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Drilling Services
Capital-intensive extraction and processing programs where safety, regulation, and supply chain complexity define execution.
SLB
Halliburton
Baker Hughes
NexTier
Inside this journey
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Pre-Discovery
Align decision roles, timeline, data access, and recent well history before deeper diagnosis.
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Stakeholder Alignment
Confirm decision roles, timeline, required data access, and what ‘good’ looks like for drilling, completions, and operations stakeholders.
Alignment Questions
Quick Context — help us understand your program at a glance
- How many wells are in this drilling campaign or batch you want us to evaluate?
- Who will be our day-to-day operator contact for technical questions and who signs off on scopes (names and roles)?
- What basin(s) and play(s) are these wells in?
- How soon do you expect to decide on a directional/fluid provider for the initial well?
- Who else on your team should be looped into technical decisions (completions, operations, procurement)?
Are we just accepting avoidable failures?
- Tell us about the most recent well that went off-plan: what happened and how did it change the project?
- How often are you experiencing stuck-pipe, fishing, or tool-failure events across recent wells?
- When a downhole failure occurs, what are the typical immediate consequences you see (choose all that apply)?
- How does the team emotionally react after those events—frustration, resignation, urgency for change? Describe.
- Have you accepted any workarounds or temporary fixes that you know are increasing long-term cost or risk?
What is the real price of downtime and missed placement?
- When drilling goes over AFE due to NPT, how do you quantify that impact today?
- Estimate the average incremental cost you attribute to a fishing or long stuck-pipe event on these wells.
- How much schedule slip (days) does a typical downhole failure add to your campaign on average?
- Which stakeholders feel the most pressure when these costs and delays happen (select top two)?
- Have past overages changed how you evaluate vendor proposals (e.g., more focus on guarantees, references, or MTBF data)? If so, how?
Who signs, who blocks, and what keeps deals stuck?
- Who ultimately approves contracting for directional + fluids services, and who can veto mobilization?
- How long is your internal approval cycle for a new service provider and what are the common gating items?
- What approvals or data access do we need before we can build a credible well-performance analysis (offset logs, LWD/MWD files, mud reports)?
- Which decision criteria will swing this engagement—price, past performance in-basin, MTBF, telemetry quality, guarantees, or crew continuity?
- If we propose a pilot well, who needs to be satisfied for the pilot to convert into a campaign? List roles and must-have evidence.
Where’s the story in your data — and where is it missing?
- Do you have offset-well files (MWD/LWD surveys, dogleg severity logs, torque-and-drag reports) available to share?
- What specific downhole failure data do you currently track (select all that apply)?
- How would you rate your rig telemetry and real-time data reliability for making steering decisions?
- Share an example: which well in your offsets best illustrates your current problem and why? (well name, date, and short description)
- Are there internal or third-party constraints that prevent sharing full logs or failure reports (NDAs, custody, vendor contracts)?
- If we asked for MTBF and dogleg severity statistics for the last 12 months, could you provide them? If not, what would you accept as a credible proxy?
What would it genuinely feel like to hit target every run?
- Describe the best-case lateral placement and completion outcome you want to see from our engagement.
- What numerical targets would make this engagement a clear success? (pick the metrics you care about)
- Which dogleg severity, placement tolerance, and MTBF thresholds would make you confident to scale from 1 well to a campaign?
- Which downstream completion constraints must we honor to avoid causing new problems (e.g., bending limit, gauge, casing design)?
- How will you measure success internally—who owns the KPIs and how often will they review performance?
If we asked you to try just one well, what would make it easy to say yes?
- How open are you to a single-well pilot that includes performance-based elements (money-back guarantee, uptime SLAs)?
- What commercial terms are deal-makers vs deal-breakers for a pilot (day rate caps, performance penalties, mobilization windows)?
- Which operational readiness items must be confirmed before mobilization for a pilot (choose all that apply)?
- What contingency plans do you require up-front if a tool fails—on-site spares, expedited shipping, or alternative well plan?
- What is a realistic mobilization window for you if we finalize terms tomorrow?
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Current State Mapping
Document recent well outcomes, stuck-pipe and fishing events, tool reliability metrics, and baseline drilling and completion constraints.
Current State
Tell Me About Your Last Few Wells
- How many horizontal/extended-reach wells did your team drill in this basin over the past 12 months?
- Thinking of those wells, how would you summarize their budget and schedule outcomes?
- Which of the following issues showed up most frequently across those wells?
- Can you share one recent well (name or ID) that best represents the problem you want to solve and a one‑sentence outcome summary?
- What was the average cost impact per well when those failures occurred (include rig time + remediation)?
Are You Quietly Accepting Preventable NPT?
- How often do you experience stuck‑pipe incidents that require fishing or sidetracks on horizontal laterals?
