1.1
DUTIES DUTIES AND RESPON RESPONSIBI SIBILITI LITIES ES OF THE WELLSITE WELLSITE GEOLOGIS GEOLOGIST T
The Wellsite Geologist is responsible for ensuring that geological data is collected, evaluated and recorded at the wellsite and reported reported to the Operations Geologist. Geologist. These duties include supervision of the Mud Logging and Wireline Logging contractors and necessitate close liaison with the Wellsite Manager (Drilling Supervisor). The Wellsite Geologist’s Checklist (Section 7.4) 7.4) is to be read and checked off as appropriate before leaving 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 Describing and recording (in the format defined in these Procedures) the litho litholo logic gical al assem assembl blag ages es enco encoun unter tered ed in the well. well. It is import importan antt to emphasise that the Wellsite Geologist and not the Mudlogger has this function as his/her primary responsibility.
•
Witnessing and reporting wireline logging operations, ensuring adequate quality control.
•
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 and paper 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 and Exploration. The Wellsite Manager (Drilling Supervisor) is responsible for the efficient, economic and safe performance of the drilling operation assuring suitable hole conditions for the well evaluation. It is important important to keep the Wellsite Manager (Drilling (Drilling Supervisor) informed informed of the expected evaluation programme, or of any programme changes, for his planning purposes. He is to be advised immediately of all hydrocarbon shows, increases in mud gas readings, significant changes in shale de nsities or any other factor which could effect rig safety or the proposed evaluation evaluation activities. All requests involving rig rig activity must
be given through the Wellsite Manager (Drilling Supervisor) and not directly to drilling drilling contractor personnel.
1.2
SAMPLE MPLE DE DESCRIP CRIPT TION ION
1.2.1 .2.1
Intr Intro oduc duction tion
The purpose of this procedural summary is to provide a methodology, which should result in a consistent and meaningful description of cutting samples within the constraints of working at wellsite. wellsite. The preparation of cutting samples 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 the utility 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. 1.2.2 2
Cutti Cutting ngs s Desc Descri ript ptio ion n
The Wellsite Geologist should note the lithological and hydrocarbon show descriptions for each sample on the Cuttings Description Report. The Cuttings Description Report should accurately reflect the sample as observed by the Wellsite Geologist with with the exception of obviously caved material. material. Separate notes should be made to reflect the Wellsite Geologist's interpretation 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 ambiguities resulting from differing styles adopted by geologists, the procedures for the description of cutting samples (Section Error: Reference source not found. found. Sample Description) should be adopted. 1.2. 1.2.2. 2.1 1 Show Show Eva Evalu luat atio ion n
be given through the Wellsite Manager (Drilling Supervisor) and not directly to drilling drilling contractor personnel.
1.2
SAMPLE MPLE DE DESCRIP CRIPT TION ION
1.2.1 .2.1
Intr Intro oduc duction tion
The purpose of this procedural summary is to provide a methodology, which should result in a consistent and meaningful description of cutting samples within the constraints of working at wellsite. wellsite. The preparation of cutting samples 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 the utility 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. 1.2.2 2
Cutti Cutting ngs s Desc Descri ript ptio ion n
The Wellsite Geologist should note the lithological and hydrocarbon show descriptions for each sample on the Cuttings Description Report. The Cuttings Description Report should accurately reflect the sample as observed by the Wellsite Geologist with with the exception of obviously caved material. material. Separate notes should be made to reflect the Wellsite Geologist's interpretation 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 ambiguities resulting from differing styles adopted by geologists, the procedures for the description of cutting samples (Section Error: Reference source not found. found. Sample Description) should be adopted. 1.2. 1.2.2. 2.1 1 Show Show Eva Evalu luat atio ion n
The Wellsite Geologist is responsible for the monitoring and reporting of all hydrocarbon shows from wellsite. In order to fulfil this function, the Wellsite Wellsite Geologist must ensure that the Mudlogging Contractor is adequately prepared and maintains all equipment in a workable state (Section 5. Mudlogging). All Hydrocarbon Shows should be reported using the Show Evaluation Report, 9.6, as a guide.
1.3 1.3
MUDL MUDLOG OGGI GING NG SUP SUPER ERV VISIO ISION N
The Wellsite Geologist is responsible for the direct supervision of the Mudlogging Contractor. The duties of the Mudlogging Contractor Contractor will be defined in Drilling Drilling Programme. Section 5. Mudlogging also contains information concerning the daily and other routine performance tests to be conducted on the Mudlogging Unit. Before going to wellsite it is important that the Wellsite Geologist is informed by the Operations Geologist the type of Mudlogging U nit 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 for each well. The Wellsite Geologist has the responsibility responsibility to ensure that any programmed cores are cut, described and transported, following the procedures detailed in Section 4. 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 to Operations Geologist with a recommendation, recommendation, for review. Agreement to core will be made following consultation consultation with others as may be required. required. Meanwhile, hole conditioning should be considered, in consultation with the Wellsite Manager (Drilling Supervisor).
1.5
WIRE IRELINE LINE LOGGING ING
The Wellsite Geologist is responsible for ensuring that the Wireline Logging Programme, as detailed in the Drilling Programme is completed in a competent and expeditious ex peditious manner. The following general comments are relevant relevant and are to be followed.. It is the responsibility of the Wellsite Geologist, to ensure that wireline logs of satisfactory quality are obtained. obtained. In order to accomplish this 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 an Extrapolated Temperature Plot (which are compon ents of a linked set of spreadsheets) should be duly completed:
1.5. 1.5.1 1
Gene Genera rall Req Requi uire reme ment nts s
•
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 Mudlogging Engineer 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 circumstances should a pit sample be taken. If this is the 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 data should be double checked for validity and all temperature data verified. This information should also also be noted on the Log Header under “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,
% 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 Wellsite Geologist will be required to supervise or attend p roduction testing.
1.7
LIAISON WITH WELLSITE MANAGER (DRILLING SUPERVISOR)
The Wellsite Geologist should keep the Wellsite Manager (Drilling Supervisor) informed of 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
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 or fax.
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 wherever possible 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 sufficient consumables for the bagging and boxing of all samples and cores.
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 dissemination of 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 Geologist is on location. Given that communication access is not unlimited, the most convenient time for transmission will be determined following discussions between the Wellsite Geologist, Drilling Supervisor and Operations geologist. This will 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 is reproduced 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 Operations Geologist. 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:
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 pore pressure 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 this should 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: •
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 to where 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 requested from the mudloggers. A brief summary of the interval lithology should p recede 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) •
•
•
•
•
The lithological descriptions for Daily Reports should be concise. Additional detail may be appropriate where the following circumstances arise:
Hydrocarbon Shows:
•
Should be described using Section 9.6 Show Evaluation Form 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 continuing calcimetry 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 be done 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
•
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 •
•
•
•
2.3
Remarks
The remarks section is for any other pertinent information not mentioned elsewhere in the DGR, such as formation tops, comparison w ith 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.
INTRODUCTION
It is important to note that the following material is designed to address the description of cutting 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. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12.
Rock type (% and modifier, if required). Colour or colour range. Hardness Fracture and texture Grain size: Range and Dominant size Sorting Angularity Sphericity Matrix Cementation: Degree, Percentage of each cement and Composition. Accessories and Fossils: Type and Percentage of rock Effective Visual porosity
13. 14.
Hydrocarbon indications 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, in the order described.
The ‘Cuttings Description Report’ is the primary recording tool for sample d escriptions. 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
2.4.1
DISCUSSION OF ELEMENTS COMPRISING A LITHOLOGICAL DESCRIPTION
Sample Quality
It is inevitable that cuttings samples will be contaminated to some extent by cavings. The use 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 and also 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 interval of missing samples and the reason why they are missing. Such intervals should be noted on the transmittal forms.
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
UNCONSOLIDATED SEDIMENTS
CONSOLIDATED SEDIMENTS
MINERALS (> 20% OR IF SIGNIFICANT)
Gravels
Breccia and Conglomerate
Quartz Carbonate Arkose
Sands
Sandstone
Silts
Siltstone
Clays
Claystone/ Shale
Glauconitic Haematitic Arkosic (> 30% Feldspar) Feldspathic (10-30% Feldspar) Micaceous Anhydritic Pyritic Carbonaceous Cherty
As for sandstones
Micaceous Haematitic/Limonitic Glauconitic Pyritic Gypsiferous Carbonaceous Chloritic Quartzose (silt size grains) Feldspathic (silt size feldspar) Dolomitic (Dolomite Rhombs)
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 calcareous claystone 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 Grain Size
Lithological Name
Greater than sand sized
Calcirudite Calcarenite Calcisiltite Calcilutite
Sand sized Silt sized Clay sized
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
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 same light 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 Friable Soft pressure. Plastic Firm Moderately hard Hard
-
Particles are discrete and non-coherent. Coherent, but crumbling under slight pressure. Clays, marls and silts which can be deformed by slight
-
Very Hard
-
Dense
-
Brittle
-
Pliant clays that show putty-like deformation. Compact, breaks under slight pressure. Grains can be detached using knife. Solidly cemented or lithified. Does not break under slight pressure, but can be scratched with knife blade. Fractures go between grains. Cannot be scratched with a knife blade, usually siliceous. Fractures pass through grains. Commonly used to indicate a fine-grained, well lithified tight rock (usually limestone) with sub-conchoidal fracture. 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 of cleavage or bedding, seen in shale and limestone cuttings. They include: Blocky
Used to describe claystone, and limestone in which fractures are 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 developed on fractures. The fracture of hard limestone produces somewhat less strongly developed curved surfaces and the fracture has been called "sub- conchoidal".
Flaky
The rock fractures into small flakes or chips. Common in some argillaceous limestones and occasionally in metamorphic rocks.
Platy
Used to describe shale in which fissility is well developed. The rock breaks in parallel sided thin plates. This is commonly caused by fracture along bedding planes, or along cleavage directions.
Splintery
Used to describe shales in which the fissility is not strongly developed, but exists sufficiently to cause irregular surfaces and 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 a rock 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 vitreous;
Smooth:
dull, nacreous, resinous, polished, and
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 Hygroclastic Hygrofissile
2.4.7
swelling in a random manner dispersing as irregular fragments separating into tabular flakes
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
Above 256 256 - 64
Boulder Cobble
Lithological Name Conglomerate
64 - 4
Pebble
4-2 2-1 1 - 1/2 1/2 - 1/4 1/4 - 1/8 1/8 - 1/16
Granule Very Coarse Coarse Medium Fine Very Fine
1/16 - 1/256
Silt
Siltstone
Less than 1/256
Clay
Claystone/Shale
Sandstone
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 describing these properties. See Appendix 2 Roundness and Sphericity for the visual appearance of the 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
Very well Well Moderate Poor
90% of grains in one grain size class, 90% of grains in two or three grain size classes, 90% of grains in four grain size classes, 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 be poorly 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 are Elongate and Spherical . See Appendix Roundness and Sphericity 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 of sphericity abandoned.
2.4.11 Cement
Identified by type and effectiveness of the cement (calcite, quartz, dolomite etc.). Adjective
% of Pore Space Filled
Well Moderately Poorly
70-100% 30-70% 0-30%
Discussion (from AAPG Sample Examination Manual) Cement is a chemical precipitate deposited around the grains and in the interstices of sediment 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, or generations 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.
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 are deposited as crystals in the interstices and as agg regates in the voids. Dolomite and calcite may be indigenous to the sandstone (the sands having been a mixture 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 porosity either by compaction, or by swelling when water is introduced into the formation. Argillaceous material can be evenly distributed in siliciclastic or carbonate rocks, or have laminated, lenticular, detrital or nodular form. Compaction and the presence of varying amounts of secondary quartz, secondary carbonate, 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-grained sandstones 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 finer grained 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 Trace Rare Minor Common Abundant
Definition less than 1% 1 - 5% 5 – 10% 10 - 20% 20% or greater
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 being examined. 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 or photographs 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 a rock, may be significant indicators of environment of deposition, as well as clues to correlation. The most common accessories are glaucon ite, 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 the microscope. 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 that have 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 poor porosity. 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 to arriving at wellsite. Porosity does not systematically vary with the size o f 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.
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 Good Fair Poor Nil (Tight)
20% and greater 15 - 20% 10 - 15% 5 - 10% 0 - 5%
Porosity type can be described as: Intergranular - intercrystalline Vuggy - cavernous Fracture Solution.
2.4.14 Hydrocarbon Indications
See Section 3. Show Evaluation
3 3.1
SHOW EVALUATION 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 log all 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 the specific chemical, physical, and biologic properties of each hydrocarbon accumulation. The physical degradation of the shows (highly volatile fractions dissipate quickly), and flushing by drilling fluids or during sample washing, also tend to mask or eliminate evidence of hydrocarbons. The presence or absence of obvious shows cannot always be taken as conclusive. In many 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 been described, together with recommendations for the ranking of the significance of shows. The following procedures have been directed, primarily, to the accurate description of shows 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 hydrocarbon show (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-based muds (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)
Colour Amount Distribution
minor (10%), moderate (10-50%), major (50-90%), saturated (100%) 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) Colour Degree 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) Colour Degree 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 its significance. 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).
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 delay between 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-stream from the gas trap to the Logging Unit. Total gas readings should be evaluated by the magnitude of deviations from a background value. The background gas, however, may change with mud chemistry and such sources should be monitored. In addition, there are several false hydrocarbon shows described 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 ---------------
=
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 LHR can 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 biodegraded oil 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 Sample Examination Manual. Minor changes have been made to make the qualitative description of shows match those utilised elsewhere in these procedu res.
