Wellsite geology.
From sample to decision.

At the initial briefing, identify one geological decision owner and the person covering each shift. Confirm who may change sample intervals, approve extra analyses, authorize a geological recommendation, accept logging data and release reports. Write the arrangements into the well setup record. Job titles alone do not establish authority: an operations geologist, drilling supervisor and directional driller may have different responsibilities on different contracts.

Record an observation in terms another geologist can inspect: a sample interval, image, curve response, survey record or operational event. Follow it with the interpretation and the uncertainty. State the proposed action separately, including its decision owner. This prevents a provisional formation pick or assumed dip from becoming indistinguishable from measured data. [S2, PDF pp. 19, 37–39]

Illustrative format: Observation: the latest sample contains a higher proportion of fresh sandstone, while the matched gamma-ray curve declines. Interpretation: possible entry into the upper reservoir interval; confidence is moderate because the cuttings are mixed and the correlation is not unique. Action: review the next lagged sample and updated directional data; discuss the target position with the operator before changing the steering recommendation. This is an example of communication structure, not a report from an actual well.

1. State the current operation, current bit depth and the depth reached by each relevant evidence stream. Include time zone and data age.
2. Explain the decision needed, the evidence supporting it, reasonable alternatives and the consequence of waiting.
3. Contact the designated decision owner by the agreed channel. Time-critical concerns require direct communication and acknowledgement.
4. Record the recommendation, recipient, acknowledgement time, decision and person authorizing it. Distinguish a recommendation from an instruction actually issued.
5. After new evidence arrives, check whether the decision assumptions still hold. Update the interpretation and notify the affected team if they have changed.

At every handover and before a significant recommendation, reconcile the target interval, current formation position, next marker, expected approach time, sample lag, last accepted survey, sensor offsets and outstanding data problems. Maintain a shared event log for corrections, calibrations and programme changes. Close a communication loop by recording the response; sending a message is only the first step. [S2, PDF pp. 36–39, 82–85]

Basis: [S1], PDF pp. 7–12; [S2], PDF pp. 7–10, 19, 36–39 and 82–85. Role assignments and communication fields are an original Chaser workflow and must be completed for the actual well.

Collect the approved prognosis, offset logs, relevant sample and core descriptions, structural interpretation, well plan and available seismic ties. Check the well identifiers, coordinate reference system, elevation source and depth reference before comparing them. Retain the original files and the date received. A familiar formation name is not evidence that two wells used the same top definition.

• Identify primary and secondary objectives, the intended landing interval, bounding beds and the evidence used to distinguish them.
• Summarize expected lithology, thickness variation, marker order, possible faults or facies change, and reservoir uncertainties. Separate the expected sequence from alternative interpretations.
• Identify intervals associated with known local operational concerns, including coal, unstable shale, loss zones or pressure changes, using the operator’s well-specific assessment.
• For each decision point, list the evidence required and its expected availability: sample return, gamma-ray coverage, survey, log suite or laboratory result. Allow for sensor-to-bit distance and surface transport delay.

1. Complete the location induction and establish the emergency arrangements, permitted access and current operational restrictions with the site representative.
2. Inspect the geological workspace and approved sample collection route. Confirm lighting, clean preparation space, microscope and imaging equipment, labelled consumables and suitable storage.
3. Review the active sampling schedule with the person collecting samples. Confirm that the label identifies the represented drilled interval and that the lag method is understood.
4. Compare the current drilling depth, time and operation across the rig, mudlogging and geological displays. Resolve discrepancies before interpreting a live curve.
5. Confirm calibration status and service records with the responsible contractor. Identify which channels are measured, calculated, manually entered or unavailable.
6. Open a known dataset in the reporting and interpretation tools. Check units, depth ordering, null handling and the ability to recover a saved interpretation.
7. Identify deficiencies, assign an owner and agree the temporary operating limitation. Do not mark equipment ready solely because it is powered on.

Keep the latest approved programme, contacts and enough reference data accessible during a network interruption. Agree how to collect time-stamped observations and preserve original acquisition files while the feed is down. When connectivity returns, reconcile overlapping records and revisions before releasing an updated interpretation. A copied file requires a known source and version; an automatically refreshed screen also requires a visible acquisition time.

Estimate whether the planned sample interval can be collected, prepared, described and entered at the expected drilling rate with the crew available. Tighten intervals deliberately at decision points and arrange coverage before the workload exceeds capacity. Identify responsibility for unsampled periods and additional sample sets. Review supplies against the remaining programme and replenishment time rather than a generic number of days. [S2, PDF pp. 19, 29–35, 108–110]

Basis: [S1], PDF pp. 7–12; [S2], PDF pp. 8–13, 19, 29–35 and 108–110. Digital readiness checks are original application guidance, not a claim that a particular connection or platform feature is active.

• Confirm the location induction, alarm meanings, muster arrangements, emergency contact route and restrictions for the current operation.
• Use the task-specific protective equipment and approved access route. Maintain awareness of moving equipment, slippery steps, hot fluid, overhead work and changing weather.
• Coordinate sample collection with the responsible crew. Do not reach into moving machinery, remove guarding or enter an exclusion zone to recover a sample.
• Where a required control or safe access is unavailable, suspend the affected geological task and notify the site representative. Record the resulting data gap.

Hydrogen sulfide can rapidly impair the sense of smell, so odour cannot establish whether an area is safe. It is toxic and flammable and may accumulate in low areas or enclosed spaces. Follow the location’s monitoring, evacuation and response arrangements. On an alarm or suspected exposure, move to safety under that plan and notify the responsible personnel; do not enter a hazardous area to investigate or attempt an unprotected rescue. Personal and area instruments, checks and alarm settings must follow the approved programme. A hydrocarbon mudlogging reading is not a substitute for an occupational H2S monitor. [W-H2S]

Before using a product, check its label, current safety data sheet and the approved task procedure. Establish the required ventilation, compatible protective equipment, safe handling, storage, spill response and waste route. Keep labelled containers and the safety information accessible to the people using the product. If the product is unidentified, the controls are unsuitable or the procedure is unavailable, do not improvise a chemical test. [W-SDS]

Use only approved methods and equipment for sample preparation. This manual does not carry forward legacy practices involving deliberate smelling or tasting, uncontrolled solvent heating or unapproved hazardous reagents. Shielded UV equipment is used according to its instructions. Obtain specialist support for analytical methods outside the trained wellsite scope, and retain an untreated sample where the investigation requires it.