- When a stuck or fishing event happens, where does the root cause most often trace back to?
- How long do those events typically extend drilling on the well (average additional rig days)?
- Describe how these events affect your team emotionally and operationally (e.g., stress on rig crew, post‑mortem friction, stakeholder pressure).
- Which preventative actions have you tried already to reduce stuck / fishing frequency?
- How confident are you that those actions were given a fair, baselined test (not a one-off)?
What Broke and When Did You First Notice It?
- Looking at directional and downhole tool reliability—do you have a current MTBF (mean time between failures) or failure rate for your directional string in this basin?
- If you have MTBF or failure rates, what are the ballpark figures for the past year (or mark Unknown)?
- Which tool/system failures have been most common (pick all that apply) and give an example for one recent failure in the follow-up field.
- Do you have the run-by-run tool performance logs (bit wear, vibration, torque) and are you able to share offset‑well logs for us to review?
- When failures occurred, who typically made the call to continue vs. stop/dress the BHA, and how quickly were those calls documented?
How Consistent Are Your Laterals, Really?
- What percentage of your recent laterals finished inside the geologic pay zone target (per your post‑job evaluation)?
- What dogleg severity (DLS) range do your completions teams consider acceptable to run completion hardware reliably?
- How often do lateral trajectories deviate more than your accepted tolerance, and what typically causes those deviations?
- Share a recent example where placement inconsistency directly caused a completion problem (e.g., packer hang, inability to land completion). What happened and what was the cost/time impact?
- How are target placement and dogleg criteria currently translated into steering programs—automated directives, manual driller adjustments, or a hybrid?
Who Feels the Pressure When Things Go Sideways?
- Who are the key decision‑makers for directional tool selection, mud program changes, and emergency fishing spend in your organization?
- When a downhole failure threatens budget, what approval timeframe is typically required to authorize a contingency spend (e.g., fishing + sidetrack)?
- How would you describe your organization’s appetite for replacing an incumbent directional provider mid‑campaign if presented with evidence of better outcomes?
- Tell us about any internal biases or assumptions that shape provider decisions (e.g., lowest day rate, national brand preference, long-standing relationships).
- What non‑technical constraints (contract terms, permitting, joint venture approvals) most often slow or block switching providers?
If We Could Measure One Thing to Predict Failure, What Would It Be?
- Which KPI do you currently believe best predicts a costly downhole event?
- Do you have a centralized dashboard that captures these KPIs in near‑real time?
- Please provide the current baseline numbers for the top two KPIs you track (or mark Unknown).
- Where does the KPI data currently live and who owns its accuracy (e.g., operator data lake, vendor portal, rig systems)?
- How would you rate the trustworthiness of that data on a scale from 1–5 and why?
What’s Standing Between That and Reality?
- Which operational constraints most limit your ability to improve reliability and placement (select all that apply)?
- How well stocked is your current spare and expendable inventory for directional BHAs and MWD/LWD electronics?
- Describe recent situations where logistics (spares, crew, fluids) directly caused a delay or forced a sub‑optimal technical choice.
- How reliable are your telemetry links (bit rate, latency, packet loss) for real‑time decisioning on deviated sections?
- What internal processes or approvals would need to change to allow a rapid pilot or a mid‑campaign tool swap?
What Would Success Look Like On Your Next Well?
- If you could eliminate one failure mode on the next well, which would create the biggest financial and schedule benefit?
- Set targets for the next well: ideal reduction in NPT, placement accuracy, and dogleg severity.
- What commercial outcomes would make you feel comfortable switching or piloting a new directional+fluids approach (e.g., cap on fishing spend, performance guarantee, shared risk)?
- What acceptance criteria will your completion team use to sign off on the wellbore for running completion hardware?
- How soon would you want to see meaningful data or results from a pilot (hours of drilling, number of lateral feet)?
What Would We Need to See and Share to Move Forward?
- Are you able to share offset well logs, dogleg/DLS plots, and recent MWD/LWD telemetry so we can do a baseline comparison?
- What access and confidentiality requirements would govern sharing that data with an external provider?
- Which pilot structure would you find most compelling for validating performance (single well pilot, split‑lateral test, staged rollout across rigs)?
- Who on your side would be the best technical and commercial contacts to coordinate a data review and pilot agreement?
- What timeline would allow your team to plan a pilot without disrupting current commitments (weeks/months)?
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Outcome Discovery
Define target lateral placement, acceptable dogleg severity, reliability thresholds, and the financial and schedule impact of failures.
Discovery Questions
Start with a Single Well: Tell Me the Story
- Which well or well identifier (name, pad, API) would you like us to use as the reference for this conversation?
- When did that well run happen (month/year) and which rig was used?
- Who on your team owned directional performance and who owned completions for that well?
