Quick snapshot: the wells that changed your thinking

• Tell me about the last batch of wells you drilled that came in over AFE, including which failure modes showed up.
• How many wells in that batch exceeded budget and by roughly how many rig days each? Options: 1-2, 3-5, 6-10, More than 10
• When those issues occurred, who on your team was first to raise the alarm and how was it escalated?
• Estimate the average additional rig days and incremental cost per well caused by stuck pipe, tool failures, or placement misses.
• Which of those failure types would cause you to replace a vendor immediately if it continued? Options: Stuck pipe, Tool failures, Lateral placement out of zone, Excessive dogleg severity, Telemetry failure

Where the current approach breaks down

• If you could eliminate one recurring failure across your drilled inventory, which would shorten schedule and improve completion runnability most?
• Who in your organization is responsible for tracking MTBF, telemetry uptime, and dogleg severity for vendor performance?
• Describe how lateral placement variance has affected production or completion hardware runs on recent wells.
• Which performance metric, dogleg severity, MTBF, telemetry latency, or lateral placement variance, creates the most pressure from leadership? Options: Dogleg severity, MTBF, Telemetry latency, Lateral placement variance, NPT days
• What single operational bottleneck would stop you from scaling a proven directional program to multiple pads?

The trade offs you are choosing right now

• Who on your leadership team is willing to accept short term schedule risk to improve long term reliability?
• How often do you approve performance based pricing versus day rate structures for directional campaigns? Options: Always day rate, Prefer day rate, rarely performance, Open to both, Prefer performance based
• Estimate your current mean time between failures for directional tools in this basin and include the sample size used for that figure.
• List the top three criteria you use when comparing directional providers for tool reliability, telemetry quality, and crew expertise. Options: Tool reliability / MTBF, Telemetry quality / uptime, Directional accuracy / placement, Crew experience in basin, Pricing model, References in basin
• If the pilot does not show measurable improvement on the first well, which internal governance step would likely cancel the rest of the campaign?

Operational readiness, in practical terms

• Name the single readiness gap that would prevent mobilization on your target date.
• Identify the role that signs the rig go no go and HSE approvals before mobilization.
• State the minimum number of spare directional tool sets and critical spares you require on site to meet your risk tolerance. Options: 0, 1, 2, 3+
• List permits or local approvals that have historically added the largest lead time for mobilization.
• Given your mobilization window, would lack of rig or crew availability force a pause, or would you accept a revised schedule? Options: Force a pause, Accept a revised schedule, Only accept with mitigations

Field configuration details that actually change outcomes

• Assuming telemetry drops below your operational threshold mid run, what fallback decision prevents escalation to a stuck pipe?
• State the telemetry uptime target you require for real time steering to be acceptable, expressed as a percentage. Options: >99%, 95-99%, 90-95%, <90%
• Describe your acceptable mud weight window for the lateral and who on site can authorize changes during a run.
• Separate mandatory steering program parameters from negotiable ones and name the top two mandatory parameters.
• Do you have a defined escalation and fishing plan that the rig team must follow when torque or vibration exceed thresholds? Options: Yes, documented plan, Informal plan only, No defined plan
• Identify the role that can approve a same day configuration deviation yet still allow the run to be accepted by completions.

If things go wrong, what happens next

• Imagine a tool failure that requires fishing and adds two full days, what is your immediate decision rule about continuing versus sidetrack?
• Provide an estimate of the average cost per stuck pipe event in your recent wells, including fishing and rig time.
• Outline which contingency steps are preapproved on site versus those that require onshore sign off.
• In the past 12 months, how many fishing operations has your program executed in this basin? Options: 0, 1-3, 4-6, 7+
• What single logistics or procedural failure would cause you to halt a campaign immediately?

The other options on your table

• Name the alternatives you are actively evaluating and what each promises to change for your well outcomes.
• For each alternative, indicate whether it is the incumbent contractor, a national provider, or an internal remediation program. Options: Incumbent contractor, National provider, Internal remediation program, Other
• Specify the performance threshold, for example MTBF improvement or dogleg target, that would keep you with your current provider.
• Has anyone formally proposed solving these problems with internal staff or capital investment instead of a vendor? Options: Yes, formally proposed, Discussed informally, No internal proposal
• Provide the name and role of anyone internally advocating for an in house program and the proposed source of funding.