3.5.1
Staining and Bleeding
The amount by which cuttings and cores will be flushed on their way to the surface is largely 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 should be reported as a proportion of the sample as minor (<10%), moderate (10 - 50%), major (50 - 90%) and saturated (90 - 100%). The colour of the stain or bleeding oil should be reported. The colour of the stain is related to oil gravity. Low API oil staining tends to be a dark brown, while high API oil staining tends to be colourless. The distribution of the stain on grains or chips should be reported as even, spotty, mottled or streaked. Ferruginous or other mineral stain may be recognised by lack of odour, fluorescence, or cut.
3.5.2
Odour
Odour may range from heavy (characteristic of low gravity oil) to light and penetrating (characteristic for condensate). Some dry gases have no odour. Describe the type as oil odour or condensate odour. Strength of odour depends on several factors, including size of sample. Depending on strength of odour detected, report as faint, moderate, or strong. Faint odours may be detected more easily on a freshly broken surface or after confining the sample in a bottle for 15-20 minutes.
3.5.3
Sample Fluorescence
Examination of mud, drill cuttings and cores for hydrocarbon fluorescence under ultraviolet light often indicates oil in small amounts, or oil of light colour which might not be detected by other means. All samples should be examined. Colours of fluorescence of crudes range from brown through green, gold, blue, and yellow to white. In most instances, the heavier oils have darker fluorescence. The intensity range is bright, moderate and weak. Distribution may be even, spotted, or mottled, as for stain. Pinpoint fluorescence is associated with individual sand grains an d may indicate condensate or gas.
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, whereas mineral fluorescence will remain undisturbed. Mineral fluorescence that may be encountered in samples includes: Calcite
dim to bright blue white to yellow (orangey pink if
Siderite Anhydrite Dolomite Amber
dull to dim orange dim to bright blue white to greyish white occasionally yellow to yellow brown bright yellow (with fast streaming cut)
aragonite)
3.5.4
Hydrocarbon (Solvent) Cut
Oil-stained samples which are degraded or oxidised may not fluoresce. Thus, failure to fluoresce 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 the colouration:, 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 an indication 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 of the pure solvent as control. The sample should be thoroughly dried before applying the
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 will not 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 commonly true 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 cut fluorescence 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 Gas/condensate 35-45o API 25-35o API 15-25o API less than 15o
no fluorescence white to blue-white, frequently "spotty" blue-white to light yellow light yellow - dark straw yellow dark straw yellow - orange brown 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 a large 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 that are 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 (dissolved hydrocarbons) flowing to the surface of the solvent. Descriptive terms for type and speed are; instant, fast, slow, streaming (individual “streams”) and blooming (“streams” coalesce). The residual cut or ring should be described by its colour and intensity. Both are related to 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.
3.6
3.6.1
OTHER HYDROCARBON DETECTION METHODS FOR CUTTINGS
Wettability
Failure of samples to wet, or their tendency to float on water when immersed, is often an indication 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 not soak 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 a small 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 CO 2 generated by the reaction of the acid with carbonate cement or matrix. In the case of calcareous rock, the reaction forms lasting iridescent 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 buoyed up 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 the fragment, 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 rapid preliminary 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 are present, they form a milky white dispersion (as they are insoluble in water, whereas
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 a depth of 1 cm. Observe the oil film thus formed under ultraviolet light and record the amount of oil released using the following scale: Show Strong Fair Weak Very weak Extremely weak
3.6.5
Proportion of Water Surface Covered by Film 100% 50 - 99% 33 - 50% 25 - 33% less than 25%
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 ne arly colourless oils where oil staining may be absent. Iridescence may be observed in the wet sample tray. Iridescence without oil 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 of contamination.
3.7
GENERALISATIONS
No "rules of thumb" can be used to relate the evidences of the presence of hydrocarbons to 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 hy drocarbon detection methods.
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.
4 4.1
DRILLING BREAKS, CORING AND SIDEWALL CORING 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 Mudlogging Engineer are of paramount importance. When a break occurs, the Mudlogging Engineer is to be responsible for advising the Wellsite 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. If coring is anticipated, a total of two to three metres of the break interval will be drilled prior to the samples being circulated to the surface for examination. Drilling breaks into the objective section should be evaluated for hydrocarbon shows as soon 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 and pump 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 sediments are absent. When pulling out of the hole prior to coring, a strap-out measurement should b e requested to ensure that there is no confusion regarding the depth at which the core was taken. Core lithology and recoveries must be recorded on the Mudlog.
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. 2. 3. 4. 5. 6. 7.
broad felt-tip markers or paint pens (red and black) with water proof ink; rags; hammer; sample bags, labelled; notepad and pen; measuring tape; 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 to correlation 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 as this increases the chances of losing the core. The Wellsite Geologist is to observe the progress of the coring operation, noting any abnormalities 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 sharp decrease 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 the Senior Coring Engineer . Those present will include: Coring Engineer, Wellsite Manager, Toolpusher, Driller, Drillfloor Crew, Roustabouts/Dogmen who will be assisting in moving and cutting the core, Mudlogger and Wellsite Geologist.
The Wellsite Geologist is the supervisor in all matters related to the handling, marking and shipment of the core. This requires that the Wellsite Geologist be present to oversee 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 the assistance 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 is then 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 should the 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 with oil-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 in black 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 partially full 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
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 top and 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 floor are sequentially included at the correct depth. Whilst this is happening a third p erson 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 “horizontal” end 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 is consistent. Then, and only then, can the cutting of the barrels commence. Red line
m 4 3 2 1
OMV Australia Audacious-2 core #1-2 core #1 1234-1235m
5/32
m 5 3 2 1
Black line
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 airtight plastic 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 analysis possible. If the core is to be choppered off the rig a hole should be pierced in the end cap if the core contains 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.
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 include core chips as the core is often shipped off the rig prior to core chip descriptions being completed and the chips are held as”insurance” 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 emailed to 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 metre sample 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, grain density 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 Petrophysicist and obtain permission for slabbing. Some of the core may be saved for whole core
analysis; as instructed by the Petrophysicist. The slabbed core will be photographed, re packaged and distributed as required.
4.3
4.3.1
SIDEWALL CORING
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 consider whether additional sidewall cores are required to thoroughly evaluate the well in a costeffective 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 depths will be provided to the Wellsite Geologist in a digital format. If rotary sidewall cores are being 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 p rovided 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. Each location 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 Wellsite Geologist 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 (Drilling Supervisor). 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
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 4.3.3
Perc Percuss ussion ion Sidew Sidewal alll Core Desc Descrip riptio tions ns
Sidewall cores should be described using using the appropriate form (Section (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 4.3.4
Rotar Rotary y Side Sidewal walll Core Core Operat Operation ions s
Ensure the sidewall core programme is provided to the Logging Engineer as a digital listing. Each location should be annotated with any pertinent information information upon the lithology expected and whether it is likely to be "soft" or "hard". Also all samples to 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 give a 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 the recovered cores. The Wellsite Geologist is responsible also to 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 4.3.5
Rotar Rotary y Side Sidewal walll Core Core Des Descr cript iption ions s
All sidewall cores should 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 n ot take chips etc). 4.3.6 4.3.6
Core Labelling Labelling,, Pack Packagin aging g and and Transpor Transportatio tation n
In order to preserve samples intact and to prevent the sample from being damaged in transit, each sample is to be packed pack ed 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:
Operators Name: Well Name: Suite Number: Sample Number: An “M” precedes the rotary (mechanical or MSCT) Sample Depth: (to be in the same format format as the wireline wireline record eg 1 decimal place)
5 5.1
MUDLOGGING NO NOTES INTRODUCTION
The Wellsite Geologist must have a proper understanding of the data supplied by the Mudlogging Contractor. This entails a familiarity familiarity with the equipment used and its limitations. Thus, it is important important that the Wellsite Wellsite Geologist take all reasonable 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 Quality Control 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 report is included as Section Section 9.8.
5.2
LAG TIME
Correct lag time is imperative to good mudlogging.
5.2.1 5.2.1
Deter Determin minati ation on of Lag Lag Time (The (Theore oretic tical al))
(a) Divide Divide hole into into conveni convenient ent diamete diameterr sections sections (e.g. (e.g. cased hole hole and open open hole hole sections);
(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) (d) Dete Determ rmin ine e pum pump p out outpu putt per per stro stroke ke;; (e) Divide Divide (c) by (d) to deter determin mine e lag lag in stroke strokes; s; (f) Divide Divide (e) (e) by pump pump strokes strokes per minu minute te to determ determine ine lag lag time time in minute minutes, s, if required.
5.2.2 5.2.2
Deter Determin minati ation on of of Lag Lag Time Time (Carb (Carbide ide))
Theoretical calculations of lag time are close to true values if the hole is in gauge, but as hole 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 (CaC2) in the drill string at a connection. When the paper container of carbide hits hits the bit, mud reacts with the carbide to 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.
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, but not always, originate from the bottom of the hole. Depending on ROP, carbide lag checks should be performed once per tour or every 250 m drilled to ensure an accurate accu rate lag time is maintained. Do not perform carbide lag checks too close to a prognosed or possible reservoir section as 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 difficult to see. Drilling parameter (ROP, torque) torque) change together with MWD data may be used to predict a lithological change which then can be verified by careful spot sampling. sampling. If the spot sampling sampling is recorded against the lag lag record (preferably total pump strokes) then the lag c an be verified or adjusted.
5.3
TOTAL TAL GA GAS DE DETECTO CTOR
The hot wire detector has been the standard instrument used for gas detection for many years. The principle of the instrument instrument is a Wheatstone bridge (balancing (balancing circuit) with two platinum filaments, one open to the atmosphere and one in contact with ditch gas which is sucked (or blown) across across it. Hydrocarbons burn on the filament, increasing increasing the resistance of the filament and thus producing a current which is recorded as units. The limitation 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. flame. The ions formed 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 the gas. Thus, an FID reading (in units) 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 type of gas. Evaluation with the chromatograph should resolve which is the case. Total gas is to be reported in percentage.
5.4
GAS CH CHROMA ROMAT TOG OGR RAPH APH
The partition gas chromatograph is usually usually used in Mudlogging. A sweep gas flows continuously through a column that is packed with inert solid (e.g. fibreglass) coated with
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 is fixed 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 concentration record. 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 3o C (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 rigs with 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 5.6.1
PIT LEVELS 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 - this is a dangerous situation - the result may be a kick or at worst a blow out.
5.6.2
Rise in Pit Levels
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 used to 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 screen and 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 compared with 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
5.9.1
EVALUATION OF MUDLOG SHOWS
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
Slow circulation rate High porosity and permeability (assuming no flushing) Small bit cuttings High hydrocarbon saturation Minimal hydraulic flushing ahead of the bit Low pressure differential of mud column to the formation High gas trap efficiency Low mud weight (low hydrostatic overbalance necessary for depleted reservoirs) Low viscosity and water loss High GOR
Other factors being equal, we can minimise effect of varying drill-rate, circulation rate and/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 the size 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 a corresponding 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 readings may 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 than needed, or flushing ahead of the bit. Consequently, the Total Gas Curve on the Mudlog does not necessarily present a simple picture 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 must be 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 the mudlog 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 potential reservoir section.
The Hydrocarbon Show Evaluation Form (Error: Reference source not found) will assist in this evaluation.
5.10 FALSE HYDROCARBON SHOWS
5.10.1 Gas
Gas in the mud does not necessarily come from the formation being drilled.
5.10.1.1 Connection Gas
Gas that arrives at the surface at the appropriate lag time after a connection. It comes from several sources: Formation not sealed with mud cake may bleed small quantities of gas into the hole when the pumps are shut off and the effective circulating density is reduced. Drilled shale and other low permeability rocks will bleed small quantities of gas into the hole when the effective circulating density is reduced. Swabbing action of the bit during the connection may drag gas from formations not sealed by mud cake. A second peak is often observed after Connection Gas. This is usually the result of the air-bubble caused by adding a new joint of pipe. As the air-bubble travels up the annulus, it often picks up a small amount of gas from the formation. 5.10.1.2 Trip Gas
Has a similar origin to connection gas. The gas peak is larger than Connection Gas due to more swabbing and the pumps being shut off for a longer time. 5.10.1.3 Recirculated Gas
Gas that has come to the surface, travelled through the surface mud system, back down the hole and up the annulus is termed recirculated gas. The gas peak will be very rounded and will occur at one complete circulation time after a previous peak. Heavy hydrocarbons, high viscosity mud and an inefficient degasser are usually the cause. The source of anomalous peaks on the Total Gas Monitor corresponding to the situations described above should be clearly marked on the Mudlog.
5.10.2 Oil
Oil in the mud, pipe dope, fluorescent mud additives and lost circulation material can make evaluation of oil shows more difficult, but with experience these can often be distinguished quite readily from formation hydrocarbons by the colours of fluorescence (see Section XX). Always examine a sample of pipe dope at the start of each well. When logging with synthetic oil based muds (SBM), some oil clings to the cuttings and gives a direct fluorescence and fluorescent cut that masks true oil shows. The fluorescence of a mud should be observed. Many of the SBMs in use today give a greenish brown to khaki direct fluorescence that contrasts with the yellows of live oil. However, as the synthetic oil and SBM filtrate tends to dissolve the native oil, genuine oil shows are unlikely to be seen in cuttings or sidewall cores. They may be seen in the central part of a core disk. It should be noted that SBM filtrate often gives a bluish-white direct and crush cut fluorescence. Therefore, extreme caution needs to be exercised when reporting any apparent fluorescence if oil based mud is being used.. Whilst it is very rarely done these days, any addition of diesel to the mud should be noted on the Mudlog, with the resultant diesel concentration. A full history of the mud system is essential to an accurate assessment of source-rock geoch emistry.
