Chap 2 Coring And Core Analysis Processes.pdf

CHAPTER 2 CORING AND CORE ANALYSIS PROCESSES

Chap 2 Coring and Core Analysis Processes.DOC

Special Core Analysis

CONTENTS : CHAPTER 2

1.

CORING AND CORE ANALYSIS PROCESSES

1

2.

CORING

3

3.

4.

2.1 Core Types 2.1.1 Conventional Core 2.1.2 Sidewall Cores

3 3 3

2.2 Core Liners 2.2.1 Gel Cores

2 2

2.3 Sponge and Pressure Core Barrels 2.3.1 Pressure Cores 2.3.2 Sponge Cores

3 3 3

CORE ANALYSIS LABORATORY PROCESSES

6

3.1 Core Handling

6

3.2 Core Arrival

8

3.3 Core Gamma Ray Logging

8

3.4 Core Scanning

9

3.5 Core Plugging

10

3.6 Plug Measurements

12

3.7 Core Slabbing and Resination

13

3.8 Core Photography

13

PETROGRAPHIC TESTS

15

4.1 Thin Section Analysis 4.1.1 Selection and Preparation 4.1.2 Carbonate Phase Staining 4.1.3 Quantitative Nodal Analysis 4.1.4 Thin Section Descriptions 4.1.5 Sandstone Classification 4.1.6 Carbonate Classification 4.1.7 Example Thin Section

16 16 16 17 18 18 19 19

4.2 Scanning Electron Microscopy

23

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4.2.1 4.2.2 4.2.3

Background Analysis Techniques Analysis

23 23 23

4.3 X-Ray Diffraction 4.3.1 Theory 4.3.2 Whole Rock Preparation and Analyses 4.3.3 Extraction of the Clay Fraction and Analyses 4.3.4 Examples

26 26 26 27 28

5.

CORE-LOG DEPTH MATCHING

31

6.

REFERENCES

36

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Coring and Core Analysis Processes

Figure 1-1 provides a flow chart for a typical core analysis process. The processes are summarised below: 1. Normally nowadays, core is recovered in aluminium or fibreglass liners. Previously, core was extracted from the barrel at wellsite. Following coring the core or core liners are recovered and assembled at wellsite. The core lengths are marked with tramlines and way up/depth markings. This aids re-assembly in the lab. Dean-Stark plugs may be taken for later analysis in the lab. Preserved samples may be taken at regular or defined intervals at wellsite or, if the core is recovered in liners, in the lab. 2. The core is boxed (or if recovered in liners, cut into suitable lengths) and shipped to the laboratory. 3. In the lab, the core is removed from the boxes or liners, re-assembled and checked for depth conformity. 4. The core sections are then passed through a gamma logger. This is essential for core-log depth matching. 5. Two plug sets are taken: one for routine porosity, permeability and fluid saturations (the RCA plug set) and the other plug set (usually taken from preserved samples) is scheduled for special core analysis (SCAL). Both horizontal and vertical RCA plugs are taken for analysis. On occasion, plugs are taken and preserved for later SCAL. 6. The plugs are cleaned and dried (fluid saturations may be measured) then subjected to porosity and permeability analysis. 7. The remainder of the core is slabbed (probe permeability measurements may be made on a surface-dried slab face) then photographed under white and UV light. 8. The slabs and plugs are then despatched to the operator’s core store and/or to partners and regulatory authorities where they are archived. A thin slab may be resinated to help protect the core from deterioration. Each of the processes are described below and in later Chapters of this course. It should be remembered that many stages in the process - cutting , recovering and handling the core; core plugging, cleaning and drying, provides an opportunity for core damage – that is the in situ core petrophysical properties are permanently altered. This is discussed in detail in the following Chapter.

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ROUTINE CORE ANALYSIS PROCESSES

Coring Conventional/Liner

Core Recovery & Catching Wellsite Dean-Stark Plug at wellsite Preserve Test in lab

Core Shipping Arrival in Laboratory

Core Removal & Assembly Layout Core Preserve Samples

Gamma Ray Log Depth Matching

Core RCA

Preserved Samples SCAL

Plugs Cut H & V Plug sets

Core

Dean-Stark/Retort Determine Fluid Saturations

Slabbing

Plug Preparation Cleaning and Drying

Probe Permeability

Air Permeability

Core Photography White Light and UV

Helium Porosity

Resination

Well Archive Figure 1-1: Coring and Core Analysis Processes Chap 2 Coring and Core Analysis Processes.DOC

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2.

Coring

2.1 Core Types 2.1.1 Conventional Core Figure 2-1 illustrates typical conventional core bits. Conventional coring techniques work well in many reservoir formations. So long as the well-site geologist has adequately marked both the core and its boxes, no particular problems are encountered in dealing with conventional core. However, jumbled sections are not infrequently encountered. Generally, the core is removed from the barrel at wellsite under uncontrolled conditions, then broken into 1m lengths and placed in wooden or reinforced cardboard core boxes for onward shipment. The core should never be washed for wellsite inspection but should be wiped down with a damp rag prior to inspection. Preserved samples are taken at wellsite.