- Briefly describe what went differently than expected on that well (placement drift, stuck pipe, tool failure, fishing, long run-in times, etc.).
- Roughly how many extra rig-hours or days did that issue add to the AFE for the well?
- How did that outcome make your team feel—was it frustration, resignation, urgency to change, or something else?
Where the Money Actually Leaves the Building
- If you treated every minute of NPT as avoidable, what would your budget conversations look like differently?
- Which single failure mode historically causes the largest cost per event on your wells?
- How frequently do you experience that failure mode across recent wells (last 12–24 months)?
- When a failure occurs, what is the typical operational path—do you pull out and run a fishing job, sidetrack, wait on spares, or something else?
- Quantify the average direct cost you assign to a single severe downhole failure on a lateral (ballpark):
- Which financial consequence worries you most—immediate AFE overrun, lost production, long-term completion rework, or reputational risk?
Are We Comfortable With ‘Good Enough’?
- What if your current directional performance is 'good enough' for the past, but not for the scale or economics you need next—what would that feel like?
- What is your current internal threshold for acceptable lateral placement accuracy (distance into/within the pay zone)?
- What maximum dogleg severity (DLS) do your completions teams accept to run their hardware reliably?
- How often do you see DLS exceed your acceptable threshold on last-12-month laterals?
- What reliability metric matters most to you when evaluating a directional vendor—mean time between failures (MTBF), % of runs without intervention, or another metric?
- How would it change your confidence and planning if a vendor could guarantee a MTBF or failure-rate in writing for your basin?
What Would Truly Change the P&L—and Your Mind
- If you could remove the biggest single technical risk on your lateral runs, what would the economic upside look like for your program?
- Which outcome would most justify choosing a different directional/fluid program: fewer fishing jobs, shaved days off schedule, more consistent placement within pay, or lower overall cost-per-lateral-foot?
- How much of a performance premium would you accept to reduce the risk of a fishing operation by 50% (percent increase in day-rate or performance fee)?
- When you think about 'consistent placement', what specific KPI would convince you—percentage of laterals hitting target, average deviation in feet, or completion-pack running metrics?
- Tell me about a time when better placement or lower DLS would have unlocked a bigger completion strategy—what was at stake?
The Hard Limits: Risk, Reliability, and What You Can’t Compromise
- What's an outcome you will not accept under any circumstances (e.g., any fishing incident, >3 days NPT, >X ft out-of-zone)?
- Which of these constraints are non-negotiable for an initial trial well?
- How do you currently qualify a vendor’s MTBF and tool reliability—data from your basin, vendor lab tests, or operator references?
- What telemetry performance do you require for real-time steering decisions (latency and update rate)?
- If a vendor proposed a performance guarantee tied to NPT or placement accuracy, what validation steps would you insist on before signing?
- How do you emotionally react when a vendor asks to run a pilot—cautious optimism, skeptical, outright distrust, or eager to try?
Operational Reality Check: Can We Actually Deliver What You Want?
- If a vendor promised <3°/100ft DLS and a specified MTBF, what operational trade-offs do you expect (e.g., lower ROP, different mud weight, more wireline runs)?
- Which rig or fleet constraints usually limit your directional choices (rotary table vs top drive, pump capacity, BHA handling, crew experience)?
- What spare-tool and logistics timelines are acceptable before you’d halt a campaign for a missing part?
- How do you evaluate the competence of a vendor’s field engineers—hands-on trial, references, certificates, or past well logs?
- Which fluids constraints are most likely to force a deviation from a vendor’s ideal steering program (formation instability, weight windows, additives availability)?
- Describe any internal process or approval that routinely slows a vendor mobilization (procurement, safety vetting, rig owner approvals, etc.).
Decide Fast or Live with the Risk: What Would Make You Say Yes?
- What one piece of evidence would most quickly convince you to pilot a new rotary steerable + engineered mud solution on a first well?
- Which commercial model are you most open to for a pilot—day-rate + performance incent, fixed-price pilot, or risk-reward share?
- Who on your side would need to sign off for a pilot and what are their top concerns (list names/roles if possible)?
- How soon could you realistically schedule an initial run if we aligned on scope and guarantees?
- What small, non-financial win would make your team feel comfortable moving from pilot to campaign (e.g., one clean lateral, telemetry consistency, zero fishing events)?
- Any final concerns or red flags we haven’t covered that would prevent you from trying a new approach?
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Solution Experience
Walk through outcomes using the customer’s offset-well data to show how specific rotary steerable and mud programs reduce NPT and improve placement consistency.
Experience Meetings
- Pre-Experience Data & Stakeholder Alignment
- Current State & Consequence Workshop
- Offset-Well Analysis: Diagnosis & Baseline Metrics
- Solution Experience — Programed Outcomes with Customer Offsets
- Pilot Readiness & Decision Meeting
- Seller to produce simulation outputs and KPI delta tables (baseline vs proposed) for distribution.
