Manual de wellsite

7/30/2019 Manual de wellsite

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1.1 DUTIES AND RESPONSIBILITIES OF THE WELLSITE GEOLOGIST

The Wellsite Geologist is responsible for ensuring that geological data is collected,

evaluated and recorded at the wellsite and reported to the Operations Geologist. These

duties include supervision of the Mud Logging and Wireline Logging contractors andnecessitate close liaison with the Wellsite Manager (Drilling Supervisor). The Wellsite

Geologists Checklist (Section 7.4) is to be read and checked off as appropriate beforeleaving the office to travel to the rig.

The Wellsite Geologist therefore has responsibilities that include those listed below.

Observing and recording all hydrocarbon shows and evaluating their significance.

Describing and recording (in the format defined in these Procedures) thelithological assemblages encountered in the well. It is important toemphasise that the Wellsite Geologist and not the Mudlogger has thisfunction as his/her primary responsibility.

Witnessing and reporting wireline logging operations, ensuring adequate qualitycontrol.

Selecting core points based on Drilling Programme and Coring Criteria.

Submitting geological reports (morning and afternoon) to Operations Geologist

consistent with the approved procedures.

Supervising the collection, packing and dispatch of ditch cuttings core samples andpaper data from the rig. Although the Mudlogging Company performs these tasks,close attention to this important aspect of their work can save many hours of

frustration and wasted effort later.

The Wellsite Geologist is empowered to implement the agreed formation evaluation

programme, as defined in the Drilling Programme or subsequent modifications. Any

deviations from that programme should be via a Drilling Change Control Form

Request. Agreement to implement the proposed variance will be given by Drilling andExploration.

The Wellsite Manager (Drilling Supervisor) is responsible for the efficient, economic andsafe performance of the drilling operation assuring suitable hole conditions for the well

evaluation. It is important to keep the Wellsite Manager (Drilling Supervisor) informed

of the expected evaluation programme, or of any programme changes, for his planningpurposes. He is to be advised immediately of all hydrocarbon shows, increases in mud

gas readings, significant changes in shale densities or any other factor which could effect

rig safety or the proposed evaluation activities. All requests involving rig activity must


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be given through the Wellsite Manager (Drilling Supervisor) and not directly to drilling

contractor personnel.

1.2 SAMPLE DESCRIPTION

1.2.1 Introduction

The purpose of this procedural summary is to provide a methodology, which shouldresult in a consistent and meaningful description of cutting samples within the constraints

of working at wellsite. The preparation of cutting samples for examination is not

addressed, as this subject is well documented in other references.

Wellsite lithological descriptions are important in providing:

An unambiguous interpretation of the lithological section drilled.

A clear identification of reservoir facies and an assessment of their potential capacity

to be hydrocarbon productive (made in association with hydrocarbon show data).

A record of the degree of caving, contamination or other factors which may affect theutility of the final lithological log.

A product, which will allow for the compilation of a Composite Well Log when

combined with wireline log data.

In order to accomplish these objectives, the following records are to be maintained.

1.2.2 Cuttings Description

The Wellsite Geologist should note the lithological and hydrocarbon show descriptionsfor each sample on the Cuttings Description Report.

The Cuttings Description Report should accurately reflect the sample as observed by theWellsite Geologist with the exception of obviously caved material. Separate notes should

be made to reflect the Wellsite Geologist's interpretation of the significance of caved

material, other contaminants and peculiarities.

In order to provide uniformity of description from well to well and to avoid ambiguitiesresulting from differing styles adopted by geologists, the procedures for the description of

cutting samples (Section Error: Reference source not found. Sample Description) shouldbe adopted.

1.2.2.1 Show Evaluation


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The Wellsite Geologist is responsible for the monitoring and reporting of all hydrocarbon

shows from wellsite. In order to fulfil this function, the Wellsite Geologist must ensure

that the Mudlogging Contractor is adequately prepared and maintains all equipment in aworkable state (Section 5. Mudlogging).

All Hydrocarbon Shows should be reported using the Show Evaluation Report, 9.6, as aguide.

1.3 MUDLOGGING SUPERVISION

The Wellsite Geologist is responsible for the direct supervision of the Mudlogging

Contractor. The duties of the Mudlogging Contractor will be defined in Drilling

Programme. Section 5. Mudlogging also contains information concerning the daily andother routine performance tests to be conducted on the Mudlogging Unit.

Before going to wellsite it is important that the Wellsite Geologist is informed by theOperations Geologist the type of Mudlogging Unit in use and makes all reasonable

attempts to ensure that he/she is familiar with the systems and procedures relevant, or

peculiar, to that unit.

The Wellsite Geologist must also check that adequate supplies of consumables are on the

drilling unit upon his/her arrival.

1.4 CORING

The coring programme (where required), is an integral part of the Drilling Programme foreach well. The Wellsite Geologist has the responsibility to ensure that any programmed

cores are cut, described and transported, following the procedures detailed inSection4.

Drilling Breaks, Coring and Sidewall Coring. Appendix 8 discusses the mechanical

aspects of coring.

Should unexpected circumstances occur which result in the Wellsite Geologist

recommending an unprogrammed core, all relevant information must be transmitted toOperations Geologist with a recommendation, for review. Agreement to core will be

made following consultation with others as may be required. Meanwhile, hole

conditioning should be considered, in consultation with the Wellsite Manager (DrillingSupervisor).

1.5 WIRELINE LOGGING


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The Wellsite Geologist is responsible for ensuring that the Wireline Logging Programme,

as detailed in the Drilling Programme is completed in a competent and expeditiousmanner. The following general comments are relevant and are to be followed..

It is the responsibility of the Wellsite Geologist, to ensure that wireline logs ofsatisfactory quality are obtained. In order to accomplish this task, a series of quality

control checks and procedures have been developed. During the logging job, the

Wireline Logging Quality Control Report, Diary of Wireline Operations and anExtrapolated Temperature Plot (which are components of a linked set of spreadsheets)

should be duly completed:

1.5.1 General Requirements

Ensure the Logging Engineer will be ready to start logging as soon as the drill pipe is

out of the hole and the pre-logging job hazard analysis has been conducted.

Check with the Driller, Wellsite Manager (Drilling Supervisor) and MudloggingEngineer about the condition of the hole, especially tight spots or bridges.

Provide a copy of the front page of the " Wireline Logging Quality Control Report "form to the Logging Engineer well in advance of the logging job. This will provide

the engineer with coordinates, elevations etc. Discuss and clarify any queries.

Provide the Logging Engineer with any requested deviation data for the well (Totco

or multishot).

Ensure that a circulated mud sample is collected and that resistivity measurements are

made by the Logging Engineer for Rm, Rmc and Rmf. All resistivity data should be

double checked for validity and all temperature data verified.

It is extremely important that a circulated mud sample be used for these

measurements. Only in unusual circumstances should a pit sample be taken. If this isthe case, the source of the sample should be annotated on the Log Header under

"Remarks" as well as the appropriate "Source of Sample" box;

If a logging pill is spotted on bottom a sample of this should be collected from the

appropriate pit and resistivity measurements made by the Logging Engineer for Rm,Rmc and Rmf. All resistivity data should be double checked for validity and all

temperature data verified. This information should also be noted on the Log Headerunder Remarks as well as the appropriate "Source of Sample" box.

The Remarks section of Log Header should also include the following information;

% Barite in mud system,


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% Potassium in mud system,

Base oil density in case of SBM mud systems,

Origin of datum position (i.e. pip-tag, tide tables, etc),Time drilling ceased,

Time circulation ceased,

Time logging tool on bottom,Time logging completed,Average logging speed,Causes for any log anomalies,

All thermometer readings.

Ensure the Logging Engineer has all Header information correctly input.

Obtain a printed header sheet and proof read BEFORE final prints are made.

Ensure the Logging Engineer has instructions for the number of prints to be made.

Ensure a minimum of two thermometers are run on each tool string in every log suite

where possible, including sidewall core runs.

1.6 PRODUCTION TESTING/DRILL STEM TESTING

Testing will be conducted consistent with the provisions of a Testing Programme which

is subject to Joint Venturer and Government approval. It is unlikely that the WellsiteGeologist will be required to supervise or attend production testing.

1.7 LIAISON WITH WELLSITE MANAGER (DRILLING SUPERVISOR)

The Wellsite Geologist should keep the Wellsite Manager (Drilling Supervisor) informedof any changes in bulk lithology, reservoir objectives, potential lost circulation zones,

potential overpressures and other matters which could reasonably be expected to

influence the safety or efficient operations of the well.

All depths and operations reported on the Geological Reports should be co-ordinated and

agreed with the Wellsite Manager (Drilling Supervisor).

1.8 DATA DISTRIBUTION

The Wellsite Geologist is to ensure that all exploration data (reports, samples logs etc.)

are correctly labelled, packaged and despatched in a timely manner.

