Program scale and operational fit

• Roughly how many wells or laterals do you expect to include in this program this year? Options: 1 (pilot), 2–9, 10–25, 26–50, More than 50 (above program support range)

Offset data and engineering review

• Do you have offset well production results and stage-level diagnostics (pressure logs, execution logs, microseismic) available for review? Options: Full set (production + microseismic + stage logs), Partial (some production or pressure logs only), Production summaries only, No offset diagnostics available
• If your data is partial or limited, please briefly note which key diagnostics are available or missing.
• Would you like an engineering design review before scheduling full discovery to determine whether stage design or execution is likely the root cause? Options: Yes — please schedule a design review, Maybe — would like the seller to recommend next steps, No — not needed before discovery

Mobilization and equipment constraints

• Are there firm mobilization windows, equipment availability constraints, or pad/surface access dates that would drive scheduling? Options: Yes — specific window (please summarize next), No — schedule is flexible, Unsure yet
• If there are specific constraints or critical dates for mobilization, please summarize them here.

Budget, authority & timeline

• Is there an allocated budget or target cost per well (or per-stage) for this program? Options: <$100,000 per well, $100,000–$250,000 per well, $250,000–$500,000 per well, >$500,000 per well, No allocated budget yet / exploratory
• Who is the primary decision maker for selecting a completion services provider, and who else typically influences that decision? Options: Completion Engineer (technical lead), Operations Manager / Director, Procurement, VP / Executive sponsor, Multiple stakeholders (team decision)
• What is your target timing for first mobilization or pilot job? Options: Within 30 days, 1–3 months, 3–6 months, 6–12 months, No fixed timeline / exploratory

A quick orientation — the wells you care about

• Tell me about the pad or well cluster you'd like us to analyze
• In your recent wells, how many laterals returned initial production 15–25% below the type curve? Options: 1–2, 3–5, 6–10, More than 10, None
• Who on your team owns completion design and will make the final call? Options: Completion Engineer, Production Engineer, Operations Manager, Director of Engineering, Other
• When did the most recent well report initial production, and how frequently do you update type curves? Options: Daily, Weekly, Monthly, Ad-hoc
• Which of these metrics matters most for your program—IP30, 90-day cumulative, EUR, or net cash flow? Options: IP30, 90-day cumulative, EUR, Net cash flow, Per-stage cost

Why you believe this is fixable

• Why do you believe stage design or execution, rather than reservoir quality, is the main cause of the shortfall?
• Provide a specific stage-level example where the result surprised you, and include what the expected versus actual was
• How many stages per well typically show pressure or proppant anomalies during pumping or flowback? Options: 1–2 stages, 3–5 stages, 6–10 stages, Most stages
• Describe the pattern you see in underperforming stages — cluster spacing, perforation hit, proppant volume, or pump schedule
• Who first raised concern about the incumbent design, and what evidence convinced them? Options: Completion Engineer, Production Engineer, Operations Lead, Field Superintendent, Other

Data we must see to justify a design change

• If we could review your offset microseismic, stage pressure traces, and frac gradient logs, which single finding would justify redesigning stage geometry?
• List the datasets you can share, for example raw microseismic event lists, stage pressure CSVs, and perforation maps Options: Raw microseismic event list, Stage pressure traces, Perforation maps, Fracture gradient logs, Flowback test data, Completion run sheets
• Estimate the completeness and sampling rate of your stage pressure telemetry across the wells you plan to pilot Options: >90% with ≥1s sample, 50–90% with 1–5s, <50% or intermittent, None
• Identify the internal owner who can approve transfer of raw sensor and microseismic files to external engineers Options: Completion engineering, Data science, Operations, Procurement
• Name the file formats and secure transfer methods you currently support for large geophysical files Options: CSV/TSV, SEG-Y, Proprietary binary, Secure FTP, Cloud object storage (S3, Azure)

Operational limits that change the economics

• Point to the operational constraint that, if unchanged, would make any redesign economically unworkable
• How often does equipment or crew availability force you to accept longer stage cycle times than your design target? Options: Almost always, Often, Sometimes, Rarely, Never
• When a pump or spread delay occurs, what is the typical days lost and the estimated dollar impact per well?
• Describe any permit, pad, or environmental limits that constrain stage spacing, proppant mass, or pump schedules
• What maximum per-stage cost keeps the project within your economics hurdle? Options: <$1,000, $1,000–$5,000, $5,000–$15,000, >$15,000, TBD

Unacceptable risks and safety triggers

• Press this: which technical or safety risk would make you stop the pilot immediately?
• On a scale from 1 to 5, how concerned are you about proppant flowback or equipment failure on this program? Options: 1, 2, 3, 4, 5
• Has your team recorded plug failures, well-control events, or surface equipment damage in recent jobs that we should know about? Options: Yes, in last 6 months, Yes, 6–24 months, Yes, >24 months, No known events
• Name the internal approvers who must sign any change that increases operational risk Options: Operations Manager, HSE Lead, Completion Lead, VP Operations, Other
• If a safety incident occurred during our operations, what is the required escalation window and required immediate action?