- Establish baseline KPIs that the proposed solution must demonstrably improve.
- Obtain customer sign-off on which offset wells will be used as proof cases.
- Seller to provide an annotated offset-well diagnostic report including time-series plots and root-cause annotations.
- Customer to confirm that the prioritized failure modes match operational experience and add any overlooked events.
- Agree which telemetry windows and data slices will be shared live during the Solution Experience walkthrough.
- Restate Future State & Acceptance Criteria
- Deliver proof that the proposed tool and mud programs achieve the agreed future-state metrics on actual offsets.
- Force customer validation at every step to ensure alignment and avoid speculative demonstrations.
- Agree a concrete pilot scope (which well(s), acceptance criteria, and measurement plan) to move from modeled proof to field validation.
- Seller to deliver detailed per-well runbooks showing rotary steerable settings, BHA recommendations, and mud program parameters.
- Introductions & Meeting Objectives
- Customer to confirm pilot well selection and sign the pilot acceptance criteria document.
- Schedule on-rig validation cadence and define real-time dashboards/feeds for pilot monitoring.
- Review Pilot Scope and Acceptance Criteria
- Obtain mutual commitment to proceed with a defined pilot including scope, acceptance criteria, and timeline.
- Ensure operational readiness (tools, fluids, telemetry, crew) and assign clear owners for mobilization tasks.
- Set the commercial guardrails and contingency terms for the pilot period.
- Execute and sign pilot SOW or amendment that includes acceptance criteria and performance guarantees.
- Seller to mobilize specified tools, spares, and fluids and confirm telemetry feed test results before rig arrival.
- Create live dashboard and reporting schedule; assign owners for real-time decision points during the pilot.
- Schedule Pre-Deployment Readiness checklist meeting 72 hours prior to mobilization.
- Confirm a crystal-clear one-sentence current state agreed by both parties.
- Agree a set of consequence metrics and the data sources to quantify them.
- Ensure complete offset-well dataset is available or identify accountable owners for missing items.
- Establish who will validate the Solution Experience outputs (customer sign-off authority).
- Customer to upload complete offset-well package (surveys, logs, torque/drag, stuck-pipe reports, mud reports, rig time sheets).
- Seller to run initial QC on uploaded data and report any unreadable/missing files within 48 hours.
- Assign customer validation owner(s) who will sign the one-sentence current state and consequence metrics.
- Restate Confirmed Current State
- Produce an agreed, documented consequence model (hours and $) tied to specific failure events.
- Ensure all stakeholders accept the quantified impact and KPIs that will be used to measure improvement.
- Agree any assumption changes to be reflected in later simulations and proposals.
- Seller to deliver a spreadsheet with NPT hours, cost-per-hour assumptions, and per-well financial impact within 3 business days.
- Customer to confirm or correct cost assumptions (rig day rate, fishing costs, discretionary overhead) in the spreadsheet.
- Mark 2–3 offset wells as priority examples for the Solution Experience modeling.
- Baseline KPI Presentation
- Agree on a prioritized list of root causes (e.g., tool reliability in X formation, insufficient ROP due to torque/drag, mud weight instability).
- One-Sentence Current State Readback
- Timeline of Key Failure Events
- Rotary Steerable Program Walkthrough
- Trajectory & Placement Overlays
- Resource & Logistics Check
- Mud Program Adjustments & Effects
- Quantify NPT and Financial Consequence
- Data Inventory & Gaps
- Commercial & Risk Terms
- Torque/Drag and Stuck-Pipe Correlation
- Combined Simulation: NPT and Placement Improvements
- Consequence Metric Alignment
- Tool Reliability & Mud Program Behavior
- Stakeholder Impact Mapping
- Execution & Measurement Plan
- Customer Validation & Adjustments
- Diagnosis Summary & Prioritized Failure Modes
- Roles, Decision Rights & Prework Assignments
- Tieback & Problem Mapping
- Decision & Next Steps
- Customer Validation Checkpoints
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Solution Scope
Define tooling, fluids, field crew makeup, telemetry requirements, SLAs, and acceptance criteria for the initial well or campaign.
Scope Configuration
- Operate rotary steerable system during lateral drilling
- Deploy and manage MWD/LWD telemetry package
- Perform real-time geosteering to maintain pay-zone placement
- Maintain engineered drilling fluid properties on-site
- Run hole-opening reamers and rotary cutters
- Execute fishing and stuck-pipe recovery operations
- Change out bit and downhole tools on the BHA
- Perform tripping, backreaming, and hole-cleaning sweeps
- Assemble and rig-up directional BHA at surface
- Operate surface real-time data transmission systems
- Run casing and casing-wear mitigation services
- Inspect, repair, and rebuild downhole tools on-site
- Perform torque-and-drag mitigation runs
Scope Questions
Operate rotary steerable system during lateral drilling
- What lateral lengths are planned for the initial well(s)?
