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NWE WellReport

Sign in

Demo sign-in. Production accounts are issued per user by the company. In this demo any password entry is accepted; nothing is stored — the sign-in lasts for this session only.

Demo accounts · fictional people

Office Admin is the company office role: the only role besides a packet's owner that can open a weekly packet, read-only, for payroll processing. Field roles see only their own timesheet and expenses — never anyone else's.

NWE WellReport — Platform Foundation

Northwest Engineering compass rose
NWE WELLREPORT
Northwest Engineering

Plan it. Drill it. Complete it. Frac it.

One engineering platform from the first design target through drilling, completions, and final well closeout.

Directional Drilling

Plan, steer, verify and report.

Engineering & Well Control

Design, execute and close out the well.

The demo uses a fictional dataset. Practice-well data stays separate.

Northwest Engineering compass rose
NWE WELLREPORT
Northwest Engineering
Saved
Well
No well entered
LIH
AWAITING LIH
Plan
—
Surveys
—
Units
API (oilfield)
Engine
min-curvature live
Leg 01 · OriginalPrimary wellbore · relative position uncertainty follows the original surface tie-in.
Northwest Engineering compass rose
NWE WELLREPORT
Northwest Engineering
PlanWell Planning WorkspaceStandalone engineering environment
Plan it · stage-based design

Well Planning

Enter the targets, create a first-guess trajectory, then tune the stages. Download the transfer file when the design is ready; the drilling team loads it through Well Setup.

Import an existing plan

Load a Compass / Well Seeker-style plan — a PDF with a text table, an Excel workbook, or a TXT/CSV listing — or paste the plan text. The identity block, design targets and stage design fill from the plan, and the imported listing stays beside the solved design as the reference. Everything remains editable, and importing never touches the drilling workspace.

Header lines above the station table fill the identity block; structural and units rows are skipped automatically.

Plan package identity & references

The issued plan carries the same engineering blocks and conventions expected in a Compass-style directional plan package.

TRUE NORTH RECORDED · MINIMUM CURVATURE · GRID CONVERGENCE

Header block

Site position & elevation

Magnetics block

Survey tool program

Issued exactly as entered in the plan report, Excel workbook and TXT transfer file.

Design targets

Target coordinates are planning inputs. Add every control point the plan must penetrate.

Stage design

Vertical, build, hold, drop and turn sections are solved in order. Suggested values stay editable; ↺ restores the latest first guess.

Offset Builder — build offsets in the shared register

The planner builds and maintains the offset set for the design here, in the one shared offset register — the same register the Planner Preview below, the DD anti-collision scan and the 3D scene read. An offset built here is the offset the live well is scanned against, with no re-entry in any other workspace, and register edits made on the DD side show here. Stations are entered as MD / INC / AZI only; TVD, N/S, E/W, VS and DLS are computed from the offset's own wellhead by the shared minimum-curvature engine. Anti-collision stays decision support: this panel adds wells to the register, it does not clear any well.

0 offsets

Planner Preview

The well being built, drawn live from the current stage design: the Directional Drilling Trajectory chart, map and vertical-section views with every registered offset well, and the Step 5 anti-collision scan run against the in-progress design. Previewing is read-only — the drilling workspace changes only when a plan is issued and loaded through Well Setup.

Live · read-only
Decision support only. This module presents calculations for a professional’s review; it does not sign off on a well for drilling — that decision belongs to the operator’s approved anti-collision program and official surveys. Separation-factor action levels are entered operator policy, never universal constants; implement against the licensed ISCWSA standard before relying on any scan.
Offset wells

Plan Summary · STAGE

Compass conventions: MD, INC, AZI, TVD, north/south, east/west, dogleg, build, turn and toolface at every stage boundary.

Full planned survey listing

Minimum-curvature stations at the selected plan interval. The complete listing is included in every exported plan package.

0 stations

The page previews the first and last stations for review; downloads contain the complete planned survey listing.

Issue plan package

Four branded files ready to attach to an email or print. Email sending itself remains a production-backend step.

4-file company packagePlan report PDF · plot PDF · Excel · TXT
Package ready to build. Complete the header blocks and stage design, then download the four files.

Planning Record · P1–P12

The complete planning record for the demo well below the trajectory designer: the Plan (basis of design, P1–P8, P10–P12) and the Drilling Program it generates (P9, the field-manual layer). One canonical hole-section list drives casing, mud, cement and bits. Every value is labeled Computed, Entered, Entered · Model or Estimate — prognosis, targets, design-factor policy and lab values are entered professional values with their source named; the software computes arithmetic only, and every auto-filled value stays editable. All wells, offsets, people and prices on these sheets are fictional demo data.

How to read a value:ComputedEnteredEntered · ModelEstimate· Demo well: Cottonwood Draw 14-3 2H (fictional) · Plan revision Rev 1
Rev 1 · issuedNo sheets flagged stale. Editing the P2 prognosis flags every dependent sheet until it is re-reviewed.

P1 · Plan Basis & Objectives

Why this well exists, what class of well it is, the datum it is planned on, who signed it, and the four review gates that must close before spud. The well class is stated on the plan's face because it tells every reader how much evidence the plan could stand on.

Basis of design

P2 · Geology & Pressure Prognosis

Formation tops and the pore-pressure / fracture-gradient prognosis — all entered values with the source named per row. The mud window is the one thing computed here: pore pressure plus trip margin up to fracture gradient minus kick margin. Edit any prognosis value and the dependent sheets (P5/P6/P7/P9/P11) flag stale until re-reviewed — planning is a cascade, not a checklist.

Prognosis entered · window computed

P3 · Trajectory Plan & Anti-Collision

The plan record: profile family, target with its geology-approved landing window, segments with their reasons, plan stations by minimum curvature (the method is recorded on the plan as provenance), the survey programme, and the anti-collision scan kept as a dated artefact per offset pair.

Decision support only

P4 · Offset Register

Offsets are chosen for similarity — same fault block, same pressure compartment, picked with the geologist — never merely for distance. Each record group carries its provenance, its confidentiality-until date, and a representative/correct caveat. Conflicting evidence is recorded, never averaged away.

Evidence, with provenance

P5 · Casing Design Record

One canonical section list, shared with P6/P7/P8. Casing seats and bit sizes are chosen together against the pressure windows, and sizing works bottom-up from the completion the borehole must fit. Design factors are the operator's entered policy — the published sources conflict, so the conflict is shown and nothing is hard-coded.

Policy entered · ratings computed

P6 · Mud Program

Per-section mud systems engineered to match the casing plan. Density windows and formulation targets are entered from the prognosis, offsets and lab work; hydrostatics, annular velocity and volumes compute from them. ECD is a named-model estimate, never arithmetic truth.

Formulation entered · hydraulics computed

P7 · Cement Program

Per-job slurry schedules. Volumes compute from capacities times one plus the entered excess; sacks divide by the entered lab yield; mix water and additive mass follow. Lab values — yield, thickening time, strength — and the excess percentage are entered, never computed.

Lab values entered · volumes computed

P8 · Bit & BHA Program

Bit size is a casing-design output — it comes off the canonical section row, not a separate choice. Nozzle TFA computes from the entered nozzle set; expected ROP and cost-per-foot come from the P4 offset record.

Sizes from P5 · TFA computed

P9 · Drilling Program

The generated field-manual layer, produced from the approved plan (P1–P8): section-by-section steps, tests and operating limits, the pre-spud pack, and a risk register whose entries key to observable triggers — each critical limit names what observation stops reliance on the assumption, and who is authorized to change the program.

Generated from the plan

P10 · Permits & Deadlines

Tracking only — nothing on this sheet files anything. Each permit stores its approval date and the rule version its expiry was derived under, because permit validity has changed by rulemaking and a single hard-coded period would be wrong. The deadline ledger is driven by well events: spud, TD, rig release, completion.

Track only · no filing

P11 · AFE & Depth-Days

The AFE in its seven parts, always in three cases — best, expected, worst — never a single fixed budget. Costs roll up from entered rates and case days; a delay scenario is priced openly as extra days times the entered day rate plus time-dependent charges.

Three cases · roll-ups computed

P12 · Revisions & Learnings

No divergence from the approved program without an approved revision; the pre-revision plan stays frozen. A lesson without an adopted-into-revision link shows as unadopted — without that link, a lessons register is a graveyard.

Frozen history · live cascade

Checks · audit witnesses

Each line recomputes a published worked example live from its pinned inputs and compares against the published result — the eight research cases D-1 to D-8, the ECD narrow-window case, and the Concordia B differential-pressure casing-seat case. A disagreement means a formula has been broken.

running

Well setup

Enter the well once. Everything downstream — the Survey Editor, plan-vs-actual, and every future module — works off this setup and the plan it carries.

Well identity

The constants that name this well across the platform.

The legal well name. Stable identifier across every report and module.
Your job number — used on the morning package and revenue report.
The operator buying the work. Drives template and branding choices later.
The rig drilling this well, as it appears on reports.
DD morning reports cover a daily window — usually 5am–5am. The reporting side keys off this.
Stamp now and all report timestamps follow rig time, not this computer's clock zone.

LIH — Lost In Hole coverage decision

The LIH decision is made on paper. Before a new well starts and before any DD tools are picked up: print the LIH sign-off sheet, the Company Man checks YES or NO for each tool class and signs it by hand. The signed paper sheet is the record of decision, filed with the well — there is no in-app LIH recording: nothing here is marked, toggled, or signed on screen. A denial signed on paper is a completed decision, not a rejection of the job.

AWAITING LIH
Your company's name, printed on the sign-off sheet under the NWE WellReport masthead.
Auto-filled from Customer / operator in Well identity. Type over it any time — your entry is what prints on the sheet.
Auto-filled from Well identity. Type over it any time — your entry is what prints on the sheet.
One signed sheet can cover every BHA on the well, or one named BHA — the BHA number prints on the sheet's BHA NUMBER line.
Your company's own warranty and inspection wording, loaded once at company level — kept across wells and printed word for word at the top of the sign-off sheet. NWE WellReport provides the workflow and the printable sheet, never the insurance language.
Your company's own acknowledgement wording — printed word for word in the shaded acknowledgement block on the sign-off sheet, above the decision lines.

Step 1 — Print the LIH sign-off sheet

The sheet carries your company's terms exactly as loaded above, the four tool classes with empty YES / NO boxes, and the signature block. Download it and print it — the Company Man checks the boxes and signs by hand.

Step 2 — The Company Man signs the paper sheet

There is nothing to record in the app. Print the sheet from Step 1, the Company Man checks YES or NO for each tool class and signs it by hand, and the signed paper is filed with the well as the record of decision. This well stays AWAITING LIH in the app — the decision itself lives on the signed paper, not on a screen.

Unit system

Set once here — every view in the platform displays and accepts entry in the system you pick. This is the only unit control in the app.

API (oilfield)

Switching changes how values read and how entry fields take them — the stored numbers never change. Angles stay in degrees in all three systems; money stays in USD in all three systems.

Well information

Enter these well-level facts once. They remain in the current well session and become the identity block for morning reporting, anti-collision, and future exports.

Producing formation or landing objective. Choose a common entry or type the operator's exact name.
Planned build rate through the curve. This is a setup target, not a measured motor yield.
Pad or surface-site name used to group wells and identify offset context.
Surface-hole latitude (decimal degrees). Powers the Field Map — leave blank to keep this well off the map.
Surface-hole longitude (decimal degrees, West is negative).
State-plane grid northing of the surface / kickoff point, as carried in the EDM wellbore record.
State-plane grid easting of the surface / kickoff point. Offset wellhead N/S and E/W are computed as differences of these grid coordinates.
Regional basin. Choose a common entry or type the exact basin name.
Primary trajectory class used for report and QC context. Choose a common entry or type the operator's exact classification.
Regulatory or operator well identifier exactly as issued.
Identifies whether reservation-specific reporting or operating requirements may apply.

TVD datum source

Define the elevation basis once. The anti-collision module must match this TVD datum and KB-height basis across every offset.

Name of the governing datum (the CD_DATUM row marked default in an EDM file).
Elevation at the rig kelly bushing, used as the reference-well TVD datum.
Vertical distance from ground level to the kelly bushing.
Auto-calculated as Rig KB − GL-to-KB when both are entered; always editable for the certified value.

TVD datum checkpoint: These elevations define the reference well's TVD basis. Every offset import must be confirmed against the same datum before anti-collision calculations can run.

Well plan magnetics

Define the well's north reference and magnetic corrections. Values remain editable because the approved MWD program and operator survey standard are authoritative.

Expected geomagnetic inclination at the well location and survey date.
Auto-fill from the geomagnetic model when location and date are available; the user can always override it with the approved MWD value.
Expected total magnetic-field strength at the well location. Enter the MWD program value in microtesla.
Reference used by the plan and reference survey. This choice flows directly into the anti-collision north checkpoint.
Retained for plan traceability; required only when Grid north is selected.
Correction actually programmed in the survey tool; retain the sign exactly as approved.

Plan import

Paste the directional plan export (a Well Seeker–style station listing works well). Columns are detected automatically — MD, INC, AZI are the must-haves; TVD, N/S, E/W, VS, DLS and the point note are welcome additions; everything else is ignored.

no plan
Header block lines before the column header (company, well, design lines) are skipped automatically. Key points — KOP, landing, TD — come from the note column. TXT, CSV, TSV, XLSX, XLSM and PDF files with a text table can be loaded directly; legacy XLS files remain visible so the app can explain the conversion step.

Tie-in point

The certified first-survey anchor. The Survey Editor's positions are built forward from this point, so the actual wellpath sits in the same coordinate frame as the plan.

not entered
Measured depth the tie-in survey was taken at.
True vertical depth at the tie-in.
North(+) / South(−) from surface location.
East(+) / West(−) from surface location.

Assembly (BHA)

Bottom-hole assembly details the steering math needs.

CONVENTIONAL · MUD MOTOR
Set once for this well or run. The full Steer workspace follows this choice.
Footage from the survey sensor to the bit. Auto-fills from the active BHA when one is set active; type over it any time, and reset to auto returns to the active BHA value.
Expected dogleg response while sliding. A typical curve motor runs 9–18 °/100 ft.
Expected build/walk response while rotating with this BHA.
Footage per survey stand on this rig — usually one stand.
Required survey spacing in the curve for this well's jurisdiction. Guidance joints remain independent.
Slides averaged for the learned motor yield.
Whether motor yield is measured as full dogleg or inclination-only.
Stands averaged for the rotary build/turn drift.

Vertical Section Plane (VS Reference)

The vertical plane along the planned well azimuth. All VS distances are measured along this plane — this is a reference frame, not the vertical part of the well.

Azimuth of the vertical-section reference plane, normally taken from the approved plan header.
Foundation status — what Phase 1 carries, and what comes later ▸

Phase 1 is the backbone, not the work

This build carries
Well setup, the plan-import service, the Survey Editor with minimum-curvature engine, the plan-deviation service, shared sign conventions, and the Ouija Board what-if projector.
Ouija Board
The projector tests forward geometry and can translate an accepted curve into a motor-yield slide/rotate proposal. It is a planning aid for qualified DD review, not an automatic rig command.
Steering engines
Vertical, the Ouija Board and Lateral reuse this backbone. The engineering-library tools remain downstream modules.
Morning Report
The six-piece package and branded Morning Email are Step 7 of the drilling workflow, fed by this same Survey Editor, plan and well setup.

Survey Editor

The screening surface for the shared Survey Ledger. Every station — typed on the Surveys/Time Breakdown Sheet, presented by the MWD hand for verification, or accepted from a WITS feed — lands here fully calculated: geometry, plan attitude, directional miss, toolface, build/turn, slide response and 3D distance.

Geosteering — current instruction (read from Geology)

Present-for-verification: the steering record lives in the Geology workspace's steering layer. This panel reads it — it is not a second store. Verify against your surveys before applying.

Geology · steering layer

Loading the current steering instruction…

Wellbore legs

Start a sidetrack deliberately from an exact survey or an interpolated MD. The parent leg remains in the Survey Editor, plots, reports and anti-collision scan.

LEG 01 · ORIGINAL
Tie-on rule: position is auto-filled from the parent traverse and remains editable. Relative position uncertainty for this leg begins at the tie point.

Survey entry & import

Typed surveys have one door: the blank entry row on the Surveys/Time Breakdown Sheet takes MD / INC / AZI and writes this same Survey Ledger. This Editor is the screening surface — the full calculated record below, its corrections, and the acceptance point for surveys arriving from the MWD hand or a WITS feed.

no surveys
Bulk import or verify an existing survey sheet
Any column order, any separator. MD, INC and AZI are the only required columns. Extra pasted values are retained only for verification; the displayed Survey Editor sheet is always recalculated.

WITS Import

WITS records land in staging first — nothing enters the well data until you accept it. Directional survey records (WITS 07 and MWD survey 12) are read with the standard record layout; depth/time records (01 / 02 / 03) stage as drilling-parameter proposals for the Surveys/Time Breakdown Sheet. Accepted surveys write into the same shared survey store as hand-entered surveys, carry their WITS provenance, and re-solve the well. A record that is incomplete, non-numeric, or does not advance past the last station fails loudly with its reason — it can never be accepted.

no records staged
Text in WITS block format (&& … !!) is routed through the WITS parser automatically: records 07 / 12 become survey stations, records 01 / 02 / 03 become parameter proposals. Other listings keep the generic field mapping below.
SourceNo batch received
Staged0
Awaiting review0
Accepted0
Rejected0
Failed0
Last batch received—

File import and the simulated feed are what this prototype does. A live feed connection to a rig EDR is production scope — nothing on this page is connected to a rig.

Interpolate

The full station at any MD in the active leg, on the same minimum-curvature engine as the survey sheet: INC / AZI interpolated on the constant-dogleg arc between the bracketing surveys, so a query at a survey's own MD returns that station exactly. Past the last survey the tool projects the bit on the PTB basis instead of extrapolating. Display only — nothing here is written to the Survey Ledger.

display only

TVDSS, grid coordinates and latitude / longitude read from Well Setup: without a KB elevation, surface grid or surface location entered there, those fields read "not entered" rather than a made-up number.

No surveys yet.

Type the first station on the Surveys/Time Breakdown Sheet, paste a survey sheet above, or to see the engine run on fictional data.

Plan vs actual

For every survey the engine finds the closest point on the plan and decomposes the miss into the language the rig uses: above or below, right or left.

Nothing to compare yet.

Plan-vs-actual needs an imported plan and imported surveys. to see it work.