Unexpected gas, a sudden drilling response, abnormal returns, deteriorating sample quality or an abrupt change in pressure-related indicators may require urgent attention, but no single geological observation establishes the cause. Notify the driller or drilling supervisor promptly through the agreed direct channel when there is a possible operational hazard. Do not wait for a polished interpretation or the daily report. Preserve what was observed, when it occurred and the source channel. [S1, PDF pp. 7, 11, 14–15; S2, PDF pp. 36, 83]

Assess periods when the geologist cannot be seen or heard by others, including travel and work in a separate unit. Establish an appropriate contact schedule, a backup contact and an action plan for missed contact. Verify that the chosen communication method works where the task occurs. Schedule higher-risk work when suitable help is available. Review the arrangement when the task or location changes. [W-ALONE]

Arrange relief when fatigue or simultaneous activities prevent reliable work. A sample backlog, unreviewed survey revision or unacknowledged warning is a visible capacity problem. Tell the geological supervisor what coverage is needed and document any interim limitation. Logging, sampling and data entry should not depend on one person remaining continuously alert for an entire prolonged operation.

Basis: [S1], PDF pp. 7 and 10–15; [S2], PDF pp. 14, 17, 36 and 83. Current hazard references: [W-H2S], [W-SDS] and [W-ALONE]. Site-specific settings and legal requirements must be established through the applicable operator and jurisdictional procedures.

Confirm the routine collection interval, intervals requiring closer sampling, number of sample sets, washed and unwashed requirements, preservation methods, storage location, laboratories and shipping instructions with the operations geologist. Select interval lengths for the objectives and expected drilling rate; a single default interval is unsuitable for every well. Identify reservoir boundaries, thin marker beds, anticipated contacts, coring points, formation changes and unusual shows that require an additional sample. Record the effective depth and time whenever the programme changes. [S1, PDF pp. 7–9, 36, 44–45, 51]

1. Verify the correct well identifier, wellbore or leg, depth datum, current hole section and active drilling depth before preparing labels.
2. Agree a safe, approved collection point with the drilling supervisor and mudlogging provider. Use equipment intended for that point; never reach across moving shaker machinery or modify a guard to obtain a sample.
3. Collect material throughout the scheduled interval using the approved collection system. A single scoop from a shaker at one instant is a spot sample and must be labelled as such.
4. Clear retained material from the collector between intervals and record screen or shaker changes. Compare suitable secondary recovery points when fines are being lost, with the supervisor's approval.
5. Retain the requested archive and analytical portions before destructive testing or aggressive washing. Collect additional samples at significant changes without replacing the routine sample sequence.
6. Log collection time, sample interval, pump or flow history reference, collector, sample type, quality and any gap or contamination. Reconcile physical labels with the digital register before the sample leaves the work area.

Begin with the annular capacity of each open and cased section, using the actual drillstring outside diameter for each segment. Include relevant surface transit between the well return and the sampling or gas measurement point. Record whether hole diameters are nominal or supported by a caliper. Washouts, tool joints, bottomhole assembly geometry and uncertain pump efficiency affect the estimate. A nominal-volume calculation is a starting model, not proof of the arrival time. [S1, PDF p. 42]

Convert annular volume to pump strokes using effective output per stroke, or integrate measured flow through time. For a sample received at a known time, work backward through the pumped-volume history to identify the corresponding bottomhole departure interval; then read the bit-depth history for that interval. Do not subtract average ROP multiplied by one lag time across connections, trips, reaming, pump shutdowns or variable drilling. During a shutdown no new pumped volume is added, although settling, gas migration and mixing may still alter the returning material. Preserve these interruptions as quality flags rather than concealing them with interpolation. This is Chaser's implementation of the volume-based lag principle in [S1, PDF p. 42].

For a transparent calculation example, a uniform 1,000 m annular segment with 216 mm hole diameter and 127 mm pipe outside diameter holds approximately 23.98 m³. At an effective steady flow of 1.50 m³/min, its theoretical annular fluid transit time is approximately 15.98 min. This covers only that segment and assumes constant geometry and flow. The complete well requires all segments and relevant surface transit; the example does not account for cuttings slip or mixing.

Check the model against a documented, operator-approved lag verification method and known events. Any tracer introduction is a contractor-controlled operation requiring approval and a suitable method for the mud system; this manual does not authorize a chemical tracer recipe. Record the method, depth, departure and arrival times or strokes, flow conditions and resulting correction. Distinguish a complete circulation measurement from annular bottoms-up transit. [S1, PDF p. 42]

• Reassess lag after a hole-section, drillstring or pump configuration change; a material change in flow or mud properties; significant losses or washout evidence; a trip; or a persistent mismatch with known events.
• Maintain separate evidence for cuttings arrival and gas arrival. Gas release, extraction and sample-line transit do not necessarily follow solid cuttings transport.
• Document the width of an arrival response as well as its peak. A broad transition is evidence of mixing and limited depth resolution, not permission to choose a precise top without qualification.
• Retain each lag-model revision. Reprocess affected sample assignments as a new interpretation while preserving original labels, collection records and the reason for change.

Assess each sample for fresh drilled material, cavings, recycled grains, mud solids, lost-circulation material, cement and metal. Cavings may resemble a previously penetrated unit and increase after trips or reaming. Size and shape help, but no single appearance proves origin. Differential transport can spread a sharp boundary across several samples or alter the apparent sequence; softer rock may disperse while hard fragments survive. Do not force a formation boundary from one mixed sample. [S1, PDF pp. 47–49]

Use explicit quality states: representative, mixed, poor recovery, contaminated, spot sample or no sample. Record the reason for a missing interval and create a labelled gap entry in the archive sequence. Do not fill a missing interval by duplicating the previous lithology. Describe observed material first; record the interpreted in-place component separately with its supporting evidence and confidence. [S1, PDF pp. 19, 47–49]

Basis: [S1], PDF pp. 19, 36, 42–49 and 51. Volume-history handling, revision control and quality-state labels are Chaser procedures developed from these principles.