Figure 2-1 Conventional Core Bits

2.1.2 Sidewall Cores Sidewall cores are taken to minimise coring costs or to obtain reservoir rock samples in an interval which has either been cored and core recovery lost, or in an interval which has not been cored. There are two main types as illustrated in Figure 2-2 and Figure 2-3:

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Percussion sidewall. This consists of a tool with a series of core “bullets” loaded with explosive charges. Typical sizes are 1” by 1”. The core bit is similar to a chisel. The bullets are loaded into the tool which is run in on wireline to the interval of interest. The gun is fired and the explosive charge shoots the bullets into the formation. The mini core plugs cut by the bullets are retained within the bullets which are then brought back into the tool using a wire chain and the tool returned to surface. The principal advantage with this method is that it is cheap. There are few advantages with this method. The driving force required for the bullets to penetrate the formation can cause stronger rock to fracture and weaker rocks to consolidate. Porosity and permeability data measured on such samples will not be representative. The prime application of percussion sidewalls is therefore restricted to obtaining samples for lithological description, grain size, and palynology and paelontology, although grain density measurements and particle size analysis measurements should be possible. Rotary sidewall. This was developed to overcome the problems with percussion sidewalls. The tool consists of a series of mini core bits within a wireline tool. The tool is lowered to the zone of interest and the core bit is extracted and pressed against the borehole wall. Mud is circulated through the tool which causes the core bit to rotate and take the sample. On completion, the bit is retracted into the tool and the tool is taken back to surface. The quality of the plugs taken by this tool is far superior to the percussion sidewall. Generally, reliable porosity and permeability data can be obtained on the plugs. However, it is much more expensive and provides fewer plugs.

Figure 2-2 Percussion Sidewall Tool

Figure 2-3: Rotary Sidewall Tool

2.2 Core Liners Core liners were developed primarily to prevent damage to the core associated with conventional core barrel assemblies. The core bit is similar, but the barrel has an inner liner Chap 2 Coring and Core Analysis Processes.DOC

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into which the core is retained as it is cut. The liners may be rubber, fibreglass (Figure 2-4), or (aluminium) Figure 2-5. Liners were first developed for unconsolidated core but almost every core caught in the North Sea recently is caught in liners. Rubber sleeve coring was the first successful technique for coring unconsolidated or poorly consolidated formations. It suffered from restrictions, being especially prone to mechanical failure and problems caused by inexperienced crews. Even in successful operations, cores were frequently contaminated by drilling mud, and disrupted by "twist-off". Fibreglass (or plastic) sleeves (liners) are more commonly used today: these can be utilised in standard core barrels giving much larger diameter cores. With careful operation, core recoveries approaching 100% can be achieved in poorly consolidated formations, even including Niger Delta reservoirs, which a number of operators had previously written off as impossible to core. The core liners are frozen, or the annular space between the core liner and the core is filled with resin, to prevent damage to the core on shipment. Unfortunately, wellsite geologists are only able to inspect the ends of each cut core section, so that wellsite lithological core description is limited. The liners are usually removed in the laboratory, under better controlled conditions, and the lithology revealed. If the rock is competent, the core can usually be easily pushed out of aluminium or fibreglass liners. However if the rock is weak, extracting the core will result in unacceptable disturbance, so in this case, plug samples are often taken through the liner prior to removing the core, and the liners must be carefully cut open to reveal the core. In cores recovered in liners, preserved samples are identified and selected under controlled conditions after the core is shipped to the laboratory.

Figure 2-4: Fibreglass Liner

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Figure 2-5: Aluminium Liner

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2.2.1 Gel Cores The recent development of an encapsulated gel coring system holds promise in preventing core damage during and after coring. For example, Baker Hughes 1 Core Gels 3 and 4 are non-toxic polypropyleneglycol-based zero spurt-loss gels which, when pre-loaded in the inner tube of the core barrel, protect core from drilling mud filtrate invasion and flushing during and after the coring process (Figure 2-6). The purpose of Gel Coring is to help preserve in situ saturations and rock properties of the reservoir sample and to improve core recovery and reduce jamming. As the core is cut and enters the inner tube, it displaces all but a substantial coating of gel which remains on the core for protection. The Gels form a water-impermeable latex-like film on the surface of the core. Core Gel 3 and 4 are high viscosity materials at ambient conditions. This allows the gels to adhere to the core and also protect it while in transit to the lab. Because the Core Gels come into direct contact with the core surface during and immediately after coring, the core is protected from drilling mud filtrate invasion. This process helps provide the core analyst with an unaltered reservoir rock sample, e.g. with formation fluid saturations that are largely undisturbed. In addition, the Core Gels provide a stabilising material in the annulus space between the inner barrel and the core, helping to support and protect the core on its trip to the surface and thence to the laboratory. Baker Hughes claim great success for the system, but early job results were mixed.

Figure 2-6: Gel Coring System (Courtesy Baker Hughes)

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2.3 Sponge and Pressure Core Barrels As the core is brought to the surface, the hydrocarbon fluid will expand and, in an oil reservoir, gas will be liberated when the oil is brought below the bubble point. Gas liberation or expansion provides a force which will cause displacement of both the native fluids and the invaded mud filtrate. Gas evolution can cause mechanical damage to cores from loosely consolidated formations, but this can be minimised by pulling the last few hundred feet of the core barrel string very slowly. The use of pressurised or sponge core barrels provides a means to prevent loss of oil from the core on hydrocarbon expansion on core recovery. There primary use is to prevent loss of oil from the core during filtrate invasion and gas evolution on core recovery. Both sponge core and pressurised core barrels are often used to determine oil-in-place in depleted zones prior to improved oil recovery project evaluation. 2.3.1 Pressure Cores The core is maintained at the reservoir pore pressure within the barrel until arrival at the laboratory. The barrel is then slowly depressurised and the volume of evolved gas determined using a gas meter (Figure 2-7). From a knowledge of the PVT properties of the oil, the volume of oil originally in the core can be determined. The whole core is then cleaned and the pore volume determined. The volume of oil determined from gas evolution and the pore volume are used to determine saturation. The application of this techniques has been constrained by its expense, safety considerations, and the availability of laboratories with the necessary equipment to handle pressured cores. 2.3.2 Sponge Cores Sponge core involves the use of a polyurethane sponge liner in the annular space between the barrel and the core. It is oil-wet, so that it adsorbs oil that bleeds from the core and holds it opposite the formation from which it bled (Figure 2-8). Sponge core analysis usually utilises whole cores. The oil from the sponge adjacent to is extracted in a specially adapted soxhlet apparatus (Figure 2-9). The oil content of the extracted oil/solvent mixture from the sponge is determined from gas chromatography, and is added to the volume of oil extracted from the adjacent whole core by conventional cleaning. From subsequent pore volume measurements on the whole core, the total oil saturation is obtained. It is much cheaper and safer than pressure core barrels and can be successful under most circumstances.