How you will know the pilot worked

• Assuming a pilot matches your stated goals, name the final barrier that would still prevent immediate contracting.
• Select up to three acceptance metrics you require for a successful pilot. Options: Dogleg severity (deg/100ft), MTBF improvement (%), Telemetry uptime (%), Lateral placement variance (ft), NPT days saved per well, Cost per lateral foot
• Enter threshold values for each chosen metric, for example MTBF +30% or dogleg below 3 deg/100ft.
• Specify the role or committee that must sign the acceptance certificate to release final payment or authorize follow on wells.
• Given a partial pass where some metrics exceed targets and others miss, indicate whether you would accept a weighted pass, partial payment, or require full compliance. Options: Accept weighted pass, Accept partial payment, Require full compliance

Operational constraints we must solve before we start

• Point to the single integration, data, permit, or tooling constraint you expect will be hardest to solve before mobilization.
• Do you have offset well logs, directional surveys, and mud logs in digital format ready to share with an engineering team? Options: All digital and ready, Some digital, some paper, Not available digitally
• Share the role and contact details for the person who owns data release and can approve transferring offset well files.
• Summarize the state of your rig telemetry integration, including whether MWD/LWD real time streams are already routed to onshore teams.
• Are there permit windows, regulatory reviews, or local approvals that must be closed before engineered fluids or telemetry gear can be used? Options: Known long lead approvals required, Short lead approvals only, No major permits required
• Give your best estimate of internal headcount available to support the campaign, for example onshore drilling engineers and coordinators.
• Declare whether unresolved constraints two weeks before mobilization would force a delay or require accepting higher operational risk. Options: Force a delay, Accept higher operational risk

Next steps and alignment

• Under what internal timeline do you expect a vendor decision to be final and who must agree to it?
• Select the preferred primary contact role for day to day coordination during the campaign. Options: Drilling Engineer, Completions Manager, Drilling Operations Director, Procurement, Onshore Coordination Engineer
• Choose your preferred cadence for progress updates during active drilling. Options: Daily operational call, Twice daily rig handover, Per shift updates, Weekly executive summary
• Share the earliest mobilization date you could accept.
• Would you commit to a multi well follow on within the same quarter if the pilot meets all acceptance criteria? Options: Yes, Maybe with conditions, Not at this time

• Operational Solution Walkthrough

• You confirm that the mapped tool, telemetry, and fluid actions address each failure mode identified in your offset wells.
• Confirm the current state and its cost
• Run the NPT reduction model using the provided offset well logs and deliver a line-item execution plan showing estimated days and cost savings before the follow-up meeting.
• Review offset well evidence and failure modes
• You agree that the modeled NPT and cost reduction is credible and sufficient to proceed to a pilot well decision.
• Provide complete offset well logs, mud reports, and recent run sheets for the candidate wells to be modeled.
• Confirm available rig dates and any operational constraints for a pilot well window.
• You agree the campaign acceptance criteria including dogleg severity target, MTBF threshold, and telemetry availability targets are appropriate for sign-off.
• Map directional tool and steering program to each failure
• Draft the pilot execution checklist including named owners, telemetry endpoints, and acceptance test steps and circulate for approval.
• Demonstrate telemetry and MTBF targets with modeled NPT reduction
• Present engineered fluids program tied to hole stability and cuttings transport
• Consolidated execution plan and acceptance criteria
• Validate the plan with you
• Agree next steps and commitments

• Operational Solution Walkthrough
• Solution Experience Deck
• Solution Brief — Operational Solution Walkthrough

• meeting
• slides
• document

• Mobilize and Deploy Rotary Steerable System
• Operate MWD/LWD Telemetry and Real-Time Data Link
• Execute Directional Steering to Target Trajectory
• Supply and Maintain Engineered Drilling Fluid System
• Perform Hole-Cleaning and Circulation Sweeps
• Run Torque-and-Drag Mitigation Operations
• Provide Onsite Directional Driller and Field Engineer
• Provide Downhole Tool Maintenance and Spare Parts
• Conduct Fishing and Downhole Tool Retrieval Services
• Acquire LWD Formation and Trajectory Logging
• Transmit Real-Time Telemetry to Client Systems
• Support Completion Hardware Running and Standoff Control
• Deliver Well Run Data Package (trajectory, mud, torque)