1. Match the container to the register and check interval order. Resolve mismatched labels before describing the sample; do not infer an identity from neighbouring bags.
2. Inspect the as-received material and record mud coatings, lost-circulation material, obvious cavings and unusual shows before washing. Retain archive and special-analysis splits first.
3. Use the approved preparation method for the mud system and intended analysis. Wash gently enough to preserve soft components and use the specified sieves. Record the mesh sizes and whether fines were lost or separately retained.
4. Inspect wet material under consistent illumination and a clean binocular microscope. Use a fresh interior surface where coatings obscure the rock; keep that examination separate from any destructive test.
5. Prepare dry material only when needed and with an approved drying method that is compatible with the intended analysis. Never heat samples reserved for volatile hydrocarbons or geochemistry unless the receiving laboratory specifies it.
6. Clean tools, trays and work surfaces between samples. Keep control materials separate from formation samples. Return the labelled archive to its assigned position and record any analytical subsamples removed.

Do not use tasting, deliberate smelling or improvised chemical mixtures as identification methods. Carbonate, fluorescence and solvent testing belong to the approved worksite laboratory procedure, with the required ventilation, protective equipment, waste handling and reagent controls. The legacy reference contains historical procedures that are not adopted here. [S1, PDF pp. 31–34, 48, 51]

Record the bulk sample composition before preferentially selecting attractive reservoir chips. If contamination is substantial, record the proportions of recovered rock and non-rock material with a stated denominator. A second estimate of interpreted formation lithology may be useful, but it must not silently replace the observed sample. Percentages within a sandstone description refer to that sandstone fraction; they are not automatically percentages of the whole sample. Every estimate should state the material population being assessed. [S1, PDF pp. 18–19, 25–26, 47–49]

Use one description order throughout the well: rock type and approximate abundance; colour and wet or dry state; coherence or induration; fracture and observable texture; grain-size range and dominant size; sorting; original grain rounding and sphericity where recognizable; matrix; cement; accessories and fossils; visible pore types; hydrocarbon observations; and sample limitations. Omit inapplicable fields rather than inserting guessed values. Record depositional interpretation and reservoir assessment in separate fields. [S1, PDF pp. 18–27]

Use the project Geological Lexicon for all striplog descriptions. Store the full term with its approved abbreviation so an exported log remains understandable. Common lithology codes may include SS for sandstone, SLTST for siltstone, SH for shale, CLST for claystone, LS for limestone, DOL for dolostone, COAL for coal and ANHY for anhydrite. These proposed codes must map to the well's configured lexicon; an import must not silently reinterpret an existing code. Abundance words such as trace, rare and minor need published project definitions. Prefer an approximate percentage when that is clearer, and avoid suggesting precision beyond a visual estimate.

Describe colour on a stated wet or dry basis under consistent light, using a comparator where available. Distinguish friable or cemented rock from hard individual mineral grains. Describe cuttings fracture without treating bit-induced breakage as an in-situ fracture system. Rounding applies to original detrital grain edges where preserved; quartz overgrowths or broken grain fragments can invalidate a rounding estimate. Sorting concerns the distribution of original grain sizes within the rock, not the range of chip sizes produced by drilling. [S1, PDF pp. 21–25]

Photograph the representative sample and any selected diagnostic chips as separate views. Include wellbore, depth interval, sample identifier, scale, preparation state and date in the image record. Keep illumination, magnification and colour handling consistent for repeated images; retain the original file. Fluorescence images require the lamp and camera conditions as metadata and must not be compared by apparent brightness if exposure settings differ. A picture complements the written observation and does not substitute for the sample archive.

Illustrative entry only: 5,210–5,215 mMD, sampled through the full interval; mixed sample, minor suspected shale cavings. Observed rock fraction approximately 85% sandstone and 15% shale. Sandstone pale grey to tan, wet; friable to moderately cemented; very fine to fine grained, dominantly fine; moderately sorted, subangular to subrounded quartz with minor lithic grains; argillaceous matrix; patchy carbonate cement suspected, identification pending approved test; rare carbonaceous fragments and pyrite. No connected pore system resolved under the microscope. Hydrocarbon observations recorded separately. Interpretation: sandstone-dominated interval, confidence moderate; shale origin uncertain. This example deliberately separates observation, uncertainty and interpretation.

At handover, compare representative samples from the same interval and reconcile any systematic differences in terminology, colour, grain size, lithology proportions or show grading. Retain disagreements where the evidence is unresolved. A revised interpretation must identify the reviewer, time and reason; the original record remains accessible. Re-examine abrupt apparent changes against lag, sample quality, mud additions and drilling events before revising a correlation. [S1, PDF pp. 18–27, 46–49]

Basis: [S1], PDF pp. 18–27, 31–34 and 47–51. Digital lexicon mapping, photographic metadata and review controls are Chaser implementation requirements.

For sandstone, record grain-size range and dominant size, sorting, recognizable original grain shape, dominant framework constituents, matrix, cement, accessories and visible pore types. Distinguish a quartz-rich description from a formal compositional classification: calling a rock quartz arenite, arkose or litharenite requires an appropriate framework-grain assessment, not a quick impression of several quartz chips. State when lithic grains, feldspar or clay minerals are uncertain under the available microscope. [S1, PDF pp. 19–25]

The table uses the sand intervals in the Wentworth scheme, with explicit boundary handling for a digital lexicon. Record the actual comparator and scheme in use. If upper and lower subdivisions such as vfU or mL are used, their boundaries must be defined in the project lexicon; importing an abbreviation alone is insufficient. Silt is approximately 0.0039 to less than 0.0625 mm and clay-sized material is smaller than approximately 0.0039 mm. Grain size describes particle size, not mineral identity. [S1, PDF p. 23]

For siltstone, shale and claystone, record colour, coherence, fissility where preserved, fracture, apparent silt or sand content, carbonate character, organic matter and accessories. Use shale when fissility is demonstrated; do not infer fissility merely from thin fragments produced by drilling. Note swelling or disaggregation observed during approved preparation and its effect on the recovered fraction. A reduced claystone percentage after washing may reflect preparation loss rather than a cleaner formation. [S1, PDF pp. 20–23, 47–49]