The timing and mode of shipment of data from the rig is included in the Drilling

Programme. When in doubt, call the Operations Geologist


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It is extremely important that all data shipments from the rig be accompanied by a

transmittal. A copy of the transmittal should be sent to Operations Geologist via email orfax.

1.9 CONFIDENTIALITY

All geological data should be considered as confidential. Such data should be discussed

only with those persons directly involved in the use thereof (i.e. Mudloggers, Wellsite

Manager (Drilling Supervisor)). Data necessary for the safe and efficient conduct of

drilling operations should be provided to the Drilling Contractor Supervisor, the Drillers,the Mud Engineers and other relevant personnel, in co-ordination with the Wellsite

Manager (Drilling Supervisor).

Speculation upon the results of the well, and their significance, should be discouraged.

1.10 DATA COMPILATIONS

The ultimate home for most of the data compiled at the wellsite is the GEOLOG data

base. As this is an Excel based application Excel spread sheets should be used whereverpossible to facilitate the loading of the data.

1.11 WELLSITE SUPPLIES

A list of supplies that could be required at the wellsite are given in Section Error:Reference source not found. Wellsite Geologist Supplies Inventory.

The Wellsite Geologist must also ensure that the Mudlogging Contractor has sufficientconsumables for the bagging and boxing of all samples and cores.


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2 REPORTING PROCEDURES

2.1 INTRODUCTION

Hard and fast rules on reporting are not appropriate to wellsite conditions. Consequently,

the following text should be taken as a guideline. The rapid and accurate disseminationof data from wellsite is one of the most important tasks of the Wellsite Geologist and this

function should be treated with care and thoroughness.

2.1.1 Routine Daily Reporting

Two reports on geological operations will be required from wellsite on a daily basis -

A Morning Report is to be transmitted to Operations

Geologist every day before 07:30, when a Wellsite Geologistis on location. Given that communication access is notunlimited, the most convenient time for transmission will bedetermined following discussions between the WellsiteGeologist, Drilling Supervisor and Operations geologist. Thiswill determine the post midnight reporting period.

The informal afternoon report will be via telephone, or a short email message, about

16:00 when a Wellsite Geologist is on location.

2.2 MORNING AND AFTERNOON DAILY REPORTS

An example of the Word template used for the Morning Daily Geological Report isreproduced in Section Error: Reference source not found.2. Instructions on the use of the

report are given below, and any clarification may be obtained from the OperationsGeologist. The Daily Report will be submitted by email.

2.2.1 Discussion

It is important to note that the effective time for the morning Daily Geological Report

(DGR) is 0000 hours and will report all operations from the previous twenty four hours(i.e. 0000 - 2400).

The file name of the file is to follow the convention: well name (eg Audacious-1), DGR(with report number), eg. georeport01, Date ( eg 28-01-98), midnight depth eg. 1505m:

Audacious-1_georeport01_28-01-98_1505m.

The Morning Report will contain the following information:


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Heading Data

This information (depth, progress, operation, deviation data, mud data etc.) should be

in agreement with that reported by the Wellsite Manager (Drilling Supervisor).

The Operations Summary should be just that - brief and to the point and should be

confirmed with the Wellsite Manager (Drilling Supervisor). The Report Date is the date of the 24 hour period.

The Report Number should be sequential by day, starting on the first full day of a

Wellsite Geologist being on the rig.

The midnight depth should always be confirmed with the Drilling Supervisor, and

likewise other information such as water depth, RT elevation, casing depths, and

FIT/LOT data.

Mud data is obtained from the Daily Mud Report (usually via the Mudloggers) and

ECD from the mudlogging Data Engineer. In addition, the Data Engineer should

provide an estimate of the pore pressure. It is important to discuss the estimated porepressure with the Data Engineer on a continual basis, as the safety of the well is

potentially at stake. If the Dxc plot displays anything but a normal trend, then thisshould be discussed in the latter Formation Pressure Estimate part of the DGR.

Survey data can be obtained from the MWD contractor, or from the Drilling

Supervisor if MWD is not being run.

Lithology:

The lithological descriptions for Daily Reports should beconcise. Additional detail may be appropriate where thefollowing circumstances arise:

Significant shows are present,

Penetration of an important objective is imminent,

When approaching a core point,

Within the primary or other reservoir objective,

At the discretion of the Wellsite Geologist.

The lithological section should be separated into intervals. Obvious interval breaks

may occur at formation boundaries, and where there are significant lithological

changes. Ultimately it is up to the common sense of the Wellsite Geologist as towhere interval breaks are assigned, but intervals should be neither too fine nor too

coarse.

The ROP range and average are best derived by the Wellsite Geologist visually from

the mudlog. An alternative method is for the interval penetration rate to be requestedfrom the mudloggers.

A brief summary of the interval lithology should precede the more detailed

description.

The detailed descriptions should be written in full (no abbreviations), and use the

format described below (Error: Reference source not found)

Hydrocarbon Shows:


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Should be described using Section 9.6 Show EvaluationForm as a guide.

Gas Data:

The following data will be obtained from the Mudlogging Engineer.

Background Gas

Background gas intervals should be broken up on the basis of change in trends, and like

lithological intervals, should not be broken up too finely or too coarsely. The best (only)way to pick intervals is graphically, from the mudlog. Once again, seeing things

graphically gives the WSG a much better feel for what is happening.

Trip Gas, Connection Gas and Gas peaks

To avoid confusion, trip gas, connection gas, and gas peaks should be absolute values,not values above background gas.

Calcimetry

Calcimetry intervals should be broken up where there is a significant change in

calcimetry, but neither too finely nor too coarsely. There is no point in continuingcalcimetry measurements once ciral or similar CaCO3 lost circulation material has

been added to the mud.

Formation Pressure Estimation

Any departure from a normally pressured regime requires explanation. This should bedone in conjunction with the mudlogging Data Engineer.

Sample Quality

Sometimes cuttings may be contaminated with cavings, cement, or mud additives,

and these should be mentioned when in significant quantities.

sample quality should be expressed as being either Unreliable, Questionable, or

Good, with explanation required for the first 2 categories.

Mudlog Equipment/Personnel

Detail any problems or rectification of problems.

MWD


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Detail the sensor measuring points in metres behind the bit, list any equipment

problems or changes, and include any pertinent remarks regarding log quality.

MWD Temperature

Safety:

The Wellsite Geologist should make any relevant comments.

2.2.2 Remarks

The remarks section is for any other pertinent information not mentioned elsewhere inthe DGR, such as formation tops, comparison with the prognosis, further discussion

of the significance of shows or any other matters of interest, and electric logging

details.

All transfers of materials from the rig should be noted here, with information

concerning the mode of transport and ETA. If any significant changes in Mud Data have occurred within that period, it should be

noted in the "Remarks" section.

The WSG should always feel free to express any concerns or voice any opinions

under this heading, as something the WSG may deem un-newsworthy may have

later ramifications.

2.3 INTRODUCTION

It is important to note that the following material is designed to address the description ofcutting samples and not core samples. For all sample types however, the order in which

the properties are to be described is given below.

SAMPLE DESCRIPTION FORMAT ( in order)

1. Rock type (% and modifier, if required).

2. Colour or colour range.

3. Hardness

4. Fracture and texture

5. Grain size: Range and Dominant size6. Sorting

7. Angularity8. Sphericity

9. Matrix

10. Cementation: Degree, Percentage of each cement and Composition.11. Accessories and Fossils: Type and Percentage of rock

12. Effective Visual porosity


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13. Hydrocarbon indications

14. Remarks: including Texture

This list contains those parameters which are considered relevant to a sample description.

Not all parameters necessarily will be utilised in a description as the rock type governs

this. However, all descriptions should be prepared by using the relevant parameters, inthe order described.

The Cuttings Description Report is the primary recording tool for sample descriptions.

The Wellsite Geologist in describing cuttings samples, will use the following aids in

addition to the routine equipment and reagents available at wellsite.

GSA Rock Colour Chart

Grain size Comparator

The sample descriptions will be entered into the Cuttings Description Report. The

order in which these are entered is given above.

2.4 DISCUSSION OF ELEMENTS COMPRISING A LITHOLOGICAL DESCRIPTION

2.4.1 Sample Quality

It is inevitable that cuttings samples will be contaminated to some extent by cavings. Theuse of sieves can reduce this problem. Very large cuttings which are obviously caved

may be removed from samples.

Any wiper trip or round trip causes an increase in cavings when drilling is resumed andalso causes a mixing up of the cuttings present in the mud column. For this reason, all

cuttings should be circulated out of the hole prior to trips made near zones of interest.

When it is not possible to catch samples (such as in lost circulation zones, an empty bag

should be included in the sequence of samples, and clearly labelled to show the intervalof missing samples and the reason why they are missing. Such intervals should be noted

on the transmittal forms.