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Figure 2-7: Pressure Core Barrel

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Sponge

Core

Liner Figure 2-8: Sponge Core Barrel

Figure 2-9 Extractor for Core Sponge

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3.

Core Analysis Laboratory Processes

3.1 Core Handling Inadequate core handling, storage and treatment cause the reservoir geologist as many problems as do operational difficulties with coring. Many clients now specify the services of a core analysis contractor to receive and box the core. This minimises error through coring vendor company personnel inexperience. Wellsite core analysis personnel can also perform wellsite core gamma logging which assists in the re-assembly of the core in the laboratory. Core caught in liners can be transported to the laboratory in 30ft or 90ft lengths, or are cut to 3ft lengths. In the former case, it is essential that, at rigsite, the liners are supported during handling and lifting, otherwise the core liners can flex (especially if fibreglass liners are used) and cause mechanical damage to the core (Figure 3-1).

Figure 3-1: Core Liner Flexing Causes Core Damage Chap 2 Coring and Core Analysis Processes.DOC

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Cutting the liners into shorter lengths minimises this problem. The sequence of events which a core will undergo after its arrival on the rig floor (or in the lab if recovered in liners) is as follows: •

Removal from core barrel or liner (not always straightforward).

•

"Way-up" marking.

•

Depth marking

•

Division into 1-m lengths

•

Sealing in foil or plastic

•

Crating

•

Preserved sample selection

The opportunities for error are high at this stage: transposition of core pieces is not uncommon and lengths may be reversed. In the case of conventional core, it may be tempting to "fit in" rubble at the end of each core length. The core is marked to ease its re-assembly in the lab and to prevent transposition errors. Schema vary from company to company but should be consistent within a company. A typical example is shown in Figure 3-2.

Depth

Figure 3-2: Typical Core Marking The core sections are firstly marked with “Tramlines”. These are vertical continuous bands of colour running the length of the core. Typical colour relationships are red on the right and black or yellow on the left as viewed when looking at the core from the bottom up. Whatever method is used, it has to be consistent. A circular depth marker is then marked on the core at regular intervals, often with an arrow pointing to the top of the core. Chap 2 Coring and Core Analysis Processes.DOC

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Core recovered in liners is not usually removed at wellsite. The core liners are often marked and cut into 1 m lengths prior to shipment to the lab where the core is removed and remarked, as above. On occasions, core plugs for Dean-Stark analysis are taken at wellsite. The processes are described in a later Chapter. 3.2 Core Arrival The lab is firstly required to carefully piece all the core back together in the correct sequence. Every break in the core should be categorised by the laboratory (e.g. goodness of fit) to aid in depth matching core and log data and to identify loss of core recovery, natural or induced fractures, etc. 3.3 Core Gamma Ray Logging A gamma ray log is almost always run in a conventional wireline or LWD log suite. The principal reason for running a gamma ray log on a core is to match driller’s depth (core depth) against wireline log depths, which is the common reference depth in a well. Both depths are frequently different. Both total and spectral (uranium, thorium and potassium ratios) core gamma logs can be run to assist in the depth matching process. Core gamma ray response is normally provided in counts per second (cps) whereas wireline logs are in API. It is possible to calibrate the gamma ray logger provided a suitable secondary API standard is available, although cps and API are correlated linearly. Thus core data and wireline data can be plotted on the same scale and where each trace overlaps the core and log depths can usually be matched. Typical equipment (Figure 3-3) includes: •

A time or speed controlled conveyor belt for core up to 4 m long.

•

A sodium iodide gamma ray detector with lead shield

•

A analyser system (multi-channel)

•

A chart recorder or computer data acquisition system.

The core is laid out, measured and marked (Section 3.2) then placed in sections on the gamma ray logger belt. Typical scan speeds are around 1 ft/min. Radioactive standards are often used to determine the logger response. The output us total (or spectral) gamma counts as a function of depth. Core gamma ray logs can also be run at rigsite, using portable, handheld loggers. This enables correct depth matching when the core is removed from the liners in the lab.

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Figure 3-3 Core Gamma Ray Logger 3.4 Core Scanning Increasingly, technology is being applied to scan the core in its liner, prior to plugging. This includes linear X-Ray and CT (Computer Tomograph) scanning. An example of a CTscanned core section is shown in Figure 3-4). In this representation, high density material (heavy minerals, barites from the mud system) show up light grey/white whereas low density material (and many fractures) appear dark. CT scanning is therefore use to select representative plug locations, avoiding heterogeneous, invaded, or fractured intervals.

Figure 3-4: CT-Scanned Core Section (Courtesy Core Laboratories) Chap 2 Coring and Core Analysis Processes.DOC

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3.5 Core Plugging Measurements of petrophysical parameters requires the preparation of representative samples, normally right cylindrical plugs. In extremely heterogeneous formations – fractured or vuggy carbonates for example, measurements are often made on whole or full diameter core. Normally two plug types are required (Figure 3-6): 1. Horizontal samples. These are plugs taken parallel to the apparent bedding plane features not perpendicular to the long axis of the core. The objective is to sample the maximum permeability in the formation which is normally parallel to bedding. Sample frequency is typically 1 per ft (25 cm). 2. Vertical samples. These are plugs taken perpendicular to the bedding not parallel to the long axis of the core. These sample the minimum permeability direction. Sample frequency depends on lithology but are around 1 per 5 ft (1.25 m) to 1 per 10 ft (2.5 m). One of the problems that arises, especially in the case of steeply dipping reservoirs or highly deviated wells, is that plug orientation is not at a constant angle to bedding features. Samples from sleeved cores must be taken 'blind' unless the sleeved core is first examined under a CT or linear X-ray scanner. The sampling may tend to be biased . The lab technician may move the sampling location to avoid shale intervals, fractured or rubble zones, etc, or zones where making a measurement on the plug would be difficult or time consuming. In RCA programmes, 1” or 1.5” diameter plugs are taken at approximately 1 foot intervals. The use of larger plugs is preferred since the errors involved in porosity and Dean-Stark measurements on small plugs can be large and can have a significant impact on the data. For example, the pore volume of a 1” plug is about 4 times smaller than the pore volume of a typical 1.5” plug of the same porosity. The plugs should be ideally taken from the centre of the core to ensure that a non-invaded samples is obtained (this is essential for Dean-Stark measurements and for SCAL plugs).