For carbonate rock, begin with limestone, dolostone or a qualified mixed description supported by available evidence. Record colour, crystal or grain size, recognizable allochems, matrix, cement, recrystallization and visible pore types. A depositional texture classification can be applied when the original fabric is preserved and recognizable; otherwise record that the texture is indeterminate in cuttings. Record evidence for dolomite rather than treating every sparkling carbonate chip as dolostone. Approved carbonate tests support mineral identification but do not themselves establish reservoir quality. [S1, PDF pp. 21–26]

Describe anhydrite, gypsum and halite as minerals or lithologies where recognized, and distinguish them from introduced mud products. Soluble components may be depleted during circulation or preparation. Dolostone is a carbonate rock and should not be classified as an evaporite simply because it occurs in an evaporitic succession. This corrects an overly broad grouping in the legacy reference. [S1, PDF pp. 21, 48]

Record coal separately from dispersed carbonaceous matter. Describe lustre, fracture, brittleness, associated lithologies and whether fragments may be caved. A coal marker can be valuable for correlation, but its presence in a sample does not by itself fix the bit in that bed. Note pyrite, glauconitic grains, mica, phosphatic particles, shell debris, plant fragments and other diagnostic constituents with an abundance estimate. Mineral identification may remain provisional until laboratory confirmation. [S1, PDF pp. 25–26, 47–49]

Accessories and fossils may constrain correlation or depositional interpretation when their identity, origin and stratigraphic context are secure. Reworked fossils, recycled grains and cavings can produce misleading signals. Keep an observation such as rare glauconitic grains separate from an interpretation such as possible marine influence; combine multiple independent indicators before assigning a depositional environment. [S1, PDF p. 26]

Report visible intergranular, intercrystalline, mouldic, vuggy or fracture-related voids only where they are resolved. State the observational scale and whether the apparent void could be a broken grain contact or drilling damage. Absence of visible pores under a binocular microscope is not zero porosity. Loose sand does not automatically establish effective reservoir porosity because drilling and sample preparation can break cemented material into grains. [S1, PDF pp. 26–27]

Do not convert qualitative words such as poor, fair or good into numerical porosity without an explicit, validated calibration. Where a porosity value is supplied by core analysis or a petrophysical model, display its method, interval, units and quality flag beside the number. Effective porosity and total porosity are different quantities and must retain their labels. Permeability cannot be measured by visual chip examination, ROP, grain size or solvent-cut speed; qualify any inferred permeability tendency and seek core or appropriately interpreted testing evidence.

For the daily report, explain the change that matters: cleaner framework, finer grains, more matrix, greater cementation, different pore type or uncertain sample quality. State whether the conclusion is observed, inferred or measured. Avoid assigning pay, fluid contact or commercial quality from cuttings or gas response alone. [S1, PDF pp. 28–35, 45–46]

Basis: [S1], PDF pp. 18–27, 28–35 and 45–49. Numerical visual-porosity bins and legacy lithology conventions have not been adopted as Chaser measurement standards.

At the start of a well or instrument change, record the gas detector and extractor, instrument range, reported units, calibration record, gas-line arrangement and known response delays. Retain raw measurements. Report total gas in the supplied units unless the provider supplies a documented conversion and calibration basis. There is no universal conversion from arbitrary gas units to ppm or percent across instruments. Record whether a chromatograph value is a concentration, an uncalibrated response or a normalized fraction. [S1, PDF pp. 29–30, 43, 45–46]

Review extraction conditions, mud flow, gas-line flow, trap immersion or loading, leaks, blockages, condensation, analyzer health and saturation flags with the mudlogging provider. A step change following equipment work needs an instrument explanation before a geological one. Compare intervals only after checking that the mud system, sampling conditions and measurement basis are sufficiently comparable. [S1, PDF pp. 42–46]

Connection and trip gas must never be dismissed as harmless merely because their timing is explainable. A change in these responses can be operationally significant. Communicate an unexpected gas increase or associated well-condition change promptly through the drilling supervisor and established well-control communication system; do not wait for the geological interpretation. The drilling crew applies its approved response procedure. [S1, PDF pp. 7–11, 29–30, 44, 46]

1. Check the timestamp, lag, depth basis and quality flags. Separate gas response time from cuttings collection time and from current bit depth.
2. Record the local background, peak, duration or depth extent and event type. Preserve the curve and operational record around the event rather than only a peak number.
3. Check ROP, flow rate, hole size, mud density and rheology, additions, pump state, drilling mode and extraction conditions. Compare like operating periods where possible.
4. Review calibrated hydrocarbon components and detection limits. Note absent, below-detection, invalid or saturated components distinctly; these are not interchangeable zeros.
5. Examine the corresponding and adjacent samples, recognizing their different transport and mixing. Record show evidence for each rock type and compare known mud and additive controls.
6. State the preferred interpretation, plausible alternatives, confidence and the additional evidence needed. Link significant show events to the daily report and any decision record.

Ratios involving C1 to C5 can help compare composition when the components are measured on a consistent basis and exceed appropriate reporting limits. Near-zero denominators, censored components, changing extraction efficiency and oil-based mud contamination can make ratios misleading. Do not assign fluid type, API gravity, saturation or pay from a fixed ratio cutoff alone. If a normalized gas curve is produced, retain its equation, units, excluded periods and input versions; label it as a derived comparison index, not a measured formation gas content. [S1, PDF pp. 29–30, 43, 45–48]

Record the lithology carrying the show, approximate proportion affected and whether evidence occurs on chip surfaces or fresh interiors. Record stain colour and distribution, visible bleeding if observed without deliberate exposure, direct fluorescence colour and distribution, and the results of any approved laboratory extraction test. Keep sample fluorescence, extract fluorescence and residue observations in separate fields. A negative result means no indication was observed under the stated method; it is not proof of no hydrocarbons. [S1, PDF pp. 28–35]

Use clean equipment, an appropriate reagent blank where an approved extraction method is performed, and representative controls for the actual mud, base fluid, pipe compound and additives. Compare selected rock fractions rather than treating the entire mixed tray as one lithology. Do not use deliberate odour testing, unsafe heating or historical solvent recipes from the reference manual. Record the approved procedure identifier and any departure that limits comparability. [S1, PDF pp. 31–34, 46–48]