- What placement/dogleg severity targets must the RSS meet?
- Which RSS models (or performance characteristics) are required or preferred?
- Do you require continuous steering by our field driller or advisory steering with your driller?
- Are there BHA compatibility constraints (bit type, motor, MWD) we must accommodate?
- Describe any rig mechanical or operational limits affecting RSS operations (e.g., rotary speed, torque limits, rig space).
Deploy and manage MWD/LWD telemetry package
- Which telemetry method is required or preferred for downlink/uplink?
- What real-time data channels are mandatory (e.g., gamma, resistivity, inclination, azimuth, annular pressure)?
- What sampling or transmission rate is required for steering and geosteering decisions?
- Do you require redundancy or backup telemetry for critical sections?
- What surface receivers, logging centers, or data formats must the package integrate with?
- Are there specific data ownership, storage, or format requirements (LAS, SEG-Y, CSV, real-time API)?
Perform real-time geosteering to maintain pay-zone placement
- Do you have offset-well logs and geological models available for geosteering?
- What acceptable lateral placement tolerance is required (vertical feet from top/bottom of pay)?
- What maximum response time for steering adjustments do you require after receiving data?
- Who will have final steering authority on wellsite decisions?
- Will geosteering be supported by on-site geoscientist, remote geosteering center, or both?
- How many wells/campaigns need geosteering support under this scope?
Maintain engineered drilling fluid properties on-site
- What drilling fluid system is planned or acceptable (water-based mud, oil-based mud, synthetic, invert emulsion)?
- What target mud density and rheology windows must be maintained?
- Is solids-control equipment (shakers, desanders, centrifuge) available on the rig or do we need to supply it?
- How frequently do you require on-site fluid sampling and lab analysis?
- Are there environmental or disposal constraints that affect fluid choices (cuttings disposal, pits)?
- Describe any known wellbore stability or contamination risks that would change the fluid program.
Run hole-opening reamers and rotary cutters
- What hole-opening size(s) are required compared to drilled gauge hole?
- What formation types and abrasiveness are expected in the lateral?
- Do you require specialized cutter metallurgy or coatings for abrasive sections?
- Are hole-opener runs planned while drilling (continuous) or during planned ream runs/tripping?
- What spare/replacement inventory should be staged on-site for cutters/reamers?
- Any clearance requirements for BHA or casing that impact hole-opening choices?
Execute fishing and stuck-pipe recovery operations
- Has this wellbore/campaign had prior stuck-pipe or fishing incidents? If yes, describe frequency and causes.
- What response SLA do you require for an on-site fishing team after an incident?
- Should the scope include a dedicated fishing tool inventory and specialist on-call?
- Are there insurance, cost-recovery, or liability rules we should accept for fishing operations?
- Would you accept contingency actions (sidetrack, plug-and-abandon) as part of the escalation plan?
- Provide known well geometry or obstructions that might influence fishing tool selection (e.g., casing shoes, prior plugs).
Change out bit and downhole tools on the BHA
- How frequently are bit or BHA changes anticipated for the initial well(s)?
- Who will perform BHA change-outs at surface—rig crew, provider field crew, or third-party technician?
- Do you require provider-managed spares, inspection, and pre-run tool rebuilds on-site?
- Are there special handling, torque, or thread-companion requirements for your drillstring or BHA components?
- Should procedural checklists and sign-offs be required for each BHA change?
- What turnaround time is acceptable between pulling BHA and running the replacement?
Perform tripping, backreaming, and hole-cleaning sweeps
- How frequently should hole-cleaning sweeps be run (by depth or time)?
- What pump rate and equivalent circulation parameters are available on the rig?
- Do you require provider-supplied sweep fluids or chemicals (e.g., viscosifiers, friction reducers)?
- Are there known cuttings transport or hole-cleaning issues in this basin/offset wells?
- Should reaming be performed while pulling out-of-hole (backream) or while sliding/rotating during drilling?
- What solids handling and disposal capacity is available or required at site?
Assemble and rig-up directional BHA at surface
- Is there adequate rig floor space and lifting capacity to assemble the maximum planned BHA length?
- Do you require provider-performed pressure, function, and endurance tests prior to running BHA?
- Who provides the assembly crew and tooling for rig-up (operator, rig, provider)?
- Do you require documented QA/QC procedures and sign-offs for BHA assembly and make-up?
- Are there specific thread compounds, torque specs, or third-party certifications required for BHA make-up?