5.11 PROBLEMS IN INTERPRETING CUTTINGS
5.11.1 Contamination from Previously Penetrated Beds 5.11.1.1 Cavings
Cavings may often be recognised as material identical to that already seen from much higher in the hole. This spalling of previously penetrated rocks into the ascending mud stream is particularly pronounced after trips of the drill stem for bit chang es, drill stem tests, coring operations or other rig activities. Spalling can also be brought about by the action of reamers/stabilisers as drilling proceeds. It is useful to check the BHA configuration if a flood of cavings from a recently drilled higher lithology is suspected. It is suppressed by good mud control, but most samples will contain caved material. Soft shales, thinly bedded brittle shales, and bentonites cave readily and may be found in samples representing depths hundred of feet below the normal stratigraphic position of those rocks. If the borehole is washed out in sections (previous hole problems) then the carrying capacity of the mud (ability to remove cuttings) deteriorates as the mud flows past the washout and subsequently slows down. In this case cuttings may circulate around in the washout and gradually rejoin the main flow to surface. Owing to differences in the hardness of rocks, the type and condition of the bit, and the practice of the driller, one cannot set any hard and fast rule for the size of true cuttings. Caved fragments tend to be larger than fragments of rock from the bit and they are
typically rounded by abrasion. Freshness of appearance, sharp edges and signs of grinding by the bit may be used as criteria for the recognition of fresh cuttings. Casing points should be carefully noted as they indicate to the geologist examining the samples what parts of the hole were open at subsequent stages of the drilling operations and thus were a potential source of cavings. Casing does not entirely eliminate uphole cavings. Rarely caved material is cemented around the bottom of the casing and can show up again in the mud stream while drilling deeper. 5.11.1.2 Recirculation
Recirculation chiefly refers to sand grains and microfossils from previously drilled rocks which re-enter the hole with the mud stream and contaminate the rising sample. The effectiveness of the desander/desilter system should be investigated and the Wellsite Manager (Drilling Supervisor) informed of possible recirculation.
5.11.2 Other Contaminants 5.11.2.1 Lost Circulation Material
A large variety of substances may be introduced into the hole to combat lost circulation difficulties. These include such obviously foreign materials as feathers, leather, hesian sacking, or seed hulls, as well as cellophane (which might be mistaken for selenite or muscovite), perlite, and coarse mica flakes which might erroneously be interpreted as formation cuttings. Most of these extraneous materials will float to the top of the sample tray when is it immersed in water, and so can be separated and discarded at once. Others may need more careful observation. Generally, the sudden appearance of a flood of freshlooking material, which occupies the greater part of a sample, is enough to put the Wellsite Geologist on his guard. The use of different size grades of CaCO3 as LCM material is common. The grains can easily be differentiated from quartz sand by the addition of a drop of acid. The Wellsite Geologist should keep in touch with the mud engineer and obtain samples of any solids added to the mud. 5.11.2.2 Cement
Cement fragments in cuttings are easily mistaken for sandy, silty, or chalky carbonate. However, most cements are of an unusual texture or colour, frequently have a glazed surface, tend to turn yellow or brown when immersed in dilute HCl, and are usually full of fine black specks. Phenolphthalein (a chemical indicator) is generally available at the wellsite (mudlogger or mud engineer) and will stain the cement pink. A sample of cement used for the previous casing string is usually available from the Wellsite Manager (Drilling Supervisor). 5.11.2.3 Drilling Mud
In examining unwashed or poorly washed cuttings, it is often important to be able to recognise the drilling muds that were used. An inexperienced sample examiner may confuse drilling mud with soft clay, bentonite, or sometimes gypsum or carbonate. Thorough washing and rinsing in a pan of water will generally remove most mud contamination. If necessary, lithic fragments can be broken open to see if the interior (fresh) differs from the surface (coated). Oil-base and oil-emulsion muds coat the cuttings with oil, and care must be taken to distinguish such occurrences from formation oil. They are generally recognised because they coat all cuttings regardless of lithology, rather than being confined to one rock type. Such contamination can sometimes be removed by washing the samples with a detergent or with dilute HCl. Lignosulfonate muds may present problems in samples used in palynological studies. 5.11.2.4 Oil Contamination, Pipe Dope, etc.
Foreign substances (such as pipe dope, grease, etc.) from the rig operations sometimes enter the mud stream. Oil may be used to free stuck drill pipe and, in some cases, a tank truck formerly used to haul fuel oil is used to haul water for rig use. In all these cases, the borehole can become contaminated with oil that can coat the drill cuttings. When foreign oil contamination is suspected, cuttings should be broken and their fresh surface examined. Naturally occurring oil will tend to stain the chips throughout. Contamination will remain on or near the surface of the chip.
5.11.2.5 Pipe Scale and Bit Shavings
Rust scale and shavings of metal may also contaminated the samples, but they can be readily removed with a small magnet. They rarely present a logging problem.
5.12 MISCELLANEOUS INTERPRETATION PROBLEMS
5.12.1 Rock Dust
If samples are not washed sufficiently, a fine d ust composed of powdered rock or dried drilling mud may cover the chips with a tightly adhering coat. In such cases, care should be taken that a fresh surface of the rock is described. Wetting the samples will tend to remove this coating, but if the chips are saturated with oil, the powder may still adhere to the surface even after immersion in water, unless a wetting agent or ordinary household detergent is used. These comments are particularly applicable to limestone and dolomite where the powdered rock film tends to be in the form of crystals which may mask the true texture of the rock. In this case, the best procedure is to break a few chips and obtain fresh surfaces for description.
5.12.2 Rock Flour
Rock flour is a common product of drilling in moderately hard to hard sandstones with a PDC bit. Rather than being able to bite in and shear grains off, the PDC cutters are scouring the surface to produce a fine powder with then aggregates into amorphous lumps, often including minute particles of other rock types out of the mud. Rock flour is generally off-white to light grey or brownish white. If the proportion of rock flour in the sample tray shows a steady or sudden increase to become the dominant product, this could indicate that the cutters are badly worn and the Drilling Supervisor should be notified. 5.12.3 Powdering
Powdering is the pulverisation of the cuttings by regrinding (failure of the mud to remove the cuttings from the bit), or by crushing between the drill pipe and wall of the borehole. It can result in the disappearance of cuttings from some intervals, and the erroneous logging of chalky limestone where none exists.
5.12.4 Fusing
Shales drilled by a diamond bit may be burned and fused, resulting in the formation of dark grey or black hard fragments that resemble igneous rock. 5.12.5 Spread
Spread is the separation of large from small cuttings by relative slippage (also called elutriation or differential settling) in the mud stream, so that the cuttings of a rock drilling up into fine chips may overtake the cuttings of a rock drilling up into coarse chips during their journey up the borehole. This results in the wrong sequence of rock types or very mixed samples being recovered.
6 6.1
GEOCHEMICAL SAMPLING INTRODUCTION
Samples intended for geochemical analysis must be preserved and insulated from loss of fluids (by dehydration or evaporation of light hydrocarbons) and bacterial degradation. In order to ensure adequate protection from these pernicious effects, the following procedures are recommended.
6.2
CANNED CUTTINGS SAMPLES
Samples, collected in accordance with the Drilling Programme, should be placed in 0.5 litre cans. Approximately ¾ of the can should be filled with sample. An attempt should be made to maintain the same "fill up" for all samples so that head-space gas analysis (if run) is more meaningful. Samples which are significantly less then the required volume (say less than half full) should be identified with an asterisk following the depth interval. The cans should then be topped up with water and ten to fifteen drops of Zepharin Chloride (bactericide) should be added. A total air gap of 20mm should be left in the can. The can should be sealed and stored inverted (a useful check on the seal of the can lid).
6.3
MUD SAMPLES
Whenever geochemical samples are being collected, mud samples should also be collected at 100m intervals or whenever a change in mud additive is made or suspected. Mud samples should be collected and stored in 0.5 litre tins and labelled with the lagged depth at which it was collected (appropriately lagged). Bactericide should also be added to these samples. Representative samples of all mud additives, pipe dope and other potential "surprises" should be obtained and stored appropriately. Talk to the Mud Engineer about any additions of diesel or oil to the mud system. Many mud additives, which in themselves are not potentially problematic for geochemical analysis, are dissolved in hydrocarbon solvents be fore being introduced into the mud system. It is also fairly common for new drill pipe to be coated with tar and "washed" with chopper fuel or diesel on the drill floor to enable the tongs to grip. All such operations should be minimised, but where unavoidable, notes should be taken to assist interpretation of geochemical data.
6.4
SIDEWALL CORES (SWC)
Any sidewall cores which are specifically collected for geochemical analysis should be carefully wrapped in cling film and aluminium foil. The samples should then be placed in SWC jars and identified as geochemical samples.
6.5
CORE CHIPS
Any core chips which have been allocated for geochemical analysis should be stored in a similar manner to sidewall cores.
7
GEOPRESSURES
Statistically, nearly half of the land wells and one third of the world's offshore wells contain geopressured zones. Geopressures are those pressures greater than the hydrostatic pressure of the formation fluids. Pressures less than hydrostatic are called subnormal. If the formation fluid is fresh water (8.33 ppg), the normal or hydrostatic gradient is 0.433 psi/ft. The maximum pressure gradient for an abnormally pressured formation is limited by what is called the overburden gradient. The overburden gradient is derived from the pressure exerted by the weight of the rocks and contained fluids above the depth of interest. Formation pressures greater than overburden pressure are uncommon.
7.1
ORIGIN OF ABNORMAL PRESSURES
Countless studies on the origin of abnormal pressures have been published. In basic terms, abnormal pressures are caused by four different phenomena, as follows:
7.1.1
Aquifer
An aquifer is simply a formation containing mobile water, much like an artesian well. In abnormal pressure theory, an aquifer is a permeable horizon that crops out at an elevation appreciably higher than the elevation of the well. The water entering the outcrop influences the pressure encountered in the well bore. Although the pressure is hydrostatic in nature, the illusion is given that it is geopressured because of the increased hydrostatic head.
7.1.2
Charged Shallow Sands
High pressure can occur in shallow sands if they are charged by gas from lower formations. This condition may result from a poor surface casing cement job, casing leak or blowout in a nearby well. Shallow sands can also be highly pressured if sediments that have been rapidly deposited overlie gas accumulations (often via fault communication). These occurrences are isolated but have caused blowouts where the casing programmes have not been designed to withstand the unexpected pressures.
7.1.3
Tectonic Movement
In areas of significant tectonism, uplifting or faulting can create geopressured environments. A formation that is normally pressured at a greater depth can be uplifted
to shallower depth. Should the original pressure be retained, abnormally high pressures can result. The magnitude of the overpressure is a function of the present depth of burial and the degree of uplift.
7.1.4
Compaction
Compaction is the most common and best-understood phenomenon causing abnormal pressure. As long as the sedimentary process allows the water in the pore spaces to escape to the surface with the addition of overburden, the formation pressure will remain hydrostatic. When the water is no longer allowed to be squeezed out, the sedimentary grains cannot compact since the water is essentially incompressible. Support of the overburden is then transferred from the rock matrix to the fluid and geopressures result. It is evident that the presence and effectiveness of the "seal" is the key to abnormal pressure from compaction. With this in mind, the existence and magnitude of pressure in a sedimentary environment are dependent on the following, all of which impede the flow of formation water: Presence of an impervious (low permeability) overlying formation - rock, salt, clay or shale deposits. Thickness of the impervious overlying strata. Depth of burial - the deeper the depth of burial, the greater the compaction and resistance to flow. Age - the older the sediments, the greater the possibility that excess reservoir pressure will be dissipated with time through micro-fissures, cracks, etc. Faulting - regional growth faults contribute to the origin of abnormal pressures by redistributing sediments and placing permeable zones opposite impervious zones, thus inhibiting the establishment of hydrostatic equilibrium. Absorption - under certain conditions, adhesion o f liquid or gas molecules to the surfaces of minerals can retard flow during the compaction of shales. Osmosis - the spontaneous flow of water to a level with a higher salt content that is separated from a horizon with low salt content by a semi-permeable (clay) membrane in effect can create permeability in the clay bed.
The perfect seal rarely exists, but as long as water expulsion is retarded, especially under conditions of rapid deposition, abnormal pressures can result.
7.1.5
Diagenesis
In sand-shale sequences, the alteration of montmorillonite to illites releases free water to the pore spaces. If the additional water is not allowed to escape, the pore fluid will tend to accept the overburden load. In carbonate sequences, diagenesis can create permeability barriers in the porous formations and effect a fluid seal.
7.1.6
Thermal Expansion
Thermal expansion of pore fluids and thermal cracking of hydrocarbons are possible origins of abnormal pressures.
7.2
DETECTION OF GEOPRESSURES DURING DRILLING
The basic aim of geopressure detection methods while drilling is the detection of the "transition zone", the zone in which subsurface pressures increase from normal to abnormal.