Live bit tracking

The 3D wellbore grows as surveys are accepted into the Survey Editor, keeping the current bit position and the engineered plan together in one mission-control view.

Active wellbore

Each newly accepted station pulses green while the bit advances along the surveyed trajectory.

Drag to orbit · Shift-drag or right-drag to pan · Wheel to zoom
Accepted surveysDirectional planOffset wellsNew station check

Offset separation vs MD

True 3D closest-approach distance from each accepted survey to the nearest selected offset well. Dashed lines mark your WATCH and ALARM limits from Anti-Collision.

—
Distances are true 3D closest approach to the offset trajectory, not the same-TVD screen used in Anti-Collision Tier 1. Offsets are managed in the .

Verification

The proof step. Every pasted TVD, N/S, E/W, VS and DLS is checked against the tie-in-anchored value recomputed from MD, INC and AZI. Position disagreements are flagged for DD review; pasted coordinates never silently replace the engine traverse.

No comparison available.

Verification needs surveys with pasted computed values (TVD, VS, DLS) alongside the recomputed engine values. to see it.

The method being verified

Engineer-grade statement of exactly what the engine computes and which conventions it keeps.

Minimum curvature (per survey interval)

β = acos( cos i₁·cos i₂ + sin i₁·sin i₂·cos(az₂ − az₁) )  (acos argument clamped to [−1, 1]) RF = (2/β)·tan(β/2)  (β → 0 ⇒ RF → 1) ΔTVD = (ΔMD/2)·(cos i₁ + cos i₂)·RF ΔN = (ΔMD/2)·(sin i₁·cos az₁ + sin i₂·cos az₂)·RF ΔE = (ΔMD/2)·(sin i₁·sin az₁ + sin i₂·sin az₂)·RF

Rates

DLS = (β in degrees / ΔMD) × 100  °/100 ft Build rate = (i₂ − i₁) / ΔMD × 100  °/100 ft Turn rate = wrap(az₂ − az₁) / ΔMD × 100  °/100 ft, wrap(x) = MOD(x + 540, 360) − 180

Vertical section & plan deviation

VS = N·cos(vsAzi) + E·sin(vsAzi)  ft Closest point on plan: dense plan arc (min-curvature subdivided ≤ 25 ft) → survey station projected to the exact nearest point on that arc → plan MD, tangent, and the miss vector. Miss frame: high-side h = component of up orthogonal to the plan tangent; above(+) = miss·h;  right(+) = miss·(t × h), looking downhole.

Conventions kept by every module

Above(+)/below(−)
Position relative to plan along the high-side direction. A station above plan reads positive.
Right(+)/left(−)
Position relative to plan across the hole, looking downhole. Positive reads right.
N(+)/S(−), E(+)/W(−)
Standard map signs from the surface location.
Toolface (for later phases)
0 = high side, + right. Magnetic-vs-gravity switch at 3° inclination (blank = high side).
Degrees ↔ radians
Conversions explicit at every trig call; acos arguments clamped; azimuth differences wrapped through ±180°.

Vertical

Step 1 of the steering workflow. The latest accepted survey projects to the bit, checks the hold miss first, then calculates the line-to-KOP call.

Vertical needs a marked KOP, a survey reference, and Sensor-to-bit.

Import the plan and surveys in the foundation steps, then enter the active BHA's Sensor-to-bit in Well Setup.

Ouija Board

Multi-nudge projection from the latest accepted survey to the selected landing target.

no survey reference

The Ouija Board needs a plan and a survey reference.

Import both in the foundation steps, or .

Build (Curve)

Step 3 of the steering workflow. The NWE AI Build Calc v15 direction-arc call takes the current Survey Editor bit to the plan landing attitude and TVD.

AI explains.Math decides the steering call.

Build needs a marked landing point and a current survey or bit position.

Import the shared plan and Survey Editor first. Sensor-to-bit and slide yield come from Well Setup.

Slide Predictor

Trend the Survey Editor’s recent motor-yield response and look ahead for the first inclination departure from plan.

Advisory only — AI talks, math decides.This projection trends recent motor yields; it does not steer the well. The Survey Editor and the DD's steering call are authoritative.

Prediction parameters

Every value is editable for the working look-ahead. One-click reset returns to the predictor default.

Survey Editor read-only
default · 8 surveys
default · 1,000 ft
default · 0.5°

Accept surveys in the Survey Editor to start the predictor.

Lateral

Step 4 of the steering workflow. Regulate inclination against the geologist's living TVD line; left/right versus plan stays reference-only.

Next Steering Call — detail

The steering call solved from the latest accepted survey, projected through PTB from the Sensor Offsets register, sized on the learned motor yield, and verified by Project Ahead against the current geology call.

waiting

0-VS Quick Calculator

One-off geology check using the same target-line and asymmetric-window math as the living table.

waiting
example value
geologist value · entered as sent
waiting for survey
waiting for survey
example value
example value
Target TVD = 0-VS TVD + tan(90° − Hold INC) × survey VS

Lateral needs a landing point, a survey reference, Sensor-to-bit, and a geology row.

Import the shared plan and surveys first. Then enter only the geologist's target update and correction distance here.

Anti-Collision

Every offset well on the pad is scanned against the reference survey through the projected bit. The Verified Scan below is a true Closest Approach 3D scan on the minimum-curvature arc, with separation computed from propagated ISCWSA/OWSG uncertainty ellipsoids — and only where a tool program's coefficients have been entered from the published model documentation. The older same-TVD presentation further down is fenced as a screening-only screen and never feeds a separation factor.

Tier 1 · same-TVD C2C — SCREENING ONLY

Always on. Horizontal centre-to-centre distance at matching TVD, with adjustable WATCH and ALARM thresholds in feet. A screening presentation, fenced below — not the verified scan.

Verified Scan · Closest Approach 3D

True 3D closest approach on the arc, pedal-curve separation from propagated ellipsoids. ES and SF compute only for pairs whose tool programs are entered from the published ISCWSA/OWSG documentation; every other pair shows geometry and reads separation not computed — model not entered.

Professional use — decision support only. Decision-support tool. Verify against the operator’s approved anti-collision program and official surveys before acting on these results. This module presents calculations for a professional’s review; it does not sign off on a well for drilling — that decision belongs to the operator’s approved anti-collision program and official surveys. Missing or unverified data is flagged NOT CHECKED rather than passed over.

Tool Programs & Reference Data

Instrument Performance Models enter this platform only from their published ISCWSA/OWSG documentation, coefficients typed in below with the source cited. A model whose coefficients are not entered is shown plainly as model not entered wherever tool programs are displayed — it is never filled with invented numbers, and no separation is computed from it. Tool programs are segmented by run / leg and fed by the platform's own records: the survey ledger, BHA records and Sensor Offsets.

ISCWSA / OWSG

Survey program — spans and their tool programs

Geomagnetic reference — run data

Instrument Performance Model library

Verified Scan — Closest Approach 3D

Closest approach evaluated at the reference survey stations plus a configurable grid, with every inserted point computed on the minimum-curvature arc between stations, never on a straightened wellbore. Separation uses the pedal-curve error surface: ES (Between Ellipses) = C2C − Minimum Separation, SF = C2C / Minimum Separation, at the selected output sigma. Warning levels are operator policy: the thresholds below are configurable and ship with the stated defaults, including the 20 ft centre-to-centre magnetic-interference warning from the reference program. No level is a clearance.

Inserted evaluation points between survey stations. Default 100 ft.
Approaches beyond this distance are not evaluated. Starting default 2,539.41 ft, operator adjustable.
Warnings are evaluated at the output sigma. Default 2.00 σ.
Pairs at or below this SF are flagged, and MASD is stated at this level. Default 1.50.
Reference program setting: 20 ft centre-to-centre. Operator adjustable.
On the Surveys/Time Breakdown Sheet, a survey row turns red — with an alert strip above the sheet — when a confirmed offset comes inside this centre-to-centre distance. Default 50 ft.
Subtracts both wells' radii from the Casing workspace records where they exist; where a record is missing the diameter-aware SF reads not computed and names the missing record.
SCREENING PRESENTATION — screening only. Everything below this line is the Tier 1 same-TVD screen and its charts: horizontal centre-to-centre at matching TVD, no ellipsoids, no separation factor. It is fenced off from the Verified Scan above and must not be read as one. This module presents calculations for a professional’s review; it does not sign off on a well for drilling — that decision belongs to the operator’s approved anti-collision program and official surveys.

Load a reference survey to run anti-collision.

Use the fictional demo well, then return here to inspect the sample offsets.

Offset Builder — build offsets in the shared register

Build and maintain offset wells here, on the DD side, in the one shared offset register — the same register the scan above, the Planner Preview and the 3D scene read. An offset built here is scanned against the live well with no re-entry, and register edits made in Well Planning show here. Stations are entered as MD / INC / AZI only; TVD, N/S, E/W, VS and DLS are computed from the offset's own wellhead by the shared minimum-curvature engine. Anti-collision stays decision support: this panel adds wells to the register, it does not clear any well.

0 offsets
Directional Drilling

BHA Builder & Tool Inventory

Part of the Directional Drilling workspace. The BHA is assembled bit-up from the one shared Tool Inventory record — the same On Location / Shipped Off ledgers as the Tool Inventory tab in this workspace, worked from either door. Mark one BHA active and its number and length feed the Morning Report and Engineering, and its sensor-to-bit fills Well Setup for the steering projection — the same record, typed once.

In-session prototype. Inventory and saved BHAs live for this session only and clear on refresh or when the tab closes — the same session rule as the rest of this demo. In production the inventory persists across wells. All tools below are fictional demo stock.
1One shared inventory

The Tool Inventory below is the Tool Inventory tab's record — same ledgers, same fields, same movement history. Ship, return or add a tool here and the Tool Inventory tab shows it, and the other way around.

2Assemble bit-up

Pick from the On Location ledger into the working BHA. Length, weight, size and serial come from the tool's inventory record, never retyped — and a tool in the BHA stands In Hole on that record until it comes out.

3Save by BHA number

Each run's assembly is saved under its BHA number so trips and rebuilds keep their own record.

4Mark one active

The active BHA's number lands on the Morning Report, its length feeds Engineering's drill-string makeup, and its sensor-to-bit fills Well Setup as an editable auto value — so the Ouija Board projects from the running assembly.

Add a tool

One record per physical tool, on the shared Tool Inventory record — the same fields as the Tool Inventory tab (Tool · Qty · Part # · Serial / Asset # · Size / Spec · Asset Type · Product Line · Resource Group · Owner · Status · BHA # · On Job · Location Note). The BHA dimensions below ride the same record: they are what the BHA Builder reads, so a buildable tool is never retyped into the assembly.

BHA dimensions (on the same record) — fill these in and the tool can be picked into a BHA with its length, weight and size carried over. Table-priced tools (collars, stabilizers, jars, subs) price from the Weights tables by OD × ID; bits, motors and sondes carry their entered weight.

Component type first, then a printed row: drillpipe reads §2 (with §1 tool-joint dimensions), collars and kellys read §3. The printed row becomes the component's starting values — every filled field stays yours to override, with the library value beside it and one click back.

On-location ledger — the shared record

Every tool physically on location, one row per line item — the same ledger as the Tool Inventory page, not a copy. “Add to BHA” drops a dimensioned tool into the working assembly in the Builder and marks it In Hole here; taking it out of the BHA brings it back.

0 tools
Surveys/Time Breakdown Sheet
5am–5am
Calculations ▾
Show calculations

Display only — every calculation keeps running underneath and totals never change. The same selection drives the Survey Editor. The record columns (row, Survey, Activity, Date, times, Hours and depths) always show.

Correction Run

Quick Scan

Drilling parameter averages — from this sheet's Slide / Rotate intervals · WITS / EDR auto-fill ready

Pipe Tally

One tally per run, kept on the DD side. Totals build joint by joint on the run's assembly snapshot; Survey Depth reads off PTB (Probe To Bit). There are no INC / AZI columns on a tally — attitude lives on the survey rows.

—

Run Summary

Computed from the Time Breakdown for every run on the well — never typed. The same rollup prints in the End-of-Well run history.

computed

Job / Ticket — commercial header

The commercial layer behind the DD reports. Its ticket / job identity seeds the Daily Revenue report header; the revenue line items and totals are unchanged by it.

fictional demo values

Connection Analysis

The drilled footage on the Surveys/Time Breakdown Sheet, grouped by connection (stand). A connection runs from one connection point on the sheet — a Survey & Connection or Connection entry — to the next; every number below is aggregated from those same entries and the Survey Editor's calculated stations, and every row names the source entries it came from. Nothing is typed here and nothing is estimated: slide feet + rotate feet make up the drilled footage of each run, connection by connection.

Loading the connection analysis…

Slide Analysis

One row per slide interval on the Surveys/Time Breakdown Sheet, scored against the surveys that bracket it. Slide Seen is the length of the interval lying at or above the deepest surveyed depth; Slide Ahead is the length drilled but not yet surveyed. A slide is scored only when its full length is seen — a partially seen slide shows its seen / ahead split and is labelled not yet scored, never scored on a projection. Motor yield is the achieved dogleg across the slide divided by its length × 100 (°/100 ft): an observed outcome of the slide as drilled, not a motor rating or capability.

Loading the slide analysis…

Checks · audit witnesses

The Wave C witnesses for these two screens and the Directional Difficulty Index, recomputed live — the published training worked example, the footage conservation identity on the loaded well, the standing guide fixture, and the Oag & Williams hand case. A disagreement means the aggregation has been broken.

running
Directional Drilling

Crew Time Sheet

Accountability for the days and jobs they were here and what jobs they worked on. Who held which seat, on which days, on this job — confirmed on the grid, then carried into each person's own weekly timesheet and expenses.

Signed in: —
Your packet is yours alone. Other people's packets do not open here.
The timesheet and expenses below form one weekly packet for this person and week.
—
Confirmed Unconfirmed Travel Standby Off / Not on location Click a date header to select the day · click one of your own bars to select it — every other person's bars are locked on your sign-in

Add a person to a seat

Roster names carry in from the morning report crew fields (Day DD / Night DD) where the well record has them; every value here is editable. Names on this sheet are the record — a span is a person, a seat, and a date range.

new span

Weekly timesheet

One row per confirmed day on the schedule grid for the selected person and week. Each row carries the tour times of the person's seat: day tour 06:00–18:00, night tour 18:00–06:00 — the row date is the tour's start date, and a night tour ends the next morning. There is no break out here: hours are end − start across the tour, 12.00 per tour. Start and end stay editable on every row, and hours recompute when you edit, including across midnight. Unconfirmed days do not appear here until you confirm them on the schedule grid — each person confirms only their own days, and nobody can confirm or change another person's time.

—
DateStartEndHoursJobWellRigStatusActivityPeg type
Total Qty (days)
0
Total hours
0.00
Week ending
—

Expenses — same week, same packet

Expense lines for the selected person and week. Line total is unit price × qty, computed live. Submitting the week submits the timesheet and these expenses together.

—
DateExpense typeDescriptionUnit priceQtyLine totalJob
Weekly expense total
$0.00

Crew Checks · audit witnesses

Every total on this sheet is recomputed from the schedule grid itself. A disagreement is shown with both numbers — nothing is ever adjusted silently. Personal hours and expenses are never shown here; checks speak in person-days and packet counts only.

running

Per-person totals — from the grid

Days worked, nights, remote days, travel and standby, and each person's first and last day on this job. Counted from the spans above, confirmed and unconfirmed shown apart where it matters.

PersonSeats heldDays workedNightsRemote daysTravelStandbyFirst dayLast day

Revenue reconciliation

Billable person-days from the grid against the Daily Revenue sheet's per-day lines for the same window. Edit the revenue figure to match the revenue sheet if it has moved; reset returns to the live read. Neither side ever adjusts the other.

Live read from Daily Costs

Change log

Grid edits made after a span is confirmed, confirmations, and packet submit / unsubmit events — each stamped with the signed-in user who made it.

    End of Well — personnel record

    This block publishes into section 13 of the End-of-Well Report: who ran this well, the seat each person held, and their days on the job.

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    NWE WELLREPORT
    Northwest Engineering
    EngineerEngineering & Well ControlStandalone technical workspace
    Workbook-verified engineering

    Engineering & Well Control

    Drill-string makeup, push-pipe sizing, soft-string torque & drag, eight land well-control toolsets, and technical lookups ported from NWE workbooks. Blue cells are inputs; every other value is computed.

    AI explains.Math decides.

    Calculating Drill Pipe Needed For The Lateral

    NWE Lateral DP Calculator · one formula, three inputs.

    TD − KOP − BHA
    from plan
    −
    from plan
    −
    active BHA record
    Drill pipe required—Waiting for TD, KOP and BHA length.

    Workbook formula: drill_pipe_ft = TD − KOP − BHA_length

    Live inputs0 Survey Editor surveysSoft-string model integrated from the bit up, one interval per survey station. Top interval: INC 0° at surface, AZI from the first survey.
    model ready

    Model inputs

    Auto-filled values remain editable and can be reset to their source.

    latest survey
    Common starting point 0.15–0.25
    Common starting point 0.20–0.30 OBM, 0.25–0.40 WBM / brine

    Drill string · bit up

    Enter each section from the bit up. The last (top) section runs to surface — its length is the bit depth minus the sections below it, figured automatically.

    Tension profile

    Tension at the top of each survey interval, block weight included.

    Torque profile

    Off-bottom rotating torque at the top of each survey interval.

    Open-hole friction sensitivity

    Nine workbook steps; cased-hole FF is held.

    Apparent friction factor

    Rig readings are corrected by the rig-vs-model rotating offset before interpolation.

    PU apparent OH FF—
    SO apparent OH FF—
    Enter rig readings to back-calculate.
    Model method & assumptions

    Soft-string torque & drag (Johancsik, Friesen & Dawson, 1984) in its 3-D vector form, ported number-for-number from the NWE Hook Load workbook. The string is cut at every survey station and integrated from the bit up; bit off bottom (0 lb at the bit), pumps off — no hydraulic lift or viscous drag. Buoyancy factor = 1 − MW ÷ 65.5 (steel, same mud inside and out). One friction factor per hole section, set by where each interval midpoint sits against the casing shoe; past the last survey the model projects straight ahead at the last INC / AZI. Soft string: pipe stiffness is ignored, and no extra drag from buckling is modeled — if slack-off puts a section in heavy compression, the rig will read lighter than the model. Calculations for a professional's review.