Figure 3-5: Core plug taken from centre of core Special Core Analysis

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Core plugs are taken using a diamond-tipped, hollow cylindrical, rotary core bit mounted on a drill press (Figure 3-7). A variety of tip lubricants are used, depending upon the fluid content, core drilling mud, and lithology/mineralogy. Typical plugging fluids are: •

Brine (made up to same composition as formation water)

•

Depolarised kerosene, base oil, or mineral oil (e.g. Blandol) which are used where brinerock incompatibility is expected or where cores are cut with oil-based mud.

Plugs should never be taken with tap water as the coolant as this can cause severe problems if the core contains authigenic clays. If there is any doubt about potential problems arising from water-formation incompatibility then depolarised kerosene or mineral oil should be used.

Figure 3-6 Correct and Incorrect Horizontal and Vertical Plugs

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Figure 3-7: Drill Press. Circulating fluid system tank shown 3.6 Plug Measurements In many cases, two sets of plugs are taken: “hot-shot” and conventional plugs. The hot shot plugs are required to provide immediate information, usually in 24 hours turnaround. These are normally horizontal plugs that are cleaned and dried quickly to provide preliminary information – initial log calibration, selection of perforation intervals, etc. The conventional plug set are subjected to more rigorous, consistent and uniform testing procedures that must not be compromised for client expediency. Typical measurements on plugs principally include: •

Fluid saturations (Dean-Stark and retort)

•

Porosity

•

Air Permeability

These are discussed in separate Chapters.

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3.7 Core Slabbing and Resination The core sections are slabbed after plugging, using a masonry saw, to provide a clean surface for detailed description and for photography. Slabbing is essential for adequate reservoir description, as it allows detailed observation of sedimentary structures poorly displayed in the rough outer surface of the core. A trained operator is essential, as mis-orientation can be confusing, and saw-marks may obscure 'real' features. The number of slabs will depend on the number of partners and government regulatory requirements. In the UK, cores are often cut into three sections (Figure 3-8). The biscuit slab is normally preserved by resination in which the slab is immersed to just below its top surface in epoxy resin. Slabbing should be performed parallel to maximum apparent dip.

Slab 1

Slab 3 “Biscuit” Slab

Figure 3-8: Typical Core Slabbing Arrangement

3.8 Core Photography Large format photography is a valuable technique, as it •

Provides a permanent record of core plug sites, depths, etc

•

Often reveals features which may later be rendered invisible by subsequent drying or deterioration.

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The core photographs should be clearly labelled and should include plug numbers (even porosity and permeability) and preserved sample intervals. Many labs now provide digital images which can be incorporated into petrophysical and geological software packages. However, unless special techniques such as infra-red or UV photography or X-ray methods are used, the resolution of sedimentary structures in heavily oil-stained cores may not be good, and detail shots are necessary to record specific bedding features. Nevertheless, it is recommended that cores always be photographed and, even if cores remain in good condition, these photographs should be reviewed during any subsequent reservoir study. Both white light (Figure 3-9) and ultra-violet (UV) images are required. UV photography (Figure 3-10) provides an indication of the presence of remaining oil (after flushing with filtrate) through oil fluorescence. The value of UV photography is enhanced by the inclusion of beakers containing different oils and/or oil-based mud filtrates which may fluoresce differently from the native oil. Comparison of oil and OBM fluorescence helps identify oilbearing intervals.

Figure 3-9: White Light Photograph

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Figure 3-10: UV Photograph

4.

Petrographic Tests

Petrographical analysis techniques allow a much more detailed description of the rock textural and cement properties that control petrophysical properties than is possible with the naked eye or a binocular microscope. In particular, these techniques are used to identify delicate grains and cements that might be easily damaged in the procedures used to prepare cores for analysis: such as core plugging, cleaning and drying. There is little point in measuring the rock properties in core analysis if the structure of the rock has been altered by inappropriate preparation techniques. If sensitive minerals can be identified prior to the core analysis programme starting, the core preparation procedures can be amended to suit. The most common petrographic analytical techniques which the core analyst can employ are: 1. Thin section analysis 2. Scanning Electron Microscopy (SEM). 3. X-Ray Diffraction (XRD) These tests are normally included in the routine core analysis programme, though they may be specified separately or , indeed, included in the SCAL programme.

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4.1 Thin Section Analysis 4.1.1 Selection and Preparation Samples are selected from core plug end trims or adjacent core pieces, Sample pieces are vacuum-impregnated with colour-dyed resin in order to facilitate identification and illustration of the pore space, then cut and lapped to a standard 30 micron thickness. Sections are then stained in: a) sodium cobaltinitrite to reveal alkali feldspar and; b) combined Alizarin Red-S/potassium ferricyanide to distinguish varieties of calcite and dolomite. The section is then cover-slipped, usually permanently. 4.1.2 Carbonate Phase Staining In order to facilitate the identification of major carbonate mineral phases, thin-sections are routinely treated with the combined stain solution formulated by Dickson2. The stain is prepared by mixing together solutions in HCl of Alizarin Red-S and potassium ferricyanide, in the approximate ratio 3:2. Prior to cover-slipping, the thin-section is lightly etched in dilute HCI, then placed in the combined stain solution until sufficient stain is fixed. Final treatment with Alizarin Red-S only (intensifier) may be used if necessary. On the basis of the stain colours produced, varieties of calcite and dolomite are distinguished as follows: •

Non-ferroan Calcite produces stain colours ranging from very pale pink, through shades of orange-pink ("peach") to purples sometimes of fairly intense tone. Colours should lack any blue hues.