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2.4.2 Rock Type

2.4.2.1 Siliciclastic

The Siliciclastic classification detailed below is to be used when describing siliciclastic

rocks.

SILICICLASTIC CLASSIFICATION

ROCK TYPES MODIFYING CONSTITUENTS

UNCONSOLIDATEDSEDIMENTS

CONSOLIDATEDSEDIMENTS

MINERALS

(> 20% OR IF SIGNIFICANT)

Breccia and Quartz

Gravels Conglomerate CarbonateArkose

GlauconiticHaematitic

Sands Sandstone Arkosic (> 30% Feldspar)Feldspathic (10-30% Feldspar)

MicaceousAnhydritic

PyriticCarbonaceous

Cherty

Silts Siltstone As for sandstones

MicaceousHaematitic/Limonitic

Glauconitic

Claystone/ PyriticClays Shale Gypsiferous

CarbonaceousChloritic

Quartzose (silt size grains)Feldspathic (silt size feldspar)

Dolomitic (Dolomite Rhombs)


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2.4.2.2 Transitional

The use of the term "grading" or transitional is informal. It is intended to describe the

transition between fine-grained siliciclastic and carbonate rocks, as given below, or

within one rock group, eg silty sandstone grading to sandstone.

Rock type % Calcareous % Clay

Calcilutite 80 100 0 - 20

Argillaceous Calcilutite 50 80 20 - 50

Calcareous Claystone 20 50 50 - 80

Claystone 0 - 20 80 - 100

The term Marl, a general sack term covering part or all of the range calcareousclaystone to argillaceous calcilutite, is not one that OMV Australia chooses to use.

2.4.2.3 Carbonates

The Carbonate Classification adopted in these procedures is that of Shields (1964).

Wentworth Scale

2.4.2.4 Evaporites

Evaporites are described according to the dominant evaporitic constituent, e.g. anhydrite,

gypsum, halite, and dolomite. Lithological terms such as dolostone are not used.

2.4.3 Colour

Grain Size Lithological Name

Greater than sand sized Calcirudite

Sand sized Calcarenite

Silt sized CalcisiltiteClay sized Calcilutite


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Colours should be those seen on wet cuttings and should be related to the GSA Rock

Colour Chart. The rock sample and the Colour Chart need to be viewed under the samelight source for consistency. It is important however, to ensure that only a significant

colour differentiation is made in describing samples. It is common to make the colour

description too elaborate and, effectively, meaningless.

2.4.4 Hardness

Loose - Particles are discrete and non-coherent.

Friable - Coherent, but crumbling under slight pressure.Soft - Clays, marls and silts which can be deformed by slight

pressure.

Plastic - Pliant clays that show putty-like deformation.Firm - Compact, breaks under slight pressure.

Moderately hard - Grains can be detached using knife.Hard - Solidly cemented or lithified. Does not break under slightpressure, but can be scratched with knife blade. Fractures

go between grains.

Very Hard - Cannot be scratched with a knife blade, usually siliceous.

Fractures pass through grains.Dense - Commonly used to indicate a fine-grained, well lithified

tight rock (usually limestone) with sub-conchoidal

fracture.Brittle - Moderately hard, but breaks easily with firm pressure.

Generally applies to shale with platy fracture.

2.4.5 Fracture

Several descriptive terms are used to describe the type of fracture, commonly a result ofcleavage or bedding, seen in shale and limestone cuttings. They include:

Blocky Used to describe claystone, and limestone in which fracturesare developed at approximately right angles, so that small

blocks are formed.

Conchoidal Commonly seen in dense rocks such as chert, argillite and flint.The term refers to the concave and convex surfaces developedon fractures. The fracture of hard limestone producessomewhat less strongly developed curved surfaces and thefracture has been called "sub- conchoidal".


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Flaky The rock fractures into small flakes or chips. Common in someargillaceous limestones and occasionally in metamorphic rocks.

Platy Used to describe shale in which fissility is well developed. Therock breaks in parallel sided thin plates. This is commonlycaused by fracture along bedding planes, or along cleavage

directions.

Splintery Used to describe shales in which the fissility is not stronglydeveloped, but exists sufficiently to cause irregular surfacesand edges, like a board broken across the grain.

Be careful that apparent fracturing is not an artefact of the sample recovery process.

2.4.6 Texture

Texture is defined by the size, shape and arrangement of the component particles of arock and much of the texture of a rock will have been described under the previous

headings of grain size, shape and sorting. Other textural descriptions in general usage are:

Rock Texture amorphous, aphanitic, crystalline, dense, flaky,heterogeneous, homogeneous, sucrosic, and vesicular.

Surface Texture of grains Smooth: dull, nacreous, resinous, polished, andvitreous;

Rough: etched, frosted, pitted, and striated.

In addition to the rock textures given above it is also useful to note here if the claystones

react with water. The responses may be described as follows:

Hygroturgid swelling in a random manner

Hygroclastic dispersing as irregular fragmentsHygrofissile separating into tabular flakes

2.4.7 Grain size

The grain size comparison charts are related to the Wentworth scale. The grain size

properties of a rock are defined by the range and dominant size of the constituents. Note

that modifying constituents are also listed on this table.

Wentworth Scale

Grade limits (diameters in mm) Grain Size Lithological Name

Above 256 Boulder 256 - 64 Cobble Conglomerate


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64 - 4 Pebble

4 - 2 Granule

2 - 1 Very Coarse1 - 1/2 Coarse

1/2 - 1/4 Medium Sandstone1/4 - 1/8 Fine

1/8 - 1/16 Very Fine

1/16 - 1/256 Silt Siltstone

Less than 1/256 Clay Claystone/Shale

Matrix will be described by type (silt, clay etc.) and proportion (%) of overall rock. See

definitions of cement and matrix in Section 2.4.11.

2.4.8 Rounding

Standard charts (comparators) should be available at wellsite to assist in describingthese properties. See Appendix 2 Roundness and Sphericity for the visual appearance ofthe descriptions below.

The following definitions apply:

Angular: Very little or no evidence or wear; edges and corners are sharp.

Secondary corners, which are the minor convexities grain profile are numerous and sharp.

Subangular: Definite signs of wear; edges and corners have been rounded off to some

extent. Secondary corners are numerous.

Subrounded: Showing considerable wear, edges and corners have been rounded off to

smooth curves. The original shape of the grain is still distinct. Secondary corners are

much reduced and rounded.

Rounded: No original faces, edges or corners remain; the entire surface consists of

broad curves.

It is important that the description given should be of the original detrital grain. If the

grain is affected by authigenic overgrowths, this should be noted and the concepts of

angularity abandoned.

2.4.9 Sorting

The following classification should be used:

Adjective Definition


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Very well 90% of grains in one grain size class,

Well 90% of grains in two or three grain size classes,

Moderate 90% of grains in four grain size classes,Poor 90% of grains in five or more grain size classes.

As can be seen, a sandstone consisting entirely of very fine to fine grains cannot bepoorly sorted.

2.4.10 Sphericity

Sphericity should be considered when describing grain shape. Standard charts(comparators) should be available at wellsite to assist in describing these properties.

The endpoints for description areElongate and Spherical. See Appendix Roundness andSphericity for the visual appearance of these endpoints.

It is important that the description given should be of the original detrital grain. If the

grain is affected by authigenic overgrowths, this should be noted and the concept ofsphericity abandoned.

2.4.11 Cement

Identified by type and effectiveness of the cement (calcite, quartz, dolomite etc.).

Adjective % of Pore Space Filled

Well 70-100%Moderately 30-70%

Poorly 0-30%

Discussion (from AAPG Sample Examination Manual)

Cement is a chemical precipitate deposited around the grains and in the interstices ofsediment as aggregates of crystals or as growths on grains of the same composition.

Matrix consists of small individual grains that fill interstices between the larger grains.

Cement is deposited chemically and matrix mechanically.

The order of precipitation of cement depends on the type of solution, number of ions in

solution and the general geochemical environment. Several different cements, orgenerations of cement, may occur in a given rock, separately or overgrown on or

replacing one another. The most common cementing materials are silica and calcite.


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Silica cement is common in nearly all quartz sandstones. This cement generally occurs

as secondary crystal overgrowth deposits in optical continuity with detrital quartz grains.

Opal, chalcedony and chert are other forms of siliceous cement. Dolomite and calcite aredeposited as crystals in the interstices and as aggregates in the voids.

Dolomite and calcite may be indigenous to the sandstone (the sands having been amixture of quartz and dolomite or calcite grains) or the carbonate may have been

precipitated as a coating around the sand grains before they were lithified. Calcite in the

form of clear spar may be present as vug or other void filling in carbonate rocks.Anhydrite and gypsum cements are more commonly associated with dolomite and silica

than with calcite. Additional cementing materials, usually of minor importance, include

pyrite (generally as small crystals) siderite, haematite, limonite, zeolites and phosphatic

material.