    RIH Fill-Up

    Running-in-hole fill-up volumes from the NWE data book: capacity = ID² ÷ 1029.4, open-end displacement = (OD² − ID²) ÷ 1029.4, closed-end displacement = OD² ÷ 1029.4. Fill-up volumes apply when a float is installed. Calculations for a professional's review.

    Data book
    from T&D inputs
    Push Pipe · HWDP sizingReference string finds the buckle zone; typed string checks the field tally.Fictional defaults · 220-row closed-form soft-string model · recalculates on every edit
    calculating

    Model inputs

    Well path, drilling conditions, agitator influence, typed HWDP, and design criteria. Every field is editable; ↺ restores its fictional default.

    Verify placeholders

    String builder · bit up

    BHA has priority, then agitator, then HWDP, then drill pipe. OD and weight values are placeholders — replace with your tally/value.

    9 component rows
    BHA rows may be added or removed; DP, HWDP, and agitator rows remain fixed.
    BHA stack length—

    1 · Where the bit is

    Closed-form KOP and build-rate geometry.

    2 · DP-alone buckling zone

    Reference string forces DP everywhere and excludes helical contact.

    Scott's placement ruleHWDP goes above the KOP.

    3 · Typed string check

    HWDP as typed

    4 · Curve clearance

    The HWDP top must remain above the KOP placement and clear of the curve in the active model.

    5 · Overall verdictCalculating
    Typed string + curve-clearance result

    Workbook self-checks

    Independent equalities carried from Checks B5, B8, B9, and B10.

    Method & limits

    Use the result as an engineering sizing screen.

    Soft-string model with straight-hole Dawson–Paslay buckling loads (conservative in the curve), one friction value per hole section and a simple agitator zone. It does not model hole cleaning, cuttings beds, or rotating torque. Use it for sizing, then confirm with your torque and drag program.

    Placeholders matter: friction factor, WOB, agitator effect, pipe OD and pipe weight all change the answer. Replace every tagged value before relying on the result.
    Tier 1 · Primary controlKill sheet · tolerance · ECD
    Tier 2 · Contingency & fluidsVolumetric · stripping · pumps · mud
    Tier 3 · ReferenceSpecifications · rules · conversions

    Technical data book lookups

    Drill pipe, HWDP & collars, tubing, casing, BOP & valves — transcribed from the workbook.

    Workbook corrections in force15" hole capacity 0.2186 bbl/ft7 × 8 triplex 4.0008 gal/stk16.3 ppg gradient 0.8476 psi/ft

    Well Control Field Record · E1–E22

    The job record beside the workbook calculators: the IADC pre-recorded data set, the kill sheet and its calculation chain, the non-circulating method logs, BOP & accumulator record, hydraulics, mud & pumps, the spec library, and a dormant MPD log. Structures follow the IADC WellCAP worksheet family (Driller's / Wait-and-Weight / Bullheading) and API Standard 53 test practice. Every value is labeled Computed (inputs + formula on the sheet), Entered, Entered · Model, or Estimate — never mixed. The loaded well and its kick are fictional demo data. Calculations for a professional's review; the operator's approved well control program remains authoritative.

    How to read a value:ComputedEnteredEntered · ModelEstimate· Sources: IADC Driller's Method worksheet · DrillingManual kill-sheet walkthrough · DrillingFormulas kick tolerance
    E11 stays dormant unless the well is flagged. MPD values are entered readings only — no live feed is claimed.

    E1 · Well Control Pre-Record

    The IADC pre-recorded data set, kept current before any kick: well geometry, casing and liners, the shoe test, capacities, pump outputs and slow-circulating rates. Capacities compute from the ID² ÷ 1029.4 family; SCR pressures are measured values, entered — never computed.

    IADC worksheet structure

    E2 · Kill Sheet

    The kick record and the witness-checkable chain: kill mud weight (rounded UP a tenth), MAMD and MAASP (rounded DOWN), ICP, FCP, strokes and the linear step-down schedule. Method selector: Driller's or Wait-and-Weight. Kill circulation rate guidance on the IADC walkthrough is 2–5 bbl/min for most cases.

    kill sheet

    E3 · Kick Tolerance

    A planning record, not a live kill-sheet value: the maximum gas volume that can be circulated out without exceeding the weakest formation, assumed at the previous casing shoe. Every input — and the single-bubble model assumption — is stored and displayed with the number.

    Planning record

    E4 · Volumetric & Lubricate-and-Bleed Log

    For when circulation is impossible. The shoe margin, safety factor and pressure increment are decided before the first step; each step is then logged as executed — time, casing pressure before / target / after, and the mud increment bled on a calibrated tank.

    Step log

    E5 · Bullheading Plan

    Initial and final maximum surface pressures are computed and checked against fracture, burst and tree working pressure before anything is pumped — the pressure-vs-volume limit table is prepared in advance, and the decision rationale is part of the record.

    Plan + limits

    E6 · Stripping / Snubbing Log

    Pipe in the hole under pressure: closed-end displacement per stand, psi per barrel in the annulus, safety and working margins in both psi and barrels, a per-stand bleed log, dry/wet pressure drop per foot (IADC formulas), and the snub-force balance.

    Step log

    E7 · BOP & Accumulator Record

    The stack as rigged up, one unified pressure-test log on the API Standard 53 initial-test basis, and the accumulator check: usable volume per bottle computed by the API method structure with the Boyle school figure shown, against the close-open-close demand of the stack as rigged.

    API Standard 53 basis

    E8 · Hydraulics & ECD Record

    ECD computes from the identity MW + APL ÷ (0.052 × TVD) — the annular pressure loss itself is entered and labeled by source (modelled or PWD-measured; no live feed is claimed). Standpipe pressure is recorded as a breakdown, surge/swab as entered model values.

    APL entered · ECD computed

    E9 · Mud & Pumps Daily Record

    Pump outputs compute per stroke with the efficiency used shown, and the trip-tank record stays here — pumps and the trip tank are the DD's plant. The fluids record — the daily mud block (API RP 13B), pit inventory, additions & losses and the barite weight-up — is owned by the Mud Engineer workspace; below, those blocks render as labeled read-only pulls from it, with source and check time. One home per fact: edit the mud record there, read it here.

    Daily record

    E10 · Spec Library

    Reference data, entered from published tables — never derived on the fly. Tubular published strengths (collapse / burst / tensile) are entered values to verify against API 5CT or the manufacturer before use. Bit nozzle hydraulics compute from the entered nozzle set, rate and mud weight.

    Reference · verify before use

    E11 · MPD Log

    Managed pressure drilling record per API RP 92M: the Influx Management Envelope limits, the Operations Matrix, surface backpressure target vs actual, choke and RCD status, the connection backpressure schedule, and a categorised influx log. All values entered — this sheet records MPD; it does not model it.

    API RP 92M record

    E12 · Rheology Suite (F8)

    The full Fann rheogram carried on the mud record — eight speeds plus the 10-second / 10-minute gels — with the API RP 13B-1 / 13D model fits: Bingham Plastic, Power Law, and Herschel-Bulkley by the measurement method and by numerical least squares. One rheology record feeds E13 and E14; nothing is re-typed there. Viscometer conversions are pinned: shear stress τ = 1.067 × dial reading (lbf/100 ft²), shear rate γ = 1.7023 × RPM (s⁻¹) — the API factors, never the legacy 1.066 / 1.703 roundings in the same code path.

    API RP 13B-1 / 13D §5.2

    E13 · Hydraulics (F11)

    The API RP 13D subset: segment annular pressure losses (Bingham slot form), ECD, bit pressure drop, and inside-string pipe losses, swept across flow rates. Rheology comes from the E12 record — the model used is printed beside every pressure. Bit nozzles use ΔP = MW × Q² ÷ (12,031 × Cd² × TFA²) with the discharge coefficient applied once, explicitly — the 10,858-family constants in other books are the same formula with Cd ≈ 0.95 already folded in, and mixing the two understates or overstates the drop by about 10%.

    API RP 13D §7 subset

    E14 · Surge & Swab (F9) · Hole-Cleaning Screen (F10)

    Surge and swab by the Burkhardt / API RP 13D §8 effective-velocity method at peak trip speed, and the API RP 13D §9 vertical hole-cleaning screen. The hole-cleaning panel is a screening tool only — it does not predict cuttings bed height, and no bed-height number appears anywhere on it.

    API RP 13D §8 / §9

    E15 · Buckling — Sinusoidal / Helical Thresholds (F2)

    Sinusoidal onset by Dawson & Paslay (1984) — there is no API RP for buckling onset. The helical threshold is a named, selectable factor times the sinusoidal load because the published literature does not agree on one: Chen, Lin & Cheatham (1990) give 2.00×, the Wicks et al. length-independent limit is √2 ≈ 1.41×, and Miska et al. (1996) put the transition in a band 1.875–2.83×. The factor and its name print on every output line — never a silent factor. Weight basis is stated on the sheet: Dawson's own published example reconciles with air weight, not buoyed weight, and the basis selector says which one is in use. Onset is not failure: the operating limits are fatigue if the string is rotated while buckled (E18) and lockup if sliding (E16/E17).

    Dawson & Paslay 1984

    E16 · Multi-Operation Torque & Drag (F3)

    The Johancsik, Friesen & Dawson (IADC/SPE 11380) soft-string model, marched segment by segment from the bit: pickup, slack-off, rotating and sliding over the survey path, with a friction-factor sensitivity sweep. This sheet carries its own case (survey path + string) so the published worked example can be loaded and reproduced exactly; the workbook T&D in the Engineering pane is a separate verification case and is untouched. Convention, printed once and used throughout: inclination and the segment weight are evaluated at the segment average, the axial force in the normal-force equation is the force at the segment bottom, entered segments are subdivided to at most 50 ft for the march, and rotating drops the axial friction term (rotation redirects friction circumferentially). Soft string neglects pipe stiffness — it understates loads in tight holes, severe local doglegs and stiff BHAs.

    Johancsik soft-string

    E17 · Apparent WOB / Overpull Margins (F5)

    No new physics: this sheet reads the E16 force profile at its two boundaries, plus API RP 7G tensile design for the overpull check. Apparent (surface-indicated) WOB is the rotating-off-bottom hookload minus the drilling hookload; actual WOB is found by inversion — the bit force is iterated until the computed surface hookload matches the measured one. Margin of overpull: MOP = 0.90 × yield × section area − the highest pickup tension in that section, checked at every section with that section's own dimensions. The combined tension-plus-torque warning prints when surface torque is high, because the pure-tension MOP overstates headroom there.

    F3 profile + API RP 7G

    E18 · Side Forces & Fatigue Screening (F4)

    Side (normal) forces come off the same E16 soft-string path — total per segment and per unit length, the White & Dawson usage. Fatigue is the Lubinski (1961) dogleg bending-stress screen: σ_b = 218 × OD × DLS against the published in-mud endurance anchors, at zero tension — a screening tool, labelled as such. Casing wear is not calculated on this sheet: the wear panel below states the gate plainly instead of printing a number.

    Screening

    E19 · BHA Analysis — Screening Subset (F6)

    Screening tool. Commercial BHA analysis is finite-element work — multi-stabilizer force/displacement with wall contact, formation anisotropy, walk tendency and dynamics — and none of that is claimed here. This sheet is the closed-form screening subset from Samuel, Formulas and Calculations, Ch. 6–7 and standard beam statics: three-point build rate for a motor assembly, pendulum side force, sag between stabilizers, stretch, free point, and twist. Two-dimensional, static, linear-elastic, idealised isotropic bit/formation. Directional tendency beyond geometric build rate, vibration, whirl and stick-slip are outside this screen.

    Screening — not FE

    E20 · Centralizer Standoff & Placement (F16)

    Standoff by ISO 10427-2 (= ANSI/API RP 10D-2), performance data per API Spec 10D / ISO 10427-1: concentric clearance, mid-span sag in a straight inclined hole (§4.4.2, no tension), lateral load per centralizer, and the spacing that meets a target the user sets. ISO 10427-2 §4.1 states there is no recommendation or requirement for a specific standoff ratio — nothing on this sheet prints one. The tension and dogleg beam-column cases (§4.4.3–4.4.5) are not computed here: their typesetting in the open text is garbled, and they wait for a licensed copy of the RP rather than ship on a reconstruction.

    ISO 10427-2 / API RP 10D-2

    E21 · Jar Placement (F17)

    Placement only. There is no API RP for jar placement — neighbouring standards (API RP 7G, Spec 7-1) are not placement methods. The basis here is the published placement literature (Schlumberger Oilfield Review, Spring 2012; Samuel, Formulas and Calculations, Ch. 7) and per-tool vendor data, entered and labelled: neutral-point roadmap, weights above and below the jar in air and in mud, hammer-weight and transition-zone rules, and pump-open force. Jar impact force is not calculated anywhere on this sheet — the exclusion is stated on the sheet itself, in place of any impact number.

    Placement — no impact model

    E22 · Cementing Hydraulics (F18)

    The E13 annular-loss machinery (API RP 13D subset) applied to a tracked multi-fluid train — mud, wash, lead and tail slurries, displacement fluid — interfaces followed by pumped volume, hydrostatics balanced inside against annulus (manometer), surface pressure and shoe ECD stage by stage. Practice frame: API STD 65-2. The free-fall (U-tube) caveat is printed where it applies, on the sheet, not buried. No published full cement-job pressure-versus-time worked example with a numeric ECD trace was found in the open literature — stated plainly on the sheet; the witnesses are the hydrostatic leg and the F11-verified friction leg, reproduced separately.

    API RP 13D extension · STD 65-2 frame

    Checks · audit witnesses

    Each line recomputes a published worked example live from its pinned inputs and compares against the published result. These are the verification test cases for the E1–E22 calculation chain, including the Wave B witnesses — a disagreement means a formula has been broken.

    running

    Tubular Library — printed reference register

    Engineering reference data: the printed tubular tables, carried verbatim — every row holds its printed values only, with the source's own dashes and blanks preserved as blanks. Read-only browse and search by section, size, and weight. Nothing in the register is editable in place; where two printed tables give different values for the same connection, each table keeps its own printed values. The Casing Program picks (C1–C8) read the §5 casing dimensions and §6-D capacities from this register, and the Cementing capacity reads (K3/K5/K6) read §6 from this register.

    Reference data · read-only
    Held out of this register: casing performance properties by grade, the make-up torque guideline tables, composite casing, and all vendor / proprietary connection tables are not yet certified for inclusion. This register ships dimensions and capacities only.

    In the §3 torque matrix, * marks the source's minimum make-up torque values. In §2, torque suffixes are the source's own markers: p = pin limited yield, b = box limited yield; a † marks a connection printed once, vertically centered on its block in the source.

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    CompleteCompletions EngineeringNine linked engineering sheets
    Complete it · deterministic workbook math

    Completions Engineering

    Pipe ratings, volumes, kill planning, tubing movement, deviated buckling, load cases, and wireline depth correction share one calculation chain. All demo data is fictional.

    Calculation state9 sheets liveAPI 5C3 checks: calculating

    Inputs

    Initial is the day the tubing is landed; final is the operation being checked. Defaults are fictional and every entered value can be overridden or reset.

    Pressure gauge psi · depth from KB

    Well & tubulars

    Pipe properties auto-fill from the 42-row API table.

    Enter from the packer specification.

    Fluids, pressure & temperature

    Initial and final conditions at the selected operation.

    Material & packer

    Enter from packer specification.
    Enter from packer specification.

    Design factors

    Editable company-standard inputs, not hidden constants.

    Confirm all highlighted values against the packer program, operator standard, and connection manufacturer before operational use.

    Pipe Table

    42 API 5CT size-and-weight rows. Burst uses 87.5% wall; collapse uses the complete API 5C3 yield, plastic, transition, and elastic region engine.

    42 rows

    Plain-end ratings

    Connection strength is not included—use the manufacturer's value.

    Volumes & Pump-down

    Up to eight inside-pipe sections and eight annulus sections, with open- and closed-end displacement and volume-to-depth.

    ID² ÷ 1029.4

    Inside-pipe sections

    Annulus sections

    Pump inputs & results

    Hydrostatic & Kill

    Kill density, fracture ceiling, limiting surface pressure, bullhead and circulation volumes.

    Well-control inputs

    Verify from the approved program.

    Pressure & kill answer

    Tubing Movement

    Vertical-well Lubinski / Hammerlindl piston, ballooning, temperature, and helical buckling effects. Free packer reports length change; fixed packer reports force.

    Geometry & condition changes

    Movement / force answer

    Vertical model assumptions: constant tubing size and weight; pressures at TVD. Friction, deviated-well bending, post-landing slack-off/pull, and fixed-case buckling iteration are excluded.

    Deviated Tubing

    Section-by-section walk-up from the packer. Compression is positive. Sinusoidal and helical thresholds follow each section's average hole angle.

    Full torque & drag required for lateral landing

    Walk-up settings

    Verify for the actual fluids and materials.

    Trajectory sections · surface to packer

    Up to 12 contiguous sections; final force is walked upward from the last row.

    Deviated movement answer

    Ratings & Loads

    Plain-end API 5C3 tubing and casing ratings checked against surface and packer load cases, including Lamé stresses and von Mises triaxial stress.

    Load cases

    Selected ratings

    Triaxial & axial-adjusted collapse

    Ratings are plain-end pipe only. Connection strength must come from the manufacturer.

    Wireline

    Buoyed tension, elastic stretch, safety factor, and collar-correlated target depth.

    Line & tool inputs

    Blank uses steel-area calculation.
    Enter from the line certificate.

    Stretch answer

    Depth correction

    Checks

    Formula results compared with ten common mill / API Bulletin 5C2 table values rounded to 10 psi and 1,000 lbf.

    running

    API 5C3 regression set

    Release threshold: every rating within 0.5% of the published value.

    Connection strength is intentionally excluded; use the manufacturer's rating.
    Packer bore and limits, design factors, fracture gradient, deviated friction factor, and wireline breaking strength remain visible editable verification inputs.
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    InterveneCoil Tubing EngineeringTwenty linked workbook sheets — engineering + job record
    Coil tubing · engineering + job record

    Coil Tubing Engineering

    String geometry, reel capacity, circulation hydraulics, drag and buckling, API 5C3 ratings, nitrogen, and fatigue share one live calculation chain — and below them, the ten-sheet job record: plan the job, run it, record it, report it, ticket it. The loaded well and both jobs are fictional.

    Calculation state20 sheets liveIndependent checks calculating

    Job record

    One record per CT job on this well · Planning → Equipment → Procedure → Monitoring → Safety

    Inputs

    Every default is editable and has a one-click reset. Highlighted values require job-specific verification.