Mobilize and Deploy Rotary Steerable System

• Which rig types and rig specifications (top drive capacity, hookload rating, pump count) will your program use for rotary steerable mobilization? Options: Conventional land rig with top drive, Pad rig with top drive and high-flow mud pumps, High-spec AC rig with 3+ pumps, Other
• What rotary steerable system class and maximum torque and weight-on-bit capacity do you require for laterals over 7,000 ft?
• How many spare bottomhole assemblies and spare rotary steerable spares must be staged in-basin before mobilization? Options: 1 BHA spare, 2 BHA spares, 3+ BHA spares, Custom
• Who on your team is the authorized rig point of contact for tool rig-up checks and hydraulic hook-up prior to mobilization?
• When is the target mobilization date and what rig shift handover window should the mobilization plan accommodate?

Operate MWD/LWD Telemetry and Real-Time Data Link

• Where will the telemetry surface unit be located on the rig (for example doghouse, mud logging van) and what is its distance to the rig floor?
• Do you require specific MWD/LWD sample rates for inclination, azimuth, and gamma for geosteering decisions? Options: 1 sample per second, 1 sample per 5 seconds, 1 sample per 30 seconds, Custom
• Confirm the target telemetry latency range in seconds to your operations center for real-time steering decision making. Options: <5 seconds, 5-15 seconds, 15-60 seconds, >60 seconds
• Provide the expected integration endpoint for real-time telemetry (IP, DNS name, or integration endpoint) and any VPN or firewall constraints we must plan for.
• Specify whether you require telemetry redundancy (for example mud-pulse plus wired drill pipe) and which secondary path is preferred. Options: Mud pulse only, Mud pulse plus wired drill pipe, Wired drill pipe only, Acoustic backup, Other

Execute Directional Steering to Target Trajectory

• List the plan view and vertical target corridors with measured depth, true vertical depth, inclination, and azimuth tolerances for each planned lateral.
• Estimate the acceptable dogleg severity in degrees per 100 ft for the campaign to meet completion runnability. Options: <=2 deg/100 ft, 2-3 deg/100 ft, 3-5 deg/100 ft, >5 deg/100 ft
• Describe the steering program escalation steps you want if inclination or azimuth trends deviate from the plan by more than the allowed tolerance.
• Select the acceptable landing-position tolerance from the target pay zone measured in true vertical depth or lateral displacement. Options: <=10 ft TVD, 10-25 ft TVD, 25-50 ft TVD, >50 ft TVD
• What acceptance criteria will confirm directional steering is successful for a well (specify dogleg threshold, landing tolerance, and an approved trajectory log format)?

Supply and Maintain Engineered Drilling Fluid System

• Choose the base fluid system and the target mud weight window in pounds per gallon for the lateral section. Options: Water-based mud 8.5-10.0 ppg, Oil-based mud 9.0-12.0 ppg, Synthetic-base mud 9.0-11.5 ppg, Custom
• State the required polymers or additives for hole cleaning and suspension based on offset well lithology (for example high-clay or high-sand conditions).
• Identify the maximum allowable total circulating pressure at planned flow rates to avoid inducing losses in the lateral section.
• Quantify the solids-control configuration you expect onsite (number of shakers, desanders, centrifuges) for the campaign. Options: Standard solids control (shakers + desander), Enhanced system (shakers + desilter + centrifuge), Full system including mud cleaners, Custom
• Record who in your organization must approve changes to fluid weight or chemistry while drilling and the required approval timeframe.

Perform Hole-Cleaning and Circulation Sweeps

• Name the sweep volumes and sweep fluid compositions you want used prior to trips and at each casing point (provide in barrels or gallons).
• Enter the minimum combined annular velocity target in feet per minute you expect for effective hole cleaning in the lateral at planned flow rates. Options: >200 ft/min, 150-200 ft/min, 100-150 ft/min, <100 ft/min, Custom
• Outline the planned circulation and backreaming schedule for cuttings removal during long laterals, including any reciprocation steps.
• Assign the operational responsibility for confirming effective hole cleaning during sweeps: rig pump operator, field engineer onsite, or remote engineering support. Options: Rig pump operator, Field engineer onsite, Remote engineer, Shared responsibility
• Define the escalation steps if cuttings loading or torque and drag exceed pre-drill thresholds during circulation.