Silt acts as a matrix, hastening cementation by filling interstices, thus decreasing the size

of interstitial spaces. Clay is a common matrix material, which may cause loss of porosityeither by compaction, or by swelling when water is introduced into the formation.

Argillaceous material can be evenly distributed in siliciclastic or carbonate rocks, or havelaminated, lenticular, detrital or nodular form.

Compaction and the presence of varying amounts of secondary quartz, secondarycarbonate, and interstitial clay are the main factors affecting pore space in siliciclastic

rocks. While there is a general reduction of porosity with depth due to secondary

cementation and compaction, ranges of porosity vary considerably due, primarily, to

extreme variations in amounts of secondary cement. For instance, coarse-grainedsandstones have greater permeability than finer ones when the same amount of cementing

material is available to both. However, the same thickness of cement will form around

the grains regardless of their size, therefore the smaller interstices, which occur in finergrained sandstones, will be cemented earliest.

2.4.12 Fossils and Accessories

Reporting

All fossils and accessories should be reported by type and relative abundance. The

following adjectives can be used but actual percentages are preferred:

Adjective Definition

Trace less than 1%Rare 1 - 5%

Minor 5 10%

Common 10 - 20%

Abundant 20% or greater


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If the proportion of an accessory is greater than 20%, it is regarded as a modifier (See

section 2.4.2).

Discussion (from AAPG Sample Examination Manual)

Microfossils and some small macrofossils, or even fragments of fossils, are used for

correlation and may also be environment indicators. For aid in correlation, the Wellsite

Geologist should record their presence and relative abundance in the samples beingexamined. More detailed identification will probably have to be made with the aid of the

literature, and/or the advice and assistance of a palaeontologist. Fossils may aid the

sample examiner in judging what part of the cuttings is in place and what part is caved. It

would be helpful to the Wellsite Geologist to have available one or more slides orphotographs illustrating the principal microfossils which might be expected to occur in

each formation they will be logging.

Accessory constituents, although constituting only a minor percentage of the bulk of arock, may be significant indicators of environment of deposition, as well as clues to

correlation. The most common accessories are glauconite, pyrite, feldspar, mica, siderite,carbonised plant remains, heavy minerals, chert, and sand-sized rock (lithic) fragments.

2.4.13 Visual Effective Porosity

Visual porosity is the estimate of free pore space seen in drill cuttings under themicroscope. It is a difficult, but important, parameter to evaluate. Generally, one cannot

see the pore spaces under the binocular microscope, except in cases of very high porosity,

and the observer must rely on other features for the porosity estimate.

In general, if you can see the porosity it is very good to excellent. Unconsolidated sands

are assumed to have very good porosity. However, beware of tightly cemented sands thathave been fragmented by the bit and exhibit apparently good porosity.

If you cannot see pores, there is a high percentage of matrix, the cuttings are smooth

textured and the interval drilled relatively slowly, then the rock is likely to have poorporosity. The fair to good grades of porosity lie between these two described cases and

experience will guide the observer. A useful technique is to describe cuttings of an offset

well and to "calibrate" the descriptions of porosity with the wireline log data, prior toarriving at wellsite.

Porosity does not systematically vary with the size of the particles making up the rock.Rocks with a fine grain size may be more porous than those with coarse grain size since

porosity is defined as the percentage of pore space to the total volume of the rock.

Factors such as sorting, packing/compaction, cementation and other effects determines

ultimate effective porosity.


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Only the porosity of potential reservoir sequences should be described, as effective

porosity is of interest. The porosity of claystone is irrelevant unless fractured.

Approximate visual porosity grades should be denoted as:

Excellent 20% and greater Good 15 - 20%Fair 10 - 15%

Poor 5 - 10%Nil (Tight) 0 - 5%

Porosity type can be described as:

Intergranular - intercrystalline

Vuggy - cavernous

FractureSolution.

2.4.14 Hydrocarbon Indications

See Section 3. Show Evaluation


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3 SHOW EVALUATION

3.1 INTRODUCTION:

Although petrophysical analyses may give a conclusive determination of the presence of

commercial quantities of oil, it is the Wellsite Geologist's responsibility to report and logall shows and to ensure that shows are well evaluated. Positive indications of

hydrocarbons in cuttings can be a decisive factor in the petrophysicist's evaluation of a

well.

Unfortunately, no specific criteria can be established as positive indications of whether or

not a show represents a potentially productive interval. The colour and intensity of stain,

fluorescence, cut, cut fluorescence and residual cut fluorescence will vary with thespecific chemical, physical, and biologic properties of each hydrocarbon accumulation.

The physical degradation of the shows (highly volatile fractions dissipate quickly), andflushing by drilling fluids or during sample washing, also tend to mask or eliminateevidence of hydrocarbons.

The presence or absence of obvious shows cannot always be taken as conclusive. Inmany cases, the only suggestion of the presence of hydrocarbons may be a positive cut

fluorescence. In other cases, only one or two of the other analytical methods may prove

positive. Hence, when the presence of hydrocarbons is suspected, it is very important

that all aspects be considered. For this reason a variety of detection methods have beendescribed, together with recommendations for the ranking of the significance of shows.

The following procedures have been directed, primarily, to the accurate description ofshows in cuttings. It is axiomatic, however, that shows in cuttings are associated with

shows in the mud systems. The levels of mud gas shows, their duration and composition,

should accompany all descriptions of hydrocarbon shows. The rating of a hydrocarbonshow (Sections 4.3 and 9.6) should attempt to reconcile the shows in the cuttings and in

the mud.

Fluorescence shows generally are severely limited in oil-based and synthetic oil-basedmuds (OBM and SBM). These muds mask genuine shows with background fluorescence

associated with the oil/synthetic oil portion of the mud. Care and judgement must be

exercised in these situations as the fluorescence seen is invariably from the mud or filtrate

(see Appendix 5.6.2).

3.2 REPORTING OF SHOWS:

Hydrocarbon shows should be reported in the following format.

1. Oil Stain (Section 4.6.1)


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Colour

Amount minor (10%), moderate (10-50%), major (50-90%),

saturated (100%)Distribution even, spotty, mottled, streaked etc.

2. Odour (Section 4.6.2)Type

Strength faint, moderate, strong

(to be used cautiously - routine sniffing of samples poses a health hazard).

3. Sample Fluorescence (Section 4.6.3)

ColourDegree or intensity weak, moderate, bright

Amount of sample (%)

Distribution see "stain"

4. Hydrocarbon (Solvent) Cut and Residue (Section 4.6.4)

Cut Colour

Residue Colour

5. Solvent Cut Fluorescence (Section 4.6.5)

ColourDegree or intensity

Type of reaction (streaming [slow, moderate, fast] instant, blooming, crush

etc.)

6. Residual Cut Fluorescence (Section 4.6.5)

Colour

Degree or intensity

7. Evaluation (Section 4.3)

Trace, poor, fair, good, very good; possible/probable type of hydrocarbon

3.3 SHOW EVALUATION FORM

To assist the determination of show evaluation a form is included in Section 9.6.

However, rather than being required as a formal reporting form, it is given as a check list

for the geologist to use before advising the Operations Geologist and discuss itssignificance. It will also help to keep consistency during the discussions. The shows are

to be reported on the Daily Geological Report with additional discussion in the

Comments section if appropriate.

3.4 MUD GAS SHOWS

Mud gas shows will be recorded on the Total Gas Detector (Section 5.3) and the Gas

Chromatograph (Section 5.4).


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Frequently, mud gas shows will appear slightly in advance of the cuttings with which

they are related. If the mud rheology is optimal, however, there should be little delaybetween these two occurrences.

3.4.1 Total Gas Readings

Total gas readings are a measure of the amount of hydrocarbons entrained in the mud

stream in the C1-C5 range. In common with the gas chromatograph, the upper limit of the

detection system is constrained by the fact that C6 (hexane) and higher molecular weight

hydrocarbons are liquid at surface conditions and are thus not carried in the air-streamfrom the gas trap to the Logging Unit.

Total gas readings should be evaluated by the magnitude of deviations from abackground value. The background gas, however, may change with mud chemistry and

such sources should be monitored. In addition, there are several false hydrocarbon showsdescribed in Section 6.10 about which the Wellsite Geologist should be familiar.

Rapid deviations away from background gas levels represent a show. The gas

chromatograph should be set to give good definition of the constituent hydrocarbons.

An increase in trip gas or connection gas may signify that:

the mud weight has lowered and the well is being swabbed in by the drill string or

a new hydrocarbon zone has been penetrated and a review of other data sources

(primarily cuttings) should be investigated.

3.4.2 Gas Chromatograph

The gas chromatograph (Section 5.4) analyses the proportion of each of the hydrocarbon

gases (up to C5) measured by the Total Gas detector.