    Gauge psi · MD ft · density ppg

    Job & CT string

    Size and grade auto-fill the current-wall geometry.

    Measure the worked string; do not guess.

    Fluid & pumping

    Newtonian thin-fluid model only.

    User guide, not a calculated threshold.

    Reel & gooseneck

    Drag & bottom end

    Use a value matched to prior jobs.
    Verify from actual equipment behavior.

    Material & design factors

    New round pipe is assumed. Ovality, wear, and bending cycles reduce real ratings. Confirm grade from the mill certificate.

    CT Table

    44 standard size rows and five grades. All reference values are editable; each row can be reset.

    44 sizes · 5 grades

    Standard sizes

    Minimum yield by grade

    Confirm with the string's mill certificate.

    Reel

    Ideal layer packing, current reel length, string volumes, and displacement.

    Capacity

    Volumes & weight

    Wraps lie in layers. Real capacity is slightly lower than ideal packing; clear layers reserve space at the flange.

    Annulus

    Sections clip automatically to the CT depth. Velocity, Reynolds number, Fanning friction, and cleaning status solve per section.

    Hole sections

    Hydraulics

    Inside-CT friction uses the Srinivasan curved-pipe correction on the reel.

    Newtonian fluids only

    Rate & inside CT

    Pressure chain

    Drag & Buckling

    Bottom-up soft-string recursion in running-in, pulling-out, and stationary modes. Tension is positive; compression is negative.

    Wellbore sections

    Mode results

    Depth correction

    Ratings & Loads

    Barlow internal yield, four-region API 5C3 collapse, torque at yield, and Lamé/von Mises triaxial stress.

    Current-wall ratings

    Load case

    Leave overrides blank to use live calculated values.

    Burst, tension & triaxial

    Nitrogen

    Fill requirement, liquid equivalent, gas-column properties, and delivery time.

    Conditions

    Read from a nitrogen chart.

    Calculated requirement

    Fatigue

    Exact bend geometry with a supplier-data life curve and Miner's-rule job log.

    SCREENING ONLY

    Life curve

    All six constants are explicit placeholders.

    Only YES unlocks a qualified result label.

    Bending strain

    Job log

    One row per job or run.

    Checks

    Six independent identities verify capacities, weight, packing, gas law, and hydrostatics.

    running
    These identities do not validate the drag recursion, operational inputs, or fatigue supplier curve. Verify before operational use.

    Job & Plan

    Planning: the operator planning inputs become the job program. Limits are hard stops for the run log — exceed one and the job record flags it.

    plan

    String Record

    Equipment: the string's permanent record — taper map, per-segment fatigue, inspection. Fatigue is tracked per segment, never as one string number. This sheet is the string's home; other sheets read it silently.

    string

    Unit & BHA

    Equipment: the unit record and the BHA as run, top to bottom. This sheet is the unit's home; the report and ticket read it silently.

    unit

    Pressure Control & Tests

    Safety: the stack as rigged up, one unified pressure-test log, and pull tests on schedule — every 1,000 ft, every 500 ft at 60° inclination or more.

    tests

    Run Log

    Monitoring: the DAS channel set as run entries — depth, speed, weights, pressures, rates, returns — with events timestamped and depth-stamped. Pickup and slack-off derive from the surface weight and the job's drag allowance.

    run log

    Drill-Out Program

    Procedure + monitoring for the mill-out: one row per plug, and the well totals split milling vs transit vs trips — transit is where the time lives.

    drill-out

    Model vs Actual

    Monitoring: planned force and friction values are ENTERED model values, labeled as entered — this app does not run a tubing-forces or hydraulics engine. Beside them, what the job actually measured.

    Entered model values

    Job Types

    The five-part template — Planning → Equipment → Procedure → Monitoring → Safety — carried per job type. Pick a type to read its field set; the current job's type is marked.

    template

    Post-Job Report

    The job closed out: chronology, planned vs actual, conclusions, problems, the equipment record, and the string's accumulated fatigue — with FATIGUE USED THIS JOB as the headline. Feeds the End-of-Well CT job summary.

    report

    Field Ticket

    Ticket number, crew and equipment on location, materials consumed, and billable time on the same chronology as the run log — closed by the company man's sign-off.

    ticket
    Northwest Engineering compass rose
    NWE WELLREPORT
    Northwest Engineering
    FracFrac EngineeringFour linked workbook sheets
    Frac it · deterministic workbook math

    Frac Stage Engineering

    Stage geometry, ppa ramps, slurry properties, treating-pressure chain, hydraulic horsepower, step-down interpretation, and workbook checks in one live calculation chain. The loaded stage is fictional.

    Calculation state4 sheets liveIndependent checks calculating

    Inputs

    Every default is editable and resettable. Highlighted values come from offset data, service-company tables, or equipment limits.

    Gauge psi · rate bpm · concentration ppa

    Well geometry

    Fluid & proppant

    Use the service-company table or offset data.

    Perforations

    Use measured erosion condition.
    From the last step-down or a stated estimate.

    Fracture & limits

    Lowest equipment rating less margin.
    Treating pressure is a design estimate. Friction reduction, gradients, near-wellbore pressure, Cd, and the surface limit must be supplied from job-specific evidence.

    Pump Schedule

    Linear ppa ramps by clean volume. Pressures solve at the end concentration of each row.

    20 rows

    Stage rows

    Stage totals

    Pressure verdict

    Pipe friction is scaled to slurry density. This remains an estimate because real friction-reducer performance changes with proppant load.

    Step-Down Test

    Enter stepped rates and measured surface pressure. The analysis removes calculated pipe and perf friction from pressure above ISIP.

    Open-perf count is an upper bound

    Rate steps

    Workbook artifact retained exactly: the open-perf inversion contains 0.4⁰, which equals 1 and is omitted algebraically. The result assumes all excess pressure is perf friction; it is not a direct measurement.

    Checks

    Seven independent identities verify perf friction, slurry properties, proppant, horsepower, hydrostatic pressure, slurry volume, and casing capacity.

    running
    Checks validate identities, not the job-specific gradients, friction reduction, or equipment limits. Verify before operational use.
    Northwest Engineering compass rose
    NWE WELLREPORT
    Northwest Engineering
    Frac OpsFrac OperationsThirteen linked workbook sheets
    Frac it · deterministic workbook math

    Frac Operations

    Plug-and-perf gun design, wireline pump-down, step-rate, DFIT, flowback, post-job, net-pressure, per-stage as-pumped records, materials and reports in one live calculation chain. Every default below is a fictional demo value — type your own numbers before operational use.

    Calculation state13 sheets liveSelf-checks calculating

    Inputs

    Every default is editable and resettable. Fields marked VERIFY are vendor or offset values the workbook cannot know — type your own before operational use.

    All defaults fictional

    Well geometry & fluid

    Perforating gun design — one stage

    Max 12.
    Must divide 360.
    Vendor spec.
    Charge data sheet.
    Use the pipe tally.
    From the CCL log.

    Wireline cable, weak point & pump-down

    Not measured — calibrate to tension logs.
    Estimate only.

    Friction & test calibration

    Converts surface pressure to bottomhole on Step-Rate, DFIT and Net Pressure.

    Pipe + perf + near-wellbore.
    ≈1.7–2.0 for slickwater.

    Flowback, sand & erosion limits

    100 continuous, 125 intermittent clean; lower for sand-laden.
    Optional override.
    ≈0.8–0.9.
    Upstream minus downstream.
    Estimate — not verified here.
    Single-phase liquid relations only — every flowback result is an estimate. The Gilbert-type column is a two-phase rule of thumb; confirm constants against your own correlation before sizing a choke to it.

    Post-job assumptions & example unit costs

    % of design proppant.
    Example rate.
    Costs use example unit rates — replace with real quotes before quoting a job.

    Perf Design

    Plug-and-perf gun design, tool string, and CCL offsets for the stage in focus. Collar depths are nominal equal-joint stepping — use the real CCL log before shooting.

    checking

    Tool string, top to bottom

    Length and air weight are editable vendor values. Gun rows fire toe-first: Gun 1 fires as the deepest cluster.

    String checks

    Plug-setting CCL position

    CCL offsets — where the CCL must be when each gun is at target depth

    Pump-Down

    Volume, tool speed, and a 13-point cable tension profile to the plug depth. The path model is vertical → constant-rate circular build → constant-inclination lateral; the tension model is a static force balance — no dynamics, no stretch, no capstan effects.

    checking

    Pump-down segments

    Type the pump rate or the gravity speed per segment; leave a segment blank to skip it.

    Results to the plug depth

    Weak-point & cable checks

    Cable tension profile — tool at 13 depths, surface to plug

    Pump-down force and the friction coefficient are estimates, not measurements. Max-speed rate uses a 10% bypass rule of thumb — estimate.

    Stage Log

    Perf / guns-out log. Plan columns calculate from the pump-down segments; type actuals as each stage is done. Twelve stage slots.

    0 stages logged

    Stages

    Log summary

    Step-Rate

    Type the rate and the surface pressure at the end of each step. Pick the break row — the last row of the first, steep line. The two lines are least-squares fits and the extension point is where they cross.

    checking

    Test settings

    Blank = use the fitted line crossing.

    Results

    Steps — up to 14

    Friction override is optional per row; blank uses the power-law calibration from Inputs.

    Extension pressure and the fracture gradient are estimates. Each line needs at least two points, and line 1 must be steeper than line 2.

    DFIT / Minifrac

    G-function analysis with a user-picked closure. The sheet suggests a row from the G·dP/dG plot, but the pick and the straight-line extension are your judgment — estimate.

    checking

    Test settings & picks

    Your pick.
    Blank = use the picked row.
    Blank = use the G = 0 extrapolation.

    Results

    Shut-in data — up to 45 rows

    Time after shut-in and pressure. Leave rows blank to skip them.

    DFIT record — entered reads

    The pre-frac test record (usually at the toe, ~20–30 bbl). The analysis above computes closure, gradient, ISIP, net pressure and fluid efficiency; the reads below are entered from the test — the full leakoff analysis lives here, not on the per-stage sheets.

    Fluid efficiency assumes Nolte α = 1, no spurt loss, and constant fracture area after shut-in.

    Flowback & Cleanup

    Choke, erosion and sand limits with load recovery. Single-phase liquid relations only — every result here is an estimate.

    checking

    Erosional & sand limits

    Type a sand cut to see the sand-limited rate.

    Choke sizing at the target rate

    Choke size table

    Liquid rate at the pressure drop; Gilbert-type pressure at the target rate; Gilbert-type rate at the flowing pressure.

    Load decline fit — exponential

    Skip early days if the rate is still ramping.

    Daily flowback — up to 21 days

    Flowback water rate and sand cut per day.

    Sand / proppant return

    Post-Job

    Type each stage once the job is done. ISIP at bottomhole = surface ISIP + hydrostatic; leave the BH override blank to use it. Costs use the example unit rates on Inputs.

    0 stages

    Per-stage results — up to 12 stages

    Roll-up

    Net Pressure

    Treatment pressure history with Nolte-Smith slope segments. Bottomhole treating pressure = surface treating pressure + slurry hydrostatic − friction. Mode thresholds are guides, not diagnostics.

    checking

    Settings

    Leave blank to use the DFIT closure pressure.
    Guide: falling net pressure.
    Guide: near-flat.
    Guide: gentle rise.
    Guide: slope near 1 = restricted extension.

    Summary

    Nolte-Smith segments — up to 6

    Pick the first and last row of each segment. Slope is ln(net pressure) against ln(time).

    Treatment history — up to 50 rows

    Time since start of pumping, surface treating pressure, slurry rate and density. Model net pressure is optional — typed values feed the match error.

    Checks

    Thirty-two identities — each line computes the same number two different ways. A difference means a formula has been broken.

    running

    Live status flags

    Module checks on the loaded job — results, not formula checks.

    Checks validate identities, not the engineering validity of the tension model, friction power law, DFIT closure pick, Gilbert correlation, or Nolte-Smith mode guides. Verify before operational use.

    Stage Record

    The as-pumped record for one stage, on the same stage the Stage Log and Post-Job sheets carry — interval, completion hardware, the pump schedule pumped, pressures, fluid system, proppant, chemical adds, balls and events. Pick a stage, then type what actually happened. Every pre-filled value can be typed over; clear a field to return to its plan value.

    stage record

    Materials — job ledger

    Five streams tracked the same way: on location, used per stage, remaining. Used figures are counted from the stage records, never typed — if a stream disagrees with the stages, the mismatch is flagged here, not hidden.

    materials

    Reports

    Well-level rollup, a design-vs-actual report for any stage, and the job summary. The rollup also feeds section 7 of the End-of-Well Report.

    reports

    Daily Costs

    The job price book and today's cost record for the active well. The daily and job totals feed the Daily / Morning Report and the Morning Email.

    Daily Cost & Revenue

    Build the job price book by category, then run the whole month in the grid — one quantity column per job day. The Daily Revenue Report, DDR and morning email update from the same record.

    Northwest Engineering compass roseNWE WELLREPORTNorthwest Engineering
    Daily Revenue Report · Report —

    Price Book & Daily Costs

    —

    Customer / job—
    Reporting dayMonth grid · category → line item → quantity per job day → day & job totals
    Upload sales quote (PDF)Fill the price book from the quote instead of retyping it.

    The quote is read entirely in your browser, on this device — the file itself is never sent or uploaded anywhere, because real quotes carry real pricing. Line items found in the quote are listed for your review first; nothing enters the price book until you apply it, and every applied rate stays editable like any other price-book row.

    Drop the quote PDF hereor click to choose the file · PDF only

    Auto source: items tied to the report day, authoritative steering footage or Daily Activity stay user-editable and show a reset when changed.

    Morning Report

    The complete morning package in one workspace: Daily Activity, Slide / Rotate Sheet, DDR, survey exports and the branded Morning Email.

    Shared report headerThese values drive every row, total and export below.
    Well identityNot entered
    AssemblyNot entered
    Survey EditorNo surveys
    Wellbore legLeg 01 · Original
    Plan referenceNo plan
    Rig timeBrowser local
    01

    Daily Activity

    Times, depths and descriptions form the official 24-hour operations record. BHA or phase changes are marked yellow.

    Directional footage source: slide / rotate sheet.

    Emissions & Performance Record

    Fuel and flare proxies are entered on each operation above. Carbon-per-foot and NPT are calculated from the activity record with deterministic math.

    FICTIONAL DEMO VALUES

    Editable proxy factors

    Default source: U.S. EPA Emission Factors Hub, diesel combustion proxy · 10.21 kg CO₂e/gal. Confirm the operator's approved factor.

    Default source: U.S. EPA natural-gas combustion factor converted at 1.037 MMBtu/Mscf · 55.05 kg CO₂/Mscf. Combustion proxy only.

    Case-insensitive keyword match against activity code and description. Every row can override the automatic tag and reset to Auto.

    Daily trend · current in-session record

    Proxy boundary: Fuel × diesel factor + flare volume × flare factor. This is an operational performance proxy, not a verified corporate GHG inventory.
    Import activity / operations rows
    not imported
    Editable reference lists
    Format: code: name. These choices feed the activity picker.
    Used by the shared report header and each activity row.
    Available to the formal cost section and exports.
    02

    Slide / Rotate Sheet

    New rows carry drilling parameters from the latest matching state. Hours, course length, ROP and differential pressure calculate automatically.

    CONVENTIONAL · MUD MOTOR
    Authoritative directional footage source

    MY is shown on the rotate row following a slide: achieved DLS × course length ÷ slide footage.

    Ouija blended slide yield—

    Intervals

    Carried values stay editable; use ↺ to restore the value copied from the previous matching Slide or Rotate row.

    no rows
    Auto-filled from Daily Activity; editable for the reporting period.
    QC: Add intervals to begin.
    03

    DDR Preview

    The formal document is built from the two grids and the existing job, personnel, pumps, costs, drill-string and pipe-tally sections.

    Northwest Engineering compass roseNWE WELLREPORTNorthwest Engineering
    Formal 24-hour record · Report —

    Daily Drilling Report

    —

    Review statusNot approved

    24-hour operations summary

    Run Analyze to draft from the activity grid.

    Survey summary

    —

    Directional performance

    —

    Job data

    —

    Personnel

    —

    Pumps

    —

    Costs

    —

    Drill string / BHA

    —

    Pipe tally

    —

    Motors on location

    —

    Mud properties

    —

    Remarks

    No remarks entered.

    Next 24 hours

    No next-tour plan entered.

    Review required. Analyze the daily record and confirm the generated sections.
    04

    Survey File Exports

    The accepted Survey Editor in the three operator-ready files included with the morning package.

    Northwest Engineering compass roseNWE WELLREPORTNorthwest Engineering
    Operator survey packageAccepted Survey Editor
    Survey 01 · TXT

    Tab-delimited surveys

    Well header plus standard MD, INC, AZI, TVD, N/S, E/W, VS and DLS columns.

    Survey 02 · Excel

    Excel workbook

    SpreadsheetML workbook with well metadata and numeric survey cells preserved for Excel.

    Survey 03 · PDF

    Survey listing

    Compact field-ready survey report with the standard operator columns and data classification.

    Survey package: No accepted surveys are available to export.
    05

    Morning Email

    The polished email body and complete attachment package—the DD company's daily billboard to the operator.

    Morning Email workspace & supporting reports
    Report 01

    BHA Report

    Current assembly from Well Setup.

    Report 02

    Daily Mud Report

    No mud report recorded for the report date yet.

    Report 03

    Slide Sheet

    Rotate and slide intervals.

    Directional Drilling

    Daily Mud Report

    One mud report per day, kept with the well's daily record. The day's mud type and weights ride into the Morning Report package as a one-line summary, and every day's report is listed in the End-of-Well daily archive.

    In-session prototype. Mud reports live for this session only and clear on refresh or when the tab closes — the same session rule as the rest of this demo. In production the daily record persists with the well.

    Mud report

    Standard daily mud check — properties, phases and volumes as reported by the mud engineer.

    —

    Mud system

    Properties

    Phases

    Volumes

    Where the mud report goes

    The same daily record, surfaced where the package needs it.

    Morning Report package

    —

    End-of-Well daily archive

    Every day's mud report is listed in the closeout archive with its type and weights in / out.

    Directional Drilling

    Failure Report

    When something fails — a motor, a tool, a bit, surface equipment — it gets written up once, with photos, against the BHA run it happened on. Saved reports print with the well's report package.

