Start with the Story: Your Recent Wells

• Tell us briefly about the latest batch of wells that flagged underperformance—how many wells, what pads, and the time window they were completed in?
• Roughly how far below type curve did initial production come in (choose the single best range)? Options: 0–5% below, 6–10% below, 11–15% below, 16–25% below, More than 25% below, Unsure/not analyzed yet
• Which indicators first made you suspect the issue was completion-related rather than reservoir-driven? Options: Lower-than-expected IP only, High variability across adjacent stages, Microseismic pattern mismatch, Rapid decline after short flowback, Mechanical issues during job, Other (explain), Unsure
• What completion provider ran those jobs and how long have they been your incumbent on this asset?
• What data do you already have available from those wells that we can review for diagnostics (select all that apply)? Options: IP and 30/60/90-day production, Pressure/ESP test data, Microseismic, Fiber-optic DAS/DFOS, Post-frac temperature logs, Fracture diagnostic runs (e.g., DTS/DAS), None/limited
• How would you describe the urgency to address the underperformance—from a scale of routine optimization to immediate commercial risk? Options: Immediate commercial risk (must act now), High priority within quarter, Optimize next year, Monitor and reassess later, Unsure

Are You Sure It's the Completions, Not the Reservoir?

• What would it mean for your program if the shortfall were actually 100% due to suboptimal stage design or execution?
• Which of these signals have you already used to separate completion failure from reservoir heterogeneity? Options: Cluster-to-cluster IP variance, Offset well comparison with same frac design, Microseismic showing inconsistent stimulated area, Pressure transient tests, No clear signals yet, Other
• Can you share a specific stage or cluster that underperformed and what the observable symptoms were (e.g., early screenout, low cluster contribution, short fracture half-length)?
• How consistent were execution logs and times (e.g., plug-to-plug cycle) across the underperforming wells? Options: Very consistent, Some variation but within expected, Large variation across stages, Execution logs incomplete/missing, Unsure
• Have you run or considered a back‑analysis or modeled redesign on offset wells to estimate expected uplift if completion variables change? Options: Yes—completed modeling, Yes—in progress, Planned but not started, Not planned, Unsure
• If we asked you to point to the single most convincing piece of evidence that completion design is the root cause, what would it be?

What Keeps You Up at Night When a Well Misses Its IP?

• How does underperformance impact your commercial targets and internal KPIs in the next 12 months? Options: Severely (misses budget/targets), Moderately (adjustments required), Manageable with minor impact, Minimal impact, Unsure
• What are the operational consequences you’ve seen—schedule delays, reworks, additional stimulation, or other actions—after noticing low IP? Options: Re-stimulation attempted, Additional diagnostic runs, Delay to next phase/pad, No corrective action taken, Other (explain)
• How does this situation affect internal stakeholder confidence (operations, asset team, finance)? Options: Erodes confidence quickly, Creates concern but controllable, Little to no effect, Varies by stakeholder
• How comfortable are you taking a short pilot that changes per-stage cost in order to prove a larger-scale uplift? Options: Comfortable with modest cost increase, Only if cost-neutral, Need clear ROI model before approving, Not comfortable—avoid extra cost, Unsure
• Tell us about a past completion issue that caused the biggest headache—what happened, how long it took to resolve, and what you learned?
• What safety or regulatory concerns factor into decisions to change completion execution on an active program? Options: Permit constraints, Well control history, Local HSE rules, Internal EHS approvals, None significant, Other

Who Really Decides Whether a Pilot Becomes the New Standard?

• If we propose a pilot, who in your organization has final sign‑off to move from pilot to repeatable program? Options: Asset Manager, Completion Engineer, Operations Manager, VP of Production, Finance / Commercial, Joint Venture partner, Other
• Who will be our day‑to‑day operational contact during the pilot (name/role), and who are the technical reviewers we should prepare materials for?
• What procurement or contracting constraints should we know about—preferred vendors, PO timelines, or pre-qualification requirements? Options: Standard PO process, Master services agreement required, Vendor pre-qualification needed, Time-consuming procurement, Flexible/fast-track allowed, Other
• How will success be objectively evaluated at the pilot level—what metrics or thresholds convert to a 'go' for scale?
• Who else outside your core team needs regular updates (e.g., JV partners, land, HSE, regulatory), and at what cadence? Options: Weekly, Bi-weekly, Monthly, On major milestones only, Not required
• Are there any internal political or organizational risks that could block a successful pilot even if the technical results are positive?