The chromatograph readings allow for a semi-quantitative evaluation of hydrocarbon

type by using several ratios calculated from the proportion of C1-C5. Each of the

Mudlogging Contractors have their own proprietary methods for doing this. A useful

reference however is Howarth et al (1984) from which the following indices are gleaned.

Gas Wetness Ratio (GWR)% = C2 + C3 + C4 + C5 x 100------------------------------

C1 + C2 + C3 + C4 + C5

Light to Heavy Ratio (LHR) = C1 + C2---------------


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C3 + C4 + C5

Oil Character Qualifier (OQR) = C4 + C5----------

C3

These ratios should be plotted by the Mud Logging Company for all intervals where

gases heavier than C3 are recorded. The results are more meaningful if C5 is present.

The numerical results of these ratios can assist in identifying the type of reservoired

hydrocarbons (Appendix Error: Reference source not found Error: Reference source not

found). The Mudlogging Contractor will have the ability to compute these ratios directly

from the input data. This makes life a great deal easier, particularly if GWR and LHRcan be plotted on the same track on a log scale. Their manual will probably have a

section describing more fully the significance of the ratios.

3.4.3 Integration with Shows from Cuttings

It is important that a hydrocarbon show be evaluated by reference to both the mud gas

and cuttings data. The latter is the subject of Sections 4.6 and 4.7.

Usually the two data sets are compatible and interpretation is straight forward. However,

when the data sets appear to be in conflict:

Check the mud gas detectors are working and are properly calibrated.

Check the Cuttings Description Report for any anomalous data, and if the data

set remains in conflict,

THINK ...is the data is telling you something?

In cases where shows are not good in cuttings (no stain, no cut and poor cut fluorescence)

but a strong mud gas show is registered, a condensate may be responsible.

In cases where shows in cuttings are good (good even stain, strong cut and cut

fluorescence) but no appreciable mud gas is detected, a very low GOR oil or biodegradedoil may have been encountered.

It would be impractical to review all of the options available in this document, but a

methodical review of the data set should yield a consistent result.

3.5 ROUTINE HYDROCARBON DETECTION METHODS FOR CUTTINGS

Much of the following text has been abstracted from Section 6 of the AAPG SampleExamination Manual. Minor changes have been made to make the qualitative description

of shows match those utilised elsewhere in these procedures.


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3.5.1 Staining and Bleeding

The amount by which cuttings and cores will be flushed on their way to the surface islargely a function of their permeability. In very permeable rocks only very small

amounts of oil are retained in the cuttings. Often bleeding oil and gas may be observed in

cores and sometimes in drill cuttings, from relatively tight formations.

The amount of oil staining on ditch cuttings and cores is primarily a function of the

distribution of the porosity and the oil distribution within the pores. The amount shouldbe reported as a proportion of the sample as minor (


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Mineral fluorescence, especially from shell fragments, may be mistaken for oil

fluorescence and is distinguished by adding a few drops of a solvent. Hydrocarbon

fluorescence will appear to flow and diffuse in the solvent as the oil dissolves, whereasmineral fluorescence will remain undisturbed. Mineral fluorescence that may be

encountered in samples includes:

Calcite dim to bright blue white to yellow (orangey pink if

aragonite)

Siderite dull to dim orangeAnhydrite dim to bright blue white to greyish white

Dolomite occasionally yellow to yellow brown

Amber bright yellow (with fast streaming cut)

3.5.4 Hydrocarbon (Solvent) Cut

Oil-stained samples which are degraded or oxidised may not fluoresce. Thus, failure tofluoresce should not be taken as decisive evidence of lack of hydrocarbons. All samples

that are suspected of containing hydrocarbons should be treated with tri-chloro-ethelene

and/or acetone.

Tri-chloro-ethelene is recommended for general use although it may become

contaminated after a long period. Acetone is a good solvent for heavy hydrocarbons but

is not recommended for routine oil detection.

To test cuttings or cores, place a few chips in a white, porcelain-evaporating dish or spot

plate and cover with reagent. The sample should be dried thoroughly at low temperature,otherwise water within the sample may prevent penetration by the reagent, thus

obstructing decisive results. The hydrocarbon extracted by the reagent is called a "cut".

It is observed under normal light and should be described based on the shade of thecolouration:, this will range from dark brown to no visible tint. A faint "residual cut" is

sometimes discernible only as an amber-coloured ring left on the dish after complete

evaporation of the reagent.

A very faint cut will leave a very faint ring and a negative cut will leave no visible

colour. The shade of the cut depends upon the gravity of the crude, the lightest crude

giving the palest cuts. Therefore, the relative darkness should not be taken as anindication of the amount of hydrocarbon present.

3.5.5 Solvent Cut and Residue Fluorescence

The most reliable test for hydrocarbons is the cut fluorescence test. In this test the effect

of the reagent on the sample is observed under ultraviolet light, along with a sample ofthe pure solvent as control. The sample should be thoroughly dried before applying the


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reagent. If hydrocarbons are present, fluorescent "streamers" will be emitted from the

sample and the intensity and colour of these streamers evaluate the test. In addition, the

speed of cutting gives some indication of the permeability (see below). Some shows willnot give a noticeable streaming effect but will leave a fluorescent ring or residue in the

dish after the reagent has evaporated. This is termed a residual cut or residual ring.

It is recommended that the cut fluorescence test be made on all intervals in which there is

even the slightest suspicion of the presence of hydrocarbons. Samples that may not give

a positive cut or will not fluoresce may give positive cut fluorescence. This is commonlytrue of the high gravity hydrocarbons that give a bright yellow cut fluorescence.

Distillates show little or no fluorescence or cut but commonly give positive cut

fluorescence, although numerous extractions may be required before it is apparent.

Generally low gravity oils will not fluoresce but will cut a very dark brown and their cutfluorescence may range from milky white to dark orange.

The colour of cut fluorescence can provide a clue to the density of the hydrocarbon:

Dry gas no fluorescence

Gas/condensate white to blue-white, frequently "spotty"35-45o API blue-white to light yellow

25-35o API light yellow - dark straw yellow

15-25o API dark straw yellow - orange brownless than 15o orange brown - no fluorescence

The intensity of the cut fluorescence is related to both the proportion of hydrocarbons in

the void space and to the porosity. Thus, bright or intense cut fluorescence signifies alarge proportion of hydrocarbon. However, the affects of flushing in high permeability

rocks will reduce the amount of hydrocarbons in samples very significantly. Therefore,

the lithology and permeability of the sediments must be considered in ranking shows thatare based on cut fluorescence. Common terms used to describe intensity are;

faint, dull, and bright.

The type and speed of cut fluorescence gives some insight into permeability. Rocks with

good permeability will produce instantaneous cut fluorescence, whereas rock with close

to zero permeability require crushing to produce any cut fluorescence. Rocks with low

permeability will often have a "streaming" cut with a stream of fluorescence (dissolvedhydrocarbons) flowing to the surface of the solvent. Descriptive terms for type and speed

are;

instant, fast, slow, streaming (individual streams) and blooming (streamscoalesce).

The residual cut or ring should be described by its colour and intensity. Both are relatedto amount of hydrocarbon and gravity in a similar way to that for cut fluorescence.

Descriptive terms are;

trace, thin ring, thick ring, thin film and thick film.


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3.6 OTHER HYDROCARBON DETECTION METHODS FOR CUTTINGS

3.6.1 Wettability

Failure of samples to wet, or their tendency to float on water when immersed, is often anindication of the presence of oil. Under the microscope, a light coloured stain that cannot

be definitely identified as an oil stain may be tested by letting one or two drops of water

fall on the surface of the stained rock fragment. In the presence of oil, the water will notsoak into the cutting or flow off its surface, but will stand on it or roll off it in spherical

beads. Dry spots may appear on the sample when the water is poured off. This, however,

is not useful in powdered (air drilled) samples which, because of particle size and surface

tension effects, will not wet.

3.6.2 Reaction in Acid of Oil Bearing Rock Fragments

Dilute HCl may be used to detect oil shows in cuttings. This is effected by immersing asmall fragment of the rock to the tested (approximately 0.5 to 2 mm diameter) in dilute

HCl. If oil is present in the rock, surface tension will cause large bubbles to form, either

from air in the pore spaces or from CO2 generated by the reaction of the acid with

carbonate cement or matrix. In the case of calcareous rock, the reaction forms lastingiridescent bubbles large enough to raise the rock fragment off the bottom of the container

in which the acid is held. Sometimes this effect is large enough to carry the fragment to

the surface of the acid before the bubbles break and the fragment sinks, only to be buoyedup again by new bubbles. The resulting bobbing effect is quite diagnostic. The bubbles,

which form on the surface of a cutting fragment of similar size (which contains no oil),

do not become large enough to float the fragment before they break away and thefragment, therefore, remains on the bottom. In the case of oil-bearing non-calcareous

sandstone, large lasting bubbles form on the surface but may not float the fragment.