    Prototype record. Failure reports and their photos are stored for this sitting only and clear when the session ends. Production keeps durable failure records with the well file.

    New failure report

    Photos attach as in-session previews and print with the report. The DD's words stand as written — nothing here is auto-drafted.

    0 reports
    Images only. Previews below are held in this session and print with the report.

    Saved failure reports — this session

    Each report prints in the same navy report format as the rest of the well's package.

    No failure reports yet.

    Write the first one above — it stays with this sitting and prints with the package.

    Directional Drilling

    Tool Inventory

    The location register: every serialized tool, where it is, whether its thread protectors are on, and when it was last inspected. This is the yard-and-location register — the BHA Builder's assembly inventory lives on its own page.

    In-session prototype. Register rows live for this session only and clear on refresh — the same session rule as the rest of this demo. Rows below are fictional demo stock for the Rattlesnake Draw well.

    Add a register row

    One row per serialized item or tracked set.

    Recorded when a run is assigned on save. Required for a powered sonde.

    Register

    Serial Number · Item Description · Quantity · Thread Protectors · Location · Last Inspection Date · Category · Status · Battery · Cumulative Hours · Current Run · Last Service.

    0 rows
    Tool Inventory · Cottonwood Draw 14-3 2H · fictional demo data

    Tool Inventory

    One record per physical tool on this well: what is on location, what has been shipped off, and the full movement trail between the two. The sheet is the handover record — the outgoing hand leaves a verified inventory, the incoming hand works from the record, not from memory. A tool sits in exactly one ledger at a time; shipping it out or bringing it back is one action on its record, and its history travels with it.

    Location state——

    On Location

    Every tool physically on location, one row per line item, on the same field structure as the location workbook: tool, quantity, part and serial numbers, size, asset type, product line, resource group, owner, status, BHA, and the On Job date and time. Ship a tool out from its row; its record and history move with it.

    —

    Add a tool

    Pick from the lists — the same lists as the workbook. Need a tool, size, or group that is not listed? Add it on the Edit Pick-Lists sheet and it appears here at once. Serial and part numbers are typed by hand. On Job carries the date and the time together.

    Register from the Tubular Library — pick a printed register row (drillpipe §2, collars §3, tubing / casing §5, capacities §6) and the item's dimensions start from the printed values. The item keeps its own record afterwards: the library is a source, not a live link, and an edit here never writes back to the register. Every library-filled dimension stays editable, with the library value beside it and one click back.

    For BHA use — the length the Builder carries for this item.

    On-location ledger

    Tool · Qty · Part # · Serial / Asset # · Size / Spec · Asset Type · Product Line · Resource Group · Owner · Status · BHA # · On Job (date + time) · Location Note.

    0 tools

    Shipped Off Location

    Tools that have left location and where they went. Off Job / Shipped and Returned carry date and time; Expected Back is a due date and stays date-only. A tool past its expected-back date with no return recorded is flagged OVERDUE until it comes home. Returning a tool moves its record home with the trail intact.

    —

    Shipped-off ledger

    Tool · Qty · Part # · Serial / Asset # · Product Line · Off Job / Shipped (date + time) · Destination · Reason · Carrier / Waybill · Expected Back (date) · Returned (date + time) · Flag.

    0 tools

    Movement History

    The chronological trail across every tool record — arrived, ran, shipped, returned — most recent first. This is the accountability trail a handover is checked against.

    —

    All movements

    Date + Time · Tool · Serial · Event · From / To · Notes. Every movement line carries its event date and time.

    Handover Check

    At crew change the incoming lead counts the iron against the On Location ledger and records the check here: confirm each tool, or flag it missing, unexpected, or in the wrong status, with a note. Every confirm and flag is stamped with the signed-in name, role, and the date and time. A flag stays open until a lead clears it.

    —

    Record a handover check

    —

    No check in progress. Start one to count the location against the ledger.

    Open discrepancies

    Flags from handover checks that no lead has cleared yet. They stay here, on the record, until they are cleared.

    0 open

    Handover log

    Every recorded check, who ran it, and what it found.

    Inventory Checks

    Recomputed live from the tool records. A check names a disagreement; it never rewrites either side to make the numbers agree.

    running

    Shipped and still out past expected back

    Oldest first. These tools left location and have not come home by the date on their record.

    —

    Stale records

    Tool records with no movement inside the window. A quiet record is how a tool gets lost on paper.

    Witnesses verify the record against itself and against the BHA Builder's record. They do not certify what is physically on location — that is the handover check, done by a person standing on the location.

    Edit Pick-Lists

    The menus behind every dropdown on this page — the same lists as the workbook's Dropdown Lists sheet. Type a new entry into any list and it appears in the add and edit forms at once, no rebuild needed. Lists live for this session, like the rest of the prototype.

    —

    Pick-lists

    Current entries are shown under each list. Additions apply to the On Location, Ship, and Return forms immediately.

    Directional Drilling

    MWD Workspace

    Decision support for the MWD hand — checks and records that support the hand's judgment; final technical judgment stays with the MWD hand.

    Prototype workspace — fictional demo data. Feeds and records shown here are staged/demo entries, not a live connection.

    Sources are named generically throughout: the acquisition system and the EDR feed — staging (demo). Nothing in this workspace connects live, sends anything, or signs off on a well.

    Geosteering — current instruction (read from Geology)

    Present-for-verification: the steering record lives in the Geology workspace's steering layer; this panel reads the same entry the DD sees. It is not a second store, and nothing here overwrites the DD's record.

    Geology · steering layer

    Loading the current steering instruction…

    Second-Check Survey QC

    An independent second check of each survey station against the well's reference values — the comparison the MWD hand runs alongside the acquisition system's own flags. It supports the hand's judgment: it never auto-rejects a survey, and no outcome here removes a station from the record.

    0 stations
    Total field — expected valuefrom MWD config
    Expected total field55,600 nT
    Tolerance± 2,500 nT
    Pass band53,100 – 58,100 nT

    Source: the MWD config reference value 0.556 G, converted at 1 G = 100,000 nT (0.556 × 100,000 = 55,600 nT) and labeled from MWD config. Total field is stated in nanotesla everywhere in this workspace — the same unit as the ND Pre Run Form field “Mag Field (nT)”. Single band: a measured total field inside ± 2,500 nT of expected passes; outside the band raises the QC flag for the MWD hand's disposition. Nothing auto-corrects.

    Enter the measured total field as it arrives with a survey, or type one to test the band.

    No measured value entered yet — the per-station check runs in the QC table below against this same expected value and band.

    Edit the demo company-reference rule set

    Tight and wide tolerances per check, plus the version label. Saving applies for this session and the QC table re-renders against the new values with the provenance shown. The regulatory set is not edited here — it stays unconfigured until a real regulatory rule set is loaded for the well.

    Well reference values carried on each station (fictional demo): reference gravity, reference dip and reference field from the well's magnetic reference sheet, with declination shown in the station record. Reference total field is the expected 55,600 nT ± 2,500 nT from MWD config (see the panel above). A station outside its preferred tolerance is not automatically a bad survey — drilling conditions, recent survey trend and the directional driller's read all stay part of the MWD hand's call.

    DD Verification Handoff

    Stations are presented to the directional driller for verification — present-for-verification, never auto-applied. Verification is the directional driller's own check, recorded as its own step. Neither record overwrites the other.

    Handoff event log

    Sensor Offsets — bit to gamma · sensor to bit

    The MWD hand's own calculation: component lengths entered from the bit upward. The two distances the MWD hand answers for — BIT TO GAMMA and SENSOR TO BIT — total from the stack, or are entered directly as measured. Every value is marked CALCULATED or ENTERED, stays overridable here, and lands on the run's MWD tool setup record without ever overwriting the DD side's own values.

    No run open

    Magnetic Spacing — non-mag clearance around the sensor

    Required non-magnetic spacing above and below the MWD sensor, read per the non-mag spacing reference chart at the run's maximum planned inclination and the heading's deviation from the North–South line. Between chart steps, inputs round UP to the next chart step — the field-conservative read. The check is information for the MWD hand's judgment, never a sign-off, and the results are presented to the DD side for verification only: nothing here overwrites any record.

    No run open
    Measured non-mag length above the sensor in the planned BHA.
    Measured non-mag length below the sensor in the planned BHA.
    A collar count appears only when a unit length is entered.

    Actual non-mag lengths are entered by hand: the run's assembly snapshot lists component types and lengths but carries no non-mag extent record, so the hand enters the measured non-mag run above and below the sensor and the entry is labeled ENTERED (demo values are labeled DEMO until replaced).

    Depth Reconciliation

    Field-practice reconciliation bands — configurable; these are practice tolerances, not regulatory limits.

    Both original records are preserved — nothing in this panel edits either depth. The MWD depth and the directional driller's depth sit side by side so the difference is visible and reconciled by the hands, station by station.

    Kelly-down tool

    Kelly-down convention: decimals are dropped (truncated), never rounded — 1,234.61 ft → 1,234 ft.

    Offset wells — shared register (read-only)

    The offsets this well is scanned against, read from the one shared offset register — the same register the anti-collision scan, the Planner Preview and the 3D scene read. Offset wells are built and maintained in the Offset Builder, which lives in Well Planning and on the DD side (Anti-Collision); this panel is the MWD hand's read of the register for scan context, not a second store, and nothing here edits it.

    0 offsets

    Pre-Run Record — one per run

    The fillable, signable pre-run record for the open run — the working record behind the Pre-Run Verification Report in Deliverables, following the pre-run form the MWD hand already works from. Auto values arrive labeled from Well Setup, the well's magnetics, Tool Inventory, the Sensor Offsets register and the run's BHA Builder snapshot; every one is overridable, with one click back to the auto value, and those sources stay read-only from here. The checklist is the hand's alone: type only what no system knows. A signed record locks its checks — corrections append, never overwrite.

    No run open

    Daily Run Report — one per day, per run

    The MWD hand's daily run report for the open run and the report day, following the incumbent daily run report's structure: run and tool identity, the day's drilling, both depth records, the day's surveys with their second-check QC, and the hand's own notes. Auto values arrive labeled from the Pre-Run Record's sources, the Time Breakdown, the shared survey ledger and the Second-Check; every one is overridable, with one click back to the auto value, and those sources stay read-only from here. Depth figures keep both records wherever the DD and MWD depths differ — never a silent merge. Hand-entered is only what no system knows. Per Jyeer's law the report is reviewed by name before it can be sent, and Send uses the same office distribution list stored with the job that the Pre-Run Record uses.

    No run open

    Deliverables

    Who receives what, in which formats — the operator profile for this well (demo). Every package moves DRAFT → IN REVIEW → RELEASED, and a release is the MWD hand's deliberate action, recorded with its timestamp. Nothing is sent automatically.

    Operator profile — recipients (demo)

    Tool Health — glance

    Battery, circulating hours and status for the tools the MWD hand runs, read straight from the Tool Inventory register.

    Read-only glance — the register is edited in Tool Inventory.

    MWD Inventory — stock records

    One stock record per MWD tool, read live from the platform Tool Inventory register — the register stays the single stock source, and this is its MWD view, not a second stock list. Tool identity, status, current location and current run assignment all come off the register row. A tool's location is not edited on this record: it changes only when a transfer is saved in Tool Transfers below, and that save writes the destination onto the register row itself, so the register and this view can never disagree.

    0 MWD tools

    Tool Transfers

    A transfer names the tool or tools, the from-location (each tool's current location, recorded as it stands at the save), the destination, the date, and the handoff — who released, who received, the carrier where relevant, and notes. Saving a transfer is what moves the tool: nothing else writes a location. Transfers are never edited or deleted after saving — a correction is a new transfer, or a note appended to the saved transfer, matching the audit posture of the rest of the workspace.

    Handover

    The tour-to-tour MWD handover: who is coming off, who is coming on, and what the incoming hand needs to know.

    Signed handovers — this session

    Directional Drilling

    Field Tickets

    The per-day billing ticket the client signs off on. Line items come from the Daily Costs price book; non-productive time is billed or not billed exactly as the office instructs — excluded NPT still shows on the ticket, marked, and stays out of the billed total.

    In-session prototype. Tickets live for this session only. Rates seed from the Daily Costs price book and stay editable on the ticket; editing a ticket never changes the price book.

    Ticket header

    One ticket per day. Changing the date opens that day's ticket.

    Line items

    Seeded from the Daily Costs categories for this day — set the quantity actually charged.

    Non-productive time (NPT)

    Each entry is billed or not billed per the office instruction on this ticket. Excluded entries print on the ticket marked EXCLUDED — NOT BILLED and are kept out of the billed total.

    No NPT recorded on this ticket.

    Add an entry if the day carried non-productive time.

    Line items subtotal$0.00
    NPT billed (included)$0.00
    Billed total$0.00

    NPT not billed: $0.00 — shown on the ticket, excluded from the billed total.

    Directional Drilling · final closeout

    End of Well Report

    The formal closeout document for the well, assembled in one flow from the shared plan, accepted surveys, directional record, BHA run history and daily reporting archive. Download opens the same document as a print-ready package.

    Northwest Engineering compass rose

    NWE WELLREPORT

    Northwest Engineering · End of Well Report

    Well closeout

    1Well summary

    The well at a glance — final depths, footage and the wellbore lineage carried into closeout.

    Wellbore lineage

    Leg 01 · Original

    2As-built survey listing

    Every accepted station from the Survey Editor, as drilled. The downloaded package carries this same listing.

    3Plan vs actual

    Final position against the plan, and the directional performance behind it.

    Awaiting a finished plan and accepted surveys.

    Directional performance

    Awaiting slide / rotate and daily activity records.

    4BHA / run history

    Every run on the well, with its end-of-run BHA Report and Motor Report — the same reports issued from the Surveys/Time Breakdown Sheet.

      5Daily archive index

      The daily record behind this report, day by day.

        6Combo plot

        Plan view + vertical section · plan and as-built

        7Frac job summary

        Stage count, fluid, proppant by mesh, water by source and stage events from the Frac Ops stage records.

        No frac stages recorded in this session.

        8CT job summary

        Each coiled tubing job on the well — type, max depth, result, and the fatigue it used — from the Coil Tubing job records.

        No CT jobs recorded in this session.

        9Engineering & Well Control summary

        The well control record for the well — kill chain, kick tolerance, BOP tests, accumulator check, ECD against the shoe, and bit hydraulics — from the Engineering Field Record (E1–E11).

        No well control record loaded in this session.

        10Well Planning summary

        Plan vs actual from the Well Planning record (P1–P12): casing seats, trajectory against the landing window, AFE against actual cost, and the lessons this well adopted — the feed-forward record for the next plan.

        No planning record loaded in this session.

        11Geology summary

        Tops actual vs prognosis, the shows summary, Formation Evaluation Log highlights and the evidence index — from the Geology record (G1–G9).

        No geology record loaded in this session.

        12Mud / Fluids summary

        Per-section program vs actual, volume totals, materials consumed, the solids-trend headline and kill-mud readiness at TD — from the Mud Engineer record (M1–M9).

        No mud engineer record loaded in this session.

        13Personnel record — Crew Time Sheet

        Who ran this well: every person on the Crew Time Sheet, the seat they held, and their days on this job — the well's personnel history, published from the confirmed schedule grid.

        No crew record loaded in this session.

        Closeout status: the package updates from the information currently held in this session.
        NORTHWEST ENGINEERING

        Founding Field Testers

        The first fifteen professionals to run NWE WellReport on real wells and tell us straight. Their names live here — and their feedback is in the product.

        Seat No. 1 CLAIMED Directional Driller
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        Northwest Engineering compass rose
        NWE WELLREPORT
        Northwest Engineering
        GroundGeologyNine linked sheets + the steering layer — play frame + wellsite working record
        Geology · the evidence chain: samples → description → fluorescence → solvent cut → gas → log

        Geology

        Two strata on one record: the play frame (G1–G2, the geologist's office tier) and the wellsite working record (G3–G9, owned by the mudlogger / well-site geologist) that the directional driller, the MWD hand and Geosteering — this workspace's steering layer, below — all read from. Every interpretation cites its evidence rows; an interpretation without evidence shows as UNSUPPORTED. Absence of stain or fluorescence records as INCONCLUSIVE, never “barren.” The demo well is the fictional Cottonwood Draw 14-3 2H; its prognosis tops are read live from Well Planning P2 — entered once there, never re-typed here.

        Record state9 sheets + steering layer live5 audit witnesses · all must read AGREE

        Play frame

        Office / context tier — the geologist owns this stratum

        Wellsite working record

        The mudlogger / well-site geologist owns this stratum · correlation and the play frame stay with the geologist

        G1 · Basin & Play Record

        The petroleum system stated whole: all six elements with their evidence notes, the timing carried as a dated events sequence (a trap that forms after generation and migration arrives is a story, not a prospect), the EIA play gazetteer, the public assessment layer with its figures labeled public-source, and sweet-spot evaluation as entered interpretations linked to their evidence. Entered-model volumetrics close the sheet — in-place only, under the 1917 discipline.

        Play frame · geologist

        G2 · Stratigraphic Column & Nomenclature

        The basin column young → old, the nomenclature scheme the well's picks stand under — a top pick is only meaningful under a named scheme — and the datum statement for the whole record: KB/RF elevation against mean sea level, one datum shared with Planning P1. Published stacks ride as labeled REFERENCE columns, never blended into the well's own record.

        Play frame · geologist

        G3 · Tops Record

        The correlation sheet. Prognosis MD/TVD are read from Planning P2 at render time — edit the prognosis there and it changes here; a P2 revision flags these rows stale-pending-review. Δ = Actual TVD − Prognosis TVD: negative = came in HIGH (shallower — anticline, uplift, over-extended thickness), positive = came in LOW (deeper — syncline, unexpected faulting). Every pick carries who picked it, when, on what evidence, and under which nomenclature scheme. The closing row is TD.

        prognosis read from P2

        G4 · Wellsite Sample Record — the Cutting Sheet

        The mudlogger's sheet. Description follows the trade's fixed order — the column order on this sheet: rock type → color → texture → cementation/matrix → fossils & accessories → sedimentary structures → visual porosity. Calcimetry (CaCO₃ % and dolomite %) is a measured column, not an impression. Lag is a stated value, never a silent assumption: the theoretical lag computes from pump and annulus; the carbide-measured lag is entered — and the entered value governs.

        cutting sheet

        G5 · Shows & Hydrocarbon Evaluation

        The show workup in its fixed order: odor → stain/bleeding → fluorescence → cut fluorescence → cut color & intensity → cut residue. The solvent cut is the discriminating test and the only route to a definitive call: a positive or negative cut decides SHOW or NO SHOW BY CUT; without a cut, absence of stain or fluorescence lands on INCONCLUSIVE by construction. No gas reading counts until its source is attributed — liberated, produced, recycled or contaminant on the formation side; trip gas, connection gas, circulation gas or Kelly gas where the operation made it. Show grading runs on structured vocabularies, and a contaminant identification table rides below the workups.