Carbonate minerals, shell fragments and some organic material can fluoresce. Coal, lignitic material and drilling additives can complicate extraction observations. Diesel, lubricants, pipe compounds and oil- or synthetic-based drilling fluids can coat cuttings or mask indigenous hydrocarbons. Keep a contamination history tied to time and depth, with control samples when appropriate. Fluorescence colour alone cannot reliably establish a formation oil source, distinguish all contaminants or determine API gravity. [S1, PDF pp. 31–34, 46–48]

Strong gas with poor cuttings shows can reflect several conditions, including gas-rich fluids, poor sample recovery or timing error. Strong sample indications with modest gas can reflect a lower-volatility hydrocarbon, extraction limitations or contamination. Treat these as hypotheses to test against calibration, operating conditions, logs and laboratory evidence. Where data remain inconsistent, report the conflict explicitly and preserve material for follow-up. [S1, PDF pp. 30–31, 45–48]

Minimum show record: event identifier; wellbore; collection and detection times; lag-model version; interpreted depth interval; raw gas units and component basis; background and peak; operating conditions; lithology and sample quality; stain and fluorescence observations; control results; contamination history; interpretation and confidence; notification details; retained samples; and follow-up action.

Basis: [S1], PDF pp. 28–35 and 42–49. Gas units, qualified interpretation and explicit test controls take precedence over historical shortcuts or unvalidated fluid-classification tables.

For this manual, mSS = KB elevation − mTVD when TVD is measured down from that same KB reference and the KB elevation is tied to the stated vertical datum. Thus KB elevation +720.00 m and TVD 2,350.00 m give −1,630.00 mSS. This signed elevation is not positive-down TVDSS. A source labelled TVDSS must be inspected before conversion. A map projection, vertical datum and north reference are separate settings; a matching unit label does not establish compatibility.

With azimuth measured clockwise from the applicable north reference, section displacement is ΔN cos A + ΔE sin A. State the section origin and A. A curved lateral can return to the same mVS at different mMD values; mVS must not be used as a unique record identifier. Keep grid, true and magnetic azimuths distinct and use the provider's documented correction rather than an assumed declination.

1. Verify wellbore identity, units, datum, north reference, station depths, inclination and azimuth. Check duplicate or reversed station depths, missing stations and unexpected trajectory changes.
2. Confirm the provider's QC status, calculation method, tie-in and revision identifier. A plausible plot does not establish survey accuracy.
3. Compare the revision against the previously accepted survey and planned trajectory. Review changed stations and the effect on tops, heel, target separation and end-of-well position.
4. Preserve original picked mMD values and acquired measurements. Recalculate derived TVD, mSS, North, East and mVS from the accepted survey and store the new survey revision with those results.
5. If the acquired MD itself is corrected, retain the original record and document that distinct correction. Do not disguise an MD correction as a TVD recalculation.
6. Record acceptance, reviewer, time and affected reports. Reissue material changes with a revision note instead of silently overwriting an issued interpretation.

Show the last accepted survey station separately from the current bit position projected beyond it. Label the extrapolation's start station, target mMD, assumed inclination and azimuth, method and uncertainty. Do not present this projection as a new measured survey. Reconcile it when the next accepted station arrives.

Record each BHA's sensor-to-bit distance and effective interval. Apply its depth correction once on a common MD basis, checking whether the provider has already shifted the data. For a simple example, a sensor 12 m behind a bit at 3,150 mMD is at approximately 3,138 mMD on that basis. Changing the BHA requires a new mapping; software must not shift every historical curve by the latest offset.

Basis: depth definitions [S5; S6]. Coordinate signs, geometric examples, survey revision controls and display requirements are original Chaser procedures.

Choose a reference well or composite type log with a known datum, survey basis and stratigraphic coverage. Identify distinctive marker sequences and uncertainty around their tops, bases and lateral continuity. Keep an observed top, a prognosed surface and an interpretation tie as separate objects. A coal marker within or above a formation is not automatically that formation's top or the top of the target reservoir. Store the marker's exact name and relationship to the target.

1. Align the relevant measurements using accepted depth and sensor mappings, then examine quality flags and drilling events before adjusting geology.
2. Compare a sequence of markers and curve shapes, supported by sample changes. Avoid a correlation based on one visually convenient spike.
3. Record each tie's measured interval, reference interval, supporting evidence and confidence. Retain reasonable alternatives when the signature is not unique.
4. Evaluate changes as competing explanations: formation dip, fault displacement, stratigraphic thickening or thinning, lateral facies change, survey revision, sensor offset, lag error or poor data.
5. Update the model only as far as the evidence supports and record the reason. Do not introduce a fault or thickness change solely to force an exact visual match.

A three-dimensional bed orientation needs true dip and dip-direction azimuth. Apparent dip is the signed slope seen in one named vertical section. For a planar bed, tan(apparent dip) = tan(true dip) × cos(section azimuth − dip-direction azimuth), using a common north reference. A section looking down dip has positive apparent dip under the positive-down-to-the-right convention used by the explorer; an along-strike section is flat; looking up dip reverses the sign. Record the section azimuth with any apparent-dip value. Do not substitute borehole inclination from vertical for formation dip.

Display plan and accepted actual trajectory together. Intersect prognosed surfaces with the three-dimensional plan to estimate where a top should be encountered, then show the uncertainty around that encounter. A horizontal line on a two-dimensional section is not automatically the correct projection of a dipping surface. Track the next geological marker, expected target top, planned heel and current measured or projected position.

Label distances by meaning: remaining mMD along the plan, vertical separation in mTVD, signed elevation difference in mSS, or true stratigraphic thickness. Isopach is thickness measured normal to bedding. The vertical distance from a coal to a target, or from target top to planned heel, is not generally an isopach. For parallel planar beds with true dip δ, normal thickness equals vertical separation multiplied by cos δ; this simplified geometry does not resolve faults or nonparallel surfaces.

Maintain the last explicitly interpreted formation dip until the next saved dip change, including beyond the final saved interval as drilling advances. Label that continuation as a carried model assumption and retain its originating interval. Before the first valid dip, show the assumption as undefined unless a documented initial value has been supplied. A change to a dip interval must identify its editor, evidence and revision.