Run Torque-and-Drag Mitigation Operations

• Attach the expected maximum surface torque limits and the alarm thresholds that should trigger mitigation actions during drilling.
• Report the mechanical mitigation methods you prefer for high torque sections such as variable RPM, diluent sweeps, or torque-reduction subs. Options: Adjust RPM and WOB, Use lubricants or diluents, Run torque-reduction sub, Change BHA design, Combination
• Measure which torque-and-drag metrics you want reported in real time for analysis (for example surface torque, block position, downhole torque estimate). Options: Surface torque, Block position, Downhole torque estimate, All of the above, Custom
• Set the planned criteria for running remedial casing or liner actions if torque exceeds safe operational limits.
• Explain how you want casing wear and abrasive exposure to be monitored and mitigated across the campaign.

Provide Onsite Directional Driller and Field Engineer

• Include the minimum experience level for the onsite directional driller in years and basin-specific well counts. Options: >10 years and 50+ basin wells, 5-10 years and 20-50 basin wells, <5 years or requires supervision, Custom
• Provide the expected onsite coverage model for directional and engineering support (24/7 with two crews, day shifts with remote night support, or day shifts only). Options: 24/7 two crews, Day shifts with remote night support, Day shifts only, Custom
• Select required certifications for field engineers such as well control level and H2S training that must be present onsite. Options: Well control certification required, H2S and HSE training required, Both well control and HSE required, Other
• Indicate the reporting cadence and format you want from the field engineer for every drilled section for example hourly PDF, real-time dashboard updates, or shift-end reports. Options: Hourly PDF, Real-time dashboard, Shift-end report, Combination
• Choose the escalation contacts and preferred contact method if the field engineer cannot resolve a downhole issue during a shift. Options: Onsite toolsmith phone, Regional technical lead phone, Remote operations center, Other

Provide Downhole Tool Maintenance and Spare Parts

• State the minimum spare parts list you require staged in-basin before the first run including BHA collars, RSS spare parts, MWD batteries, and telemetry antennas.
• Identify the mean time between failures MTBF threshold in hours per tool that you require as a contractual performance metric. Options: >=200 hours, 100-200 hours, <100 hours, Custom
• Quantify your preferred spare tool replenishment lead time for in-basin shipping after a failed tool is diagnosed. Options: <48 hours, 48-72 hours, 3-7 days, >7 days
• Record whether you require onsite tool refurbishment capability versus sending tools to a maintenance facility for overhaul. Options: Onsite refurbishment required, Send to maintenance facility, Hybrid approach
• Name preferred maintenance facilities or cities where you authorize tool overhauls to be performed if onsite refurbishment is not available.

Conduct Fishing and Downhole Tool Retrieval Services

• Enter the maximum acceptable non-productive time window for fishing operations before authorization to sidetrack the hole. Options: <24 hours, 24-48 hours, 48-72 hours, >72 hours
• Outline the fishing tool inventory and sizes you require to be available for typical lateral tool failures.
• Assign the approval authority for initiating a fishing run versus pulling out of hole for BHA recovery and who must sign off. Options: Onsite rig manager, Your drilling engineer, Joint decision, Other
• Define the communication protocol and estimated mobilization time for specialist fishing crews when a stuck-pipe event is declared.
• Attach the acceptance criteria for a successful retrieval including required recovered parts list or log evidence to close a fishing event.

Acquire LWD Formation and Trajectory Logging

• Report the LWD logs required for geosteering including gamma, resistivity, density, neutron, and sonic and any minimum depth of investigation requirements.
• Measure the preferred logging interval by measured depth for formation evaluation and trajectory correction. Options: 1 ft, 5 ft, 10 ft, Custom
• Set the reporting frequency for tool face, inclination, and azimuth that you need for steering corrections while drilling. Options: Real-time 1 Hz, 1 sample per 5 seconds, 1 sample per 30 seconds, Custom
• Explain how you want LWD quality control flags and bad-sensor markers to be reported in the log package for post-run analysis.
• Include whether you will provide offset-well petrophysical models or templates we must use for in-run correlation. Options: Yes, will provide models, No, prefer in-run calibration, Will provide after kickoff

Transmit Real-Time Telemetry to Client Systems

• Specify the integration endpoint format you require for telemetry delivery such as MQTT, REST API, or secure SFTP and any required field names. Options: MQTT, REST API, SFTP, Other
• Identify the telemetry performance targets you expect for planning purposes including target uptime and packet loss figures. Options: >99% uptime target, 95-99% uptime, 90-95% uptime, Custom
• Quantify the data fields and sampling rates to be forwarded to your integration endpoint and indicate if you will attach a schema.
• Record your preferred authentication and network method for the telemetry endpoint for example VPN credentials, IP allowlist, or token-based authentication. Options: VPN, IP allowlist, Token-based OAuth, Other
• Name the recipients and escalation path in your operations center who must be notified of telemetry outages or degraded data.