        Show order fixed · cut decides

        G6 · Mud Log — Formation Evaluation Log

        The central strip record and the well's decision input while drilling: coring points, wireline triggers, sidewall-core picks and test intervals are logged here as decisions with their evidence links, beside the alert register — the five standing alerts (ROP break, pit gain/loss, flow change, density variation, gas/oil indication) plus washout and H₂S carried as candidate alert types — each with time, value, reported-to and action — and a trip-monitoring register kept on the trend-over-total rule. Alerts carry their timestamps into the well's daily record, alongside operations: one well, one ledger. This sheet generates the Daily Surface Logging Report on G9.

        formation evaluation log

        G7 · Core & Evidence Register

        Every evidence type registered the same way — core, wireline suites, seismic interpretations, geochemistry — each with source, provenance and entered-by/date. Core descriptions follow the workshop sheet pattern: box, member, log depth, lithology profile, named surfaces and systems tracts, photo references. Interpretations anywhere in this workspace cite rows on this register; a claim with no row here shows as UNSUPPORTED.

        Evidence, with provenance

        G8 · Correlation & Structure

        Offset correlation in the 1917 method: a named key bed, its elevation on the stated datum, read across the offsets. Structure reads are labeled INTERPRETATIONS and cite their tops evidence. Conflicting evidence is recorded with both sources — never averaged. Every dry hole near the prospect is explained by the model or flagged UNEXPLAINED, and an unexplained dry hole shows against the prospect until it is resolved.

        Key-bed method · conflicts preserved

        G9 · Deliverables & Handover

        The logger's deliverable set, per day: the Cutting Sheet, the Daily Surface Logging Report, the Masterlog update, the Sample Manifest, and the Hand Over signed at tour change. Nothing releases unreviewed — the same rule as the MWD deliverables — and a corrected version is tracked with its change note, never silently overwritten.

        deliverables

        Checks · audit witnesses

        The five witnesses from the Geology research record, recomputed live: the tops-sheet delta convention, the theoretical-lag chain, the 1917 volumetric discipline, the five-way-corroborated Williston stack order, and the Bakken log-signature fingerprint. A disagreement means a formula or a column has been broken.

        running
        Witnesses verify the record's arithmetic, conventions and column order against the published sources. They do not certify any pick — judgment stays with the geologist and the well-site geologist.

        Steering layer — Geosteering

        The steering record lives here, in Geology. It reads G1/G2 (the model), G3 (tops — tie points anchor here), G5/G6 (the evidence), the survey ledger (position) and the run record (BHA dialect). One record, one home; the DD and MWD chairs read it from their own panels.

        Cross-Section — the steering picture

        Stratigraphic bands keyed to the G2 column colors, the target window shaded with its optimal line, hard ceiling / floor in the warning treatment, tie points with their ΔTVD callouts, the fault as an offset break, and Point Ahead dashed inside its uncertainty ribbon. Depths are TVD; the horizontal axis is horizontal length from the landing point.

        Reads G2 · G3 · survey ledger

        Target definition & tie-point register

        The target is defined on the marker (stratigraphic slice) and displayed in TVD. A tie point shifts the MODEL — never the trajectory record — and every dependent display re-solves live and flags STALE until re-reviewed (G3 doctrine).

        Model: G3 picks + tie points

        Steering Decision Log

        One entry per instruction or interpretation event, routed to DD + MWD + wellsite geologist together — one entry, visible on all three chairs; its home is this layer. The dialect follows the run record: MOTOR or RSS.

        decision log

        Fault Event — the state machine

        SUSPECTED → HOLD DECLARED → INTERVAL CAPTURED → THROW ESTIMATED → RE-PLAN DECIDED ONCE → closed. The hold is deliberate: no knee-jerk correction between the break and the decision. The throw is an ESTIMATE feeding a decision, never survey fact.

        Fault F-1 · worked through all states

        DD Confirmation & In-Zone KPI

        The feedback loop: what the BHA was expected to deliver (ENTERED-MODEL), what the surveys say the rock gave, and the ratio — interval by interval. Below it, the in-zone read with its out-of-zone attribution and the Point Ahead honesty display.

        Reads the survey ledger + run record

        Strip Log — type log beside real-time log

        GR tracks with the sweet-spot signature band shaded behind the curve, marker picks flagged on both tracks, and the fault and data-loss intervals shaded and labeled. Depths are MD on the bit timeline; log-evidence events also carry the sensor timeline (offset 47.5 ft, this run's sensor-to-bit).

        Two-timeline record

        Steering Checks — witnesses W1–W12

        Twelve fixed test vectors from the build scope, recomputed live by this layer's own calculators, each showing computed vs expected. They are additional to the workbook's 28 self-tests (Checks sheet of the workbook below), which stand unchanged. Live flags — tripped communication triggers and window-blindness disagreements — surface here as record entries.

        running
        Witnesses verify the steering layer's arithmetic against the scope's hand-computed vectors. They do not certify a steering call — judgment stays with the geosteerer, the DD and the operator's program.

        Workbook sheets

        The folded Geosteering & Landing workbook — the steering layer's working sheets, on the Cottonwood Draw record
        Northwest Engineering compass rose
        NWE WELLREPORT
        Northwest Engineering
        SteerGeosteering & LandingGeology's steering layer — the folded workbook sheets
        Geology · steering layer · deterministic workbook math

        Geosteering & Landing — workbook sheets

        Apparent dip, constant-DLS landing geometry, projection, geo log, footage, steering corrections, and independent checks share one live calculation chain. These are the steering layer's working sheets, folded into the Geology workspace — reconciled with the steering record above, never a separate destination. The loaded well is Cottonwood Draw 14-3 2H (fictional demo), seeded on its Geology G3 record: Wolfcamp A top prognosis 9,820 ft TVD (P2), actual pick 9,866 ft TVD (G3, faulted LOW), window 9,915–9,965 ft TVD (P3).

        Calculation state9 sheets live28 self-tests calculating

        Inputs

        Every value is editable; the reset control beside each field restores its fictional demo value.

        Target zone & formation dip

        Dip azimuth is the direction the zone gets deeper.

        Current bit position

        Last survey plus previous station for observed rates.

        Landing & projection

        Gamma, footage & steering

        Highlighted thresholds are workbook placeholders.

        Apparent Dip

        Exact flat-plane form along the current wellbore azimuth.

        atan(tan(true dip) × cos(azimuth difference))

        At the bit

        15° azimuth sweep

        True-dip sensitivity grid

        Rows: true dip; columns: angular difference from dip azimuth.

        Landing

        Exact target-plane solve, constant-DLS geometry, and 31-point minimum-curvature re-integration.

        Landing result

        Plan comparison

        31-point landing path

        11 tangent points and 20 build points.

        Sensitivity

        Seven complete landing resolves across dip and zone-top uncertainty.

        Landing uncertainty matrix

        Point Ahead

        Two 20-step minimum-curvature tables: survey to bit, then bit to point ahead.

        Observed & projected rates

        Projection result

        20 steps · survey to bit

        20 steps · bit to ahead

        Geo Log

        Landing tie-in plus 80 stations. Type MD, inclination, azimuth, gamma, marker, and log call; position, TVT/TST, flags, and footage calculate automatically.

        80 stations

        Landing tie-in

        MD, INC, and AZI auto-fill from Landing and remain editable.

        Stations after tie-in

        Contiguous entry required. Row reset restores the fictional demo station or clears the row.

        Footage & Steer

        Lateral footage classification and both workbook steering corrections.

        Lateral footage

        Steering correction

        (A) instant-change closed form; (B) build-then-hold secant solve.

        Footage by bin

        12 bins; each interval belongs to the bin containing its end MD.

        Section Chart

        Depth increases downward. Zone surfaces follow the flat-plane dip model.

        Lateral section

        Landing curve

        Checks

        Twenty-eight independent identities and limiting cases from the workbook.

        running
        Self-tests verify formula consistency. The module remains unverified for field use until workbook numbers are run through it.
        Northwest Engineering compass rose
        NWE WELLREPORT
        Northwest Engineering
        FluidsMud EngineerNine linked sheets + Checks — the drilling fluids record
        Mud Engineer · one ledger, one home per fact — measured is measured

        Mud Engineer

        The drilling fluids engineer's chair: the daily mud report in the field's own section order, performed against the mud program read live from Well Planning P6 — entered once there, never re-typed here. Mud-check values are test results (API RP 13B methods), entered as read with the test named; an untested property shows NOT RUN, never a carried-forward value dressed as today's. Out-of-program properties raise an INVESTIGATE flag with the evidence shown — flags, never verdicts; the mud engineer's judgment and words close them. Quantities live here; mud money lives on the catalog and M9 only — never in DD Daily Costs. The demo well is the fictional Cottonwood Draw 14-3 2H, mid-lateral on an oil-base (invert) system.

        Record state9 sheets + Checks live10 audit witnesses · all must read AGREE

        M1 · Program vs Actual

        The P6 mud program pulled read-only, section by section, beside the actuals from M2's latest check. Comparison columns exist only where P6 carries a target — this sheet never fabricates a target P6 doesn't state. This sheet also owns the mud-system configuration: the declared family per section (fresh-water / calcium-treated / salt-saturated brine / oil-base invert / synthetic-based SBM) sets which property panel M2 §7 renders — a synthetic-based section renders the invert panel under its own declared name. A P6 revision flags the affected section STALE-PENDING-REVIEW until the mud engineer re-reviews it.

        program read from P6

        M2 · Daily Mud Report — the mud check

        One report per day, serial-numbered per well. Its sections stand in the daily report's own order — header → drilling assembly (read) → casing record (read) → mud volumes → sample line → circulating strip → CURRENT MUD PROPERTIES → fluid volumes & losses → hydraulics display (read from E8) → author line — because the field's order governs. The generated report on M8 prints in this same order: sheet and printout are one document.

        Drilling Mud Report No. 14

        M3 · Solids Analysis & Dilution

        The trend sheet: per-day rows pulled from M2 — total solids, the computed LGS/HGS split, density. For salt systems the trend reads total solids beside salt-adjusted solids (the salt fraction is not drilled solid). The dilution compute sizes the build and the equal discard; the drilled-solids reading is a labeled INTERPRETATION tied to its rows — the engineer's call, in his words.

        Trend · dilution computed

        M4 · Volumes & Pits

        Pit-by-pit inventory summing to the system total, and the daily volume balance with named streams. The balance must tie to the displayed barrel (0.1 bbl) or the sheet shows UNRECONCILED — no quiet rounding. Kill-mud status reads its weight from Engineering's rounded Kill Mud Weight (E2 Kill Sheet, rounded UP to 0.1 per IADC WellSharp) with provenance — never a local figure; the P6 program value stands beside it for comparison.

        balance must tie

        M5 · Treatments & Recommendations

        The day's actions and advice in the two populations the daily report keeps: treatment rows, and the standing-instructions block — the mud engineer's recommended treatments in his own words, reprinted on the daily report until he changes them. The barite weight-up compute lives here under the pinned IADC constant set, shown on the sheet — the same set Engineering E9 displays.

        Weight-up computed · constants pinned

        M6 · Mud Materials Ledger

        Products on location, picked from the Mud Products catalog — no free-typed names. Each line carries RECEIVED and USED in the product's own unit; ON HAND computes RECEIVED − USED. USED is the shared record: the day's M5 treatments post to it, so a treatment draws stock down here in the same action. Two populations: catalog products, and bulk fluids in the additions shape. Quantities only on this sheet — the usage flows to M9 Mud Costs, which prices it at the catalog unit costs there; mud money never enters DD Daily Costs, and no price is entered or shown here.

        quantities only

        Mud Products — the catalog

        The standard drilling-fluid products the workspace picks from, grouped by category with each product's default unit and unit cost — the price M9 Mud Costs works from. Unit costs live on this catalog and on M9 only, never in DD Daily Costs. Categories and products are display organization only — the catalog recommends nothing; the mud engineer's judgment governs what gets used, and M5/M6 record what he actually did. Add a product once on the Edit product list and it is pickable on M5 and M6 immediately.

        catalog

        M7 · Solids-Control Equipment

        The equipment record — entered observations, nothing computed from them: shakers and screens, desander / desilter, mud cleaner, centrifuges, downtime with reasons. The estimated discard volume feeds M4 as a labeled ESTIMATE. Equipment efficiency appears only as a labeled interpretation on M3, never as a computed rating here.

        Entered observations

        M8 · Daily Report & Handover

        The mud engineer's deliverable: the generated Daily Mud Report — one page in M2's section order — assembled for release, reviewed by a human before it goes, with corrected versions tracked by change note. The time-distribution line rides here and prints on the report. Handover is signed at tour change; where the DD filed in the mud engineer's place, the handover names him and says so. End-of-Well §12 pulls its summary from this sheet and the M4/M6 totals.

        deliverable

        M9 · Mud Costs & Reports

        The mud side's own cost sheet — separate from DD Daily Costs by structure, not by habit. Product cost is the day's M6 usage priced at the Mud Products catalog unit costs: the quantity comes from the shared M6 record and is never re-typed here, and the unit cost is entered once on the catalog. Service and other lines are entered on this sheet. Mud costs live here and in the two mud reports below only — they are not part of DD Daily Costs or Daily Revenue, and no DD cost ever appears on this sheet.

        mud money only

        Checks · audit witnesses & live flags

        The witnesses from the build scope, recomputed live — including the E9 migration law: E9's shipped barite witness (1,003 sx) re-verifies here under the same pinned constant set, and E9's triplex constant (0.1050 bbl/stk) stays native to E9, untouched — plus the delta-pass witnesses D1–D26 and the delta live tiles (LGS methods and target, dilution-form sanity, kill-weight provenance, retort OWR, solids-density consistency, salt-chain state). Below them, the live pane: volume tie, retort sum, open program-band flags, kill-mud shortfall, and the diagnostic flag — rising YP + rising fluid loss + rising chlorides is a kick-or-salt-contamination prompt to look, never a diagnosis.

        running
        Witnesses verify the record's arithmetic and behavior against the build scope. They do not certify a mud program — judgment stays with the mud engineer.
        Northwest Engineering compass rose
        NWE WELLREPORT
        Northwest Engineering
        WellboreCasing ProgramSheets C1–C8 — design, tally, run, cement and checks on one record
        Casing Program · one record from the seat in the window to the cement top

        Casing Program

        The whole well stands on its casing. This workspace carries each string from the seat chosen against the pore-pressure / fracture window, through the API 5C3 load check on the picked pipe, to the joint-by-joint tally that ran it, the running sheet, and the cement job. Ratings are computed from the 5C3 formulas, never typed in. Setting depths read the window and the planned TD from Well Planning; MAASP and capacities read from Engineering & Well Control; the tension buoyancy runs off the mud weight on the Mud Engineer M2 record — each read live, on a cold open, with its source named. The demo well is the fictional Cottonwood Draw 14-3 2H.

        Record stateSheets C1–C8 liveWitness sets on Checks · all must read AGREE
        This workspace presents calculations and records for a professional's review; it does not sign off on a casing design or on a well for drilling. The design of record is the operator's approved casing program.

        C1 · Program

        The well's strings on one record: name, hole size, the picked pipe (OD, weight, grade, connection from C3), shoe MD and TVD, and — liners only — the liner-top depth. Plain strings with a liner-top field in v1; the liner hanger hardware kit is a later phase. Any string can be flagged contingent in the Status column, with its trigger condition written on the record in the plan's own words — the string runs only if that condition happens, and the flag and trigger show wherever the string is listed. The flag is record metadata only: it changes no depth, rating, tally, volume or check. Every value here is editable, and every sheet below re-derives from this record.

        One record · feeds C2–C8

        C2 · Setting Depths

        Each shoe stood against the pore-pressure / fracture window read from the Well Planning record (P6 pressure window, P2 prognosis) and the planned TD. The window floor is pore pressure plus the entered trip margin; the ceiling is fracture pressure minus the entered kick margin. The margin at each shoe is shown in ppg and as MAASP in psi, computed by the Engineering & Well Control method.

        Window read · margins computed

        C3 · String Picks

        The pipe library the program picks from: OD, weight, grade, connection, wall, ID, drift and coupling OD for the standard US land sizes. Wall, ID, drift and coupling OD fill from the printed §5 casing dimension register in the Tubular Library when size and weight match a printed row; every filled field remains editable (an override shows the library value beside it, with one click back), and new rows can be added; ratings on C4 compute from these dimensions by the API 5C3 formulas. Sour service: L-80 is the NACE MR0175 sour grade; P-110 is barred from sour service — the rule rides on every pick as a note, never a silent block.

        library

        C4 · Load Check — the design sheet

        API 5C3 ratings computed from the formulas: burst by Barlow with the 0.875 wall factor; collapse by regime (yield / plastic / transition / elastic, selected by D/t) with the 5C3 grade coefficients derived from yield strength; tension from body yield with buoyancy factor BF = 1 − MW/65.5 on the mud weight read from Mud Engineer M2, plus an entered overpull allowance. Collapse is derated for tension above the neutral point. Every load case states its internal / external fluid basis on its face — a case with no stated basis is flagged on C8. Design factors are company-editable; the lowest safety factor on a string is marked GOVERNING.

        5C3 computed · factors entered

        C5 · Tally

        Joint-by-joint tally for every string, in running order — the first line run stands at the top. The tally is the string's depth authority: cumulative length is re-derived at every row, section boundaries on tapered strings are labeled so the running order cannot be misread, and section sums and the string total foot automatically against the C1 shoe.

        Depth authority · foots to the shoe

        C6 · Running Sheet

        Running order per string with its float equipment. The shoe track is the standard 40 ft, set from the shoe by the tally: float collar depth = shoe − shoe track. The collar placement rule by size stands on the sheet, thread lock at and below the collar is noted, and the pre-job safety checklist closes the sheet.

        Execution · v1

        C7 · Cementing

        Annular capacity by AC = (Dh² − OD²) / 1029.4 bbl/ft. Lead and tail slurry volumes and densities are entered per job; slurry tops, strokes to bump the plug, and collar-to-shoe capacity compute from the record, and the maximum displacement rate is checked against MAASP read from the Engineering record.