If We Could Re‑Design One Stage, What Would We Test?

• Which single design variable do you suspect would yield the biggest uplift if optimized (choose one): spacing, cluster density, perforation strategy, proppant loading, fluid chemistry, or plug tech? Options: Stage spacing, Cluster density/placement, Perforation cluster geometry, Proppant type/volume, Fluid chemistry/viscosifier, Plug technology, Other
• How many stages would you be willing to include in an initial pilot on a single well or pad to generate statistically meaningful results? Options: 1–3 stages, 4–8 stages, 9–15 stages, Entire well (~30 stages), Unsure—need guidance
• Which plug technologies are acceptable for your wells today (select all that apply) and which carry elevated risk for you? Options: Dissolvable frac plugs (acceptable), Dissolvable (elevated risk), Composite plugs (acceptable), Composite (elevated risk), Cement/ball-and-shear options, No preference
• What monitoring and telemetry would you demand on pilot stages to feel confident (e.g., fiber, pressure gauges, DTS/DAS, microseismic)? Options: Fiber-optic DAS/DFOS, Downhole gauges, Microseismic, Surface treatment data only, Temperature logs, All available diagnostics, Other
• What acceptance criteria would demonstrate pilot success to you—list primary metrics and minimum thresholds (e.g., % uplift, cost per incremental bbl, cycle time improvement).
• Would you prefer a single-variable pilot (change one thing at a time) or a bundled test (multiple complementary changes) and why? Options: Single-variable, Bundled test, Hybrid/depends on objective, Unsure—need recommendation

Talk Money, Timing, and What You Can Live With

• What is your expected per-stage cost today (ballpark) and what is the maximum per-stage spend you would consider for a pilot?
• What uplift in IP or EUR would justify a per-stage cost increase of 5–15% for you? Options: <5% uplift, 5–10% uplift, 11–20% uplift, >20% uplift, Depends on NPV model
• What mobilization windows are mandatory for your upcoming program (months/dates), and how flexible are those windows? Options: Fixed dates—no flexibility, Some flexibility ±2 weeks, Flexible within quarter, Completely flexible, Unsure
• How quickly can your organization make a contracting decision for a pilot once technical terms and pricing are agreed? Options: Within 1–2 weeks, 2–4 weeks, 1–2 months, Longer than 2 months, Unsure
• What financial approvals or ROI thresholds must be met before you can greenlight a pilot scope with higher per-stage spend? Options: Asset-level approval, Corporate finance sign-off, ROI/NPV hurdle, Capex limits, No additional approvals
• Are there penalties, weather seasons, or operational blackout periods we must avoid when scheduling a pilot? Options: Hurricane/winter season constraints, Environmental windows, Rig move/availability conflicts, No-go periods for JV partners, None

What Would Make Us a Trusted Partner?

• When you think of a completion partner that feels truly reliable, what three attributes come to mind first (e.g., speed, reliability, transparency)?
• Which proof points carry the most weight for you: case studies on offset wells, independent lab results, safety record, or operational metrics like average cycle time? Options: Offset well case studies, Independent lab/testing, Safety & incident history, Operational metrics (cycle time, uptime), Client references, All of the above
• How transparent do you expect the provider to be on per-stage pricing, failure rates, and job-level data during a pilot? Options: Fully transparent (all data), Partially (summaries + redacted details), Only high-level results, As negotiated
• Describe a time a vendor lost your trust during a critical execution—what specifically broke down and how should a partner prevent that from happening again?
• What reporting cadence and format would make the pilot feel safe—daily operational updates, post-job forensic reports, or weekly technical reviews? Options: Daily operational logs, Real-time telemetry + dashboards, Weekly technical reviews, Post-job forensic reports, Monthly summary only
• What contractual or warranty terms would you require to feel comfortable with a pilot (e.g., performance guarantee, unit pricing lock, remediation clauses)?
• If we delivered the technical uplift but had one minor safety or schedule incident, what would you need from us to restore confidence? Options: Transparent root-cause and action plan, Financial remediation, Third-party audit, Leadership-level engagement, Other

Next Steps: What Would You Be Comfortable Trying First?