Support Completion Hardware Running and Standoff Control

• Enter the completion hardware outer diameter and inner diameter restrictions and the standoff targets required to support running completion strings after drilling.
• Outline the acceptable casing wear and dogleg limits that would allow the completion hardware to be run without rework. Options: <=3 deg/100 ft dogleg and no casing wear, <=4 deg/100 ft with minor wear, Custom
• Assign responsibility for verifying standoff and centralizer placement prior to running completion hardware. Options: Rig crew, Field engineer, Completion contractor, Joint responsibility
• Define the verification logging or drift run required post-drilling before the completion run for example caliper, drift, or casing inspection. Options: Caliper run, Drift run, Casing inspection log, Combination
• Report the expected deliverable format for the as-drilled verification to be handed to the completion crew for immediate use. Options: PDF well log package, Digital LAS files plus survey CSV, Dashboard export only, Combination

• Master Services Agreement (MSA)
• Statement of Work (SOW)
• Pricing Schedule & Commercial Terms
• Performance Pricing Addendum
• Warranty & Reliability Commitment
• Acceptance Criteria & Payment Milestones
• Mutual Operational Obligations Annex
• Change Order Agreement
• Insurance & Certificate of Insurance (COI) Requirements
• References & Proven Performance Confirmation

• Go-live Health Check (Week 1-4)
• First Measurement Review (Weeks 4-10)
• Acceptance Gate and Incumbent Wind-down (Around Day 90)
• Quarterly Operational Review

• Re-confirm success criteria and owners
• Determine whether placement accuracy and NPT hours per well are trending toward the targets recorded in Well Program Scope.
• Agree a corrective action plan with owners and dates to address the top contributors to any shortfalls.
• Deliver a root-cause analysis for any wells failing placement accuracy with recommended steering and fluids adjustments.
• Schedule spare-tool mobilization or maintenance actions aimed at improving tool MTBF and confirm dates in the logistics plan.
• Restate acceptance criteria and numeric targets
• Produce a documented acceptance decision for each criterion recorded in Well Program Scope with a named signatory.
• Confirm incumbent wind-down actions are agreed and scheduled so no team members continue work in the legacy provider environment.
• Publish the acceptance decision record including pass/fail per criterion, evidence links, and the named signatory.
• Execute incumbent wind-down tasks: archive or migrate legacy data, set read-only access where required, and close any renewal flags on the incumbent contract.
• Create remediation tickets for any failed acceptance criteria with owners and completion dates and add to the shared backlog.
• Trend analysis for MTBF and completion-runability
• Confirm MTBF and completion-runability rate are stable or improving relative to targets recorded in Well Program Scope, or identify corrective actions if not.
• Agree the top backlog priorities for the next quarter with owners and resolution dates.
• Update the shared backlog with priority, owner, and target resolution dates for the top three operational issues.
• Deliver a quarterly field performance summary including MTBF, NPT hours per well, placement accuracy trend, and completion-runability rate.
• All deployment validation checklist items are either verified complete or assigned a remediation owner and date.
• No open telemetry or tooling blockers remain unresolved beyond the next 7 days without an assigned owner.
• Publish the go-live validation report listing verified checks, outstanding issues, and assigned owners.
• Remediate any critical telemetry or integration failures and confirm resolution via the shared channel before the next review.
• Present first-period outcome data
• NPT and major incident review
• Root-cause diagnosis for variances
• Present final outcome data against each criterion
• Deployment and telemetry validation
• Document pass/fail per criterion and capture formal acceptance
• Early operational signals
• Backlog and enhancement request burn-down
• Agree corrective actions and owners
• Update shared backlog and acceptance timeline
• Open blockers and immediate risks
• Incumbent wind-down
• Field feedback and procedural improvements
• Agree remediation plan for any failed criteria
• Agree next quarter priorities and measurable targets
• Agree immediate remediation actions