- What is the expected time window for rig-up and breakout activities (hours) to plan crew shifts?
Operate surface real-time data transmission systems
- What connectivity options are available at site for remote monitoring (satellite, cellular, wired)?
- Who are the recipients of the live data feed (operator team, remote geosteering center, vendor engineers)?
- Are there cybersecurity or VPN requirements for transmitting downhole data?
- What alerting thresholds and escalation contacts should be configured for key telemetry alarms?
- Do you require archival of raw real-time data and delivery format (e.g., API, files)?
- Do you require fuel/ power redundancy, UPS or generator support for surface telemetry systems?
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Mutual Commit
Agree commercial terms, performance guarantees, reference checks, and mutual responsibilities for mobilization and execution.
Agreement Modules
- Statement of Work (SOW)
- Master Services Agreement (MSA)
- Pricing & Payment Schedule
- Service Level Agreement (SLA) & Performance Guarantees
- Mobilization & Execution Responsibilities
- Acceptance Criteria & Initial Well Validation Plan
- Reference & Technical Capability Check
- Change Order & Scope Variation Process
- Insurance, Indemnity & Liability Schedule
- Data Access, Ownership & Telemetry Agreement
- Spare Parts, Tooling & Consumables Commitment
- Termination, Remedies & Dispute Resolution
- Pilot Trial & Acceptance Period Agreement
- HSE & Competency Confirmation
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Deployment
Operationalize the campaign with readiness checks, sequencing, and outcome validation.
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Pre-Deployment Readiness
Confirm rig specs, tool and spare inventory, fluids availability, telemetry links, and contingency plans before mobilizing.
Readiness Questions
Start Here — who are you and what brought you to this campaign?
- Which best describes your role in this program?
- How many wells are in the immediate program you’re focused on?
- What is your ideal timeline to make a supplier or process change for this program?
- Briefly, what is the single most important outcome you need from a directional/drilling fluids partner on this campaign?
- Who else on your team must be part of vendor selection and operational sign-off?
Are you quietly tolerating avoidable rig time and cost?
- How long have you been accepting non-productive time (stuck pipe, tool fishing, sidetracks, or placement misses) as a recurring cost of drilling?
- On average, how many stuck-pipe or fishing events have you experienced per well in the last campaign?
- When a downhole failure occurs, what is the typical incremental cost you see (rig time + remediation + lost production)?
- Tell us about the last incident that annoyed you most—what happened, how long did it add to the well, and what was the emotional impact on the team?
- What measures have you tried to reduce these events (e.g., different downhole tools, revised mud program, crew training)? Which felt helpful, which didn’t?
What if the tools you rely on are the weak link?
- Which directional/drilling toolsets have you used recently on these laterals?
- Do you currently track mean time between failures (MTBF) or similar reliability metrics for your directional vendor(s)? If so, what is your baseline number?
- What failure modes do you see most often (select all that apply) and roughly how often each appears?
- When a tool fails, how quickly is a replacement/spare typically available on-site or via mobilization?
- Describe a recent failure that required a fishing operation or sidetrack—what caused it, how long did recovery take, and what would you change next time?
Who pays the price when laterals miss the zone?
- How often have laterals in your recent program drifted outside the target pay zone or exceeded acceptable dogleg severity?
- What placement accuracy do your completions teams require (e.g., lateral window in feet, max allowable DLS)?
- How have placement misses affected completion runs (e.g., stuck packers, inability to run hardware, extra rig time)? Provide an example if possible.
- Which metric matters most to your completion success and commercial decision—directional accuracy, consistency of DLS, run success rate, or something else?
- How confident are you in the offset-well data you have to predict placement and steering behavior?
If you could wave a wand and remove surprises, what would the morning-after look like?
- What three quantitative goals would prove the partner is delivering value on your first well (e.g., X% fewer NPT hours, Y ft placement accuracy, Z MTBF)?
- Pick the top two outcomes that would make you consider expanding to a multi-well campaign.
- What would a successful initial well mean for your team emotionally and operationally (confidence, schedule relief, fewer emergency calls)?
- Which KPIs would you want included in a performance guarantee or SLA?
- How would you like to visualize/report performance during the pilot—daily dashboard, post-run report, or weekly review?
What’s standing between the plan on paper and getting rigs rolling?
- If your incumbent vendor could fix reliability tomorrow, what practical obstacles would still block faster, safer drilling (e.g., rig specs, fluids supply, crew slots)?
- Which rig specs are non-negotiable for you to accept a new tool/fluid combination?
- How robust are your telemetry and data links today—do you get continuous real-time data, occasional dropouts, or mostly post-run downloads?
- Do you have internal approval gates (HSE sign-off, engineering review, procurement window) that typically add lead time before mobilization? If so, how long?