• Based on this conversation, which pilot shape would you be most open to right now? Options: Single-well focused pilot, Multi-well pad pilot, Split-stage A/B test on one well, Modeling + one validation well, I need a recommendation
• What top three things would you want to see in our initial proposal to move toward a discovery-to-pilot kickoff?
• Who should be on the invite list for a technical kickoff meeting to align scope, telemetry, and success metrics?
• How soon should we reconvene after you’ve reviewed this discovery—pick the earliest realistic checkpoint? Options: This week, Next 2 weeks, Within a month, In 1–2 months, Later—TBD
• Is there any additional context, cultural consideration, or “non-negotiable” constraint we haven’t covered that would block a pilot?

• Current-State Confirmation (Pre-Work Review)
• Consequence Quantification Workshop
• Redesign Scenarios Review (Modeled Outcomes)
• Solution Experience: Diagnostics → Proof → Validation
• Commercial Impact & Pilot Calibration

• Identify final open assumptions and agree on immediate data/tests the pilot must resolve.
• Customer to understand and accept the assumptions behind each scenario and its expected per-stage uplift.
• Select 1–2 prioritized redesign scenarios to advance into the Solution Experience validation and pilot design.
• Agree on residual risks and required data/controls to reduce uncertainty during the pilot.
• Seller to deliver a scenario comparison table (per-stage uplift, cost delta, cycle-time change, confidence level) within 48 hours.
• Customer to indicate preferred scenario(s) and any constraint (e.g., cannot exceed X% cost uplift).
• Modeling team to prepare a focused, higher-resolution model for the lead scenario for the validation session.
• State current-state, consequence, and target future-state
• Force explicit validation from the customer that the proposed redesign addresses the defined problem(s).
• Demonstrate measurable proof that the future state (numeric uplift, cycle-time reduction, cost per stage) is achievable.
• Introduce objectives & meeting rules
• Customer to provide formal validation responses to the forced-confirmation questions within 24 hours.
• Seller to list and prioritize remaining assumptions and propose quick tests or data captures for the pilot to resolve them.
• Prepare a compact validation deck summarizing proofs and customer confirmations for use in commercial discussion.
• Recap validated scenario and quantified uplift
• Agree on a per-stage pricing framework and the commercial terms for the pilot.
• Confirm resource and mobilization windows and remove any capacity blockers.
• Approve go/no-go criteria and a pilot decision timeline with named decision owners.
• Seller to issue a draft pilot commercial proposal (scope, per-stage pricing, payment terms) within 48 hours.
• Operations teams to confirm crew/equipment reservation and provide a mobilization availability calendar.
• Legal/commercial to draft a one-page pilot agreement capturing acceptance criteria and liability/safety terms for review.
• Produce a single clear sentence that states the current state and who is affected.
• Agree the prioritized list of underperforming stages and linked evidence per stage.
• Identify all missing data or QC tasks required before modeling can proceed.
• Set baseline KPIs and numeric success thresholds to evaluate uplift.
• Customer to deliver any missing logs/raw microseismic and grant access to data repositories within 48 hours.
• Seller engineering lead to QC the provided datasets and flag any anomalies within 72 hours.
• Owner assigned for baseline KPI document to be circulated for sign-off.
• Create a one-line current-state statement and circulate to attendees for confirmation.
• Recap current-state sentence & agreed KPIs
• Produce an explicit statement of consequence (e.g., $X lost per well and Y hours spread time per 30-stage well).
• Agree the operator's minimum uplift threshold and acceptable cost delta per stage to proceed to pilot.
• Identify which operational and safety consequences are most material to operator decision-making.
• Seller to produce a per-stage and per-well P&L impact table with sensitivity ranges and deliver within 3 business days.
• Customer to confirm economic inputs (e.g., pricing, discount rate, operating cost assumptions).
• Joint team to record and prioritize consequences that must be resolved in pilot acceptance criteria.
• Scenario overview and assumptions
• Proof from offset wells mapped to design changes
• Per-stage costing and pricing options
• Review compiled offset-well diagnostics
• Quantify production shortfall per well & per stage
• Modeled per-stage uplift & well-level impact (Scenario 1..N)
• Pilot-level economics and ROI
• Gap mapping: which stages underperformed and why we suspect completion design/execution
• Cost per-stage delta and cycle-time implications
• Model-driven proof of future-state for lead scenario
• Operational cost and schedule consequences
• Interactive validation: live what-if adjustments
• Data sufficiency checklist & pre-work remaining
• Risk and safety consequence mapping
• Mobilization, equipment availability & operational constraints
• Risk & failure-mode matrix for each scenario
• Decision checklist & timeline
• Prioritization exercise and selection of candidate pilot scenarios
• Forced confirmation & next-step decision
• Agree baseline KPIs and success metrics
• Sensitivity analysis & break-even thresholds