It should be pointed out that this test is very sensitive to the slightest amount of

hydrocarbons, even those found in carbonaceous shale. Therefore, it is well to discount

the importance of a positive test unless the bobbing effect is clearly evident or lasting

iridescent bubbles are observed. The test is very useful, however, as a simple and rapidpreliminary check for the presence of hydrocarbons. A positive oil-acid reaction alerts

the observer to intervals worthy of more exhaustive testing.

3.6.3 Acetone-Water Test

If the presence of oil or condensate is suspected and provided no carbonaceous or lignitic

matter is present in the rock sample, the acetone-water test may be tried. The rock is

powdered and placed in a test tube and acetone is added. After shaking it vigorously it is

filtered into another test tube and an excess of water is added. When hydrocarbons arepresent, they form a milky white dispersion (as they are insoluble in water, whereas


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acetone and water are completely miscible). This is a very sensitive test and a control

sample is recommended whenever this test is attempted.

3.6.4 Hot-Water Test

Place 500 cc of fresh, unwashed cuttings in a tin or beaker, which has a capacity of 1,000

cc. Pour in hot water with a temperature of at least 80 oC until it covers the sample to adepth of 1 cm. Observe the oil film thus formed under ultraviolet light and record the

amount of oil released using the following scale:

Show Proportion of Water Surface Covered by Film

Strong 100%Fair 50 - 99%

Weak 33 - 50%Very weak 25 - 33%

Extremely weak less than 25%

3.6.5 Iridescence

Iridescence may be associated with oil of any colour or gravity, but it is more likely to be

observable and significant for the lighter, more nearly colourless oils where oil staining

may be absent. Iridescence may be observed in the wet sample tray. Iridescence withoutoil colouration or staining may indicate the presence of light oil or condensate.

As iridescence will also be obtained from diesel, be sure to investigate the possibility ofcontamination.

3.7 GENERALISATIONS

No "rules of thumb" can be used to relate the evidences of the presence of hydrocarbonsto potential production. However, some generalisations are worth noting.

1. Lack of visible stain is not conclusive proof of the absence of hydrocarbons. Gas,

distillates and high gravity oils ordinarily will have no visible stain.

2. Lack of fluorescence is not conclusive proof of the absence of hydrocarbons.

3. Bona fide hydrocarbon shows will usually give a positive cut fluorescence. High

gravity hydrocarbons will often give a positive cut fluorescence and/or a residual

cut, but will give negative results with all other hydrocarbon detection methods.


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4. The oil acid reaction test will give positive results when oil is present, but it is

very sensitive and may give positive results in the presence of insignificant

amounts of hydrocarbons.


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4 DRILLING BREAKS, CORING AND SIDEWALL CORING

4.1 DRILLING BREAKS

A significant drilling break will be considered as an increase or decrease (depending on

type of bit see below) in penetration rate to a value of twice (or more) the previous rate,if impermeable rock (generally shale/claystone or siltstone) lies above the break point.

However, it is not possible to lay down a precise definition of a significant drilling break

before the event and the experience of the Wellsite Geologist and the MudloggingEngineer are of paramount importance.

When a break occurs, the Mudlogging Engineer is to be responsible for advising theWellsite Geologist and the Wellsite Manager (Drilling Supervisor) of the event. The

driller will check for flow. When the Wellsite Manager (Drilling Supervisor) is satisfied

that no unusual or excessive fluid entry or gain has occurred, drilling will continue. Ifcoring is anticipated, a total of two to three metres of the break interval will be drilledprior to the samples being circulated to the surface for examination.

Drilling breaks into the objective section should be evaluated for hydrocarbon shows assoon as possible, in order for a quick decision on coring to be made. The Wellsite

Geologist will be responsible for this evaluation (and the recommendation on coring).

Be aware that PDC type bits often drill better in shales and that a sandstone lithology may

in fact decrease the drilling rate. The important feature in this case is to look for other

changes as well as drilling rate eg. Torque. Close liaison with the driller is imperative

and it has been found that maintaining uniform drilling parameters (WOB, RPM andpump pressure) often allows a lithological change to be quickly recognised by changes in

drilling characteristics.

4.2 CORING

Coring will be undertaken in accordance with the Drilling Programme and Coring

Criteria. Often it is the intention to continuously core any hydrocarbon bearing, porous

reservoir interval unit to below the oil/water contact, or until reservoir quality sedimentsare absent.

When pulling out of the hole prior to coring, a strap-out measurement should be

requested to ensure that there is no confusion regarding the depth at which the core wastaken.

Core lithology and recoveries must be recorded on the Mudlog.


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The Mudlogging personnel, supervised by the Wellsite Geologist will carry out the

handling, sampling and packaging of cores.

4.2.1 Items Required

The following items need to be ready for use prior to the core barrel reaching the surface:

1. broad felt-tip markers or paint pens (red and black) with water proof ink;2. rags;

3. hammer;

4. sample bags, labelled;5. notepad and pen;

6. measuring tape;7. eye protection and breathing apparatus, for use if cutting the barrel and core.

4.2.2 General Procedures

When coring, the penetration rate should be recorded every 0.5 metre. Ditch cuttings

samples are to be taken at 1 metre intervals while coring is in progress to serve as an aid tocorrelation in the case of partial recovery and as a standby in the case of zero recovery.

Samples should also be taken from the desander and desilter (if running). Since these cores

may be cut rapidly and with low flow rates, only the samples from the top of the core may

be circulated out, as it is not recommended to circulate bottoms up after cutting the core asthis increases the chances of losing the core.

The Wellsite Geologist is to observe the progress of the coring operation, noting anyabnormalities in rotary torque or pump pressure that may indicate potential zones of lost

core. It is advisable to plot formation dependent parameters such as ROP, pump pressure

and torque against cuttings lithology, noting that these changes may be very small. A sharpdecrease in drilling rate, for example, may indicate that jamming has taken place. If it

appears that jamming of the core has occurred, then the coring run should be aborted to

avoid destroying the interval of core below the jamming point.

4.2.3 Core Handling

Prior to commencement of coring, a Job Hazard Analysis (JHA) will organised by theSenior Coring Engineer . Those present will include: Coring Engineer, WellsiteManager, Toolpusher, Driller, Drillfloor Crew, Roustabouts/Dogmen who will be assistingin moving and cutting the core, Mudlogger and Wellsite Geologist.


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The Wellsite Geologist is the supervisor in all matters related to the handling, markingand shipment of the core. This requires that the Wellsite Geologist be present tooversee and assist with these operations.

Ensure that the core is checked for H2S with a Drager tube as early as possible after the core

arrives at the surface.

If the core is to be cut up at the wellsite, another JHA should be held with all those to be

involved prior to the cutting and sealing operation. It may be necessary to request theassistance of a roustabout through the Wellsite Manager to help with the core cutting.

The aluminium inner sleeve is removed from the outer core barrel one section at a time (it

comes in 9m joinable lengths with internal flush connections), with a roughneck utilising a

rubber pipe cleaner to remove most of the mud from the inner barrel. Each inner barrel isthen secured in a core cradle, lowered down the V-door and laid out on the

catwalk/pipedeck.

4.2.4 Core cleaning, marking and cutting

ONLY WHEN IT IS SAFE TO DO SO (ie cranes have stopped laying down coring

assembly/picking up next coring or drilling assembly on/from the catwalk/pipedeck) should

cleaning, marking, cutting (or running core gamma) of the core proceed. At no time shouldthe core be worked on when cranes are working overhead.

The inner barrels must be sufficiently cleaned so that markings do not smear. Cloth rags

and water should be used with water-based mud, and cloth rags with diluted detergent withoil-based mud, then cleaned with cloth rags and water to prevent any detergent residue

which may make marking of barrels difficult.

Markings must be made with permanent ink/paint markers. When the lengths of inner

barrel are laid out in order, the top of the core is located and marked showing the depth at

which coring commenced. Parallel reference lines are then marked on the inner barrels inblack and red markers. These consist of parallel black and red lines and an orientation

arrow (at metre intervals on the reference lines). When facing the core (core in a vertical

position) the arrowhead will point to the bottom of the core (increasing depth) with the red

line is on the right of the black line.

Core chips from barrel ends are to be taken for initial microscopic analysis and description.

Retain the core chip samples for possible future examination. Any barrels only partiallyfull will be adequately packed to ensure no core movement within the barrel. Seal barrels

with end caps and clips (ensure they are tightened securely) as soon as possible. If

required, core gamma ray equipment should be run.