- What contingencies would you expect the service provider to bring to site (spare tools, fluids inventory, alternate telemetry link)?
Okay—what would make mobilization a no-brainer?
- Which commercial model would lower your barrier to trying a new vendor for one well?
- What reference checks or evidence would you need before giving a partner the go-ahead (offset-well reports, basin-specific MTBF data, on-site reference call)?
- Who in your organization would ultimately sign off on a mobilization and what criteria do they require?
- If we agreed to a short, low-risk pilot well, what readiness items would you expect to be confirmed before mobilization (pick all that must be satisfied)?
- Realistically, what date would you be prepared to green-light a mobilization, assuming open issues above are resolved?
- What's one small assurance or contractual term that would make you comfortable committing to a first-well pilot?
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Deployment Enablement
Schedule mobilization, assign owners, run detailed execution checklists, and verify real-time data feeds and field engineer assignments.
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Validation Checklist
Verify telemetry quality, steering program parameters, mud program behavior, and acceptance criteria are met after initial lateral runs.
Validation Questions
Start Here — Tell Us About the Well That Keeps You Up at Night
- Which role are you answering for today?
- Who on your team will need to be involved in technical and commercial discussions for this campaign?
- How many wells make up the program or batch you’re evaluating right now?
- Which basin and play are these wells in (basin / field / pad names)?
- Briefly describe the primary reason you opened this conversation (one or two sentences).
When the Rig Stops: How Much Is It Costing You?
- If you totaled the last 6 months of NPT related to stuck pipe, tool failures, or fishing, would it change how you allocate capital?
- How frequently are you seeing NPT events caused by downhole failures or placement issues on similar laterals?
- On average, how many hours or days of rig time does a typical stuck-pipe or fishing event add for your wells?
- What is your best estimate of the incremental direct cost per NPT event (rig/day and fishing) in your program?
- Tell us about a recent incident where an NPT or placement miss had the largest operational or commercial impact — what happened and what was the outcome?
Who Really Calls the Shots? (Decision Paths, Timelines, and Hidden Hurdles)
- Who has final approval authority for selecting a directional/mud services provider for this campaign?
- Which internal groups must sign off before a mobilization can occur?
- What approval timeline do you typically work to for a pilot well (weeks/months)?
- Have previous vendor selections stalled because of contractual, insurance, or mobilization conditions? If so, what specifically caused the stall?
- Which commercial structures are you most open to for a first well: purely day-rate, partial performance incentive, or full performance-based?
What Have Your Last Wells Actually Taught You?
- Do you have offset-well datasets (survey runs, dogleg plots, LWD/MWD logs, torque/drag reports) ready to share for engineering review?
- What patterns do your offset wells show most clearly — drift out of-pay, excessive doglegs, recurring stuck-pipe at similar TVDs, or tool-specific failures?
- What MTBF (mean time between failures) or failure rate would you expect from a best-in-class directional tool in your basin? Please provide numbers if available.
- What average dogleg severity (deg/100ft) have your recent laterals recorded, and what would you consider acceptable?
- Share an example of an offset well where placement or tool performance exceeded or fell short of expectations — what drove that result?
What’s Getting in the Way of a Better Well? (Root Causes, Not Symptoms)
- If you had to name the single most common root cause of placement problems or stuck-pipe in your program, what would it be?
- How often do you experience telemetry dropouts or low-bandwidth that hinder real-time steering decisions?
- How do you currently manage mud weight and rheology changes in the lateral section—centralized lab support, field adjustments, or vendor-managed?
- When tools fail downhole, what’s your typical contingency path (fishing, sidetrack, wait-for-spare, rig down)?
- Describe the last time a small operational change prevented a larger problem on one of your wells — what was the change and why did it work?
If Everything Went Right: The Outcomes That Matter Most
- Imagine this campaign is a clear success — what three measurable outcomes would make you call it a win?
- Which KPIs will you use to evaluate success for the pilot well?
- What maximum dogleg severity and lateral placement tolerance must we meet to avoid completion run rework?
- What minimum telemetry performance (latency, update rate, packet loss) do you require to make steering decisions you trust?
- Quantify the acceptable reliability improvement you’d need to justify switching providers (e.g., MTBF increase, % fewer fishing events).
What Would Make You Trust a New Directional Partner?
- What evidence would change your mind about switching vendors: offset-well data, tool reliability reports, on-site engineer demos, commercial guarantees, or references?
- How important are basin-specific engineering teams and local experience when you evaluate a new provider?
- Which acceptance criteria would make your first well a ‘go’ for broader rollout: technical thresholds only, technical + commercial targets, or proof-of-concept milestones?
- Would you require third-party verification or joint post-run analysis to validate results from a new provider?
- Which reference checks matter most — similar offset well performance, regional safety record, or execution reliability across campaigns?