        Volumes computed · MAASP checked

        Cementing · Slurry design & printed tables

        This section designs the cement jobs for the strings the Casing Program carries: slurry density, mix water and yield by the absolute-volume method (K1), proven against the printed slurry tables carried verbatim below (K2). C7 stays the summary surface — it reads the job volumes and tops from this record; the designs worked here are what C7 summarizes. Every computed value stays overridable: switch the designer to fixed-water mode to set the water yourself, edit any absolute-volume factor on its row, and every dose is entered, never locked.

        K1 designer · K2 printed tables
        Reference check: standard blend at 16.0 lb/gal — water 5.86 gal/sk, yield 1.48 ft³/skAGREE

        K1 · Slurry Designer — absolute-volume method

        Base: one 94 lb sack of cement. Solids weight W = sum of material weights; solids volume V = sum of weight × absolute-volume factor. Water A solves density = (W + 8.33·A) / (V + A); yield = (V + A) × 0.1337 ft³/sk. Only the sourced factors below ship in the library — a blend using an additive with no sourced factor is served by the K2 printed tables instead, and the designer says so on the row.

        MaterialAbs. vol. factor (gal/lb)Basis
        Cement0.0382Sourced
        SSA-1 silica0.0456Sourced
        GasStop0.1009Sourced
        CFR-30.0938Sourced
        HR-50.0750Sourced
        Water0.1200Sourced · 8.33 lb/gal
        NaCl in solution, by concentration5% 0.0368 · 6% 0.0372 · 10% 0.0385 · 12% 0.0391 · 15% 0.0398 · 18% 0.0405 · 20% 0.0409 · 24% 0.0417 · 25% 0.0418 · 30% 0.0426 · 35.14% 0.0433Sourced · between printed concentrations the factor is interpolated and labeled INTERPOLATED
        KCl in solution, by concentration1% 0.0436 · 2% 0.0440 · 3% 0.0444 · 5% 0.0450 · 10% 0.0463 · 15% 0.0475 · 20% 0.0481 · 25% 0.0488 · 30% 0.0493 · 31.58% 0.0495Sourced · between printed concentrations the factor is interpolated and labeled INTERPOLATED
        CaCl₂ in solution, by concentration2% 0.0220 · 4% 0.0229 · 5% 0.0234 · 10% 0.0252 · 15% 0.0266 · 20% 0.0278 · 30% 0.0296 · 40% 0.0311 · 50% 0.0325 · 60% 0.0339 · 66.67% 0.0346Sourced · between printed concentrations the factor is interpolated and labeled INTERPOLATED
        Fixed-water mode is the override: set the mix water and read the density it makes.
        Named designs are kept for this session; Wave 2 job sheets consume them.
        Material (base: cement, 94 lb/sk)DoseAV factor (gal/lb)Remove row
        Per-sack materials — computed
        Materiallb/skAV factor (gal/lb)Volume (gal)
        Method · W = Σ material weights (lb/sk) · V = Σ (lb × AV factor) (gal/sk) · density = (W + 8.33·A) / (V + A) lb/gal · yield = (V + A) × 0.1337 ft³/sk · Water AV 0.1200 gal/lb at 8.33 lb/gal. Salt is dosed as lb of salt per sack; its concentration in solution selects the in-solution factor from the printed table above.
        Named slurry designs — this session
        DesignDensity (lb/gal)Water (gal/sk)Yield (ft³/sk)

        K2 · Slurry Tables — printed rows, carried verbatim

        Pick the family, enter or step the density, and read the printed row. A density that is not a printed row is computed by the K1 method and labeled COMPUTED where the blend maps to sourced factors (Neat, SSA-1 35%); everywhere else the nearest printed rows above and below stand, labeled as printed rows. Nothing here is silently interpolated.

        K3 · Cement Volumes per String

        Geometry read from the Casing Program records for Cottonwood Draw 14-3 2H (C1 picks, shoe depths, hole sizes). Volumes are computed from the designed tops, so the resulting top equals the designed top by construction. Designed tops are seeded from the tops C7 records for each string: the lead top is C7's calculated slurry top, and the tail top is seeded from C7's tail volume at C7's capacity. Capacities read the §6 Dimensions & Capacities register in the Tubular Library (printed values first; the §6 printed equation, annular capacity = 0.0009714 × (D² − d²) bbl/ft, covers any diameter pair with no printed row); cased-hole intervals run at gauge, open-hole intervals carry the string's excess. Every field is editable and every number below re-derives live.

        K4 · Sacks & Materials Takeoff

        Sacks = ceil(volume ft³ ÷ yield ft³/sk), from the K3 volumes and the K1/K2 yield of the chosen slurry. Additive pounds = dose per sack (K1 design, or the K2 family's printed concentration column where it has one) × sacks. Mix water = water gal/sk × sacks. Nothing here is re-typed: change a top, an excess, or a slurry in K3 and this sheet moves.

        K5 · Displacement & Plugs

        Displacement to plug bump per string, the balanced-plug calculator on the standard method, and the buoyancy panel for steel in the job fluid.

        Reference line (balanced plug): V = 110 ft³, Cp = 0.0325 ft³/ft, Ca = 0.1697 ft³/ft, depth 8,000 ft — computing……

        K6 · Hydrostatics of the Job

        The stacked column at bump, per string: mud ahead from surface to the lead top, spacer where entered, lead, then tail to the shoe. Ph = 0.05195 × density × height, summed per segment; column heights are MD differences (the record carries no per-top TVD, so MD stands as TVD for the column, as labeled). Engineering's LOT figures are displayed read-only beside the EMW — read from its record, never recomputed here.

        Reference line (hydrostatics): 12.3 lb/gal at 13,760 ft — computing……

        K7 · Job Record

        Design beside as-pumped, per string. A record, not a sign-off: there are no approval controls on this sheet. Variances compute from what you enter.

        K8 · Checks Pane

        Named checks over the whole Wave 2 chain, recomputed live. Each reads AGREE or FLAG in plain words.

        Checks: computing……

        C8 · Casing Checks

        The witness pane: the four filed witness sets (PetroSmart worked example, the King / 5C3 worked pipe, the annular-volume example, the King buoyancy example) re-derived live, the Cottonwood demo witnesses, and the live consistency gates — tally totals against string lengths, collar depth against shoe − 40 ft, a stated fluid basis on every load case, the governing safety factor named per string, and every cross-feed resolved on a cold open.

        running
        Witnesses verify this record's arithmetic against the filed worked examples. They do not certify a casing design — judgment stays with the engineer of record.
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        Northwest Engineering
        SteerSurvey QC & BHA PerformanceTen linked workbook sheets
        Survey integrity · deterministic workbook math

        Survey QC & BHA Performance

        Minimum curvature, north-reference conversion, survey quality control, axial interference, bit projection, motor geometry, slide planning, and rotary BHA trend analysis share one live chain. Every loaded well and station is fictional.

        Calculation state10 sheets live26 self-tests calculating

        Inputs

        North references, tie-in, QC references, and axial-field assumptions. Every value is editable; ↺ restores its fictional demo value.

        Job & north reference

        True = Magnetic + Declination. True = Grid + Convergence.

        Tie-in & vertical section

        QC references & tolerances

        Reference values are editable; highlighted tolerances are workbook placeholders.

        Axial field source

        The direct value or the editable pole-model estimate feeds Survey QC and Axial Mag.

        Axial magnetic interference is a screening estimate, not a correction. Confirm limits with the MWD vendor and an approved magnetic reference.

        Surveys

        Full minimum-curvature engine with Magnetic, True, and Grid conversion. Type MD, inclination, raw azimuth, and optional Bt/Gt/Dip/tool face.

        loading

        Fictional Survey Editor

        The intentionally bad magnetic-field reading keeps the QC FAIL path visible. Every source cell and row has a reset.

        Computed columns: used INC, TRUE/GRID/MAG/work azimuth, course, dogleg, DLS, build, turn, survey-derived tool face, ratio factor, TVD, N/S, E/W, VS, closure, closure azimuth, and row note.

        Survey QC

        Per-station PASS, FAIL, or NO DATA from total field, dip, and gravity; axial screening is reported separately.

        calculating

        Station verdicts

        Plots

        All charts read the live Survey Editor in the selected work north reference.

        Axial Magnetic Interference

        Exact closed form plus small-k approximation and both workbook sweeps.

        screening only

        One case

        Model boundary

        Steel above and below the non-mag collar can add false axial field. This exact trigonometric result estimates the resulting magnetic-azimuth error; it does not correct a survey.
        dAz = atan2(sin A, cos A + k) − A
        k = dBz · sin(Inc) / [B · cos(dip)]

        Error vs magnetic azimuth

        0–360° in 15° increments at the case inclination.

        Error vs inclination

        0–90° in 10° increments at the case magnetic azimuth.

        Project Ahead

        Constant-curvature projection from the last measured station to the bit and beyond.

        Projection settings

        Model boundary

        Constant curvature is a prediction, not a guarantee. Formation, WOB, and slide/rotate behavior can change the real BHA response. Use it to see where the bit may be.

        Projected bit & ahead-of-bit stations

        Blue distances are editable and independently resettable.

        Motor BUR

        Three-point-contact quadratic geometry with residual checks and bend-angle sensitivity.

        Motor & hole inputs

        Geometry result

        Geometric motor BUR is an upper bound. Real yield is usually lower; the editable realisation factor or measured-yield override controls the planning value.

        Bend-angle sensitivity

        Slide Plan

        Four solvers: required-DLS percentage, rotary-tendency balance, tool-face resolution, and target direction.

        A · Slide percentage & time

        B · Counter rotary tendency

        C · Tool-face resolution

        D · Reach target direction

        Rotary BHA

        Qualitative tendency table plus Timoshenko beam-column fulcrum estimate.

        General tendency guide

        Industry behavior only; not tuned to a formation or hole size. Walk is not modeled.

        BHA typeTends toMore WOBNotes
        FulcrumBUILD angleMore buildDepends on span, stiffness, inclination, and WOB.
        PendulumDROP angleLess dropRun light WOB to drop; unsupported length matters.
        PackedHOLD angle and azimuthLittle changeShort spans limit sag; residual walk depends on bit, RPM, formation.
        Slick / unstabilizedUnpredictable; often dropsVariableUsually reserved for straight-hole or specific tendency work.

        Fulcrum inputs

        Fulcrum result

        Fulcrum rate is a trend, not a prediction. The wall-contact cap is approximate; formation and bit tendencies are excluded.

        Estimated build rate vs WOB

        Checks

        A is the main calculation; B is an independent identity, limit, or round trip.

        running
        Self-tests verify formula consistency, not field-model validity. Compare this module against the source workbook before operational use.
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        EngineerPore Pressure / Mud Window / Rig SizingThirteen linked workbook sheets
        Pressure envelope · equipment capacity

        Pore Pressure / Mud Window / Rig Sizing

        Integrated overburden, three Eaton pore-pressure curves, three fracture-gradient methods, bottom-up casing seats, and linked rig-capacity checks. The loaded Falcon Prairie 14H case is entirely fictional.

        Calculation state13 sheets live27 self-tests calculating
        Screening tool only. Eaton, Matthews–Kelly, and d-exponent methods are empirical and require offset calibration. Rig, BOP, pump, pit, and solids checks do not replace manufacturer data books, API 4F/8C/9B/16A, or operator standards.

        Inputs

        Pressure-model controls, NCT trends, empirical coefficients, and design margins. Amber inputs require basin or policy calibration.

        Rock Tables

        Editable Poisson ratio and Matthews–Kelly Ki tables with clamped linear interpolation. Entire tables are illustrative placeholders.

        CALIBRATE TO BASIN

        Poisson ratio ν(TVD)

        Matthews–Kelly Ki(Di)

        Depth Data

        Up to 60 contiguous, increasing TVD rows. Leave a measurement blank to skip its matching curve.

        60 rows

        Paste log and drilling data

        TVD, RHOB, OBG override, Sonic DT, Resistivity, NCT flag, ROP, RPM, WOB, bit size, mud weight. Tabs, commas, or spaces accepted.

        Fictional 250 ft-spaced example loaded.

        Source table

        Pore Pressure

        Trapezoid overburden, hydrostatic, sonic/resistivity/dxc Eaton curves, and weighted log-linear NCT regression.

        calculating

        Pressure profile

        Frac Gradient

        Eaton, minimum horizontal stress, and Matthews–Kelly, with an editable design-curve selector.

        Fracture-gradient profile

        Mud Window

        Minimum, maximum, rounded design weight, window status, and bottom-up casing-seat selection.

        calculating

        Pressure envelope

        Pore pressureFrac gradientDesign mud weight

        Casing seats

        Mud-window table

        Rig Inputs

        Hoisting, pump, well-control, geometry, alarm, and solids-control inputs. Amber values are ratings, policies, or estimates to verify.

        Active surface tanks

        Hoisting

        Required hookload, block-and-tackle efficiency, line loads, rope factor, derrick load, and drawworks power.

        Lines strung comparison

        Pumps

        Selected pump duty plus the seven-liner workbook table. Rod-load pressure is an estimate; use the manufacturer's liner chart for selection.

        Liner comparison

        BOP & Kick

        Gas-to-surface and shoe-limited MASP, API rating selection, weakest-link check, and the workbook's simple shut-in kick screen.

        MASP & weakest link

        Kick at TD

        Single gas slug at bottom; no expansion or migration. Screening estimate only.

        Pits & Solids

        Active volume, hole volume, bottoms-up, alarm resolution, drilled-solids load, and first-pass equipment capacity.

        Volumes & alarms

        Solids control

        FIT / LOT

        Surface-pressure formation-integrity and leak-off analysis at the casing shoe. Every entered value is editable; ↺ restores its fictional demo value.

        AI talks, math decides. The notes explain the result; the verdicts below come only from the entered readings, equations, and pass rules.

        Test setup

        FIT stops at target; LOT continues until pressure leaves the straight line.

        Pump calculator

        Typed pump output controls the table. The triplex calculator stays advisory until used.

        Hole volume

        Fluid volume under pressure and ideal rigid-hole compressibility slope.

        Rules & use of result

        Amber rules are PLACEHOLDER values. Replace them with the approved procedure.

        Pump-in table

        40 reading slots. The first N points fit the straight line; the first later point more than tolerance below it is flagged. Leak-off is the preceding reading.

        40 slots

        Hold & decay

        Pressure loss is measured from ISIP to the exact required hold-time reading.

        31 slots

        Pressure vs volume

        MeasuredFitted lineLeak-off pick

        Hold / decay

        Results

        The test

        Leak-off

        Shut-in & hold

        What you can drill with

        Limits: surface-pressure test read at the shoe with one mud weight. It assumes the same mud all the way up, a rigid hole, and gauge pressure read at surface. Temperature and gel strength are not corrected for. The pass rules are inputs, not a standard. Use your operator's test procedure.

        FIT / LOT checks

        Seven workbook identities compute the same number two ways. They verify formula consistency, not field validity.

        running

        Checks

        Twenty-seven workbook identities plus the live design verdicts. Identity checks verify formula consistency, not model validity.

        running

        Design verdicts

        Verify before operational use. Compare this implementation against the source workbook and calibrate all highlighted assumptions to approved offsets, equipment certificates, and operating standards.
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        Northwest Engineering
        ControlWell Control / Trips / Stuck PipeTen linked workbook sheets
        Kill · circulate · trip · recover

        Well Control / Trips / Stuck Pipe

        Kill sheet, pressure schedule, gas circulation, trip monitoring, swab and surge screening, free point, jarring, and back-off — linked to one fictional well case.

        Calculation state10 sheets live30 self-tests calculating
        Engineering screening only. The gas, swab/surge, differential-sticking, jar-impact, and back-off models carry the source workbook’s assumptions. Confirm field inputs, equipment limits, approved procedures, and the source workbook before operational use.

        Inputs

        Every workbook input remains editable. Amber fields are PLACEHOLDER or ESTIMATE values requiring job-specific confirmation.

        Survey MD / TVD

        Editable 40-station MD/TVD table. TVD is linearly interpolated; keep MD increasing and include the shoe, top of BHA, and bit.

        7 stations

        Volumes

        Two-section string and four-segment annulus, with capacities, volumes, pump strokes, and time at the kill rate.

        String

        Annulus

        Kill Sheet

        Driller’s method and wait-and-weight with kill mud, ICP/FCP, influx estimate, MAASP, and kick tolerance.

        calculating

        Depths, pressures & mud

        Method instructions

        Kick estimate

        ESTIMATE · Pit gain is treated as influx volume at bottom. Type and density are rule-of-thumb outputs.

        MAASP & kick tolerance

        Kick tolerance is an ESTIMATE using one influx slug, constant influx gradient, and the leak-off pressure at the shoe.

        Kill Schedule

        Twenty-one pressure points from ICP to FCP. TVD at the kill-mud front flattens the schedule through the lateral.

        21 steps

        Gas Circulation

        Twenty-five gas-top rise steps plus the shoe case using the workbook’s ideal-gas quadratic solution.

        ESTIMATE
        Single ideal-gas slug, constant temperature, no gas in solution, no migration, gas weight ignored, and no annular friction.

        Trip Sheet

        POOH and RIH theoretical displacement versus entered readings. Each actual reading is editable and individually resettable.

        open-end displacement

        Pulling out · 45 lines

        Running in · 45 lines

        Swab / Surge

        Four annular regions, rheology-based pressure loss, trip margin, and a ten-speed sweep.

        ESTIMATE ONLY
        Steady-state, closed pipe, concentric annulus, no rotation, no gels. Use to rank speeds — not to certify one.

        Four-region model

        Speed sweep

        Stuck Pipe

        Free point by stretch and rotation, differential sticking, simplified jar impact, and back-off torque count.

        ESTIMATE MODELS

        Free point

        Differential sticking · ESTIMATE

        Jar impact · ESTIMATE

        Back-off · ESTIMATE

        Checks

        Thirty independent identities and limiting cases from the source workbook.

        running
        Verify before trusting. Self-tests validate formula consistency only. They do not validate the kill, gas, swab/surge, sticking, or jar models against field data.
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        Northwest Engineering
        ReportDaily ReportingTwelve linked workbook sheets
        Log once · report everywhere

        Daily Reporting

        A master activity log feeds the directional daily report, 60-day summary, survey and plan comparison, BHA records, directional-charge helper, KPIs, plan versus actual, and 25 linked checks. The loaded Copper Ridge 8H job is fictional.