As OMV Australia requires the inner barrel with core intact to be cut into 1 metre lengths

at the well site, the following procedures will apply. Once the top of the core has been

positively located, usually by cutting off the empty upper part of the inner barrel, saw cut


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locations are marked on the barrel. Naturally, these will mostly be 1 metre apart but

occasionally it is convenient to cut slightly more or less than a metre such that subsequent

cuts on an even metre. As the cut depths are marked, each section is marked with the topand bottom depth (horizontally) on the barrel but offset from the ends such that the

depths will be clear of the sealing caps. This is a two man job with both checking the

depths are sequential. Be sure that any pieces removed at the barrel break on the rig floorare sequentially included at the correct depth. Whilst this is happening a third person can

start putting OMV Australia, the well name, core number and end depths (vertically) on

the central part of the section - be sure this is done consistently such that horizontalend depth matches the vertical depth nearest to it (see figure below). Once the cut

marking is complete, double check that the tally is consistent and all pieces have been

included, then count the number of sections. Each section should then be marked 1 of 32,

2 of 32 (or 1/32) etc starting from the top. Again double check that everything isconsistent. Then, and only then, can the cutting of the barrels commence.

OMV Australia

A fully marked core piece ready to be capped.

The cutting is performed by the coring company personnel using the coring company

equipment. Adequate safety precautions must be taken by all involved in cutting the core to

avoid breathing the dust from cutting and also in handling the saw and core pieces.

As the saw cuts are made, core chips should be taken from every cut for microscopic

examination, description and show analysis. The sleeve is then sealed with the airtightplastic end caps made secure with steel clips. The end caps are then marked with their

appropriate depths. The core lengths can then be packed securely in core crates for

dispatch from the wellsite. Time is of the essence in sealing the cores into the sleeves as

soon after cutting as possible.

Removal of the core from the inner barrel at the wellsite is not to be attempted,as the core

is to remain as undisturbed as possible to achieve the most meaningful core analysispossible.

If the core is to be choppered off the rig a hole should be pierced in the end cap if the corecontains gas as this will expand and the caps could pop off. As the hole should be in the

centre or upper side of the cap to prevent expanding gas forcing mud out, this operation

should be undertaken when the core sections are in their transport position.

Audacious-2 core #1-2core #1

1234-1235m 5/321234

m

1235

m

Red line

Black line


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4.2.5 Core Shipping

The Wellsite Geologist must ensure that all core (including odd pieces) is packed and

shipped together, as missing pieces can cause delays in core analysis. This does not includecore chips as the core is often shipped off the rig prior to core chip descriptions being

completed and the chips are held asinsurance in case anything happens to the core in

transit.

A core piece reconciliation sheet (in the form of a transmittal) should then be filled in to

assist the laboratory in reconstructing the core. The transmittal should be faxed or emailedto the core laboratory with a copy, sealed in a plastic envelope, attached to one of the core

pieces in the shipment and a copy emailed to the Operations Geologist.

Cores are to be despatched by workboat/truck to the designated core laboratory as soon as

possible, with the Operations Geologist being notified of the shipment details.

4.2.6 Descriptions

All core chip descriptions should be compiled on the Core Chip Description Form (9.4)

The details of the descriptions should be sufficient to identify the nature of any reservoir

lithologies, the distribution of the lithology (i.e. a crude net::gross given the 1 metresample spacing), the effective visual porosity and the amount and distribution of the

hydrocarbon shows. Any information re the nature of the bedding (fine laminations or

massive bedding) observed whilst handling the core should be included.

4.2.7 Core Analysis

Whilst the this section is not strictly applicable to wellsite operations, it has been

included to complete the discussion on coring.

The Core Analysis Company, upon consultation with the Petrophysicist will take plug

samples in the pre-selected sections of reservoir rock for porosity, permeability, graindensity and fluid saturation analyses. A core gamma ray log will be run on the whole

core.

Other analyses, including whole core analysis and Special Core Analysis (SCAL) may be

requested as required.

Upon completion of analyses, the Core Analysis Company will inform the Petrophysicistand obtain permission for slabbing. Some of the core may be saved for whole core


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analysis; as instructed by the Petrophysicist. The slabbed core will be photographed, re-

packaged and distributed as required.

4.3 SIDEWALL CORING

4.3.1 Programme

The generalities of the percussion and/or rotary sidewall core programme, ie purpose of

sampling, interval to be covered and number of runs, will be given in the Drilling

Programme. However, it is the responsibility of the Wellsite Geologist to considerwhether additional sidewall cores are required to thoroughly evaluate the well in a cost-

effective manner. If an additional gun/run is required this should be agreed by the

Operations Geologist.

Upon recording the first log in the well, a preliminary programme of sampling depthswill be provided to the Wellsite Geologist in a digital format. If rotary sidewall cores arebeing acquired, the percussion sidewall cores will be mainly acquired in non-reservoir

lithologies for seal and biostratigraphic purposes.

The relative density of sidewall cores to be used for biostratigraphy, geochemistry,lithology determination, petrology and other purposes will be resolved by Project

Geologist, who will ensure that the sidewall core programme satisfies the well objectives.

4.3.2 Percussion Sidewall Core Operations

A percussion sidewall core programme will be provided to the Wellsite Geologist (in

digital format) via the Operations Geologist. The Logging Engineer will incorporate this

into a shooting list spreadsheet to determine the bullet type, charge and ring sizes. Eachlocation is to be annotated with any pertinent information such as the expected lithology

and sonic, gamma ray and caliper values. Actual lithology of the recovered cores should

be noted in the comments section of the shooting list and a copy obtained by the WellsiteGeologist for future reference.

When the tool is being handled on the rig-floor or cat-walk, ensure all safety precautions

are observed. Discuss this with the Logging Engineer and Wellsite Manager (DrillingSupervisor). All arc-welding and radio transmissions from the rig should be shut-down

during critical phases of these operations. In certain circumstances the cable can act as an

aerial and cause auto- firing of the charges.

When the tool is recovered to surface, the Wellsite Geologist should assist the Logging

Engineer with retrieval of the sidewall cores. As each bullet is removed from its tether,they should be replaced in their respective places in the gun or placed in pre-marked

containers, to ensure that cores are not misplaced in depth. Each core should be pressed


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from the bullet in the presence of the Geologist and placed into bottles and appropriately

labelled.

Lost or partial recoveries should be logged and agreed with the Logging Engineer as they

are not chargeable.

4.3.3 Percussion Sidewall Core Descriptions

Sidewall cores should be described using the appropriate form (Section 9.4). Sidewall

cores acquired on subsequent runs in the hole are to be numbered sequentially from the

previous run. Abbreviations used with this form should be self explanatory.

4.3.4 Rotary Sidewall Core Operations

Ensure the sidewall core programme is provided to the Logging Engineer as a digital

listing. Each location should be annotated with any pertinent information upon thelithology expected and whether it is likely to be "soft" or "hard". Also all samples to be

taken in out-of-gauge hole should be identified. The logging Engineer should drop two

discs, say half way through the program or after a critical interval has been cored, to givea correlation point for sample recovery reference.

When the tool is recovered to surface, the Wellsite Geologist, in consultation with the

Logging Engineer, is responsible for the final assignment of core number/depth to therecovered cores. The Wellsite Geologist is responsible also to ensure the cores are placed

in their appropriately numbered container.

Lost or partial recoveries should be logged and agreed with the Logging Engineer as they

are not chargeable.

4.3.5 Rotary Sidewall Core Descriptions

All sidewall cores should be described using the appropriate form (Section 9.5). The

cores should not be tampered with in the process of description (ie do not take chips etc).

4.3.6 Core Labelling, Packaging and Transportation

In order to preserve samples intact and to prevent the sample from being damaged intransit, each sample is to be packed using aluminium foil (shiny side to core) and then

wrapped in cling wrap. The cores are then to be packed in a box and hand carried to the

Operations Geologist (or Designate) by the Wellsite Geologist.

All sidewall core containers should be labelled thus:


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Operators Name:

Well Name:

Suite Number:Sample Number: An M precedes the rotary (mechanical orMSCT)

Sample Depth: (to be in the same format as the wireline record eg 1 decimal

place)


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5 MUDLOGGING NOTES

5.1 INTRODUCTION

The Wellsite Geologist must have a proper understanding of the data supplied by the

Mudlogging Contractor. This entails a familiarity with the equipment used and itslimitations. Thus, it is important that the Wellsite Geologist take all reasonable steps to

become acquainted with the components of the Mudlogging Unit being utilised by the

contractor for each well, in advance of arriving at wellsite. A Mudlogging QualityControl Report should be a completed on an as required basis (at the start of a new

project, when mudlogging crew members change and when the quality of the service

appears to be slipping). A pro-forma of the report is included as Section 9.8.

5.2 LAG TIME

Correct lag time is imperative to good mudlogging.

5.2.1 Determination of Lag Time (Theoretical)

(a) Divide hole into convenient diameter sections (e.g. cased hole and open holesections);

(b) Determine the annular volume of each section, using appropriate tables (the

Wellsite Manager (Drilling Supervisor) and Mud Engineer will have some);

(c) Sum section volumes to give total annular volume;(d) Determine pump output per stroke;(e) Divide (c) by (d) to determine lag in strokes;

(f) Divide (e) by pump strokes per minute to determine lag time in minutes, if

required.

