hd grains can be detached using knife. Small chips can easily be broken by

hand hard hd grains cannot be detached with knife, fractures go between grains. Chips

difficult to break by hand. very hard v hd fractures pass through grains brittle brit rock breaks readily into sharp pieces e.g. coal plastic plas rock may be moulded with fingers

2.2.14. Fracture, Break Nature of break indicative of internal rock stresses and composition e.g. angular break, conchoidal, crumbly, fissile, hackly, splintery, and earthy. Marked slaking or swelling in water is characteristic of montmorillonites and distinguishes them from kaolinite and illite.

non-swelling non swell does not break up in water even after adding 1%HCl hygroturgid hygroturg swelling in a random manner hygroclastic hygroclas swelling into irregular pieces hygrofissile hygrofis swelling into flakes cryptofissile cryptofis swelling into flakes only after adding 1%HCl

N.B. if reaction in distilled water is inhibited by traces of oil add droplet of HCl to break oil film 2.2.15. Accessories Can be indicative of depositional environment. Common accessories and their densities are:- apatite - r 3.2, biotite - r 2.84, muscovite - r 2.91, pyrite - r 4.91, siderite - r 3.72, sphaerosiderite, chert, carbonaceous material, feldspar, glauconite, plant remains. 2.2.16. Fossils Macrofossils, microfossils and fossil fragments are used for correlation (Figs 2.12 - 2.14, Appendix 2.2) and may indicate environment. In known basins the wellsite geologist should be familiar with those diagnostic forms readily observable in cuttings and cores. 2.2.17. Structures Most sedimentary structures generally are not discernible in cuttings. Bedding, particularly in shales, may be evident as laminations. Secondary features may also be recognised e.g. brecciation, veins, fractures, recrystallisation, secondary cementation. 2.2.18. Porosity Estimate amount and type, preferably on dry cuttings. Samples with porosity must always be checked for hydrocarbons whether or not staining is seen.

f range(%) Good >15 Moderate 10-15 Poor 5-10 Trace <5

2.3. SHOWS The process has three stages: - Assessing the evidence obtained while drilling, which is used to decide whether or not to start, continue or cease coring; to

increase sampling rates; or to run wireline logs. - Evaluation of the final suite of electrical logs after drilling has stopped to recommend the running of additional logging tools

or to test the well.

- The overall assessment of the well results in order to decide the commercial worth of the well, by revision of reserves

estimates. The first and second tasks are carried out by the Wellsite Geologist in consultation with the Operations Centre. However a wellsite petroleum engineer will usually have prime responsibility both at the wellsite and in the office for the second task. It is useful for the Wellsite Geologist to be able to make a complementary assessment of the electric logs. In some circumstances the wellsite geologist may be the only BP representative at wellsite to carry out this task. The third phase of assessment is normally undertaken in the operating office. 2.3.1. Procedure for Show Description The approach outlined below is used to evaluate potential reservoir and source rocks from cuttings during drilling, and conventional core/sidewall core:

White Light

o Oil stain - describe degree of stain / percentage of reservoir lithology stained, stain colour, viscosity (dead, live, wax), gas bleed from cuttings and core

o Hydrocarbon odour -- none, slight, fair, strong o Cut - degree (streaming, blooming, instant), change in depth of colour with

time; crush cut colour

o Residual ring - thickness, degree and time taken, colour and depth of colour UV Light o Direct fluorescence - intensity, colour, percentage of relevant lithology, degree (pin point

etc) o Cut fluorescence - speed, intensity, colour, translucent / opaque Solvent cut samples

only of core and sidewall core, not the whole core o Crush cut fluorescence - speed, intensity, colour. Used to distinguish petroleum from mineral

fluorescence o Residual ring -

fluorescence colour, intensity,

Other o Oil in the mud - colour, volume, odour - take a sample (Section 4.5.5) o Gas in the mud - record total and chromatograph gas analyses - take sample from

possum belly (Section 4.5.3) o Cuttings gas - break up the cuttings and draw off the released gas for analysis o Acid test - if lithology is calcareous (carbonate or cemented sandstone) add 10%

dilute HCl to cuttings. Bubbles which form, if enveloped in oil, will persist at the acid's surface.