7.2.1
Kick
Kick conditions exist when there is insufficient hydrostatic head to control pressure in permeable formations. Although lost circulation, swabbing and failure to fill the hole on a trip can create this condition; we are specifically interested in the situation in which the formation pressure exceeds the hydrostatic pressure of the mud column. Actually, taking a kick was one of the first methods used to find the initial transition zone. A relatively low mud weight was carried until the first pressured sand was penetrated. After the kick was controlled, the formation pressure was calculated and protective casing set.
This technique has very apparent limitations. Although it is still used inadvertently when other indicators are masked, it is not recommended. Other techniques, although not as spectacular, are preferred.
7.2.2
Presence of Contaminating Formation Fluids
The presence of oil, gas or water can indicate insufficient mud weight. Indications include an increase in gas cutting of mud, formation oil in the mud or a change in chloride concentration in the mud filtrate, due to water entering the hole. The chloride concentration in the mud tends to decrease with normal compaction, and increase in
overpressured shale. However, salt-saturated muds as used in offshore wells obscure this parameter. Influxes of formation water will cause the salinity of high salt content muds to drop.
7.2.3
Increase in Background and Connection Gas
Gas detection equipment has been proven as a successful as indicator of high-pressured intervals. If differential pressure is created on bottom by a combination of low-density mud and higher formation pressure, small amounts of gas will enter the wellbore and increase the amount of background gas in the mud. Background gas normally increases gradually in the transition zone. Connection gas, however, is more concentrated. If the hydrostatic mud column is only slightly above the formation pressure, the piston effect created by u pward movement of the pipe while making a connection can swab the well.
7.2.4
Abnormal Trip Fill-Up Behaviour
It is always good drilling practice to keep the hole full while pulling out of the hole for a trip. If the height of the fluid in the annulus is not sufficiently maintained, the hydrostatic head could become low enough to allow entry of formation fluids into the wellbore. The swabbing effect also aggravates this condition. Mud must be pumped into the annulus to compensate for the removed volume of steel. Automatic recorders or trip tanks are used to periodically check the amount of mud pumped. If the volume of mud is appreciably less than the volume of steel removed, flow can be induced in the well.
7.2.5
Change in Size and Shape of Shale Cuttings
Shale cuttings from the transition zone are generally larger (than those from the normally pressured zone) and the edges are sharp and angular. Normally pressured shale cuttings are small with rounded edges and are generally flat. The size and shape of the shale cuttings depend on several variables, including: mineralogical, chemical and physical properties of the formation: Drilling mud properties Circulating conditions (including type of flow) Hole geometry Bit type Sampling methods.
7.2.6
Increase in Fill on Bottom
The shale cuttings caving off the walls of the hole tend to load the hole. Unless the hydraulics of the mud system is altered, these cuttings fall to the bottom. In some cases, the cuttings will close around the drill collars and bit, requiring pumping out of the hole to free the drill string.
7.2.7
Increase in Drag and Torque
The increase in the size and amount of cuttings in the well can correspondingly increase drill string torque.
7.2.8
Increase in Penetration Rate in Shale
Various studies have indicated a relationship between penetration rate and differential pressure (bottom hole pressure difference between the mud column and formation). They show that penetration rate decreases as the differential pressure increases and vice versa. Under constant drilling conditions in the normally pressured section, the differential pressure increases with depth. A one-ppg overbalance at 1500m equals approx. 265 psi: at 3000m a one ppg overbalance equals approx. 530 psi. This causes a corresponding decrease in penetration rate in the shales that follow a definite trend in the no rmal section. The ever-decreasing trend reverses as overpressures are encountered, thus permitting detection of the transition zone. This particular technique has been used successfully in many areas over pre-selected intervals beginning immediately above the expected top of geopressures. Care must be taken to maintain constant variables (rotary speed, weight on bit, mud weight, hydraulics, etc.) to prevent, masking the indicator. Bit dulling near the end of a bit run can also mask the transition zone, so a new bit should be run as close as possible to the top of expected geopressures.
7.2.9
Decreases in Shale Bulk Density Trend
Several authors have devised methods to measure bulk density of shale cuttings at wellsite. The plot of shale density versus depth is similar to that derived from the density log and, as such, is closely related to porosity. The general method works quite well in certain areas, but does not apply universally. Density plots should be considered with other relevant data.
7.2.10 Shale Factor
This is a measurement of the degree of diagenesis that has taken place, as montmorillonite in the claystone changes to illite with burial. In overpressured zones this change is retarded, with subsequent increase in the 'shale factor' which reflects the absorptive properties of the clay. Note that measurements should be recorded regardless of lithology in the pre-Tertiary section (as they may reflect the clay content) conventional core fragments. SUMMARY OF GEOPRESSURE INDICATIONS
Parameters Which Increase: Penetration rate Percentage of shale cavings Size of shale cavings Torque Connection gas Trip gas Shale factor Flowline temperature Chloride concentration (Mud flow out - kick) Parameters Which Decrease: Shale density d-exponent Mud volume required to fill hole during trip MWD resistivty
7.2.11 Increase in Flowline Temperature
Fluids within the transition zone are immobile and under greater pressures and as such, can have above-normal temperatures. As a result, the formation gains heat that is transferred to the mud during drilling operations. Unfortunately, this indicator has many pitfalls and should not be relied on exclusively since flowline temperature variations are a function of: Circulation time Hole depth Time elapsed since trip Actual bottom hole temperature Volume of mud
Water depth Delta T (Temperature Out - Temperature In) should decrease with depth. Also ‘end to end' temperature plots are useful.
7.2.12 Decrease in d-Exponent Trend
Unfortunately, it is often impractical to maintain constant drilling variables to use penetration rate as an indication of geopressures. Jordan and Shirley introduced the dexponent in 1966 to consider the more significant drilling variables by "normalising" the penetration rate. Although originally developed for the Louisiana Gulf Coast, the technique has gained popularity in other areas. The d-exponent is derived from the fundamental drilling equation relating penetration rate to weight on bit, rotary speed, bit size and formation drilling ability. This will not be discussed in any more detail in this document.
7.2.13 Fracture Pressure Gradient Determinations
Most lost circulation is caused by natural or induced fractures opened by excessive mud pressure. Lost circulation can be critical because if the hydrostatic pressure of the mud falls below the formation pore pressure, then the well will either kick or an “underground blow out" will result. The latter situation usually occurs when the well is shut in, and flow from the high pressure zone breaks down a lower pressure formation elsewhere in the hole. However, break down of lower pressure formation may also occur during attempts to circulate the kick out if the technique or mud weight used is incorrect. In either case, it will then be necessary before killing the well to heal the lost circulation zone, which can be very difficult. It is therefore important to calculate fracture pressures. If the ECD nears the fracture pressure gradient, it becomes necessary to set casing to prevent problems of lost circulation and probable kicks.
Empirical techniques for estimating fracturing pressure have been proposed by Goldsmith & Wilson, Matthews & Kelly, Eaton and several others.
7.3
PRESSURE DETECTION AFTER DRILLING
There are a variety of methods both direct and indirect that can be used to confirm formation pressures after the well has been drilled. Some of the more common techniques are mentioned below are: Drill Stem Tests, Wireline Log Evaluation and Formation Pressure Measurements
7.4
WELLSITE GEOLOGIST'S CHECKLIST
(Check ) A. PRIOR TO LEAVING OFFICE * Are you familiar with the Geological Objectives of the well? * Do you have copies of the necessary offset well data?
* Do you have a copy of the Drilling Program and Well Proposal? * Is your HUET card valid? * If travelling to the Timor Sea area, take valid passport (mandatory for ZOCA wells, advisable for non-ZOCA).
* Have you been advised of your travel/accommodation arrangements to the rig? * Do you have all the required Safety Equipment for the rig? (hard hat, safety boo ts, safety glasses, appropriate clothing)
B. ON ARRIVAL AT RIG * Discuss Geological Objectives with Wellsite Manager and Drilling Engineer. * Review Geological Objectives and Sampling Program with the Mudloggers. * Review Geological Objectives and Logging Program with MWD engineers(if on board).
* Ensure that Mudloggers have all the necessary equipment and consumables: * Confirm necessary offset well data are aboard. * Confirm all reporting forms are current. * Confirm necessary MWD tools are aboard. * Confirm necessary wireline logging tools are aboard. * Confirm necessary coring gear is aboard/in transit.
C. WHILE DRILLING Note: Wherever possible all data or image files are to be sent to town in digital form, either as an emailo attachment or dropped into a network drive. Mudlogging:
* Ensure correct mudlog format (for both “fax/A4” and final formats) and scales are used. * Check and edit mudlog regularly, and always prior to sending to town. * Up to date mudlog to be transmitted to town prior to agreed morning and afternoon times daily (and/or whenever else required).
* Ensure appropriate samples are being collected by Mudloggers: * Ensure samples are stored in appropriate containers. * Mudloggers to check lag routinely. * Gas detectors to be calibrated routinely. * Mudlog trip & connection gases should be absolute values, not above background.
* Ensure Mudloggers communicate sufficiently and timely with drill floor, pits, wellsite manager, WSG. MWD:
* Ensure correct log format and scales are used. * Ensure MWD hands communicate immediately with driller, then Wellsite Manager and WSG, if drill string vibrations become unacceptable
* Ensure MWD hands communicate sufficiently and timely with drill floor, wellsite manager, WSG. * Logs to be transmitted to town at regular intervals (and always prior to agreed morning and afternoon times daily) at a scales of 1:500 (& other scales as requested) * Log digital data to be transmitted daily. * Reasons for any missing data to be annotated on logs prior to sending.
* Survey data to be transmitted to town daily on directional wells, at TD on vertical wells.
Coring:
* Check that required gear is aboard (including sufficient barrels, core crates, end caps and clips). * Catch and describe cuttings samples while coring, and include in DGR as "cuttings while coring". * Attend JHA prior to core arriving at surface. * Ensure core is checked for H2S with Drager tube as early as possible after core arrives at surface. * Be present on rig f loor while breaking down inner barrels, and box end pieces correctly. * Ensure inner barrels are laid out in cradles down the V-door and o nto the catwalk/pipedeck safely. * Do not begin cleaning inner barrels on the pipe deck until safe to do so. * Ensure inner barrels are properly cleaned so that b arrel markings won't smear. * Ensure inner barrels are measured and marked up as per coring program. * If core is to be cut at the wellsite, organise and hold JHA with those involved prior to cutting and that necessary permits have been obtained by Coring contractors. * Ensure safe work practices throughout the entire core cutting routine. * Ensure all pieces of core are put in core crates (1m pieces) or core baskets (9m lengths) and are securely packed. * Describe core end chips using OMV Australia format and send descriptions to Operations Geologist. * Ensure all core, including boxes, leaves the rig together.
* Core chips to be manifested and transported to town with mudlogging samples. * Send Operations Geologist a Core Reconciliation Report, and advise mode of transport and ETA at destination of core. Daily Geological Report: * Transmit to town by 07:30 WST daily. * Confirm all depths reported (and drilling operations performed) with Wellsite Manager (midnight, casing, water, and RT elevation depths). * Ensure that the morning report is updated by the end of each tour. * Ensure DGR gas and ROP values agree with mudlog values.
* Trip & connection gases should be absolute values, not above background. * Remark fully on problems and deficiencies of mudlogging equipment and personnel. * Include mud and circulation data and maximum recorded temperatures, when wireline logging.
* Include provisional formation tops.
WSG general: * The end of hitch post-mortem is to be started on day one and added to as necessary when an issue arises. Do not wait till the last day. Some of your important observations will be lost. * Constantly check for unsafe acts and situations (do STOP or similar safety observation course on the rig).
D.
WIRELINE LOGGING
General:
* While POOH for logs (earlier if timing requires), contact Operations Geologist for final briefing. Email best. * Prior to POOH for logs, ensure mud sample is taken just prior to stopping circulation (to be manifested and sent to town with mudlogging samples). * Ensure mud engineer supplies wireline logging contractor with all pertinent mud data, and with a filtrate
and filter cake sample when drilling with water-based mud. * Attend logging JHA. * Ensure logging engineer has a copy of the final detailed logging program, and fully understands OMV's requirements * Ensure that, where appropriate, hole is logged while running in the hole in the event that up-logs cannot be obtained.
* Repeat sections will generally be logged over 70m unless advised otherwise. * Ensure there is acceptable agreement between main logs and repeat sections. * All data sent to town must be on depth, unless directed otherwise.
* Digital data and faxed prints should be transmitted to town urgently after the data has been acquired, but without impinging on wellsite operations (unless directed to). * Faxed logs should be at 1:500 scale unless directed otherwise. * Ensure log headers are carefully checked for accuracy (especially final coords, depths). * Transmit logging reports (pressure/sample, SWC desc. etc) ASAP after each run, but only when finalised.
*(In most cases) Wellsite Manager to sign-off wireline invoice; WSG to countersign to confirm that services written have been performed. Wireline Sampling Runs (MDT, RFT, FMT, RCI):
* Depth correlation to be performed at regular intervals when logged interval of sufficient length to warrant it. * When sample chambers opened at wellsite, gas released must be checked for H2S with Drager tube. * Hydrocarbon fluid samples drained at wellsite must be stored in suitable glass bottles.
* Water samples drained at wellsite to be stored in plastic bottles. * Transmit pressure/sample reports to town ASAP. Sidewall Cores:
* Depth correlation to be performed at regular intervals when shooting interval of sufficient length to warrant it. * After shooting, WSG to ensure correct transfer of shot bullets from guns to SWC cases on catwalk.
* Ensure SWC jars are labelled correctly. * Transmit SWC descriptions and SWC Shooting Checklist to town ASAP. * Ensure SWC’s are wrapped in aluminium foil and then clear wrap (so that they don't move around in jars).