•

Non-ferroan Dolomite does not react and remains unstained.

•

Ferroan Calcite typically produces the colour Turnbull's blue, a fairly dark shade of Royal blue. With a weaker reaction, paler sky-blue colours may be produced. Pink-colour AR-S pigment is usually visible beneath the blue and contributes to the overall colour tone. Shades of mauve/violet with a weak blue component are thought to indicate lower iron content.

•

Ferroan Dolomite stains a fairly consistent turquoise blue or cyan, the colour tone intensifying to reflect increasing immersion time or crystal solubility. Confusion with ferroan calcite may arise in cases where the shade approaches a deep sky-blue, but with dolomite the stain tends to be ragged and incomplete due to its poorer solubility in HCI. Other optical properties are always considered in order to confirm identification.

Siderite may react very sparingly and take pin-points of blue stain. It is not uncommon for coarse sparry calcite (eg. grainstone cement) to remain unstained. Such varieties are. however, usually non-ferroan.

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4.1.3 Quantitative Nodal Analysis Modal analysis is a technique used for determining the quantitative mineralogy of a thin section. The data is presented in a tabulated form which lists the percentage abundance of every recorded constituent. Results of the analysis can be used for: •

Classifying samples within a general scheme

•

Comparison with other samples

•

Use as a statistical data base

Typical equipment includes a microscope with an automatic camera and a motor driven stage, together with a personal computer with point-count totaliser software with connecting interface unit to drive attached stage. Prepared thin sections are point counted using the Line Method. The line method involves counting the number of constituents present in a given thin section sample. This is done by counting individual components (for example. framework grains, clays, cements or pores) encountered by the intersection of the cross-hairs along linear traverses spaced equidistantly along the slide. The result of the method is a “number frequency” that simply shows how often particular components were encountered during the count. This "number frequency'' is automatically recalculated as a percentage figure by the point-count software. The percentage figure obtained from these modal analyses is related to, but distinctly different from, the area, volume or weight of any constituent present within that thin section. Stage interval: The stage interval setting is used to vary the number of points observed during one traverse of a slide. The point-count software allows the operator to select the desired stage interval prior to each point count. Ideally, the stage should only land on an individual grain once during a point count otherwise the sample will become biased due to an increased probability of a larger grain being encountered several times during an analysis than a smaller one. Consequently, the stage interval is set so as to advance the slide by a distance equivalent to the average grain size of that sample. However, within the majority of samples analysed, individual grains do not have the same cross-sectional area and consequently some element of bias towards the coarser fraction is to be expected but can be kept to a minimum by adjusting the stage setting. At the end of each traverse, the slide carrier is pulled back to reset it ready for the next traverse and the ratchet knob is turned to present a new section of the slide. For general purposes 300 points is a good number to count in order to get the maximum level of accuracy for the minimum investment of time. Below 300, the probable error increases rapidly, whereas above 300 it decreases slowly. However, the particular type of investigation being done determines the number of grains to be counted. A thin section is placed with the point-count stage holder and set so that the point count will start at the top left hand corner of the sample. The mineral beneath the cross-hairs is identified according to its optical properties (using plane or doubly polarised light as appropriate) as defined by Deer et al3 and Kerr4 . The relevant channel button is pressed once to record the occurrence of a particular component and is stored as a running total within the automated computer point-count system. The stage traverses automatically as each button is pressed, and the next mineral identification is made. When the edge of the thin section is Chap 2 Coring and Core Analysis Processes.DOC

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reached. the thin section holder is pulled back to reset it ready for the next traverse and the ratchet knob is turned a small amount to present a new area of the slide. When the target count has been reached, the point count program immediately displays a percentage listing of the various recorded components and allows the operator to enter trace proportions of any rare components which were present within the slide but not encountered under the cross-hairs during the counting procedure. These components are noted as traces in order to distinguish them from completely absent minerals in the thin section. When all the thin sections have been point counted, a print out of the modal table for all samples may be obtained. 4.1.4 Thin Section Descriptions Utilising the modal analysis data obtained during point counting, systematic descriptions of samples are made. Three levels of thin section description exist: a) Standard b) Intermediate c) Detailed A standard description lists major authigenic phases. porosity types and reservoir controls. Intermediate format is similar but also has an additional section to deal with specific client requests, for example a diagenetic sequence or information pertaining to fractures. Detailed level descriptions include a systematic listing of all detrital components, authigenic phases and porosity types present in a sample as well as a sample summary, a diagenetic sequence and a section on porosity and permeability characteristics. In addition. each level of description gives: 1. A visual estimate of grain size range and mean using graticule measurements which can be converted to microns or the Wentworth size class (for example, fine sand, granule, pebble) using the classification table above. 2. A visual estimation of sorting using charts for visual estimation of sorting based on Pettijohn et al. al 5 (Figure 4-1). 3. An estimation of grain packing (compaction) based on the grain contacts of framework quartz grains (Allen6 ) Figure 4-2. 4. A note on the overall fabric of the thin section visible on a thin section scale. For example, horizontal lamination of micas, ripple cross-lamination, bioturbation or fracturing. 5. Where requested by a client, an assessment of the sphericity of detrital framework grains using images of representative grains (Figure 4-3) after Pettijohn et a/. (1973). 4.1.5 Sandstone Classification The point count software automatically classifies sandstone samples according to a scheme illustrated in Figure 4-4. This classification system recalculates the quartz, feldspar and lithic components of a sample to 100% and the values obtained are plotted on a triangular graph. Chap 2 Coring and Core Analysis Processes.DOC