n.b. when evaluating shows the absence of one or more of the above is as important as its presence in making judgements on

the quality and nature of hydrocarbon in the reservoir. See Fig 2.11 for symbols. 2.3.1.1. Oil Stain Once a colour associated with hydrocarbons is established then the percent of stain in the total representative sample is estimated. Suspected cavings should be excluded from estimate. The visual percentage can be equated to a qualitative descriptor as follows

%stain show rating None No stain 0 - 30 Poor stain 30 - 60 Fair stain 60 - 100 Good stain

Oil stain may be difficult to detect on dried samples while on fresh cuttings viewed under the microscope an obvious oil stain may be apparent or small gas bubbles coming from the cuttings may be seen. The colour of an oil sand is a function primarily of the oil colour, with low gravity oil stains tending towards black and high gravity oil stains tending towards colourless. 2.3.1.2. Fluorescence All potential reservoir lithologies must should be viewed under ultraviolet light both before and after washing. Mud going into the hole should be sampled and checked for fluorescence to avoid confusion with any hydrocarbon shows.

Gravity (oAPI) Colour (at 3600Å) < 15 Brown 15 - 25 Orange 25 - 35 Yellow to Cream

35 - 45 White > 45 Blue White to Violet

Direct Fluorescence

High gravity oil stain may be colourless even though a uniform fluorescence is noted. Refined oils usually show white or blue-white, but pipe dope can be confused with mineral oil. Check the appearance of the pipe dope being used in ordinary light. Some minerals also fluoresce, e.g. calcite, some bentonites, feldspars, anhydrite, chert, dolomite and limestone. Fluorescence of these minerals is usually dull, although occasionally bright colours are seen. Mineral fluorescence varies, related to impurities and composition.

Cuts Cuts are made by dropping a non-fluorescent solvent (spectrograde Trichloroethane) onto washed cuttings in a watch glass or spot plate to distinguish between oil and mineral fluorescence. Examine the resultant solution in white and UV light for colour and fluorescence. If the solvent fluoresces, this indicates that oil is present. Oil alters the cut to a light yellow colour, which darkens with time. The immediate cut compared to the cut after standing is an indication of permeability. The slower the leaching of the cuttings, the lower the permeability. If the fluorescence does not spread, then it is due to mineral fluorescence.

Cuttings Gas Cuttings shows can be confirmed by using the cuttings gas detector. Gas is drawn off a sample, immediately after pulverising in an electric blender. The gas is fed into a gas detector as for the gas from above the drilling fluid returns - high readings usually indicate low permeability. Waxes - distinguish from dead oil by heating - should become liquid & mobile 2.3.2. Detection of Hydrocarbons in the Mud System 2.3.2.1. Oil in the Mud Sample all oil shows whether seen as an oil scum or irridescent sheen in the header tank / across the shale shakers or in cuttings samples. It is essential to collect a mud sample from the flow line when the lag time has elapsed after a fast drilling break. If a large mud sample is collected then enough oil may rise to the surface on standing for a small sample to be isolated for future geochemical analysis. In order to achieve the volume required skim the mud surface with a can. While standing orders are to be issued to the mudloggers to collect these samples the geologist should also view the "show" to obtain a clear picture of its quality. Oil in the mud can be detected by the mud engineer when a mud sample is retorted as part of his routine check on mud solids. 2.3.2.2. Analysis of Gas Readings During drilling, gas is continuously introduced into the mud system and eventually liberated at surface. Gas concentration measured at the surface is a function of rate of penetration, absolute pore volume and formation pressure. Rate of penetration (for a given rate of mud circulation) is the most important factor. On entering a hydrocarbon bearing zone, only hydrocarbons from the rock volume drilled are released into the mud system. Indeed some of the hydrocarbons in this rock volume are flushed into the formation by the positive differential pressure across the rock - mud interface. The mud cake which builds up prevents further hydrocarbons from being liberated into the wellbore. Therefore an increase in gas at surface indicates only that the rock has greater porosity than that above; it says nothing about permeability. During coring a smaller portion of the rock is mechanically broken down than when drilling, which together with lower penetration rates conspires to give lower gas concentrations at surface. 2.3.2.3. Total Gas Measurement Total gas levels may be determined using either catalysis or more modern flame ionization techniques depending on the logging unit in use.