* Rotary SWC’s described keeping core intact (whole core under scope, natural fluorescence only - no cut) . VSP
* Raw stack, TWT table and observers log should be sent to the office when available. Conclusion
* Wireline QC, diary, Horner Plot, MDT tables, SWC descriptions and shooting list log should be sent to the office when available.
E.
AT TD, PRIOR TO LEAVING RIG
* Complete well post-mortem and send to Operations Geologist with Checklist sheet completed. * Check mudloggers' sample manifest.
* Check that manifested samples are pr operly packed for transportation (especially hydrocarbon fluid samples). * Ensure all samples/logs/core to leave the rig are manifested, with copies sent to Operations Geologist, shore logistics base, and a copy to the wellsite file. * Ensure any confidential data is either locked in Geologists' filing cabinet, or sent back to town. If rig is going to another operator next well, send all confidential data to town. * Ensure all required reports have been transmitted to town. Litholog, core and logging reports should be copied to floppy and hand-carried to town as a contingency. * Hand-carry SWCs.
8
Conventional Coring
8.1
General
Conventional cores are (in the main) intact specimens of formation, and are therefore very important in that they can supply direct measurements of rock and fluid properties, compared to cuttings (usually too small to take meaningful direct measurements) and wireline logging data (where measurements are depe ndent on assumptions that are often difficult to determine accurately). Coring is therefore an invaluable tool for geologists, petrophysicists, reservoir engineers, and drilling engineers, and can provide information on some or all of the following: reservoir properties (lithology, porosity, permeability, fluid saturation), depositional environment, diagenesis, reservoir geometry, and rock properties. One of the main reasons for cutting conventional core is to provide a calibration for wireline logs, so as to improve porosity, permeability, net-to-gross, and hydrocarbon saturation estimates. Conventional core results should lead to a better understanding of both geological and engineering issues that may ultimately lead to produ cing hydrocarbons at a lower unit cost.
8.2
Coring Equipment
The WSG should become familiar with all aspects of coring, including the different types of equipment used and the principles involved. By having an appreciation of this, the WSG may be able to better help in finding the best method to core certain formations, which may ultimately lead to better core recovery and to cutting core more efficiently (and cheaply). The core barrel is typically made up of the following components:
8.2.1
Outer Barrel
The outer barrel houses the other core barrel components and transmits weight, rotation, and drilling fluid to the core bit, and is normally defined by its OD. Most coring contractors’ outer barrel sections are 8m long, and together with the 1m stabilisers form the 9m core barrel sections.
8.2.2
Inner Barrel
The inner barrel contains the core when it has entered the core barrel, and inner barrel size is usually defined by the size of core it holds. It is generally 9m feet long to match the outer barrel sections. The inner barrel string (a series of inner barrels) is connected to
the swivel assembly at the top end of the core barrel, and is suspended inside the outer barrel with the lower end incorporating the catcher assembly and terminating inside the core bit. There is a small axial and radial clearance between the core bit and the lower end of the inner barrel. Early inner barrels were made of steel, and the recovered core was removed from the barrels on the rig floor and possibly sealed with wax (seal peel) before boxing and transporting to the core laboratory. These day s most coring is performed using either fibreglass or aluminium inner barrels, which significantly improve core quality and recovery as these inner barrels offer less resistance to core entry, reducing core jamming and loss. Other advantages are that the fibreglass and aluminium inner barrels become the packaging system for the core from the time it is cut until it reaches the core analysis laboratory; soft/friable/broken/fractured core is kept intact; and it is safer to lay out than to slip a 9 m core from a steel inner barrel. The inner barrels and contained core can be cut into 1m lengths at the wellsite using a saw and sealed with plastic caps, or alternatively sent to the lab in their original 9m lengths which has advantages in that the core is handled less and doesn’t need to be pieced together at the lab to the extent that 1m pieces do. The less a core is handled prior to analysis, the better chance it will have of being in good condition and the better the chance of not having pieces misplaced or turned upside down, so in theory the more meaningful the core analysis. Aluminium barrels can be used in wells that are too hot for the use of fibreglass barrels, and have the added advantage of being fluted on the inside, which allows for the escape of pressure/gases from the core barrel as it is pulled to the surface.
8.2.3
Swivel Assembly
The swivel assembly connects the inner barrel to the outer barrel via a thrust bearing comprised of ball bearings seated in a race. The bearing prevents the rotation of the drill string from being transmitted to the inner barrel. This enables the inner barrel to remain stationary during coring. Any rotation of the inner barrel could cause core barrel jamming, thereby prematurely terminating the core run. A system attached to the swivel assembly allows the drilling fluid to be diverted from the inner barrel to the annulus. Drilling fluid flows through the inner barrel prior to coring, ensuring that there is no fill or debris inside. Dropping a steel ball prior to the start of coring diverts the flow of the fluid from the inner barrel to the core barrel annulus. The ball seat is connected to the bottom of the swivel assembly.
8.2.4
Catcher Assembly
The catcher assembly is normally composed of the upper shoe, lower shoe, and core catcher. It provides the means of breaking the core from the bottom of the hole and retaining it inside the inner barrel.
The upper shoe is a sub, and is available in different lengths to compensate for different lower shoes. This maintains the constant length of the catcher assembly. The lower shoe houses the catcher and provides the entry point for core into the inner barrel. The core catcher types that are typically used with the lower shoe are the spring catcher and the slip catcher, with the spring catcher most commonly used. It is a one piece catcher separate from but located inside the pilot shoe. It is shaped like a short cylinder split along its length. The pilot shoe is tapered internally with the narrow end at the bottom of the shoe. The catcher is activated by pulling the core barrel off the bottom of the hole. Tungsten carbide grit on the inside of the catcher grips the core. This forces the catcher downward in relation to the pilot shoe. The split in the catcher allows it to contract circumferentially as the taper in the p ilot shoe narrows. The greater the pull on the catcher, the tighter it will hold the core. This allows the spring catcher to break very hard consolidated cores off the bottom of the hole. The slip catcher operates on the same principle as the spring catcher. The difference between the two is that the slip catcher is composed of 5 grit-coated slips which are integral to the pilot shoe. When the core barrel is pulled upward, the grit on the slips grips the core. This forces the slips downward in relation to the pilot shoe. When the core barrel is pulled upward, the grit on the slips grips the core, forcing the slips downward in relation to the pilot shoe. The internal taper of the pilot shoe forces the slips inward to hold the core more tightly. The slip type catcher sometimes incorporates the scribe knives for oriented coring (see section 6.3.7). In hard fractured formations the slip catcher may assist in reducing core jamming. Core catcher types are listed below:
CORE CATCHERS Type Split Ring, Spring Collet Slip
Dog or Flapper Basket Full Closure
Recommended Usage Consolidated formations Where formation characteristics are unknown Consolidated formations, normally run with flapper catcher or with orientation knives Consolidated, fractured, and unconsolidated formations where geology is unknown Unconsolidated formations, normally run with another core catcher type Friable to unconsolidated formations to provide positive full closure
8.2.5 Safety Joint The purpose of a safety joint is to enable the inner barrel to be extracted from the core barrel if the outer barrel becomes stuck in the hole. It also provides a convenient separation of the outer and inner barrels for servicing. The adjustable safety joint facilitates the spacing of the inner barrel, saving rig time, since spacing can be achieved without breaking out the swivel assembly, which must be broken out to adjust the inner
barrel spacing with the use of shims. The adjustable safety joint offers more accurate spacing of the inner barrel. A handle is fitted into the top API box connection of the core barrel. Turning the handle lowers the inner barrel until it touches the core bit. The inner barrel is then raised to the correct lead (to allow for thermal expansion of the inner barrels) by rotating the handle a predetermined number of turns in the opposite direction.
8.2.6
Stabilisers
The purpose of stabilisers is to centralise the core b arrel in the well bore. Effective stabilisation: * minimises disturbance to the core as it enters the inner barrel, improving core recovery * increases ROP * minimises core bit wear * prolongs core barrel life * assists in keeping hole angle * assists in providing an in-gauge hole Stabilisers are typically about 1m long and are usually 1/32 inch below the nominal hole size. There is normally one more stabiliser than outer barrel sections. So a 90 feet core barrel has 3 outer barrel sections and 4 stabilisers.
8.2.7
Core Bits
A core bit cuts an annular hole forming the core. It is connected to the bottom end of the outer barrel, and comes in many different forms with the most common being diamond and PDC. Core bit selection can be crucial to the coring operation (and therefore to the success of the overall well programme), and the WSG should ensure that expected lithology and hardness of formation information has been relayed to both the Drilling Supervisor and the corehand, so as to enable the optimum bit selection.
8.3
8.3.1
SPECIAL CORING SYSTEMS
General
Special coring systems have evolved to fill specific coring needs. Pressure retained and sponge core barrels arose from a need for better oil saturation estimates. The rubbersleeve and full-closure coring systems were developed specifically to improve the quality of cores cut from unconsolidated formations. The other systems listed have equally unique capabilities making them all very useful to the engineers and geologists employing them.
SPECIAL CORING SYSTEMS Coring System Maximum Core Dimensions Pressure Retained 3.75” x 10’ (5000 psi)
Special Applications Pressure retained analyses, fluid
2.5” x 20’ (10000 psi) Sponge Lined Full-Closure
3.5” x 30’ 5.0” x 60’
Rubber-Sleeve
3.0” x 20’
Wireline Retrievable
2.75” x 30’
8.3.2
saturations, gas volume and composition. Fluid saturations Recovering unconsolidated formations Recovering unconsolidated formations Coring is possible without tripping pipe
Pressure Retained Coring
Pressure retaining core barrels are designed to retrieve cores maintained at reservoir pressure. Accepted as the best method for obtaining core-based oil saturation data, pressure retained cores also capture reservoir gases. The tool is especially useful when studying the feasibility of enhanced recovery projects, and estimating methane production from coal. Pressure retained core barrels are available in two sizes: 6” and 8” O.D. that cut cores 2.50” and 3.75” O.D. respectively. The 6” O.D. barrel cuts up to 20ft of 2.5” diameter core while holding a maximum of 10,000 psi pressure. The 8” O.D. barrel cuts 3m of 3.75” diameter core while retaining a maximum of 5,000 psi internal pressure. The maximum recommended operating temperature is 180°F. Pressure core barrels are sophisticated tools requiring an onsite facility to service the barrel and handle the pressurised cores.
8.3.3
Sponge-Lined Coring System
The sponge lined coring system was developed to improve the accuracy of core-based oil saturation data. Sponge coring system does not trap reservoir gases, instead it traps oil expelled as the core is brought to the surface. The saturation information is very useful when evaluating enhanced oil recovery projects. A sponge coring system has the advantage of being less expensive to operate than a pressure coring system while providing an opportunity to improve the accuracy of the core based oil saturation data. The sponge is stable to a temperature of 350°F. The sponge coring system is limited to cutting a maximum of 9m of 3.5” diameter core per trip.
8.3.4
Full-Closure Coring Systems
Full-closure coring systems were developed to improve the recovery of unconsolidated, highly fractured, or congolmeritic formations. The systems use core b arrel liners or disposable inner core barrels, and a special core catching system to retrieve the troublesome rocks.
Full-closure technology allows the inner core b arrel to slip gently over the soft, fractured, or conglomeritic core, with a minimum of disturbance, and then seals the core within the core barrel. This is accomplished through the use of a full-closure core catcher assembly which permits the unobstructed entry of the core into the inner core barrel, and then after coring seals off the bottom of the inner barrel. Full-closure coring systems are currently limited to cutting either 3.5 or 4” diameter cores. The recommended core length is 9m. The smooth bore entry used here would result in lost core if the tool was lifted off bottom before activating the full-closure core catcher.
8.3.5
Rubber Sleeve Core Barrel
The rubber sleeve coring system was the first system developed to improve the chances for recovering unconsolidated sands, conglomerates, and hard fractured formations. The rubber-sleeve barrel is unique in that the top of the inner barrel does not move relative to the core during coring. The outer barrel is drilled down around a column of rock which is progressively encased in a rubber sleeve. The “rubber sleeve” stretches tightly around the core, wrapping it securely and protecting it from fluid washing, blocking, friction, grinding and crumbling. The core is supported by the rubber sleeve, thus aiding in the recovery of soft formations that would not support their weight. There is only one size of rubber-sleeve core barrel which cuts 6m of 3” diameter core per trip. The rubber sleeve itself is limited to temperatures no higher than 200°F. The tool is not recommended for use in holes with more than 45° of inclination. And, coring must be stopped approximately every two feet to allow the tool to be reset which might lead to core jamming in fractured formations. The system works best from fixed drilling platforms, yet it can be operated from floating rigs if rig movement is minimal.
8.3.6
Wireline Retrievable Core Barrel
Wireline retrievable coring tools are operationally similar to conventional coring systems except they are designed for the inner core barrel to be pulled to the surface by a wireline. This speeds the coring operation by eliminating the need to trip the entire drill string for each core. A new section of inner barrel may be pumped down the drillstring and latched into place for additional coring, or a drill plug may be pumped down to facilitate drilling ahead. Wireline retrievable coring tools are usually smaller and lighter than c onventional coring systems which is an asset when they must be transported to remote locations or by helicopter. Unfortunately, the core diameters are limited to a maximum of 2.75” since the entire inner core barrel assembly must pass through the drill string. Also care must be taken to prevent swabbing oil or gas into the wellbore as the inner barrel is recovered.