This continuity rule applies to the geological model. It must never create missing measured gamma-ray observations. Display modelled or dip-derived curves separately from measured GR, with explicit provenance and distinguishable styling. A measured-data gap remains visible even when the structural model continues through it.

For every material recommendation, record current mMD, last accepted survey, projected bit position, target window, preferred interpretation, alternatives, evidence, confidence and the next observation that would change the interpretation. State the requested geological outcome and communicate it to the authorized decision-maker and directional team. Record acknowledgment and the adopted action. After the next survey or diagnostic measurement, assess whether the expected result occurred and revise the model if necessary.

Basis: integrated sample, gas and operational interpretation in [S1, PDF pp. 18–35 and 42–49; S8]. Correlation, geometry, dip-continuation and decision-record requirements are original Chaser procedures tailored to the requested workflow.

WITSML provides standardized exchange of wellsite information, including logs and trajectories; it differs from WITS. A data standard alone does not guarantee a particular connection's completeness or correctness. [S7] Appoint the person responsible for connection setup and source mapping. Verify well, wellbore, leg, curve identity, units, index type, timezone and depth basis before admitting a feed to the interpreted record.

1. Register the source file or feed and retain the acquired data. For LAS, CSV, spreadsheet or native-log imports, review headers, null codes, duplicates and interval coverage before mapping fields.
2. Keep time-indexed and depth-indexed curves distinct. Document the conversion, sensor correction and lag model when transforming one into the other.
3. Check start and end depths, full lateral coverage, gaps, units, signs and suspicious steps against the source. Do not accept a successful upload message as proof that the complete dataset is displayed.
4. Assign quality states to raw measurements, interpreted values and derived products. Preserve rejected or superseded records in the audit trail rather than erasing their existence.
5. Display the latest valid acquisition time and depth, connection status and known delay. A last value that remains on screen must still show when it was measured.

Configure track order and width, curve assignment and units, scales, lithology, sample descriptions, shows, photos, tops and drilling events for the well's purpose. Save the layout separately from geological content. A layout change must not change a pick or measurement. Use the Geological Lexicon for descriptions and store the underlying structured fields alongside the rendered text.

Keep the relevant vertical, build and horizontal intervals accessible, with an explicit displayed depth range. Review the whole lateral as well as the latest interval. When importing a legacy striplog, distinguish recovered structured data from text or graphics transcribed from a PDF; verify uncertain depth alignment against the original and record transcription confidence.

Do not substitute zeros for null measurements. Any interpolation, smoothing, carry-forward display or averaged overlay needs a visible label, defined window, coverage rule and access to the raw curve. A held last value may support a status display, but its age and non-measured continuation must remain apparent. State whether a mean is weighted by time, depth or record count, and exclude invalid periods consistently.

DRQI is a configurable interpretation indicator only after its formula, normalization, input curves, exclusions and version have been validated for the intended use. Do not invent a DRQI calculation or portray it as measured porosity, permeability or a universal reservoir-quality scale. Save its provenance and review the raw input response whenever the indicator changes materially.

Before issue, reconcile the striplog, sample register, tops, survey revision and narrative at a stated cutoff. Freeze an issued snapshot with its source and interpretation versions, recipient access and reviewer. Continue live interpretation as a subsequent version. Confirm that another authorized user can retrieve the same issued view, and maintain a documented recovery route for a connectivity outage or corrupted local session.

Basis: WITSML scope and distinction from WITS [S7]; integrated mud-log content [S8]. Infinity requirements, import checks, provenance and release controls are original Chaser procedures and require project verification.

1. Review the approved objectives, coverage and acquisition programme with operations geology and the logging specialist. Clarify priority intervals and the required deliverables.
2. Provide the accepted well identifier, depth datum, survey version, casing information and relevant drilling and hole-condition history. Discuss operational constraints with the drilling supervisor.
3. Obtain the tool-string diagram and actual sensor positions. Check whether each required sensor can cover the interval of interest within the planned run.
4. Arrange the agreed mud-property measurements and record their sample source, time and temperature. Include additives or system changes relevant to interpretation.
5. Confirm the contractor’s calibration and quality-control plan, repeat coverage, required acquisition files and responsible recipient for early results.
6. Keep a logging diary of run identity, times, covered interval, conditions, interruptions, observed limitations and the acceptance decision. Specialist personnel retain control of their equipment.

Check the original header before importing a curve. Record whether depth represents the bit, sensor, wireline measurement or a processed reference. Do not apply a second sensor-offset correction to a dataset already corrected by its provider. Compare overlapping markers and accepted survey or depth-control evidence with the specialists. Investigate differences rather than shifting a curve until it looks convenient. Retain the original depth and the documented transformation as separate records. [S2, PDF pp. 80–81, 87–90]

Real-time and memory data may differ in sampling, processing and completeness. Record which product is displayed and replace it through a controlled revision when improved data are accepted. Low sample density during fast drilling, missing telemetry, smoothing and variable vertical resolution can affect thin-bed interpretation. A fine plotting increment does not create measurement resolution. [S2, PDF pp. 80–81]

A low gamma-ray interval is not automatically clean reservoir, and elevated resistivity is not automatically hydrocarbon pay. Assess the mineralogy, fluid system, borehole environment, effective porosity evidence and geological continuity. Report a quick-look interpretation with its assumptions and confidence; reserve quantitative saturation or net-pay results for an appropriate, documented petrophysical method and accepted inputs.

Neutron porosity responds strongly to hydrogen and is affected by clay, fluid and matrix. Gas generally reduces its apparent porosity because the hydrogen density is low. Evaluate a possible density–neutron gas crossover only after checking compatible lithology scales, depth alignment and borehole quality. The relationship is supporting evidence, not a stand-alone declaration of gas or producibility. [W-SLB-NPHI]

For each run, retain raw and processed files, headers, calibration and repeat information, tool configuration, quality flags and the processing version. Identify missing coverage or intervals that require a repeat or later specialist review. Record whether data are accepted for correlation, qualitative evaluation or quantitative analysis; those are different uses. A failed measurement remains flagged in the composite record rather than being silently replaced by an assumed value. [S1, PDF pp. 10–11; S2, PDF pp. 89–95]

Basis: [S1], PDF pp. 10–11; [S2], PDF pp. 80–81 and 86–97. Neutron response checked against [W-SLB-NPHI]. Tool-specific operating limits and acquisition settings come from the current service programme and manufacturer guidance.