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The sample plots in a position respective to these three calculated values, and the corresponding area of the graph is identified to describe the basic sandstone classification. This simple, three-variable spectral classification may then be qualified according to the following conventions: 1. If the detrital matrix clay content is equal to or greater than 15%, then the suffix wacke is used; if less than 15% the sandstone is classified as an arenite. 2. If any authigenic mineral is present in amounts equal to or greater than 10%, then an adjectival prefix is added such as dolomitic, kaolinitic, illitic, siliceous, is used as appropriate. 4.1.6 Carbonate Classification The classification of carbonate lithologies is based upon a combination of the schemes of Folk7 and Dunham8. This approach is adopted to enable comprehensive naming of limestones according to both composition and depositional fabric. The scheme of Folk is used to describe the objective (spectral) composition of the limestones and reference is made to allochems - bioclasts, ooliths, intraclasts, pellets, peloids - and orthochems which comprises interparticle matrix or micrite and forms of sparry calcite or sparite. Using a convenient form of abbreviation for allochem types, compositional rock names are generated e.g. biopelmicrite, oobiosparite etc. 4.1.7 Example Thin Section An example of a thin section from a North Sea reservoir sandstone is shown in Figure 4-5.

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Figure 4-1: Sorting Classification

Figure 4-2: Compaction Classification

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Figure 4-3: Roundness and Sphericity

Figure 4-4: Sandstone Classification

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Figure 4-5: Example Thin Section This view shows a moderate to poorly sorted quartz arenite, Grain coating and pore lining residual hydrocarbons are developed on the grain surfaces. Note the presence of hydrocarbons covering quartz overgrowth terminations indicating a post quartz overgrowth hydrocarbon migration. Primary intergranular porosity (18.5%) is dominant and occurs evenly through the sample, averaging 150 microns in size. Interconnectivity between pores is generally well developed with compactional and silica overgrowth contacts, although abundant are not pervasive. Secondary porosity (2%) is formed from the often complete dissolution of unstable grains to give oversized pores (about 350 microns). The oversized pores add considerably to the interconnectivity of the intergranular pore network. The high modal porosity coupled with the limited compaction, open pore network enhanced by secondary dissolution and the absence of any significant pore occluding authigenic cement indicates substantial reservoir potential. The sample helium porosity is 17.6%, and the air permeability is 580 mD.

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4.2 Scanning Electron Microscopy 4.2.1 Background SEM analysis allows the detailed evaluation of rock specimens and can provide unique insights into the nature of the rock pore structure and the location and morphology of cements (especially clays). Conventional light microscopes use a series of glass lenses to bend light waves and create a magnified image. The Scanning Electron Microscope creates the magnified images by using electrons instead of light waves. The SEM shows very detailed 3-dimensional images at much higher magnifications than is possible with a light microscope. The images created without light waves are rendered black and white. Samples have to be prepared carefully to withstand the vacuum inside the microscope. Because the SEM illuminates them with electrons, samples also have to be made to conduct electricity. SEM rock chip samples are coated with a very thin layer of gold using a sputter coater. After the air is pumped out of the column, an electron gun [at the top] emits a beam of high energy electrons. This beam travels downward through a series of magnetic lenses designed to focus the electrons to a very fine spot (Figure 4-6). Near the bottom, a set of scanning coils moves the focused beam back and forth across the specimen, row by row. As the electron beam hits each spot on the sample, secondary electrons are knocked loose from its surface. A detector counts these electrons and sends the signals to an amplifier The final image is built up from the number of electrons emitted from each spot on the sample. The SEM has a large depth of field, which allows a large amount of the sample to be in focus at one time. The SEM also produces images of high resolution, which means that closely spaced features can be examined at a high magnification. 4.2.2 Analysis Techniques Samples are prepared for SEM analysis by removing a small freshly fractured rock fragment measuring less than 1cm diameter following air or critical point drying. Individual fragments are cemented onto aluminium stubs with collodial carbon. Electrical conductivity is established by applying a thin film of gold in a sputter coater and, where necessary, by applying a coating of colloidal carbon around the base of the sample. Samples are analysed in a scanning electron microscope fitted with an EDAX energy dispersive X-ray microanalyser 4.2.3 Analysis All SEM analyses should be carried out by an experienced operator, with extensive interpretation skills in clay mineralogy, texture and morphology. Clay and cement phases are identified using a combination of morphology and qualitative EDS microanalyses, and compared with in-house photographic records, published manuals and standard EDS mineral traces. Example of SEM photomicrographs are shown in Figure 4-7

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Figure 4-6: SEM Schematic

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c

d

a

b SEM Photomicrograph (x 654): This view shows occasional well-developed kaolinite (a) occasionally filling pores, with traces of calcite cement (b). Note quartz overgrowths (c) and pyrite framboid (d). This is a clean, fine grained poorly cemented sandstone. Detrital and authigenic clays are rare and the main causes of porosity reduction are via quartz overgrowths. 16.2% Porosity: 150 mD Air Permeability

SEM Photomicrograph (x 425): Clean, fine grained sandstone with well developed quartz overgrowths. Note fibrous illite bridging pores. 18.1% Porosity: 304 mD Air Permeability

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4.3 X-Ray Diffraction 4.3.1 Theory Structural information about locations of atoms in a crystalline mineral can be deduced from the sharp diffraction spots the crystal produces from the sharp diffraction pattern in a beam of X-Rays. Put simply, the phenomenon of diffraction occurs when penetrating radiation, such as X-rays, enters a crystalline substance and is scattered. The direction and intensity of the scattered (diffracted) beams depends on the orientation of the crystal lattice with respect to the incident beam. (Figure 4-8). Any face of a crystal lattice consists of parallel rows of atoms separated by a unique distance (d-spacing), which are capable of diffracting X-rays. In order for a beam to be 100% diffracted, the distance it travels between rows of atoms at the angle of incidence must be equal to an integral multiple of the wavelength of the incident beam. D-spacings which are greater or lesser than the wavelength of the directed X-ray beam at the angle of incidence will produce a diffracted beam of less than 100% intensity. Diffraction occurs at an angle of incidence equal to the Bragg angle, θ