8.3.7
Oriented Coring
This allows formation dip, strike, directional permeability, principle stress, and fracture alignment to be determined. A better understanding of the shape and properties of the reservoir structure is obtained. Oriented cores are used to orient fractures, stress fields, and permeability trends. Exploration, production, and drilling operations use the information to explore for fractured reservoirs, design waterfloods, and plan horizontal wells. Oriented cores are typically cut using a conventional core barrel fitted with a special scribe shoe, and a device for recording the orientation of the primary scribe knife relative to magnetic north. Laboratory methods used to orient cores are correlation with borehole imaging logs, and the paleomagnetic method. The table below lists methods commonly used to orient cores.
Method Multishot Survey Electronic Survey Paleomagnetic Method Log Correlations
8.4
8.4.1
CORE ORIENTATION METHODS Location Comments Well Must stop drilling to take reading. Well Records orientation vs. time Laboratory Orients one continuous interval. Laboratory Requires correlatable features in core and wellbore
CORING BITS
General Guidelines
Coring bits are a basic part of the coring system. Unfortunately, for experts and novices alike, bits come in a bewildering array of styles. Fortunately, general bit information guidelines are available from manufacturers to aid in the selection. With a little bit of background information it is possible to make informed decisions on cutter types, bit profile, and hydraulic considerations for the range of anticipated coring conditions. Consider the goals of the coring programme, and confirm with the coring contractor that it has proven itself in a similar application. The hardness (compressive strength), abrasivity, and variability of the rocks to be cored will have the greatest influence on cutter selection. Guidelines suggest using smaller more impact resistant cutters as the formations get harder. Low-invasion face discharge core bits designed for unconsolidated to medium strength formations can be used in harder or more abrasive rocks, but bit life may be drastically reduced.
Natural diamond core bits are used where the formation is too hard (high compressive strength) and/or abrasive for other type cutting elements. Natural stones can be set in a tungsten carbide matrix as individual stones in a set pattern or as dispersed fine mesh grit as in impregnated type bits. Impregnated natural diamond bits are for ultra-hard applications. The information presented here is meant to provide an overview of what types of coring bits are available. Specific details on coring bits and recommendations for particular applications should be obtained from coring contractors.
GENERAL CORING BIT GUIDE Rock Properties Rock Type Ultra-Hard, abrasive Quartzite, Igneous rock Rocks Hard, abrasive rock Sandstone, Siltstone
Hard, non-abrasive rock Medium to hard rock with abrasive layers Soft to medium strength rock Soft rocks, no sticky layers Soft, sticky rock
8.4.2
Limestone, Dolomite, Anhydrite Sandstone, Limestone, Shale Sandstone, Chalk, Shale Salt, Anhydrite, Shale Gumbo Clay
Core Bit Impregnated natural diamond
Natural diamonds surface set or TSD cutters TSD cutters TSD or surface set natural diamonds PDC cutters, low fluid invasion design PDC or roller cone cutters PDC cutters, face discharge
Thermally Stable Diamond - TSP
Thermally stable (diamond) product, TSP, is similar to PDC in that it is also a man-made diamond material. The main difference in the TSP material is that it has a higher range of thermal stability due to the leaching of the metal catalyst used in the sintering process of the manufacturer. These cutters are suitable for formations generally considered too hard and/or abrasive for PDC cutters. They are not recommended for soft formations.
8.4.3
Polycrystalline Diamond Compact - PDC
Polycrystalline diamond compact (PDC) cutters are man-made diamond materials that consist of a layer of micron sized diamond grit sintered together and bonded to tungsten carbide studs. The thickness of the polycrystalline diamond layer is only 0.020” to 0.060”.
PDC bits are used to efficiently core formations ranging from very soft to medium hard. The bits are designed to cut by shearing resulting in a rapid rate of penetration. Due to the geometry of the PDC cutter, they are not well suited to impact damage, and therefore are not recommended for very hard, highly fractured, or cherty formations.
8.4.4
Roller Cone
The roller cone core bit uses 4 rotating cones set with tungsten carbide insert or hardfaced milled-tooth cutters for coring purposes. The cutters in the cones roll and impact the hole bottom and fail the formation in compression by chipping action. Due to the slow cutting action (chipping - compressive failure) and the number of moving parts, roller cone core bits are not very common.
8.4.5
Fluid Discharge Characteristics of Core Bits
8.4.5.1 Throat Discharge
Throat discharge core bits are designed to divert some of the fluid that would normally pass through the throat of the bit to the face of the bit. This cleans the face of the bit and reduces the scouring of the core as it enters the core barrel. Face discharge bits are recommended for use in soft and friable formations. 8.4.5.2 Low-Invasion Profile The low-Invasion profile coring bits are designed to maximise penetration rate, and minimise drilling mud filtrate invasion into the core. The design incorporates face discharge ports, a reduced number of cutters, and a diminished clearance between the inner core barrel and the bit face. Use of the low-invasion profile core bits is recommended for soft to medium strength formations. Harder formations would slow the rate of penetration and possibly damage the cutters.
9
9.1
DRILLING FLUID ENGINEERING
INTRODUCTION
Drilling fluids have been used since the earliest days of drilling. Initial fluids were crude, often consisting of little more than clay, and Barite for density control. Over the years systems progressed in complexity and cost, as more and more drilling demands were made on the systems. Wells were targeted to greater and greater depths, requiring more advanced drilling fluid control. Horizontal and extended reach wells have added further complexity. In conjunction with the ongoing search for a “perfect” non-damaging system has been the impact of present environmental considerations. Environmental considerations now heavily affect the b uilding and maintenance of drilling fluids, occasionally to the detriment of the system’s performance. Selection and maintenance of a modern drilling mud is a trade off of competing requirements and objectives. Today there is still no single, “perfect” mud. The modern wellsite and exploration geologists, must be able to communicate their requirements to operational drilling personnel while understanding the consequ ences of their requirements from both a cost and operational perspective.
9.2
HISTORY
Despite the huge database of drilled wells using the same mud, related mistakes are being made today as before and many misconceptions still abound. Early record keeping had been particularly bad, with a host of end of well reports not recording the drilling fluid system utilised, let alone any of the properties experienced or the chemicals used. Many older systems have been superseded or radically altered in nature. This has led to a loss of understanding of their original application and hence the subsequent interpretation of the data generated. Many younger drilling and geological personnel are unaware of the earlier system types and the implications of the properties they experienced when researching modern wells. Confusion between trade named systems and actual chemical types compound the problem. Drilling fluid types have evolved and changed radically over the years. Advances in clay chemistry have led to a better understanding of the mechanics of clay hydration. Down
hole logging improvements now provide a better picture of formation effects and have therefore been a valuable source of feedback, resulting in further changes. Advances in polymer chemistry have created a totally new breed of drilling fluids that are enabling extremely low solids systems to be run with a fraction of the well bore damage that was being experienced with older systems. Oligomers, Glycerol and full Cationic based drilling muds are being tested and are carving out niche markets as their inhibition, lubricity and environmental improvements make their use cost effective or environmentally mandatory. Chrome Lignite / Lignosulphonate (Spersene/XP-20) systems are only being used in areas where high temperatures preclude the use of polymer systems and oil muds are not cost effective. Gyp and Lime muds are usually avoided as the high levels of solids the systems carry reduce penetration rates, increase pump and equipment wear and can cause considerable formation damage. The KCL/PHPA system has effectively replaced the standard Gel/Polymer mud for drilling low weight stable formations as it is cleaner, faster drilling and less damaging to potential production zones. A listing of the generally recognised standard systems and their advantages and disadvantages is included in the Drilling Fluid Systems section.
9.3
FUNCTIONS OF A DRILLING FLUID
The ten basic functions of a drilling fluid system are: 1. 2. 3. 4. 5. 6. 7. 8. 9. 10.
To remove the cuttings from the holes and carry them to surface. To cool and lubricate the bit and drill string. To coat the well bore with a low permeability filter cake. To control subsurface pressures. To hold cuttings and weight material in suspension when circulation is interrupted. To release sand and cuttings at the surface. To help support the drill string and casing. To reduce any adverse effects upon the formation adjacent to the wellbore. To transmit hydraulic horsepower to the bit. To control corrosion.
The job of the Drilling Fluid Engineer is to manipulate parameters to achieve as many of the above results as possible, simultaneously. All drilling fluids are a compromise between conflicting requirements. It is essential to understand that changing one property may have repercussions on other parameters.
Changes experienced while drilling, such as differing formations, rig constraints, cost considerations and the availability of treating chemicals are only a few of the impacts on the final composition of the fluid. During the programming process, and continuously while drilling, the above objectives should be re-evaluated as their priority may change. At times, geological preferences may be compromised to ensure a wellbore is not lost when drilling difficulties are encountered. At other times drilling optimisation is sacrificed to enable improvements in the quality of geological data collected.
9.4
DRILLING FLUID PROPERTIES
To achieve the listed objectives, either in total or in part, the drilling fluid is tested and continuously modified by dilution and chemical addition. Geological changes down hole require versatility in blending. To achieve the optimum performance from any drilling fluid system it must be constantly modified and rebuilt. The testing of drilling fluids is extremely varied and it is becoming increasingly complex. The objective is, however, always the same: To monitor the system to provide the optimum drilling environment with the maximum formation protection. This monitoring of the mud is done on an almost continuous basis, principally by the operation of chemical testing. Tests and testing procedures vary enormously depending upon the specific requirements at the time and the type of drilling fluid in use. A drilling fluid engineer will use the range of tests on which to base a recommended treatment. He will develop a “feel” for the chemical interactions that are taking place and react accordingly. Prior to discussing the range of systems in use today, and some of the systems no longer in use, it is useful to cover the basic drilling fluid properties. A wide battery of tests is available to the engineer. Testing can take considerable time and results are of varying importance. The introduction of new chemicals or the running of new systems naturally requires additional testing. As it is not possible to effectively report on all the tests available in this context, it is beneficial to cover the standard tests that are carried out on the bulk of water-based systems. It is recommended that the Wellsite Geologist becomes familiar with the Daily Mud Engineering Report and maintains a close liaison with the Drilling Fluid Engineer. The Drilling Fluid Engineer is often aware of changes to the mud that are being driven by formation chemistry that the Wellsite Geologist may not see. The dispersing nature of
some formations often will not be seen by the Wellsite Geologist in their samples, as the material may have dispersed into the drilling fluid. The principal testing on most water-based muds and reported in the Daily Mud Engineering Report consists of the following:
9.4.1
Sample
The drilling fluid is generally sampled from either the “ac tive” mud pit (the pit on line) or the Flowline. The report form will indicate from where the sample was collected. A pit sample should reflect what is going down the hole, after chemical treatment and solids removal. It should be accurate to the well program in terms of its chemistry. Flow Line samples are extremely useful to compare with the Pit sample. This comparison will indicate the effects down-hole exposure is having upon the mud. Discuss the variance with the mud engineer to extract formation chemistry information. The rate of mud disintegration and the chemical changes being experienced can indicate the type and nature of formation being drilled.
9.4.2
Time Sample Taken
Noting the time the sample was collected will enable the engineer to compare the rate of chemical change from the time the samples were taken. Ideally a full test should be taken on a Pit Sample and a further test taken at the Flow Line once a full circulation has completed. Note the Circulation Times from the form and the actual test times to determine where the sample was at the time of testing.
9.4.3
Flowline Temperature
Monitoring Flowline temperature ensures additives are not expected to perform outside their normal operating range. Do not always believe the quoted effective bottom hole temperature limits of many products. Chemicals will generally degrade rapidly as temperatures increase to their published maximums. Many, including some of the exotic polymers, will catastrophically fail prior to temperatures reaching their operating limits. Others will produce unacceptable effects, including the generation of CO2. These can confuse the Wellsite Geologist if he is unaware of the limitations of the system. The bulk of drilling fluid additives are effective up to 1 20°C, with very few capable of withstanding drilling conditions at 150°C. Discussions with the mud engineer on the temperature regime of his chemicals will help identify formation versus additives induced changes.
9.4.4
Depth
The depth at which the sample is collected and tested is recorded. The Wellsite Geologist should compare formation tops and geological changes with changes that may have been registered in the fluid chemistry at the same depths. Alert the drilling fluid engineer to anticipated changes in formation and he will be able to confirm changes also seen in the fluid.
9.4.5
Weight
The density reading in conjunction with hole condition is a valuable tool for estimating the down-hole pressure regime. A density increase will generally improve hole cleaning and may result in Wellsite Geologist seeing a change in the ratio of sand/clay cuttings returning to surface or in the blend of formation returning. These changes may not be directly related to formation changes but are associated with the changed hole-cleaning environment. Under-balanced drilling will often result in cavings entering the wellbore from further up the hole further confusing sample interpretation.
9.4.6
Funnel Viscosity
The Marsh Funnel was the first, and is still the simplest, of mud testing tools. The measurement will enable the mud engineer or derrickman to get a quick understanding of changes in overall system viscosity. The Marsh Funnel Viscosity will not tell from what source the viscosity changes are occurring. PHPA and high polymer muds typically run much higher viscosity than traditional systems. Funnel viscosities of 40 to 55 sec/qt are regarded as normal. Water has a viscosity of 32 sec/qt.