        Calculation state12 sheets live25 self-tests calculating

        Inputs

        Well header, reporting period, tie-in, and directional-charge assumptions. Every default can be changed; ↺ restores its fictional demo value.

        Well / job header

        Report settings & tie-in

        Invoice helper inputs

        PLACEHOLDER rates only — replace with approved contract values.

        Codes

        Twenty-two activity codes drive the log lookups, group hours, NPT, pumps-on, on-bottom, and standby logic.

        8 GROUPS · IMMUTABLE
        Group names are fixed calculation keys: Rotary drilling, Slide drilling, Reaming, Tripping, Connection, Circulating, Survey, Other.

        Time Log

        Master log in report-day order. Midnight wraps automatically; code lookups, footage, emissions, NPT, day keys, and chain checks calculate on every edit.

        0 / 700 rows

        Emissions factors

        Editable proxy factors; each reset restores the fictional demo assumption.

        FICTIONAL DEMO VALUES

        Proxy boundary: diesel combustion plus entered flare volume only. This is not a verified corporate GHG inventory; methane slip, purchased electricity, transport, embodied carbon, and other scopes are excluded. The diesel factor is stored in kilograms: the source figure 10.21 is lb CO₂e/gal, converted at 2.20462 lb/kg to 4.6313 kg CO₂e/gal, so every total on this sheet is kilograms throughout.

        Emissions & performance record

        Fuel and flare roll up from each operation; NPT uses the activity-code class, with keyword fallback for uncoded rows.

        LIVE

        Fuel and flare are typed per operation. NPT rows are tinted. Time-chain, depth-link, or row problems are highlighted. Fully blank rows are clean.

        Daily Report

        Pick one logged report date. Everything except the date and remarks comes from the linked sheets.

        Directional Daily Report

        24-hour time log

        First 40 rows for the selected date.

        calculating

        Day Summary

        Sixty report days of SUMIFS-equivalent calculations from the Time Log, plus whole-job totals.

        60 DAYS

        Survey

        Up to 200 stations: minimum curvature, DLS/build/turn, position, independent haversine dogleg check, plan comparison, and projected bit position.

        BIT PROJECTION · ESTIMATE

        Capacity: 200 stations. Ahead/above/right compare the survey with the plan at the same MD; high/low compares TVD at the same vertical section.

        Plan

        Up to 120 plan stations. MD, inclination, azimuth, and TVD are editable; N/E, minimum-curvature TVD, VS, DLS, and TVD sanity calculate.

        BHA & Bit

        BHA, bit, and mud-motor records roll footage and hours up from the Time Log by BHA number.

        BHA record · 12 runs

        Bit record · IADC 8-part dull grade

        Mud motor record · 12 runs

        Service limits are editable PLACEHOLDERS.

        Invoice

        A working helper for directional charges only — not an invoice document. Check every rate before use.

        PLACEHOLDER RATES

        KPIs & Charts

        Whole-job drilling, connection, trip, time, NPT-category, and activity-group performance.

        Plan TD

        Typed planned depth and planned cumulative cost against Day Summary and Invoice actuals. Planned costs are PLACEHOLDERS.

        PLANNED COSTS · VERIFY

        Checks

        Twenty-five cross-sheet identities and limits, including emissions and NPT rollups, reading the current Inputs, Time Log, Survey, Plan, BHA, Invoice, and KPI calculations.

        running
        Self-tests verify formula consistency. Compare this module against the source workbook before field or billing use.
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        Northwest Engineering
        ProduceProduction / Workover / P&ATen linked workbook sheets
        Produce it · deterministic workbook math

        Production / Workover / P&A

        Monthly and daily production performance with type-curve flags, well-test allocation and sales reconciliation, slickline wireline limits, fishing and free-point math, tubing and kill planning, balanced cement plugs, casing cut-and-pull, and a full P&A cost roll-up. The loaded job is fictional.

        Calculation state10 sheets liveIndependent checks calculating

        Prod Inputs

        Settings, type curve, and the latest-month summary. Every default is editable and has a one-click reset. Highlighted values are placeholders you must set for your well.

        Gauge psi · bbl · Mscf

        Well & type curve

        Your forecast — the sheet cannot know your reservoir.

        Your forecast.
        Nominal, per year.
        Your forecast. b = 0 uses the exponential branch.
        Your call.
        Your call.
        A stand-in for reservoir pressure at the wellhead, not a true bottomhole drawdown.
        Your call.

        Latest-month summary

        Every value below is calculated — click any value to override it; the reset restores the auto value.

        Pressure normalisation is an ESTIMATE: normalised rate = rate × (static − reference) / (static − flowing). It assumes the rate is proportional to wellhead drawdown — a rough estimate that only separates a pressure (choke) effect from a real rate loss. If a month's flowing pressure is at or above the static proxy, the normalised cell stays blank.

        Monthly

        30 months of volumes and pressures. Type the blue cells; every other column calculates. Leave a month's oil blank to skip it.

        30 rows

        Monthly production data

        Rates are on-stream (volume ÷ days on-stream). Click any calculated value to override it.

        Documented workbook behavior — exponential branch: the type-curve forecast is Arps hyperbolic at mid-month (t = 0.5, 1.5, …). If you set b = 0, the module uses the exponential branch q = qi × e−Di·t instead of dividing by zero. Checks 33–35 verify the closed forms and the b → 0 limit.

        Daily

        One month of daily data, scaled to a full day (volume × 24 ÷ hours on-stream). Type the blue cells; leave a day's oil blank to skip it.

        31 rows

        Daily production data

        Type the first date once; later dates fill automatically.

        Month totals

        Flags

        PARTIAL DAY if hours < 24 · CHOKE CHANGE if the choke differs from the day before · LOW if the oil rate is below the UNDER threshold times the prior 7-day average · otherwise OK.

        Documented workbook behavior — Daily column R: the header reads “CHP − THP (psi)” but the workbook formula is =I−H, i.e. choke minus CHP (first day: 32 − 752 = −720). Reproduced exactly as written; flagged as a likely header/formula mismatch — verify before relying on it.

        Well Test

        Test rate × days on-stream gives a theoretical month; the battery meters give the real total. The allocation factor scales every well so the total matches the meters.

        8 wells

        Allocation period & battery

        Your policy.
        Your policy.
        Get from a fluid study or your own tank data.
        Evaporation, line fill, measurement difference.
        From your gas contract / plant statement.
        Your policy.

        Allocation factors

        1.000 = tests agree with the battery. Above 1 = tests under-read the tank total. Applied to every well.

        The example deliberately includes weak tests: EX-4H is STALE (107-day-old test) and EX-5H is SHORT (8-hour test). These wells get an allocation based on a weak test — consider re-testing.

        Well tests

        Up to 8 wells. Clear a well name to skip its row.

        Sales reconciliation

        The sales statement is the money number. If the difference is outside tolerance, look at tank gauging, the inventory build, run-ticket timing, plant shrink and fuel before blaming the well tests.

        Wireline

        Slickline: wire, stretch, weak point, jars, pressure control. Vertical well assumed — use the drag inputs for deviation and friction. Jar results are ESTIMATE only.

        Forces lb · psi · ft

        Wire

        From the wire certificate.
        If typed, the maker's rated break is used instead of strength × area.

        Well, fluid and pressure

        Friction from deviation, deposits and wire against the tubing.
        Depends on how tight the pack-off is run.

        Weights & surface tensions

        Weak point & safety factor

        From the weak point data sheet / your company policy.
        Your company policy.

        Stretch & depth correction

        Wire and tools are assumed steel in this fluid. Gas wells: use the gas gradient as ppg.

        Jar & pull-up ESTIMATE

        Ratio of peak blow to the pull at the jar; use your jar vendor data.

        Pressure control

        From the equipment tag / certificate.
        From the equipment tag / certificate.
        Your company policy.
        Your company policy.

        Tool string

        Type the blue cells, top tool first. Weight in fluid calculates from the buoyancy factor.

        Stretch, tension and safety factor vs depth

        Depth fractions of the planned wire depth.

        Fishing

        Overshot and spear pull limits, free point from pipe stretch, and a jarring estimate. Jarring results are ESTIMATE only.

        Forces lb · stretch in

        Fish & pulling string

        Grade J-55 is 55,000 psi minimum yield; check your pipe tally.
        Your company policy.
        From your pipe tables, already includes your design factor.

        Overshot (outside catch)

        Heat-treated alloy; from the tool data.
        Use the manufacturer's rating.
        The bowl-wall limit is an upper-limit sanity check: gross wall area × yield × design factor, ignoring grapple slots and threads.

        Spear (inside catch)

        From the tool data.
        Use the manufacturer's rating.

        Free point from pipe stretch

        Stretch e (in) = pull (lb) × length (ft) × 12 / (area × E). Constants are derived, not looked up.

        Jarring ESTIMATE ONLY

        Friction on the string.
        Peak blow / net overpull; from the jar vendor chart for your collar weight.
        If the peak blow exceeds the fish pipe allowable pull, reduce overpull or stop.

        Tubing & Kill

        Tubing dimensions, circulate-out, kill fluid density and the bullhead pressure window. Single fluid density per column; no temperature effects. Bullhead friction and reservoir-pressure estimates are ESTIMATE.

        bbl · ft · psi · ppg

        Tubing and casing

        Treating line and pump manifold.

        Pump

        0.95 is a common starting value; use your pump data.

        Volume to pump

        Kill fluid density ESTIMATE

        Gas about 1 to 3 ppg, oil about 7, water about 8.4; sets the formation pressure estimate.
        Type the known formation pressure to replace the estimate.
        Your well-control policy.

        Bullhead ESTIMATE

        From offset data or a leak-off / step-rate test; this is the limit you must stay under.
        Extra pressure needed to push fluid into the formation at your rate.
        For the friction estimate.
        Extra volume so no gas is left at the perfs.
        Lowest of wellhead, tubing burst and casing rating, with your margin.

        Common tubing sizes

        Nominal API tubing sizes — published values; check them against your own tally before relying on them.

        P&A Plugs

        Balanced cement plug design. YOU choose the plug list: depths, lengths and hole sizes. The loaded plugs are an EXAMPLE — not a statement of what any regulator requires.

        REGULATOR RULES VARY
        Regulator disclaimer: regulator rules vary and change. Plug depth, length, cement class, tagging, pressure testing and reporting are set by your regulator (and by the lease / operator program). This workbook asserts no plugging rule — enter the current rule and its date in the last column of each plug row.

        Cement and workstring

        Use the cementing company's slurry design; 1.15 is a typical neat Portland slurry.
        From the slurry design.
        All fluids around the plug are assumed this density, so the balanced plug has equal pressure inside and outside.

        Totals

        Feed the cost roll-up on the next sheet.

        Plug list

        Up to 8 plugs. Pipe is set at the bottom of the plug; the pipe is pulled slowly out of the cement column.

        Documented workbook behavior: mix water is computed from unrounded sacks (column L), not the rounded-up sack count (column M). Cement volume = plug length × hole capacity × (1 + excess); top-of-plug design = bottom − length; always tag the plug and follow your regulator and the cementer on testing.

        P&A Casing & Cost

        Casing cut-and-pull, the cost roll-up, and the P&A liability export. Every rate is a placeholder number — replace with quotes.

        ALL RATES · VERIFY

        Casing cut-and-pull

        Normally you cut above the top of cement, so this is small. Hundreds of feet of good bond usually cannot be pulled.
        Unknown without a bond log; could be far higher or lower.
        Friction, dog-legs, sand.
        Check your casing record.
        Your policy.
        From the casing tables for your size, weight, grade and thread.
        Derrick or jack rating.

        P&A liability export

        Copy these cells into the P&A / abandonment line of the economics workbook. Values are in today's money (the cost basis year below); the economics workbook should escalate and discount them to the year of abandonment.

        Your forecast of when the well is plugged.
        Stays PLACEHOLDER until every rate above is replaced with a quote.
        Export this number: P&A liability, your share ($). Well name flows from Prod Inputs.

        Cost roll-up

        Every rate is a placeholder — replace with quotes. Quantities marked auto pull from the plug sheet.

        Your policy.
        Scrap value of tubing, wellhead, equipment less the cost to recover.

        Checks

        35 independent identities recompute quantities two different ways, reading the current inputs across all ten sheets.

        running
        Scope of these checks: internal arithmetic consistency only. They do not validate the engineering models, your inputs, or field validity — compare against the source workbook and your own data before operational use. Three documented workbook behaviors are preserved exactly: the Daily column-R formula (I−H, not CHP−THP), the b = 0 exponential branch in the type curve, and mix water from unrounded sacks.
        Northwest Engineering compass rose
        NWE WELLREPORT
        Northwest Engineering
        The hubMaster Well FileWell data entered once · feeds every module
        The hub · deterministic workbook math

        Master Well File

        Every common well input lives here, entered once. The sixteen module feeds below carry these values into each engineering module automatically — fields the hub does not own stay module-local and are never overwritten. The loaded job is fictional demo data.

        Hub stateHub live43 checks calculating
        The hub · visual front door

        Field Map

        Every well in the registry at its surface location. Click a marker for the well summary, then open its Master Well File. Fictional demo data.

        DrillingCompletedPlanned

        Summary dashboard

        Well identity, key depths, live status, and the casing schematic — everything calculated from the Well Data tab.

        Fictional demo well

        Well schematic

        MD bars drawn from the casing, tubing, and perforation tops and bottoms in Well Data §5–§6.

        How to work the hub

        The workflow the workbook was built around.

        1. Type each well input once, on the Well Data tab — light fields are inputs, calculated fields recompute live.
        2. Open the Module Feeds tab and apply each feed group into its module; values marked NONE stay in the module and the hub never overwrites them.
        3. Keep Plan vs Actual, the revision log, the job-file index, and the NPT log current as the well is drilled.
        4. A blank in the hub feeds as a blank — it never pastes over a value you typed in a module.
        5. Plan-vs-actual checks fail until actual data is entered. That is intended, not an error.

        Sheet guide

        What lives where in this hub.

        SummaryDashboard — identity, depths, status, schematic
        Well Data12 sections of common inputs, entered once
        Plan vs ActualTolerances, station variances, footage / days / cost
        Log & IndexRevision log · job-file index · NPT / lessons learned
        Module Feeds16 export interface contracts, one per module
        Checks43 consistency rules + overall verdict
        Not coveredPasted data tables inside the modules — surveys, logs, time logs, monthly production

        Well Data — common inputs

        Entered once here. Every default is editable; every calculated value is clickable to override, with a one-click reset back to the auto value. Fields marked VERIFY are placeholders you must set for your well.

        ft · psi gauge · ppg · degrees

        §1 · Well identity

        Who and what this well is.

        Corrected mapping: the Daily Report feed reads this field — not oil gravity.
        Free text — not fed to any module.
        Often blank until known.

        §2 · Location, map system, datum

        Surface position and reference frames.

        KB − ground.
        0 = wellhead.
        0 = wellhead.
        N-S × E-W ÷ 43560.

        §3 · Key plan targets

        Copy of the plan stations from the well-plan workbook. VS projects each station onto the VS azimuth.

        §4 · Depths and plan summary

        Calculated from the targets table, except where marked.

        TVD − KB.
        TD MD − lateral start MD.
        From the plan workbook Sections sheet.
        Flat lateral: TD TVD.
        Example — set for your well.
        Tangent interpolation — example.
        Liner shoe MD − shoe track.

        §5 · Casing / liner program

        Build your program here — never hard-coded. ID = OD − 2 × wall.

        §6 · Tubing string and packer

        Bottom MD links to the packer depth in §4.

        = packer MD.
        OD − 2 × wall.

        §7 · Mud weight, pore and fracture gradient

        One row per hole section, following the casing program. Margin = MW − pore.

        §8 · Pressure, temperature, gradients

        Reservoir pressure used = measured override, else the pore-pressure estimate.

        Often blank; estimate used when blank.
        Prod-hole pore ppg × 0.052 × mid-perf TVD + 14.7.
        Example.

        §9 · Fluids and completion load scenario

        Design-case values — fictional in this demo.

        §10 · Reservoir and fluid properties

        Example values in the workbook — fictional here.

        Production hole diameter ÷ 2 ÷ 12.

        §11 · Pad, spacing and stimulation design

        Setbacks, spacing, and the stage/cluster design.

        INT(stage spacing ÷ cluster spacing).

        §12 · Price deck, ownership, costs, production forecast

        PLACEHOLDER — not a forecast. The stepped deck covers years 1–10; years 11+ reuse year-10 prices.

        Negative = receive less.
        Standard 6.
        Master stores EFFECTIVE annual Di.
        Derived for the Decline / Prod-Workover feeds: b=0 → −ln(1−De), else ((1−De)−b−1)/b.

        Stepped price deck — years 1–10

        Plan vs Actual

        Traffic lights: GREEN within the first limit, AMBER within the second, RED beyond. Time and cost count overruns only; depth and footage count a miss in either direction. Variance is only meaningful at equal MD — enter actual surveys interpolated to the plan station MDs.

        NO ACTUALS

        Tolerances

        All editable — these are your limits, not hard-coded.

        Survey / position at each plan station

        Type the actuals; variances and station status calculate. Blank actual MD = no score yet.

        Total displacement

        At the last station with an actual entered.

        Depth / time / cost / footage

        Plan vs actual variance and scores.

        Footage, days and cost by hole section

        Section names follow Well Data §7. Plan footage = shoe MD − previous shoe MD.

        Log & Index

        Revision history, the job-file index, and the NPT / lessons-learned log.

        0 current

        Revision log

        Fill top-to-bottom with no gaps. The last row feeds the Summary version stamp.

        Job-file index

        The 17 workbooks in this job and which feed sheet each one takes.

        Lessons learned / NPT log

        Fictional example rows — replace with your events.

        NPT summary by category

        Fixed 10-category list, summed from the log.

        NPT as % of actual days = total NPT hours ÷ (actual days × 24).

        Module feeds — the interface contracts

        Each feed lists the target module's input cells, the hub value behind each one, and the map type: 1:1 direct copy · DERIVED computed from hub fields · PARTIAL hub value with a caveat · NONE no hub value — the module keeps its own entry and the hub never overwrites it. "Apply feed" stamps the feed as applied; re-apply any time the hub changes.

        16 contracts

        Checks

        43 consistency rules the well data must satisfy. Rules 25–27 fail until actual data is entered — that is intended. Everything below is calculated; nothing here is typed.

        —

        Info — not counted in the verdict

        })();