1. Confirm the approved interval, geological objective, decision authority, coring contractor, analytical priorities and any oriented-core requirements. Record how the start point was selected and its uncertainty.
2. Confirm the driller's depth basis and current tally, and preserve the core-run top and base as acquired. Do not assume the cuttings depth model or a later wireline shift is identical to the coring depth.
3. Review the recovery and handling plan with the drilling supervisor, coring provider and laboratory. Establish safe access, equipment responsibilities, gas and pressure precautions, exclusion zones and custody handoffs.
4. Prepare sequential identifiers, labels, the recovery tally, approved containers, marking equipment and shipping materials. Arrange personnel so identification can be checked by a second person without delaying preservation.
5. Agree which chips or plugs may be removed, which surfaces must remain undisturbed and which analyses have priority. No unscheduled washing, sawing, splitting or sampling should compromise the programme.

Track drilling progress and relevant operational changes during coring, and preserve any requested cuttings. Report a suspected jam, abnormal response or threat to the objective to the supervisor and coring contractor. The geologist provides the geological assessment; the authorized operational team determines how to continue, stop or retrieve the assembly. [S1, PDF pp. 36–37]

The coring provider establishes when equipment and material are safe for geological handling. Do not work beneath suspended loads, open potentially pressurized equipment or improvise venting of a gas-bearing container. Maintain the agreed gas-detection and handling controls. Record any delay or exposure that could affect fluid or volatile measurements. The legacy manual's handling examples are not substitutes for the current provider's procedure. [S1, PDF pp. 37–39]

1. Identify the top of the recovered sequence with the coring provider and preserve original order. Give every piece, sleeve and box a unique identifier tied to the core run.
2. Mark top and bottom explicitly and use the agreed directional marking convention. Record what an orientation line represents; a line indicating downhole direction is not automatically a measured geographic orientation.
3. Measure recovered lengths and reconcile all pieces, including fragments from barrel breaks. Record the cut interval and recovered length separately, with gaps and uncertain positions clearly identified.
4. Calculate recovery as recovered length divided by the recorded cut interval, multiplied by 100. Investigate apparent recovery over 100% instead of silently capping it; expansion, loose material, mixed runs or tally error may be involved.
5. Do not stretch recovered material evenly through a missing interval or invent the position of lost core. Use observed boundaries and a documented placement model, preserving alternative placements where unresolved.
6. Apply labels to the container and its durable record, and have a second person check order, depths, piece counts and end labels. Photograph the sequence and retain the signed reconciliation record.

Record lithology, preserved sedimentary structures, bed contacts, fractures, visible pores and shows at a scale appropriate to the core. Distinguish natural fractures from recovery damage where evidence permits, and flag uncertain cases. Keep descriptions based on whole core, core chips and sidewall cores as separate evidence types. Preserve oriented surfaces, fragile fabric and material designated for fluid-sensitive analysis. [S1, PDF pp. 38–41]

Maintain the original core depth scale when later correlating core gamma or lithology to a wireline or LWD log. Store any shift as a separate transformation with tie points, method, reviewer and uncertainty. Core depth, log depth and sample identifiers must remain recoverable after alignment. A matched plot should not erase the acquired record.

Prepare a target list with wellbore, depth reference, requested depth, geological purpose, expected lithology and priority. The logging provider controls tool selection, safe operation and release of recovered samples. Maintain the mapping between requested depth, attempted depth, recovered sample number, recovery condition and provider depth correction. Record failed or partial recoveries explicitly. Keep consecutive identifiers across runs and verify the mapping jointly with the logging engineer. [S1, PDF pp. 40–41]

Do not handle a sidewall assembly until the provider declares it safe. Do not assume that every recovered plug is suitable for every analysis: sampling damage, mud invasion, size and preservation affect the result. Use the receiving laboratory's packaging instructions and record any deviation. Avoid chipping or breaking a plug for a quick description unless authorized. [S1, PDF pp. 40–41]

Obtain the laboratory's written requirements for container, sample mass or fill, headspace, preservation, temperature, holding time and shipping before collecting material for headspace gas, source-rock analysis, biostratigraphy or other specialist work. Do not adopt the reference manual's canned-sample bactericide recipe as a universal method. Different analytical objectives require different handling, and a preservative may interfere with the requested test. [S1, PDF p. 51]

Collect suitable mud, base-fluid and additive controls when the programme calls for contamination assessment. Record all relevant additions and their timing, and preserve the unwashed or unheated state when required. For every special sample, retain the requested analysis, actual method, collection time, preservation time, responsible person and any exposure or storage departure. [S1, PDF pp. 47–48, 51]

The shipment register must identify every sample or container, core run and interval, package count, preservation condition, requested analyses, destination, sender, courier and each custody handoff. Include gap and damage records so the laboratory can reconstruct the sequence without guessing. Use the approved transport classification and packing arrangement for the actual materials. Send the receiving laboratory the inventory and confirm receipt, condition and discrepancies. A shipped status is not a received status. [S1, PDF pp. 39–41, 51]

Basis: [S1], PDF pp. 36–41 and 51. Core-depth transformations, custody tracking and laboratory-specific preservation controls are Chaser procedures developed from these principles.

Agree the daily cutoff and delivery time at well setup. Record period start, period end, time zone and issue time explicitly; do not assume the local civil day is always exactly 24 elapsed hours across a clock change. At cutoff, reconcile bit depth, current operation and interval progress with the accepted drilling record. Preserve discrepancies as unresolved items until reconciled. Data acquired after cutoff belong in a labelled current-status update, not silently in the previous period.

1. Current status: well and leg, issue time, current operation, bit mMD, last accepted survey and its depth, evidence coverage and data age.
2. Period summary: start and end depth, drilled interval, operational events relevant to the geology, and any period with no new formation drilled.
3. Geological interpretation: formations and markers encountered, target position, supporting observations, alternatives and confidence.
4. Interval evaluation: lithology, reservoir observations, ROP, gamma ray, gas and sample quality using consistent fields and units.
5. Changes and exceptions: survey revisions, depth corrections, outages, missing samples, changed mud system, revised picks or superseded interpretations.
6. Forward plan: next marker or decision point, available lead distance, required evidence, recommended action, decision owner and outstanding questions.