Where Could Small Changes Deliver Big Wins? (Operational Levers We Can Pull Together)
- Which of these operational levers do you believe are under-optimized today?
- How often are field engineers rotated between rigs in your programs, and does that affect continuity?
- What current fluid issues most commonly show up in laterals (e.g., balling, cuttings transport, ROP loss), and how are they addressed today?
- Do you maintain a spare-tool inventory on-site or rely on vendor mobilization for replacements?
- Have you previously adjusted steering programs in real time based on offset data? If yes, how did that change the outcome?
Ready to Move? What Would a Safe First Step Look Like?
- Would you consider a single-well pilot with clear acceptance gates as the next step?
- What mobilization timeline would you need to meet operational windows on your pad?
- Which readiness items must be confirmed before mobilization (select all that apply)?
- Which commercial model would make you most comfortable committing to a pilot?
- How will you measure the pilot’s success after the initial lateral runs (who signs off and what data will validate it)?
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Success
Review performance vs KPIs, capture lessons learned, and maintain a shared backlog for issues and enhancements.
Success Reviews
- Performance Review & KPI Workshop
- Lessons Learned / After Action Review (AAR)
- Shared Backlog Grooming & Prioritization
- Customer Performance Review & Commercial Reconciliation
- Playbook Update & Continuous Improvement Planning
Issues & Enhancements
- Obtain mutual sign-off on credits/bonuses or other commercial outcomes.
- Establish a regular cadence for backlog review and progress updates.
- Update the shared backlog with priorities, acceptance criteria, owners, and due dates.
- Create tickets for procurement-related items (spares, fluids) and link to backlog entries.
- Schedule sprint/release dates for engineering or process changes.
- Set recurring backlog grooming cadence (e.g., biweekly) and invite required stakeholders.
- Confirm the commercial path forward (extend, trial additional wells, or close-out) and required approvals.
- Issue adjusted invoices or credit memos per agreed reconciliation.
- Contract KPI & Guarantee Recap
- Agree and document commercial reconciliation based on validated KPI measurements.
- Introductions & Objectives
- Document commercial sign-off in CustomerNode and circulate to finance and legal teams.
- Request formal reference/testimonial if performance meets customer satisfaction thresholds.
- Record any contract amendments or new commercial terms for future wells.
- Scope of Playbook Changes
- Produce a prioritized list of playbook updates with owners and target completion dates.
- Agree a training plan to close competency gaps identified in the AAR.
- Ensure logistics and spare provisioning reflect lessons to reduce future NPT risk.
- Update monitoring rules to provide early warning on critical KPIs.
- Deliver updated playbook drafts for review and publish finalized versions to the shared library.
- Schedule and enroll field staff in required training modules before the next job.
- Place procurement orders for identified critical spares and update inventory targets.
- Implement revised dashboard thresholds and test alerting/escalation workflows.
- Create a shared, validated view of campaign performance vs KPIs.
- Quantify the cost and schedule consequences of KPI variances.
- Agree immediate mitigation actions with named owners and deadlines.
- Identify items requiring deeper root-cause analysis in follow-up sessions.
- Deliver a consolidated KPI variance report with supporting logs and timestamps.
- Assign root-cause investigation leads for each high-impact variance.
- Compute and circulate final dollar impact reconciliation for the campaign.
- Schedule the Lessons Learned AAR meeting with required pre-work deadlines.
- AAR Objective & Ground Rules
- Validate and document root causes with evidence and cross-functional agreement.
- Define specific corrective actions with acceptance criteria and validation methods.
- Create a knowledge capture plan to update playbooks and train crews before the next mobilization.
- Publish a formal AAR report with root-cause evidence, corrective actions, owners, and verification steps.
- Create test/validation runs (pilot parameters) for the next well and assign responsible engineers.
- Update the central knowledge base and notify field leads of required changes.
- Schedule hands-on training sessions or ride-alongs for crew members impacted by the lessons.
- Backlog Intake Review
- Produce a prioritized backlog with clear owners and measurable acceptance criteria.
- Ensure high-impact items have defined verification methods and target delivery windows.
- KPI Dashboard Walkthrough
- Triage & Categorization
- Timeline & Event Reconstruction
- Define Revised Procedures & Acceptance Criteria
- Measured Performance Summary
- What Went Well
- Top Variances & Root-Cause Summaries
- Prioritization (Impact vs Effort)
- Commercial Reconciliation Calculations
- Training & Competency Plan
- Financial & Schedule Impact Assessment
- What Failed & Root Cause Analysis
- Spares, Consumables & Logistics Update
- Define Acceptance Criteria & SLAs
- Mutual Actions & Next Steps
- Assign Owners & Roadmap Placement
- Sign-off & Record
- Monitoring Dashboard & Escalation Rules