Catalytic Filament Gas Detector This is an application of a Wheatstone bridge in which two of the resistors are replaced by matched platinum filaments (the reference and detector cells). One filament is open to air, the other is in a cell connected to the stream of ditch gas. The filaments are heated by passing current through the bridge, hence the name 'hot wire analyser'. The bridge is in balance when air is in the detector cell. Exothermic oxidation of hydrocarbon gases introduced into the sample cell further heats the detector filament, increasing its resistance and causing an electrical imbalance. A current proportional to the total gas present flows to a milliameter, the reading is recorded and output to a chart. Two meters are provided; one is set at a voltage which causes oxidation of all gases and records "total gas". The second is set at a lower voltage and hence lower temperature, which is sufficient to oxidize only wet gases (C2-C5). The difference between the two readings is the quantity of methane (C1) present.

Flame Ionisation Gas Detector

A continuous gas/air mix is fed into a constant temperature hydrogen flame, situated between two high-voltage electrodes. Hydrocarbon gases are ionized into charged hydrocarbon residues and free electrons. A constant proportion of the charged particles is attracted to the positive electrode, inducing a current proportional to the total concentration of hydrocarbon gas. This is measured as the 'C1 - equivalent' concentration, i.e. that of free carbon (C1) atoms.

The reading given by any gas will be a product of its concentration and its carbon number. The F.I.D. is calibrated to read 1.00 when a 1% mixture of methane in air is ionized. Thus a reading of 15.00 can be produced by the presence of 15% methane (15x1), or 3% pentane (3x5), or, for example, a mixture such as 5% methane, 2% ethane, 1% propane, 0.5% butane and 0.2% pentane [(5x1)+(2x2)+(1x3)+(0.5x4)+(0.2x5) = 15.00]. The F.I.D. is more accurate than the catalytic detector, especially at high gas levels, where the latter is difficult to attenuate and tends to saturate. The F.I.D. has a greater dynamic range than the catalytic detector, is less likely to be affected by temperature changes, and is unaffected by normal amounts of CO2, N2 and H2S. 2.3.2.4. Chromatographic Gas Detection The composition and proportions of individual gases in the ditch gas sample are determined by gas chromatography. A fixed quantity of the ditch gas is passed at regular intervals through a column of inorganic granules, wherein gases of different density migrate at different speeds and separate out. The separated gases are then analysed either in a catalytic or flame ionization detector depending on the type fitted. The proportions of each component gas are displayed as a chromatogram. The chromatograph can also be used to analyse cuttings gas, i.e. that produced by pulverising a fixed amount of cuttings in water. The ratio of cuttings gas to ditch gas may be of use in estimating the permeability of a reservoir unit. 2.3.3. Oil Based Mud (OBM) Oil based muds usually give increased rates of penetration and greater hole stability. The drawbacks are reduced efficiency of some resistivity logging tools (dual laterolog and FMS) and the obscuring of hydrocarbon shows. Identifying which hydrocarbons come from the formation and which from the mud can be resolved by careful observation and a simple test. Before any potential hydrocarbon bearing interval is drilled, samples of the oil based mud should checked for a 'base' fluorescence. Properly conditioned OBM should show no fluorescence but it must be checked. Keep aside a fresh sample for reference. The gas chromatograph will show the 'base' gas volume (%). When a hydrocarbon bearing formation is penetrated differences in the mud fluorescence can be noted by comparison with the stored mud sample. The reference mud sample should not be taken before a casing point if the potential reservoir is in the next hole section. Mud conditioning may alter the OBM properties. The stored sample should correspond as closely as possible to the mud used when drilling the reservoir. Similarly, departures from the base reading on the chromatograph allow a proper evaluation of the formation gas to be made. If the oil based mud does fluoresce a simple filter paper test can distinguish between formation and drilling hydrocarbons. Due to the different densities of formation and mud oils they will migrate across filter paper at different rates. The test involves dissolving hydrocarbons from a cuttings sample with organic solvent and dripping it onto a filter paper. Under UV light the different oils will be seen forming concentric rings on the paper. Comparison with the standard or base OBM sample, which should show just one ring, will allow a good evaluation of the formation hydrocarbon fluorescence.