9.4.7
Plastic Viscosity and Yield Point
Plastic Viscosity and Yield Point are measured to determine the flow properties of the fluid at known shear rates. The determination of Plastic Viscosity and Yield Point are derived from the Bingham Model and indicate the nature of the viscosity in the fluid. Low end Shear Rates are now also routinely tested and included on the drilling fluid form to evaluate the performance of drilling fluids in extended reach and horizontal wells. At its simplest Plastic Viscosity is a measurement of the solids content of the drilling fluid and the Yield Point is a measurement of the electrochemical charging of the mud. Drilling fluids that have high concentrations of solids will have high PV’s and modern polymer specific muds, which have viscosity generated from polymers instead of clays, have low PV’s and high YP’s. The ratio of the two is important and should be taken into account when evaluating hole cleaning and particle suspension. The trend is to run the Yield Point much higher today than in previous times. Horizontal and extended drilling have demonstrated that very high low end rheologies are necessary to clean these wells and prevent the buildup of cuttings in the hole.
9.4.8
Gel Strengths
The Gel Strength is essentially a measurement of the thrixothropic nature of the mud, ie how quickly the fluid will produce gels and thicken once circulation is broken and to what extend this will continue. Readings are taken from the Fann Rheometer at 10 second and 10 minute durations and the degrees of deflection recorded. Ideally a fluid that produces a very quick gelling action is sought to stop cuttings settling in the hole once circulation is stopped. A high gel will produce a fluid that becomes too thick while out of the hole for extended periods, normally while logging or tripping. 10 second gel values of between 5 and 15 are acceptable, while 10 minute gels as high as 40 will be obtained and are not a cause for concern. A mud with a medium to low 10 sec gel, and a low 10 min gel, is described as having flat gels, while high 10 minute gels indicate the mud continues to thicken and is said to be progressive in nature.
9.4.9
Filtrate
Of special significance to the Wellsite Geologist is the rate at which drilling fluid is lost to the formation. The API fluid loss testing procedure is conducted to ascertain the nature and type of filter cake build up and the rate of filtrate loss across a membrane. It is essential to obtain a satisfactory fluid loss value and the deposition of a thin, impermeable filter cake across the wellbore. Two types of filtration are present; dynamic filtration which occurs wh en the mud is circulating and static filtration when the fluid is at rest. Dynamic filtration testing is usually conducted in town to test the nature of the losses while circulating. These are generally significantly higher than static test results. To control the amount of filtrate lost to a formation, dynamic filtration must be controlled and to prevent disposition of thick filter cakes, static filtration must be controlled. Loss of fluid (usually water and soluble chemicals) from the mud into the formation only occurs when the permeability is such that it will allow the passage of fluid between the pore openings. If the openings are large enough, the first effect is a mud spurt that enters these openings at the face of the well bore. Then, as additional fluid is lost, a build up of the mud solids (wall cake) is formed on the wall face. There are a number of problems that can arise in drilling and completion operations due to muds with faulty filtration characteristics. These include: 1. 2.
Formation evaluation problems from excessive filtrate invasion and thick filter cakes. Excessive formation damage from mud filtrate.
When large volumes of filtrate enter a formation, the formation fluids may be flushed from the zone around the wellbore to the extent that logging tools give erroneous results. Formation test tools may also recover only filtrate, making it difficult to determine the true fluid content of a formation. If there are clays in a formation, water filtrate may cause the clay particles to swell or disperse and thereby reduce the formation permeability. Factors Affecting Filtration are: Time Pressure
- Filtrate volume increases in direct proportion to the square root of time. - If the filtration medium were constant, the amount of filtration would vary as the square root of pressure. In the case of mud filter cake, this does not hold true because the cake is subject to compressibility and continued deposition of material into the cake causes changes in porosity and permeability.
Cake Permeability on Fluid Loss is primarily influenced by temperature and the state of deflocculation of the system. It has been recognised that there is a correlation between high pressure-high temperature filtration properties and wellbore problems. Problems of primary concern are production zone damage (attributed to water blocking and the effect of mud filtration on shale or clay within the producing zone). Water loss should not be considered as an absolute value, but as a guide or criterion to the filtration properties of the mud in the hole. Because of the many variables influencing the filtration properties of drilling mud in a well, it is most difficult to accurately predict fluid loss to the formation from the simple API filtration test. As the hole is drilled deeper, it is necessary to adjust the fluid loss of the mud to assist in penetrating the new formations encountered. Consequently, it is not uncommon to drill a surface hole with a mud having a fluid loss of 20 cc. Values in the order of 4 to 8 are usually programmed for final hole intervals.
9.4.10 API HPHT Filtrate
The API HPHT test is designed to reflect the actual drilling conditions that are being encountered down-hole. A testing regime of 300°F and a pressure differential of 500 psi is the standard set-up; however, the test is often varied to reflect the particular well being drilled. Target HPHT losses of 20 to 25 cc’s are generally achieved.
9.4.11 Cake Thickness
The cake thickness is measured in 32nd‘s of an inch and will provide valuable information to the mud engineer on the nature of the filter cake. Investigation of the cake will enable
the engineer to test the strength of the cake in its condition. Correct filter cake makeup is essential in the avoidance of differential sticking.
9.4.12 Solids Content
Solids are reported as a percentage of the total drilling fluid and can be calculated by either a mass balance or the result tested with a Solids Retort Test Kit. A known volume of mud has the water driven from it and this is then distilled. The results of the retort are included into a solids analysis calculation and the resulting solids fraction further broken down into high and low gravity solids by calculation. The volume of salt is included in the calculation. The use of high volume linear motion shakers, centrifuges and low weight drilling fluids, have resulted in muds being run (where geologically possible) with the solids content typically in the 4% to 6% range.
9.4.13 Sand Content
Sand will have an abrasive effect upon drilling steels and results in excessive pump damage. Values in the order of 0.25% are generally considered to be maxima. This value will be exceeded occasionally at the time of pay zone drilling or during intervals of rapid drilling in sandy formations.
9.4.14 Methylene Blue Capacity
The testing of the Methylene Blue Content will enable the mud engineer to determine the Cation Exchange Capacity of the mud and hence the clay content. Clays have a detrimental effect upon most drilling fluids and often effect rheology directly. The dispersion into the drilling fluid of the clays is lost sample to Wellsite Geologist. This formation is lost in the fluid phase of the drilling fluid and is eventually dumped in the dilution volume. Changes (particularly increases) in this value should be noted to ensure that the Wellsite Geologist is aware of its volume. CEC v alues of 20 to 25 are considered to be maxima in low solids drilling fluid systems.
9.4.15 pH
A battery of alkalinity testing is performed. Many chemicals operate within narrow pH bands and many are destroyed outside these fine ranges. The pH will affect performance and stability of many chemicals. Modern drilling fluids are generally run with low pH values by traditional standards. PHPA (Partially Hydrolysed Polyacrylamide), a powerful and common shale encapsulator, is extremely sensitive to increases in pH above 9.5 and a value of 10.0 will totally destroy the polymer. A low pH will lead to increases in steel corrosion. The Wellsite Geologist should be aware that corrosion additives may
be added to the fluid that may be seen in their samples or will appear in subsequent laboratory testing. All corrosion additives (and other occasional additives) do not always appear on the drilling fluid report form.
9.4.16 Alkalinity (Pm Pf Mf)
Alkalinity testing is conducted on the drilling fluid in addition to straight pH testing. While the drilling fluid may have sufficient alkalinity the hy droxyl blend may not be in acceptable ratios. Interpretation of results will alert the Mud Engineer to potential carbonate and bicarbonate contamination. Contamination can be the result of drilling soft cement, incorrect chemical additions or formation contamination. The Pf/Mf ratio should be closely monitored. As carbonate contamination is experienced the Mf value will increase, possibly up to 5 times the Pf in extreme cases. Alkalinity results should be evaluated in conjunction with the 10 minute gel, which will also indicate progressive gels in carbonate/bicarbonate environments.
9.4.17 Chloride
The chloride test is very significant in areas wh ere salt can contaminate the drilling fluid. The salt may come from make up water, salt stringers or from salt water flows. Many drilling fluids being built in Australia use sea water in their make up. KCl is added in 90% of the wells drilled in the country to control swelling shales with its additional chloride burden. Sea water muds will typically run with chloride levels of 25k to 30k. Additions of KCl are gradually being reduced to ensure that the drilling fluid conforms to environmental needs. Chloride is an extremely aggressive ion and while the bulk of chemical additives now in use are salt tolerant, almost all will suffer a loss of performance to one degree or another as the chloride concentration increases.
9.4.18 Total Hardness
Water containing large amounts of dissolved calcium and magnesium salts is referred to as hard water. Many wells are drilled with hard water that is often pre-treated by the engineer before using. Drilling clays have low yields when mixed in hard waters. The harder the water the more bentonite that is required to make a satisfactory mud. Calcium can be picked up when drilling cement or sections of limey shale. Drilling anhydrite will also result in eventual contamination of the drilling fluid system. Many chemical additives are hardness sensitive. PHPA muds are destroyed in the presence of calcium and calcium levels should never exceed 2000 ppm. Extensive calcium contamination will result in abnormally high water loss and high gels.
9.4.19 Additional Testing
Drilling Fluid Report Forms will contain a large range of further test results and analyses depending upon the type of system being run. Look for the additions and, as the engineer who has generated the report is on the rig, discuss with him the direct implication chemical changes to the system will have on cuttings samples.
9.5
DRILLING FLUID ADDITIVES
Drilling Fluid additives come in a huge variety and cover a vast range of chemical types. It is not possible to effectively cover the full range of materials in this context. “World Oil” publish an annual drilling fluid guide. This is essential for Wellsite Geologist, who will come across many unknown products during their careers and it is highly recommended that copies be kept in all oil company libraries. The use of back copies is a major help when researching old wells that contain additives with on ly their trade names listed. Instead of detailing a large range of individual products it will be of greater use to briefly cover the types of materials and their general applications. Individual chemical information should be sought from the “World Oil Guide” with questions addressed to the relevant drilling fluid company when possible.
9.5.1
Fluid Loss Control Additives
Many types of materials are available to control fluid loss in water-based muds. Their application will vary according to the type of mud being used and the chemical environment of the mud. The most common fluid loss control agents are the clays. 9.5.1.1 Clays
The primary fluid loss control agent for most water-based muds are the clay solids present in the system. The starting point for good filtration control is a fluid having the correct particle size distribution of solids. This would be interpreted as a mud having a wide range of particle size, a large percentage of these particles being one micron or less. In effect, this particle size distribution produces a filter cake having both low porosity and low permeability. To achieve this, an attempt is made to obtain a maximum density filter cake. This simply means a gradation of particle sizes such that each successively smaller particle size plugs openings existing between the larger size particles. Commercial clays not only develop viscosity but also have the ability to lower fluid loss. Bentonite is particularly suited for the purpose. The ability of bentonite to reduce filtration can be attributed to: (1) particle size, (2) the flat p late-like shape of the particles, and (3) the capacity to hydrate and compress under pressure. Other factors being equal,
the finer the particle size, the lower the fluid loss. Bentonite has a larger percentage of fine particles than any other clay. A deficiency of good bentonite solids in the mud causes increased fluid loss, particularly at increased temperature and pressure. 9.5.1.2 Starch
If the mineral colloids are not enough to lower the fluid loss, organic colloids such as starch may be used. In some muds, the addition of starch not only lowers fluid loss, but stabilises the mud as well. The majority of starch used in the oil industry is made from corn. The starch grains are separated from the corn and specially processed so that they will rapidly and efficiently swell and gelatinise to furnish maximum reduction in fluid loss. This should occur regardless of pH, hot or cold water. Such starches are known as pregelatinised starches. The outside amylopectin shell is ruptured with heat, liberating the amylose inside which absorbs water and swells to form sponge-like bags. The loss of free water from the system aids in the reduction of the fluid loss. The sponge-like bags will fit into the tiny openings left in the filter cake and lower the fluid loss by a plugging action. At 250°F, polysaccharides are temperature stable. However, when the temperature is raised to 275°F, the chemical will decompose rapidly. Starches are effective as a drilling fluid stabiliser when evaporate or hydratable shale sections are penetrated and for stabilisation, filtration and rheological con trol of high electrolyte content workover fluids.
9.5.2
Polymers
With the advances in drilling fluid technology, the usage of water soluble polymers has developed several mud systems that have reduced fluid losses. There are several type polymers that are capable of reducing fluid loss characteristics of a mud system. The type polymers are classified by their action within a mud system. This classification is based upon the polymer’s performance by either adsorption onto the solids or by viscosifying the fluid phase. The most common fluid loss polymers viscosify the fluid phase to reduce fluid loss in a given mud system. These polymers are normally anionic and are less sensitive to their environment. They will develop viscosity in the presence of hardness and salt. However, high concentrations may reduce their effectiveness. Extreme care should be taken when adding a polymer, due to the possible interactions of several chemicals present in a mud system. In field operations, thorough pilot testing is essential before additions are made to the active system. 9.5.2.1 Sodium Carboxyl-Methyl Cellulose (CMC)
CMC is an organic colloid used for filtration control. The structure of CMC is that of a long chain molecule that can be polymerised into different lengths or grades. The material is commonly made in three grades, each varying in viscosity, suspension, and fluid loss reduction qualities. The three grades are commonly called high viscosity CMC,
medium or regular viscosity CMC, and low viscosity CMC. They will also vary in their purity. Four theories have been advanced to explain the reduction of fluid loss by CMC. 1. 2. 3. 4.
A wadding or wedging action of the long chains into narrow openings. A curling up of these long chains into a ball that forms a plug. A filming of the clay particles. Viscosification of the fluid phase.