λ = 2d sinθ Most diffractometers in petrographic applications utilise a powdered sample, a goniometer, and a fixed-position detector to measure the diffraction patterns of unknowns. The powdered sample provides (theoretically) all possible orientations of the crystal lattice, the goniometer provides a variety of angles of incidence, and the detector measures the intensity of the diffracted beam. The resulting analysis is described graphically as a set of peaks with % intensity on the Y-axis and goniometer angle on the X-axis. The exact angle and intensity of a set of peaks is unique to the crystal structure being examined. A perfect crystal has welldefined, single peaks (Figure 4-9), whereas a imperfect crystal has a broader distribution. Amorphous material (such as liquid or glass) has poorly defined diffraction peaks. In a multi-component mixture, confusion can arise when two or more components have a peak in the same, or nearby, location on the X-axis. It is for sorting out these mixtures that a good search/match engine or a search method becomes most important. The X-Ray diffraction method is most useful for qualitative, rather than quantitative, analysis (although it can be used for both). 4.3.2 Whole Rock Preparation and Analyses Selected samples are gently disaggregated under alcohol in an agate mortar, and the resulting slurry is transferred to a micronising mill (comprising agate segmented bars) and alcohol-reduced for a period of ten minutes. Samples are dried at 60°C down to 22°C in dry air, and then back-filled into an aluminium holder (4g of sample) to produce a randomly orientated powder mount. Alcohol is used during preparation to prevent damage to water-sensitive phases, and to reduce damage to the lattice. Two scans are run for each sample to determine major crystalline phases. Chap 2 Coring and Core Analysis Processes.DOC

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1. After temperature stabilisation the random powder sample is analysed using CuKa radiation at a scan speed of 1 °20m-1 over an angular range of 1.5 to 40.0°2O [Time: 40 minutes]. 2. Upon completion of the 1st scan detailed analysis of each peak is made to determine the area, intensity and position. The resulting data is stored in a digital format which undergoes matrix flushing producing semiquantitative results. 4.3.3 Extraction of the Clay Fraction and Analyses Initial disaggregation is conducted using a jaw crusher down to 4mm. The sample is washed in distilled water to remove rock flour contamination, at this point all contamination (i.e. organics and carbonate) is removed, and the sample is then stored in a large test tube with a dispersing agent for 24 hours (cutting samples such as "Hot-Shots' may have drilling mud removed using a screen and ultra sound). Secondary disaggregation is conducted under distilled water in an agate mortar. Liberation of the clay component is achieved by standing the tube of rock grains and dispersing agent (of known density) in an ultrasonic bath for 30 minutes. The >80 micron fraction is removed from suspension. All clay fraction sizes are removed and concentrated using centrifugation. Known aliquots of the clay suspension are then filtered under vacuum onto a membrane. The resulting clay film is transferred to a known substrate by a membrane filter peel technique, giving a reproducible, preferred orientated film of known thickness. Four traces are run for each sample: 1. After drying the clay mount at room temperature and humidity. [Angular range 1 ° to 30 ° 2(3 CuKa] . 2. After ethylene glycol saturation [24 hours at 25°C]or [~'Hot Shot"] 2 hours at 60°C. [Angular range 1 ° to 20°26) CuKa]. This causes any expandable clays to expand and increase their lattice spacing. 3. Immediately following heating to 375°C for 30 minutes [Angular range: 4 to 10 ° 2C CuKa]. This causes any expandable clays to collapse. 4. After heating to 550°C for 14 hours [angular range: 1 ° to 30°2C CuKa]. Clay minerals are identified by using the four X-ray diffraction patterns of orientated aggregates that enhance the basal [001 reflections (Z)]. This is because h.k.l peaks are very similar in their X-Y directions. Mineral type is determined by peak position, intensity, shape and breadth. Peak reflections are determined by Bragg's Law. Illite and Glauconite Identification and Quantification Pure illite and pure glauconite are unaffected by ethylene glycol and heating to 550°C. Glauconite has a higher 001/003 intensity ratio than illite but determination is made on the 002 reflection as glauconite exhibits little or no peak at 5.00 A [18°2C CuKa] due to heavy scattering from octahedral iron. Both glauconite and illite in most cases are quantified using the intensity and crystallinity of the 10.1 A [9°20] 001 reflection. Chlorite and Kaolinite Identification and Quantification Chlorite has a basal series of diffraction peaks based on a first order reflection at 14.2 A, and kaolinite has reflections based on a 7.1 A structure. Even order chlorite peaks superimpose on Chap 2 Coring and Core Analysis Processes.DOC