Use verified data rather than estimating statistics from a plotted image when the digital values are available. State whether averages are time-weighted, depth-weighted or arithmetic over a defined sampling grid. Exclude invalid readings through a documented rule and report the valid coverage. Do not treat nulls as zero or include display-carried values as new observations. Where downlinks, reaming or connections affect a curve, preserve those events and explain their inclusion or exclusion from the summary.

Describe the interval trend and its implication in connected sentences. Link every interpretation to the relevant samples or curves. For example: Illustrative only: sandstone content increased through the latest sampled interval while the depth-matched gamma-ray response declined. This supports an approach to the sandier portion of the target, although mixed returns limit the contact pick. The next sample and accepted survey will be reviewed before revising the trajectory recommendation. Keep invented examples out of an actual well report.

When a survey is replaced, retain its earlier version and the accepted replacement. Recalculate dependent mTVD, mSS and spatial values, then review tops, projections, interval statistics and annotations affected by the change. A revised survey can change the calculated position of a pick without changing its original mMD observation. Record the revision reason and affected outputs, and issue a labelled correction when a previously distributed report would otherwise mislead the reader.

• Current operation; bit depth; last accepted survey; last described sample; latest valid gamma-ray and gas coverage; and the time of each.
• Best geological position, supporting markers, competing correlations, uncertainty and the next decision point.
• Active instructions and recommendations, who authorized them, what has been executed and what still awaits a decision.
• Sample backlog, missing intervals, instrument problems, lag status, changed additives and any incomplete quality checks.
• Reporting deadlines, outstanding data requests, sample shipments, interpretation version and location of the working record.

The incoming geologist should repeat back the target position, next decision and unresolved risk or data issue, then record acceptance of the handover. A saved checklist is a reminder; it is not evidence that another person has reviewed the work. If there is no new drilling, still record the operation, evaluation work and outstanding actions. [S1, PDF pp. 8, 13–15; S2, PDF pp. 38–39]

Basis: [S1], PDF pp. 8 and 13–17; [S2], PDF pp. 37–39. Defined data weighting, revision control and the digital handover structure are original Chaser application guidance.

1. Confirm well and leg identities, final drilling depth, accepted survey version, datum and coordinate conventions. Resolve duplicate wells or incorrectly assigned branches before exporting.
2. Compare the final striplog, formation tops, sample intervals, show records and accepted logging coverage. Explain conflicts rather than forcing agreement.
3. Review the sample inventory against the programme. Identify missing, mixed, contaminated or unrepresentative intervals and any laboratory results still pending.
4. Reconcile interpretations changed by final surveys, memory logs, core descriptions or laboratory results. Preserve the basis and version history for material changes.
5. Check that all promised deliverables exist, open correctly and cover the intended interval. Provide a clear manifest of files and physical sample shipments.
6. Obtain the designated technical review and acceptance record. Carry unresolved items into a named action list with an owner and expected resolution.

Verify that the final display includes the entire drilled interval required by the programme. A cropped viewport must not be mistaken for missing acquisition. Check build and landing separately where the decision context differs from the lateral. Confirm that displayed sample images, formation markers and curve tracks refer to the correct depth and leg. Review axis labels and scales after every change of coordinate display.

Classify a gap as not acquired, unavailable, rejected, not applicable or still pending. These states mean different things. Where a channel failed, record the last valid observation and restoration time. Where an interval was not sampled, preserve that fact rather than borrowing a nearby description. Where a calculated projection extends beyond measured data, label the projection and its assumptions.

Retain original acquisition files separately from interpreted and publication-ready products. Keep a delivery manifest with filenames, well identity, coverage, version and recipient. Transfer physical samples with an inventory and record of custody. Use the client’s approved destinations and access rules; an online manual available to the public does not authorize publication of confidential well data. [S1, PDF pp. 11–12, 17; S2, PDF pp. 35, 39]

Hold a focused review of what affected geological decisions: prediction errors, ambiguous correlations, sample transport uncertainty, survey revisions, delayed information and repeated manual work. Separate geological surprises from acquisition failures. Record the change needed, the person responsible and how its effectiveness will be checked on the next well. Update reusable templates only after confirming that the change applies beyond a single well.

Quality acceptance should be explicit. Ask whether another geologist could reproduce the depth references, locate the evidence for a formation pick, understand why a steering recommendation changed and identify the limits of the reservoir assessment. If any answer is no, improve the record before closing the action.

Basis: [S1], PDF pp. 11–12 and 16–17; [S2], PDF pp. 35, 39 and 95–97. Closeout acceptance and review records are an original Chaser workflow.

If upper and lower subdivisions are used, adopt an explicit half-phi scheme. Each full Wentworth sand grade is split at its geometric midpoint. Values below are rounded for display; the exact boundaries derive from powers of two. The lower bound is included and the upper bound excluded. This declared convention resolves abbreviations rather than assuming every legacy log uses the same scheme.

Sample X014, 3,100–3,105 mMD: observed rock fraction approximately 90% SS and 10% SH. SS pale grey, wet; fr to mod indur; vfU–fU, dominantly fL; mod srt; sa–sr qtz with minor lithic grains; arg mat; patchy calc cmt suspected; rare pyr and carbsc fragments. Pores unresolved at microscope scale. No direct fluor observed under the recorded conditions. Interpretation: sandstone-dominated interval; minor shale may include cavings. This invented training example is not a client well or a reservoir measurement.

KB elevation +720.00 m, accepted TVD 2,350.00 m: mSS is −1,630.00 m. A later survey changes the same 3,100.00 mMD pick to 2,350.80 mTVD; its new mSS is −1,630.80 m. Preserve the MD pick and both survey revisions. If a target surface remains at −1,628.00 mSS at that position, the pick is now 2.80 m vertically below it. That separation is neither along-hole distance nor automatically stratigraphic thickness; review the target model before recommending a correction.

Basis: descriptive categories and full sand grades [S1, PDF pp. 18–27]; MD and TVD concepts [S5; S6]. Codes, half-phi subdivision convention and numerical examples are original Chaser training material.