The other paths you're weighing

• What would have to be demonstrably true about your incumbent or an internal solution for you to keep them instead of switching?
• List the alternative providers or internal programs you've evaluated in the last 12 months Options: Incumbent provider(s), Internal team, New entrant startups, Alternative technology, No other options
• Share how the incumbent's recent offset performance compares on per-stage cycle time, per-stage cost, and IP uplift
• Has anyone proposed solving this problem entirely in-house, and if so, who and what was their plan? Options: Yes, detailed plan, Yes, informal proposal, No, Still discussing
• Identify the contractual or organizational barriers that would keep you with the current provider even if uplift is possible

Readiness — systems, approvals, and timing

• Assume data, permissions, and a four-week mobilization window are constraints, which single missing item would stop a pilot from starting? Options: Data access, Signed NDA, API keys, Field access, All are available
• Provide the names or categories of systems we must integrate with, for example your telemetry store, SCADA, or field data warehouse Options: Telemetry store, SCADA, Field historian, Cloud storage, Other
• Point to the team that owns API access or data-sharing approvals and the best contact to move permissions
• Estimate the time you typically need for legal and data-sharing approval for external engineering access Options: <2 weeks, 2–4 weeks, 4–8 weeks, >8 weeks, Depends on legal review
• Are there regulatory, permit, or land-access windows that could block mobilization within a 4-week target? Options: Yes, fixed windows, Yes, flexible, No known windows, Not sure

Acceptance criteria and next steps

• Declare the single measurable pilot result that would allow procurement to sign a follow-on contract the same week
• Share the stakeholders and their approval thresholds required to move from pilot to multi-well program Options: Operations, Procurement, Engineering, Legal, Executive sponsor
• Sketch the funding path and timeline if the pilot meets its target, including who signs budget reallocation Options: Immediate reallocation, Quarterly budget cycle, Requires executive approval, Requires board approval
• Are there commercial terms or contract clauses procurement will not accept under any circumstances? Options: Yes, No, Need to review
• Within what earliest start date could you mobilize a one-well pilot if datasets and approvals are ready? Options: Immediately, Within 2 weeks, Within 1 month, Longer than 1 month, Unsure

How we'll measure success together

• Choose the single metric that will determine pilot success from your perspective Options: IP30 uplift, Per-stage cycle time, Stage efficiency, 90-day cumulative, Cost per stage
• Report the three KPIs you want reported per-stage and their acceptable thresholds Options: Per-stage cycle time, Stage pressure anomaly rate, Proppant placement efficiency, Production per stage, Other
• Within what cadence do you need KPI reporting during the pilot—real-time, hourly, or daily summaries? Options: Real-time, Hourly, Daily, Weekly summaries
• Specify the contact roles that should receive real-time alerts and who owns field escalation Options: Operations lead, Completion engineer, HSE lead, Site superintendent, Production engineer
• Explain the remediation steps and who must authorize a stop if a stage misses the agreed threshold during pilot

• Completion Design Review Session

• Confirm the current state and its cost to your program
• You confirm the identified underperforming stages and accept the quantified cost of the current state as the decision baseline.
• Run the uplift model against the buyer's full offset dataset and deliver a per-stage uplift and economic impact report before the follow-up decision meeting.
• Provide raw offset microseismic files, stage-level pressure logs, and initial production by stage for the selected pad.
• Review stage-level diagnostics from offset wells
• You validate at least one alternative stage design as deployable for a pilot based on projected uplift and cycle-time impact.
• Show alternative stage designs and modeled uplift
• You agree the evidence package required after the pilot to make a go/no-go procurement decision.
• Confirm pilot well(s) and sign off on acceptance metrics for IP uplift and per-stage cycle time.
• Validate deployable design and cycle-time assumptions
• Confirm next-step pilot metrics and timeline
• Customer confirmation checkpoint

• Completion Design Review Session
• Completion Design Review Deck
• Completion Design Review Brief