CMC is an effective fluid loss additive in most water-based muds, working particularly well in the calcium treated systems. It will also stabilise calcium and sodium systems. CMC is not subject to bacterial degradation and performs well in all alkaline pH ranges. CMC becomes less effective as a water loss control agent as salt concentrations exceed 50,000 ppm. CMC is subject to complete degradation when temperatures exceed 250°F. The choice of CMC to use depends upon what properties are desired. When suspending properties as well as low filtration rates are desired, the choice will generally be either high or medium viscosity CMC. When less viscosity and a decrease in fluid loss is desired, the low viscosity CMC is adequate. 9.5.2.2 Polyanionic Cellulose
Polypac is an organic fluid loss agent designed particularly for application in muds containing high salt concentration for low solids drilling fluids. The material is a polyanionic long chain polymer of high molecular weight. Pac will give both viscosity and fluid loss control in either fresh or salt water. Pac is effective in the makeup and maintenance of low solids muds. 9.5.2.3 Chemical Thinners/Dispersants
The use of chemical thinners is not generally required in modern muds. High rates of polymer additions are required to maintain viscosity in the low solids environments and thinning is infrequently required. Environmental restrictions on the use of Chrome (an essential ingredient in most thinners) has also resulted in a general loss of effectiveness and hence a reduction in their use. The change in basic drilling fluid philosophy from one of causing the solids to disperse into the mud, and hence keeping viscosity down, to one of encapsulating solids and preventing their hydration is the single biggest factor in the demise of the thinners/dispersants use. Improved dispersion generally results in decreased filtration and higher solids. This is a result of an homogeneous distribution of the various particle size solids present in the fluid. Some dispersants are better than others, however, when used in sufficient quantities most are effective.
Lignite and Lignosulphonate (Tannathin, XP-20, and Spersene) all have exceptional ability to lower fluid loss. The proper use of these materials greatly extends the ability to control the drilling fluid at elevated temperatures and pressures far beyond that which can be obtained with starch or CMC. The materials are not easily affected by bacterial degradation and can be used effectively in high salt or calcium concentrations. It is significant that these chemicals will reduce both the API fluid loss and the HTHP fluid loss as well. At temperatures above 315°F increased amounts of XP-20 should be used and decreased amounts of Lignosulphonate used. The modified lignite is extremely temperature stable above 450°F. Therefore, with increased temperatures, lignite should be utilised to provide proper fluid loss control in dispersed systems. 9.5.2.4 Viscosifiers
Bentonite, Gel or Sodium Montmorillonite have traditionally been the viscosifying base for almost all drilling fluid systems. Bentonite is still the most widely used viscosifier and has particular application in top hole drilling. The material will provide exceptional fluid loss control and provides a base on which many polymers act. Bentonite will provide Yield Point which is essential to hole cleaning and will not suffer the temperature thinning effects that are the trade mark of many polymer systems. Biopolymer and PHPA polmyers now also dominate the viscosfying functions of drilling fluids. Biopolymers find application in almost all drilling environments and are untroubled by the bulk of drilling contaminants. This branch of chemicals is of increasing importance as more is understood abou t the hydraulics of cleaning horizontal and extended reach wells. The shear thinning nature of the group enables low solid fluids to be built and maintained at a cheap cost. The systems are relatively stable chemically. The ability of these materials to revert, and their biodegradability, allow for cleaner fluids to be built that clean up at the well’s completion without major stimulation.
9.6
DRILLING FLUID SYSTEMS
Drilling fluid systems have continuously evolved to their present state. Systems that for many years performed extremely well have recently become “extinct” with the advances being made in Polymer Chemistry. Systems that were once thought to be highly effective have been superseded as more sophisticated testing has revealed either shortcomings in their performance or that their effects on the formation are unacceptable.
An example of this is the demise of the CL/CLS (Chrome Lignite/Chrome Lignosulphonate) System. Early drilling fluids were only concerned with the drilling aspects of wildcatting. Mud Systems were designed to get cuttings from the hole and to control subsurface pressures only. The understanding that a mud with density control which balanced formation pressures would reduce hole problems, resulted in further formulation changes. Speciality completion fluids were formulated as production EOR methods were refined. Solids levels in the fluid were of little concern and many systems including the Gyp and CL/CLS systems actually required high solids levels to be effective. Emphasis over the years has therefore changed from a mud that will “get you to TD”, to a fluid that will provide maximum formation protection, return the maximum amount of geological information, provide the fastest possible drilling environment and remain cost effective. Many differing systems have evolved as these goals change from operator to operator, and from well to well to best suit the conditions. In general, basic description categories are recognised, although almost all have numerous subsets. Drilling fluids have generally been divided into water-based and oil-based systems. A new breed of synthetic systems is now being pushed to market. These “new” muds will continue to infiltrate the drilling world as costs decrease and as environmental pressures make their upfront cost less important or regulation makes their use mandatory.
9.6.1
Water-Based Systems
Water-based muds are described by their major constituents. Names vary occasionally for the same system, depending on the emphasis required at the time of drilling. Systems are often converted from one type to another adding to the definition confusion. Water-based names will ideally contain any major salt additions and the principal polymer used in its construction. Examples include KCL/Polyacrylamide, Seawater/Drispac. Names will also often include a trade name if it is well recognised (or the mud company has done a good marketing job) eg Freshwater Polysal or Spersene/XP-20.
9.6.2
Oil-Based Systems
Oil-based systems commenced in the Gulf of Mexico with the addition of diesel to the drilling fluid to aid lubricity. Increases in the concentration were seen to aid in the inhibition of shale swelling. The development of the Invert Oil Emulsion was the next logical development. Variations in the oil/water ratio have been made over the years as emulsifying technology improved and the cost of oil escalated. Simply put, the more water in the emulsion the less oil and hence the lower cost.
9.6.3
System Summary
See table below. Mud System
Advantages
Disadvantages
Spud Muds
Cheap, Simple Chemistry
No Inhibition
Gel Polymer
Cheap, Low Solids, Versatile
Little Inhibition
Lime Systems
Cheap, Solids Tolerant, Relatively Inhibitive
High Solids Contents, High Fluid Loss
Gyp Systems
Cheap, Solids Tolerant, Relatively Inhibitive
High Solids Contents
Salt Systems
Relatively, Inhibitive, Low Solids, Moderate Price
Poor Filtrate Control, Poor Lubricity, Weight Limitations
PHPA
Low Solids, Inhibitive, Low friction
Low Solids Tolerance, Can be expensive
Cationic Polymer
Highly Inhibitive, Environmentally acceptable
High Cost
Low Toxicity OilBased Systems
Excellent Inhibition, Excellent Lubricity
High Cost, Environmental problems
Glycerol
Environmentally acceptable
High Cost
Synthetic Systems
Excellent Inhibitation, Excellent Lubricity, Environmentally Clean
High Cost
The aim of effective fluid selection is to match formation chemistries with down-hole expectations and to provide an inhibiting environment to the drilled cuttings and the well bore. All muds have advantages and disadvantages.
9.7
NEW DRILLING FLUID SYSTEMS
A range of new drilling fluid systems (most proprietary) is finding a w ay to market as environmental pressures continue. The search continues for a fluid that will replace oil based drilling muds at a reasonable cost. Different companies have had different approaches to the problem and a wide range of “exotic” materials have been tested, or are being tested. These include peanut oil and palm oil. Adverse effects on blowout preventer rubbers can occur and oil fluorescence can be masked. It is up to the wellsite geologist to ensure he is aware of the properties and individual characteristics of the base fluid that is being run.
9.7.1
Synthetic Systems (Novadril)
This is a low toxicity, synthetic-based emulsion system that offers inhibition, wellbore stability, lubricity, and temperature stability that previously could only be achieved with toxic oil-based mud systems. Novadril is formulated with a base carrier; a synthetic oligomer that is not produced directly or indirectly from crude oil. The system is formulated as an invert emulsion in which the synthetic oligomer based fluid forms the continuous phase. A brine solution serves as the dispersed phase. As with an oil based system, oil/water ratios can range from 90/10 to 60/40. Oligomers can be contrasted to mineral oils which are manufactured from crude by a refining process. These mineral oils comprise a broad range of hydrocarbons of varying toxicities, including some aromatics.
9.7.2
Oligomers do not contain toxic hydrocarbons.
This makes the system non-toxic and it will not upset wellsite hydrocarbon searching. Physical properties vary from oil-based systems principally by the higher viscosities that are experienced in the oligomers. Other beneficial properties of the replacements are the high flash point and low pour values that the systems exhibit. High flash point provides a safer environment as there are not volatile components which could ignite and the low pour point enables the system to be run in the coldest of environments. All oil-based alternatives are expensive.
9.7.3
Envirotherm
This is a mud system designed for high temperature drilling that is chrome-free and acceptable for drilling in environmentally sensitive areas. Envirotherm is temperature stable in excess of 400°F (240°C). Envirotherm utilises two products; a proprietary chrome-free lignosulphonate and a water-soluable, polymeric resin as the primary temperature stabilisers.
9.7.4
A Cationic Water-Based Mud System
The Cationic system is a newly developed water-based mud system, utilising exotic cationic polymers to provide exceptional shale stabilisation. It is designed for drilling water-sensitive shale formations containing highly reactive clay minerals. Cationic polymers tend to be adsorbed more strongly than anionic polymers by attaching to clay surfaces dominated with negative charges. This strong adsorption can be utilised for better encapsulation and swelling suppression, hence superior shale inhibition. Drilling fluids containing properly selected cationic polymers have been proven to be more inhibitive than conventional water-based muds. Previous utilisation of cationic polymers to formulate practical drilling fluids was unsuccessful due to their high toxicity and strong interaction with other mud additives. The toxicity made former cationic polymers envrionmentally unacceptable; while the interaction made them less effective as severe flocculation and precipitation often occurs with bentonite, drill solids, anionic polymers, and weight materials. By applying advanced cationic polymer chemistry, the cationic system prevents the undesired interactions. Cationic polymers with low toxicity are carefully selected to provide shale inhibition without sacrificing environmental accountability. The cationic systems consist of an encapsulating polymer (MCAT), a swelling suppression polymer (MCAT-A), and chloride-enhanced water phase. The system is formulated to be compatible with conventional anionic polymers and weight materials. A non-ionic polymer also can be used as a secondary shale encapsulator to enhance inhibition. Because of its highly inhibitive nature, the cationic system can be considered as an alternative to oil-based muds. The low toxicity nature of the cationic system makes it desirable for drilling operations in offshore and other environmentally sensitive areas.
9.7.5
Causes of Shale Inhibition
Many shale-related drilling problems can be attributed to hydration (water adsorption) of clay minerals, which changes the physical strength of shales, leading to disintegration of cuttings, swelling, and sloughing into the wellbore. To stabilise a shale formation, and to prevent shale cuttings from dispersing, hydration of clay minerals must be reduced during drilling. The most troublesome swelling clays are smectite, illite, and mixed-layer clays. They are commonly referred to as 2:1 layer clays. Each layer is composed of AO-O-OH (octahedral) sheet sandwiched between two Si-O (tetrahedral) sheets. Due to ion substitution in the octahedral and/octahedral sheets, an overall charge is generated on the surfaces of each layer. The negative charges are balanced and the layers weakly held
together by interlayer cations. During hydration, water molecules can be attracted to interlayer cations as well as to clay layers by hydrogen bonding. The type of interlay cation is important in determining the amount of water that can be attracted; for example, sodium attracts more water molecules than calcium or potassium. Two mechanisms are often cited to account for the hydration of clay minerals; they are surface (crystalline) hydration and osmotic (intercrystalline) hydration. During surface hydration, one to two layers of water molecules can be adsorbed by both interlayer cations and clay surfaces. The distance between clay layers increases as the interlayer cations move away from the clay surfaces. As a result, volume of the clay may double upon surface hydration. Certain types of clays such as smectite with sodium or lithium as the interlay cation, can absorb water molecules continuously through the development of diffused double layers. This phenomenon is similar to osmosis, which is the transfer of water through a semi permeable membrane. It is often called osmotic hydration. Volume increase associated with osmotic hydration is usually several times greater than that d ue to surface hydration. A shale tends to undergo surface hydration immediately upon contact with water and may continue to absorb water osmitically, depending on the type of clay minerals, exchangeable cations, and its water content. Absorption of cationic polymers on clay surfaces can reduce surface and osmotic hydration.
9.7.6
Inhibition
To maintain shale stability, it is necessary to prevent clays from hydrating and swelling. The stabilising effects of the cationic systems are primarily derived from two cationic polymers, which provide polymer encapsulation and swelling suppression, respectively. Since over 90% of the clay surface is negatively charged, sites for cationic (+) polymer attachment are readily available. This is in sharp contrast to the attachment of anionic polymers which occurs at the positively-charges edges. Thus, cationic polymers can provide more effective shale inhibition than anionic polymers. The higher molecular weight cationic polymer is the primary encapsulating agent for the cationic system. Its large molecular size allows it to be attached to the exterior surfaces of clay particles through ionic bonding. A protective layer of polymer is formed to prevent cuttings from dispersing. A secondary encapsulating agent enhances shale stability by attaching to shale particles through hydrogen bonding. The inhibition provided by MCAT-A is of a different nature. Because of its small molecular size, it can penetrate the clay layers and adsorb on the interior surfaces. The adsorbtion of MCAT-A results in a complete displacement of interlayer cations, consequently retarding surface hydration and impeding osmotic swelling of the clays.