• Run Plug-and-Perf Perforating (per stage)
• Install Dissolvable Frac Plugs (per stage)
• Install Composite Bridge Plugs (per stage)
• Stage Hydraulic Fracture Pumping (per stage)
• Proppant Blending and Injection (per stage)
• Frac Fluid Mixing and Supply
• Real-Time Fracture Pressure and Rate Acquisition
• Mill-Out and Wellbore Cleanout
• Zonal Cementing and Squeeze Placement
• Gravel-Pack Sand Control Installation
• Install Electric Submersible Pump (ESP)
• Install Rod Pump (Beam Pump)
• Perform Flowback and Initial Production Test

Run Plug-and-Perf Perforating (per stage)

• What is the planned top and bottom MD/TVT for this stage?
• How many perforation clusters do you require per stage? Options: 1, 2, 3, 4, Custom (specify in comments)
• Preferred perforating gun system/type? Options: Shaped charge tubing conveyed, Wireline-conveyed, Through-tubing, E-line perforating, No preference (advise)
• Desired shots-per-foot and phasing for clusters (e.g., 4 SPF @ 120°)?
• Are there toolface/orientation requirements for cluster placement? Options: Yes - specific toolface/orientation, No - free orientation, Unknown - need recommendation
• Max allowable perforating pressure spike or wellbore constraint?
• Are there restrictions on perforating charge type due to logging or casing? Options: Yes - restrict high-energy, No restrictions, Unknown
• Do you require post-perf integrity checks (pressure test, imaging)? Options: Yes - pressure test, Yes - cased-hole imaging, No

Install Dissolvable Frac Plugs (per stage)

• Is dissolvable plug technology acceptable for this well given expected bottomhole temperature and chemistry? Options: Yes, No, Unsure - send recommended selection
• What is the expected bottomhole temperature (°F/°C) and lateral length?
• Target dissolution timeframe (days/weeks) required before production testing? Options: <7 days, 7-30 days, 30-90 days, Custom/Not sure
• Do you have historical failure rate limits above which dissolvable plugs are unacceptable? Options: <1%, <5%, <10%, No hard limit
• Do you require vendor certification or traceability for each dissolvable plug? Options: Yes, No, Optional
• Any wellbore fluids/chemistries (e.g., high Ca2+, CO2) that could affect dissolution?
• Would you like a mixed program (dissolvable + composite) for risk mitigation? Options: Yes, No, Discuss options

Install Composite Bridge Plugs (per stage)

• Is composite plug preferred for specific intervals (depth, temperature, openhole vs cased hole)? Options: Yes - specify intervals, No, Undecided - need engineering recommendation
• Required pressure and temperature ratings for composite plugs?
• Preferred retrieval/mill-out approach for composite plugs? Options: Mill-out with drill pipe/bit, Pull and retrieve, Leave in place until abandonment, Undecided
• Are there torque/tension limits or mechanical restrictions in the lateral that affect plug installation? Options: Yes, No, Unknown
• Do you require performance warranties, run records, or batch traceability for each composite plug? Options: Yes, No, Optional
• Do you need compatibility confirmation between plug materials and planned frac fluids/chemicals? Options: Yes, No
• Target turnaround time between plug installation and next stage perf/pump? Options: Immediate (hours), Same day, Next day, Other

Stage Hydraulic Fracture Pumping (per stage)

• What is the design pump schedule for this stage (rate profile: bbl/min or BPM, and step schedule)?
• What is the target maximum treating pressure and surface pressure constraints?
• Do you require diversion techniques (ball drop, chemical diverters, pulse pacing)? Options: Yes - ball/plug diversion, Yes - chemical diversion, No, Discuss recommendation
• Expected proppant mass (lbs or kg) and concentration (lb/gal or kg/m3) for this stage?
• Preferred frac fluid type for the stage? Options: Slickwater, Gel/viscosified, Crosslinked, Oil-based, Other/Custom
• Target stage cycle time (minutes per stage) and acceptable window? Options: <45 minutes, 45-60 minutes, 60-90 minutes, >90 minutes
• Are there surface equipment limitations (pump rate, horsepower, blender capacity)? Options: Yes - list constraints, No
• Do you require an erosion/abrasion mitigation plan for high sand rates? Options: Yes, No