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the members of kaolinite 001 series. So the distinction between chlorite and kaolinite is most difficult. Chlorite is determined by an amplification peak intensity at 14.2 A[6°2CCuKa] upon heating to 550°C and the presence of an 003 reflection 4.74 A [18.5°2C Cuka]. In cases where chlorite masks the presence of kaolinite a further trace may be run using sample material that has been treated with ON HCL. This collapses the chlorite peaks allowing verification but not quantification of kaolinite as intensity is reduced in the kaolinite. Detailed identification of the chlorite and kaolinite can be determined by mathematical manipulation of the diffractogram and comparing with standard patterns. Quantification of pure chlorite is calculated on the corresponding unique peak of the chlorite present compared to a known quantity of internal standard. Total chlorite is always measured on the 7.10 A [12.5°2O CuKa] peak and kaolinite is quantified using 003 reflection. Mixtures of kaolinite and chlorite are quantified using 003 reflections. If this is impossible a slow scan to improve resolution at 24 [Kaolinite 002] and 25 1 °2(3 [chlorite 004] is used. Smectite Identification and Quantification Smectite is identified by a movement of the 001 reflection upon glycolation to 16.9 A :5.2°2C CuKa]. Note that on the air-dried trace the presence of a broad peak at 15 A [6°2C CuKa]. Quantification is taken on the glycolated trace at 16.9 A [5.2°2(] CuKa] if detected. Illite-smectite Identification and Quantification Illite-smectite is identified by a broad shoulder on the 001 illite reflection at 15 A [6°2C CuKa] separating to a distinct smectite peak at 16.9 A - 17.2 A. Comparing 375°C trace with the glycol trace gives direct quantification at 10 A [9°20 CuKa]. 4.3.4 Examples An example of whole rock and clay fraction diffractograms are shown on Figure 4-10 and Figure 4-11.

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Figure 4-8: X-Ray Incidence and Refraction

Figure 4-9: Typical X-Ray Diffraction Patterns

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Figure 4-10: Whole Rock Diffractogram

Figure 4-11: Clay Fraction Diffractogram

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5.

Core-Log Depth Matching

Following assessment of the nature of the core and log data and its accuracy and reliability, the next stage in core/log data integration and reconciliation is to ensure that there is a reliable depth correlation between core and log data from the same well. This is essential process for density log calibration, etc. On most occasions the driller’s depth (core) will be different from the logger’s depth, since both use different methods to calculate depth. An indication of any depth mismatch can be obtained from analysis of data that can be conveniently measured on both core and logs: e.g. gamma ray response and log density/core porosity. The key is not to match absolute values (e.g. core and log gamma have different scale units and core is usually ambient values) but the trends. For example, Figure 5-1 compares the log gamma trace in a well (logger’s depth) with a core gamma ray trace (driller’s depth) from measurements made in the laboratory. In these relatively clean sands there is little activity on the gamma logs, but at about 17576 ft MD there is an excursion in the core gamma towards high values associated with a shaly layer. A similar excursion is seen on the porosity (density-calibrated) log at 17682 ft MD. This suggests that the core depth is 6 feet too high compared to the log depth and so the core data should be shifted down by 6 ft to obtain a match with log data. The log (density log) and ambient core porosity comparison from the same well is shown in Figure 5-2. In this case, the relative amplitude of the core data is greater than the log data, due to different measurement scales and biased core sampling, but again, an excursion to low porosity (associated with the shaly layer on the gamma) can be seen on both the core and log plots. This indicates a depth shift of about 5 ft, which agrees well with the gamma log. For reasons discussed below, core gamma generally provides a better tool with which to match drilled and logged depths, and should be run on all core analysis jobs. The core porosity and log porosity match must consider the effects of biased sampling (cores are usually selected from the best quality intervals, not strictly on a foot-by-foot basis) and the scale of the measurement (about 25 to 80 cc) is much lower than logs (equivalent volume about 100,000 cc). Prior to depth matching, the core data should be averaged, to “smooth out” localised “peaks and troughs”. This accounts for the vertical section (volume) of rock which the logging tools actually considers (about 3 ft). Typical weightings might be: 1 times φcore

(1 ft above subject depth)

3 times φcore

(at subject depth)

1 times φcore

(1 ft below subject depth)

This provides a mean weighted core porosity with which to compare the log porosity. Figure 5-3, from the same data set, shows the point and smoothed depth-shifted core data plotted against the log data. The smoothed core trend better fits the log trend. Chap 2 Coring and Core Analysis Processes.DOC

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Core-log depth matching is often viewed as a “black art”. One of the problems is dealing with lost core recovery and the stretch in the wireline. Ideally, the core-log depth shift is constant over a given core run and a so-called “stretch shift” is applied. However, in the industry we normally fit the core to the logs but in reality we should be fitting the logs to the core since the core is not normally expected to contract or expand too much. Industry practice (especially using automated software) therefore leads to so-called stretch shifts in which the cores are expanded or contracted to fit the logs such that the depth shift is not constant for a given core run.

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Porosity (-) 0.00 17500

0.10

0.20

0.30

17520

Depth (ft MD)

17540

Log Ambient Core

17560

17580 core 5 ft higher

17600

17620

Figure 12: Core and Log Porosity Trends

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Gamma Ray (API) 0

20

40

60

80

100

17500

17520

Depth (ft MD)

17540

Log Core

17560

17580 core 6 ft higher

17600

17620

Figure 13: Core and Log Gamma Ray Activity

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3 point running average

Point data

Figure 5-3: Depth Matching using Continuous Log and Smoothed Core Porosity

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6.

1

References

www.bakerhughes.com/inteq/Drilling/coring/gelcore/gelcore_tds.pdf

2

Dickson, JAD, 1966, “Carbonate Identification and Genesis as revealed by Staining”, Journal of Sedimentary Petrology, 36, 491-505 3

Deer, W.A., Howie, R.A., and Zussman, J., 1966, An Introduction to the Rock Forming Minerals, Longman Group, London.

4

Kerr, P.F., 1977, Optical Mineralogy, McGraw-Hill Book Company

5

Pettijohn, F.J., Potter, P.E., and Siever, R., 1973, Sand and Sandstone, Springer-Verlag, New York, 618 pp.

6

Allen, J.R.L, 1962, “Petrology, Origin and Deposition of the Highest Lower Old Red Sandstone of Shropshire, England”, Journal of Sedimentary Petrology, 32, 657-697 7

Folk, R.L., 1959, “Practical Petrographical Classification of Limestones”, AAPB Bulletin, 43,

8

Dunham, R.J, 1962 “Classification of Carbonate Rocks According to Depositional Texture”, AAPG Mem 1

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