5.2.2 Determination of Lag Time (Carbide)

Theoretical calculations of lag time are close to true values if the hole is in gauge, but ashole enlargement is not uncommon, carbide lags should be performed regularly by the

mudloggers to determine true lag time and also to test the efficiency of the gas detection

equipment.

The procedure is to insert a fixed quantity of carbide (CaC 2) in the drill string at a

connection. When the paper container of carbide hits the bit, mud reacts with the carbideto form acetylene gas (C2H2). This travels up the annulus and is recorded as a gas peak

on the gas detection equipment, affecting both C1 and C2 curves on the chromatograph.

Each carbide check should be recorded on the Mudlog.


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Lag time is determined by subtracting the calculated down time from the total time.

Trip gas and connection gas will also be good indicators of lag time as they usually, butnot always, originate from the bottom of the hole.

Depending on ROP, carbide lag checks should be performed once per tour or every 250m drilled to ensure an accurate lag time is maintained.

Do not perform carbide lag checks too close to a prognosed or possible reservoir sectionas the gas peak may complicate identifying carbide gas from formation / reservoir gas.

If oil based mud is being used a carbide lag test is ineffective. Rice or some other marker

may be used but tends to be difficult to see. Drilling parameter (ROP, torque) changetogether with MWD data may be used to predict a lithological change which then can be

verified by careful spot sampling. If the spot sampling is recorded against the lag record

(preferably total pump strokes) then the lag can be verified or adjusted.

5.3 TOTAL GAS DETECTOR

The hot wire detector has been the standard instrument used for gas detection for many

years. The principle of the instrument is a Wheatstone bridge (balancing circuit) withtwo platinum filaments, one open to the atmosphere and one in contact with ditch gas

which is sucked (or blown) across it. Hydrocarbons burn on the filament, increasing the

resistance of the filament and thus producing a current which is recorded as units. Thelimitation of a hot wire detector is that as the percentage of hydrocarbons increases, a

point is reached where insufficient air is present for combustion, leading to inaccurate gas

readings.

A flame ionization detector (FID) system can be used instead of the hot wire detector.

All hydrocarbons are burned between ionized poles in a hydrocarbon flame. The ionsformed during burning (proportional to volume of hydrocarbons) flow to the ionizing

poles, and are measured as total hydrocarbon percentage.

The reponse of the FID is in proportion to both the quantity and carbon number of thegas. Thus, an FID reading (in units) is only correct if the gas is all methane. A change in

FID reading can be caused by a change in concentration and/or type of gas. Evaluation

with the chromatograph should resolve which is the case.

Total gas is to be reported in percentage.

5.4 GAS CHROMATOGRAPH

The partition gas chromatograph is usually used in Mudlogging. A sweep gas flowscontinuously through a column that is packed with inert solid (e.g. fibreglass) coated with


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a non-volatile organic liquid. The heavier components of the sample tend to be absorbed

into the column material and are swept very slowly along it. The lighter components are

relatively unaffected and move along very rapidly. The transit time for each compound isfixed for a given pressure, temperature and flow rate of the carrier gas.

The signal from the gas analyser is fed to a strip chart to produce a time vs concentrationrecord. The position of the peak indicates the composition of the gas, the area under the

peak (for convenience often taken as the height of the peak) equals concentration.

Hydrocarbons heavier than C5 are usually not of interest, (as pentane is a liquid below 3-oC (so will probably condense in the suction line to the logging unit), and the total cycle

would be very long to record C5+. Thus a backflush air sample is blown through the

column after a few minutes to remove heavy gases.

Analysis for the amount of gas in the exit stream from the column may be made with a

number of instruments. A flame ionization system similar to the total gas detector is

usually used.

The instrument is calibrated with two known mixtures for low and high range sensitivity.

Chromatograph readings will be reported in ppm.

5.5 DRILL RATE

Drill rate is an important diagnostic tool used to evaluate porosity, lithology changes and

geopressured formations. Several devices are used to measure drill rate, all of them

measure the relative movements of the drill string with reference to the rig floor. On rigswith motion compensation, the sensor should be placed above the motion compensator.

The depth is not determined independently by the Mudloggers - they need the pipe tally.This pipe tally often proves to be wrong, so, much care should be taken to ensure that

depths are correct, especially in fast drilling, in reservoir sections and whilst coring.

Prior to coring, it is advisable that the drill pipe be strapped out of the hole.

5.6 PIT LEVELS

5.6.1 Drop in Pit Levels

Mud returns have been lost or partially lost to the formation. The level of mud in the

well bore will drop, lowering the hydrostatic head, possible below the pore pressure - thisis a dangerous situation - the result may be a kick or at worst a blow out.

5.6.2 Rise in Pit Levels


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The formation fluid is entering the well bore. Mud is being displaced. The well is

flowing. The formation fluid may be water, oil or gas - this also is a dangerous

situation - this is a kick or a blowout.

All changes in pit levels must be investigated and acted upon.

5.7 OTHER COMMON EQUIPMENT

Hydrogen sulphide is monitored for safety reasons. Other parameters such as continuous

weight on bit, rotary RPM, torque, pump pressure, mud weight, mud resistivity and mud

temperature will be recorded by the Mudlogging Contractor. These parameters are usedto determine drilling efficiency, bit life, "D" exponent and other drilling criteria. The

Wellsite Geologist will become familiar with the use of this data by correlation of such

variables as ROP to lithology.

5.8 SAMPLING PROCEDURES (CUTTINGS)

Cuttings samples are usually collected at the shale shaker. The Wellsite Geologist will

ensure:

lag time is correct,

the sample is representative of the sample interval - place a board under the screenand collect samples off the board, cleaning it thoroughly after each sample has been

taken. Note that samples directly off the screen represent only a few moments of

drilling and are not representative,

all drilling breaks are sampled, regardless of the prescribed sampling interval,

a flowline and desander/desilter sample is collected from time to time and comparedwith samples from the main shakers. If significant fine material is going over the

main shakers, catch samples from the desander/desilter as well as from the shaker and

have finer shaker screens fitted if possible.

5.9 EVALUATION OF MUDLOG SHOWS

5.9.1 Factors Affecting Gas Shows

Several factors affect the size of a gas show as recorded at the surface on the Total Gas

detector. The strongest gas indication will result from:

Large hole size

Fast drilling rate


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Slow circulation rate

High porosity and permeability (assuming no flushing)

Small bit cuttingsHigh hydrocarbon saturation

Minimal hydraulic flushing ahead of the bit

Low pressure differential of mud column to the formationHigh gas trap efficiency

Low mud weight (low hydrostatic overbalance necessary for depleted reservoirs)

Low viscosity and water lossHigh GOR

Other factors being equal, we can minimise effect of varying drill-rate, circulation rateand/or hole size on the Total Gas reading to produce a Normalised Total Gas value by

using the following formula:.

NTG = TG x (Q/(ROP x D

2

))

Where NTG = normalised total gas, TG = actual total gas, Q = flow rate, gals/min, ROP = rate of penetration, m/hr and

D = bit size, ins.

It should be emphasised that changes in drilling parameters can have major impact on thesize of a gas show. Relatively low gas readings on the mudlog alone do not necessarily

imply low gas saturation in the formation. For example, simply by decreasing the

drilling-rate (eg. in controlled drilling), with all other factors constant, we will cause acorresponding decrease in the total gas readings that would be obtained from a

homogeneous, gas-saturated reservoir.

The effect of permeability should also be considered. Frequently, high ditch-gas readingsmay be obtained from tight gas-bearing section (typically with corresponding high

cuttings gas readings) while ditch gas shows from more porous and permeable gas-

bearing reservoirs may be reduced due to a higher hydrostatic overbalance pressure thanneeded, or flushing ahead of the bit.

Consequently, the Total Gas Curve on the Mudlog does not necessarily present a simplepicture of the occurrence of gas in the formation. A low Total Gas indication on the

Mudlog does not always imply a high water saturation in the formation. Changes in the

gas curve tend to be more important than absolute values. Only by taking into account all

the interacting variables can a property evaluation be made. The Wellsite Geologist mustbe aware of all relevant drilling parameters in evaluating a show, so that no potential pay

zones are overlooked, and to enable him to make a sound recommendation for further

evaluation if necessary (i.e. testing and/or log evaluation). Whilst the gas values on themudlog are those actually recorded, Mudlogging contractor can produce a normalised

plot of the various gas values and such plots should be requested when, for instance,

significantly varying ROPs are encountered on penetrating, and within, a potentialreservoir section.


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The Hydrocarbon Show Evaluation Form (Error: Reference source not found) will assist

in this evaluation.

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