Proppant Blending and Injection (per stage)

• What proppant types/sizes are specified for the stage (e.g., 20/40, 100 mesh, ceramic)?
• Is a multi-proppant or graded-proppant strategy desired? Options: Yes - multi/graded, No - single size, Undecided
• Target proppant concentration (lb/gal or kg/m3) and total mass per stage?
• Are coated proppants or chemical treatments (flowback inhibitors, resin) required? Options: Yes - coated/resin, No, Optional
• Is on-site blending capacity sufficient for the planned rate (blender size/throughput)? Options: Yes - sufficient, No - needs upgrade, Unknown - please advise
• Do you require QA/QC sampling and sieve analysis during the job? Options: Yes, No
• Are there proppant custody-transfer or inventory reporting requirements? Options: Yes, No

Frac Fluid Mixing and Supply

• Which base fluid is specified for the program? Options: Freshwater, Recycled water, Produced water, Brine, Oil-based, Other
• Do you plan to use slickwater, gelled fluids, or crosslinked chemistries? Options: Slickwater, Gelled, Crosslinked, Foamed, Custom
• Are specific chemical additives required (biocide, friction reducer, breaker, scale inhibitor)?
• What is the required mixing and storage capacity on site (bbl/day or cubic meters/day)?
• Do you require supply chain confirmation for recycled or produced water (treatment specs)? Options: Yes, No, Discuss
• Any environmental or disposal constraints for returned fluids or chemical selection? Options: Yes - specify, No
• Do you require pumpability tests or lab verification of fluid recipes before the job? Options: Yes, No

Real-Time Fracture Pressure and Rate Acquisition

• Do you require downhole pressure/temperature gauges per stage? Options: Yes - per stage, Yes - select stages, No
• Preferred telemetry method for real-time data? Options: Wireline/Memory gauge (post-job), Fiber-optic distributed sensing (DTS/DAS), Surface pressure/rate-only, Real-time e-line/CT
• What sample rate and latency are required for decision-making (e.g., 1s, 10s, 1min)? Options: 1s-10s, 10s-1min, 1-5min, 5min+
• Do you require integration of telemetry into your SCADA/operations dashboard? Options: Yes - API/SCADA integration, No - vendor dashboard only, Discuss options
• Are there predefined triggers for adjusting operations in real time (e.g., max pressure, rate drop)? Options: Yes - provide triggers, No - want recommendations
• Do you require alarms, escalation paths, and on-call engineering during pumping? Options: Yes, No

Mill-Out and Wellbore Cleanout

• Is mill-out required for the selected plug technology, and which stages need it? Options: Yes - all stages, Yes - selected stages, No
• Preferred mill-out method and tools (drill, specialty mill, E-line milling)? Options: Drill pipe/bit, E-line milling, Coil tubing milling, Other
• Expected volume and type of cuttings/debris and plan for solids handling?
• Required cleanout circulation volumes, fluid type, and additives for solids transport?
• Do you require verification of full bore (e.g., caliper, camera) after mill-out? Options: Yes - caliper/logging, Yes - camera/visual, No
• Are there restrictions on mill-out time or wellbore torque/tension limits? Options: Yes - specify, No
• Do you need a contingency plan for stuck mills or broken tools? Options: Yes, No

Zonal Cementing and Squeeze Placement

• Is squeeze cementing required for this stage or adjacent casing intervals? Options: Yes - specify interval, No, Maybe - engineering to advise
• Required cement slurry properties (density, compressive strength, additives)?
• Do you require zonal isolation verification (pressure test, CBL, gamma)? Options: Yes - pressure test, Yes - CBL/sonic, No

• Statement of Work (SOW)
• Per-Stage Pricing Schedule
• Mobilization Window & Schedule Commitment
• Equipment Availability & Reservation
• Safety, Liability & Indemnity Terms
• Insurance Certificates & Risk Transfer
• Go/No‑Go Criteria and Decision Rights
• Acceptance Criteria & Performance Guarantees
• Payment Terms & Invoicing Milestones
• Change Order & Scope Adjustment Process
• Permits, Regulatory & Landowner Responsibilities
• Operational Runbooks & Technical Deliverables
• Single‑Point‑of‑Contact & Escalation Matrix
• Cancellation, Rescheduling & Force Majeure

• Pilot Outcomes Review (Executive Decision)
• Technical Lessons Learned & Root Cause Workshop
• Economics & Commercial Terms Review
• Safety, Compliance & Quality Review
• Scale-Up Planning Workshop (Operational Go/No-Go)

• Create a prioritized safety/quality remediation plan with owners and target close dates (owner: HSE Lead).
• Update stage design library with chosen cluster spacing, perforation geometry and plug selection rules (owner: Completion Engineering).
• Schedule targeted validation runs and required telemetry (owner: Field Operations / Data Team).
• Produce revised execution runbooks and distribute to crews for training (owner: Ops Readiness).
• Current Cost Baseline
• Agree on a target commercial model (pricing and incentives) that preserves operator economics and is executable for the vendor.
• Identify any commercial conditions tied to technical validation and define timelines for contracting.
• Confirm mobilization constraints and incorporate them into the commercial proposal.
• Issue a formal commercial proposal covering agreed pricing tiers and performance KPIs (owner: Commercial Lead).
• Confirm mobilization windows and equipment reservations for proposed program start dates (owner: Logistics Manager).
• Draft contract amendment with performance clauses and acceptance criteria (owner: Legal/Contracts).
• Safety Current State & KPI Dashboard
• Confirm that safety and quality performance meet operator thresholds or identify remediations required before scale-up.
• Assign owners and timelines for all corrective actions, training, and audits needed to mitigate safety/quality risk.
• Define the safety evidence package required to clear operational go/no-go gates.
• Opening & Objectives
• Schedule mandatory crew training sessions and refresher on revised runbooks (owner: Ops Training).
• If required, book a third‑party HSE audit and produce compliance certificate before mobilization (owner: Compliance).
• Recap Decisions & Required Conditions
• Produce a runnable scale-up program plan with timeline, owners and resource commitments.
• Establish clear go/no-go gates and acceptance criteria tied to the pilot evidence and defined KPIs.
• Set the program governance and KPI review cadence to monitor performance during ramp.
• Publish the program Gantt, assigned owners and critical path with dates for the first 3 months (owner: Program Manager).
• Order long‑lead equipment and confirm spare parts inventory aligned to ramp plan (owner: Procurement).
• Establish weekly KPI review meeting invites and dashboard access for stakeholders (owner: Data/Operations).
• Establish a single, agreed set of pilot performance numbers and their financial consequence.
• Reach an executive decision on scale-up (full, phased, or no-go) or list conditions required for approval.
• Assign owners and timelines for the commercial and operational follow-ups required by the decision.
• Publish an 'official results' one‑pager with the reconciled pilot metrics and financial impact.
• If approved to scale, initiate commercial amendment and mobilization hold notices to operations (owner: Commercial Lead).
• If conditional approval, list required remediation items and target dates for re-review (owner: Engineering Lead).
• Recap Current State & Problem Statement (one-sentence)
• Agree on validated root causes for underperforming stages using pilot telemetry and diagnostics.
• Commit to a concrete set of engineering changes and how each will be proven in subsequent wells.
• Define measurement methods and acceptance criteria for technical validation prior to scale-up.
• Current State Summary (one-sentence)
• Financial Consequence & ROI Scenarios
• Data Package Review
• Define Future State (one-sentence operational target)
• Incident & Quality Deviation Reviews
• Regulatory & Permit Status
• Pricing Structure & Volume Discounts
• Root Cause Analysis (structured RCA)
• Program Timeline & Critical Path
• Consequence Analysis
• Resource & Logistics Plan
• Modeled vs Actual Performance — Data Walkthrough
• Mobilization, Equipment Availability & Lead Times
• Corrective Actions, Training & Audit Plan
• Engineering Fixes & Proof Paths
• Validation & Data Integrity Check
• Validation Tests & Acceptance Criteria
• Contracting Path and Approval Timeline
• Go/No-Go Gates, Acceptance Criteria & Monitoring Cadence
• Validation Criteria for Safety Go/No-Go
• Decision Framing and Straw Vote
• Action Owners & Timeline
• Action Owners, Communication & Risk Register
• Next Steps, Owners, and Timing