• meeting
• slides
• document

• Supply and Install Dissolvable Frac Plugs
• Supply and Install Composite Bridge Plugs
• Execute Plug-and-Perf Perforating Runs
• Perform Multistage Hydraulic Fracturing Pumping
• Stage-by-Stage Proppant Slurry Placement
• Blend and Deliver Frac Fluid Recipes Onsite
• Cementing and Squeeze Operations for Zonal Isolation
• Sand Control Installation (Screens and Gravelpack)
• Install Artificial Lift Equipment and Commissioning
• Production Flowback and Well Testing Services
• Mill or Drill-Out Composite Plugs and Cleanup
• Proppant Flowback Mitigation Hardware Installation
• Pressure Integrity Testing and Annulus Verification
• Emergency Well Control and Kill Operations

Supply and Install Dissolvable Frac Plugs

• How many wells or API numbers require dissolvable plug deployments in this program?
• Which lateral measured depth (MD) intervals are you planning to isolate with dissolvable plugs (MD or TVD-ft)?
• Do you have an expected in-situ dissolution window based on lateral temperature or lab data (for example: <30 days, 30-90 days, >90 days)? Options: <30 days, 30-90 days, >90 days, Unknown / no data
• Specify the maximum acceptable post-job plug failure rate (percent) that would trigger a change to alternate plug technology for this program. Options: <1%, 1-3%, 3-5%, >5%, No threshold set
• What evidence will validate a dissolvable plug deployment as accepted (for example: CT/liner integrity log, absence of required mill run within X days, or production tracer result)?

Supply and Install Composite Bridge Plugs

• How many composite bridge plugs do you plan to install per well and at which MD/TVD depths?
• Specify the downhole temperature and pressure ranges in the intervals where composite plugs will be run.
• Which run method do you prefer for composite plug installation (e.g., drill-string set, wireline set, coiled tubing set)? Options: Drill-string set, Wireline set, Coiled tubing set, No preference
• Indicate any required compatibility constraints for composite plug materials with your well fluids (e.g., high CO2, high H2S, sour service). Options: CO2 resistant, H2S resistant, High-temperature rated, Standard compatibility, Unknown
• Who on your team will authorize a composite- plug drill-out scope if the composite plug cannot be reliably dissolved?

Execute Plug-and-Perf Perforating Runs

• How many perforating runs per well and how many stages per run do you plan (list by well/API or pad)?
• Which perforation geometry do you prefer for underperforming stages (cluster spacing in ft, shots-per-cluster, phasing)?
• Do you have offset well perforating logs or casing collar locator (CCL) data we should match for charge alignment and phasing? Options: Yes - provide logs, No - provide target depths only, Unknown
• Specify the max acceptable perforating run time or hole-cleaning constraint per run that would affect tool choice.
• Identify the responsible party for supplying guns, detonators, and explosive handling documentation at the site. Options: You supply, We supply, Joint arrangement

Perform Multistage Hydraulic Fracturing Pumping

• Provide the planned number of stages per lateral and the target treated interval lengths (ft) by well or pad.
• State your preferred treating fluid system for the program (for example: slickwater, linear gel, crosslinked gel, or hybrid). Options: Slickwater, Linear gel, Crosslinked gel, Hybrid / custom, Undecided
• Indicate the target average cycle-time per stage (minutes from lead-in to plug cut) you expect to achieve for budget modeling. Options: <40 min, 40-60 min, 60-90 min, >90 min, No target
• Provide the maximum allowable treating pressure for any stage based on design or completion limits (psi).
• Identify required surface monitoring integrations during pumping (for example: SCADA telemetry, downhole pressure gauges, microseismic trigger access). Options: SCADA telemetry, Downhole gauges, Microseismic link, No integrations required, Other

Stage-by-Stage Proppant Slurry Placement

• Specify per-stage proppant mass targets in pounds or lb/ft for each stage type (list by shallow/median/deep if applicable).
• Which proppant types and mesh sizes are acceptable for this program (for example: 40/70 sand, 100 mesh resin-coated, ceramic coarse)?
• Indicate your tolerance for proppant fines percentage or silt content delivered by the supplier (percent). Options: <1%, 1-3%, 3-5%, >5%, Unknown
• List any offset well proppant placement profiles (proppant per stage vs. stage number) you want us to replicate or improve upon.
• Provide expected proppant sourcing preferences or constraints (single supplier, multiple suppliers, proximity limit in miles). Options: Single supplier, Multiple supplier options, Proximity limit, No preference

Blend and Deliver Frac Fluid Recipes Onsite

• Describe the frac fluid recipe parameters you require us to deliver onsite (polymer type and ppm, friction reducer, breaker type, target viscosity at shear).
• Indicate required batching capacity per hour for fluid blending to meet pad pumping schedules (bbl/hr).
• Specify the water source and any water quality constraints (TDS, iron, hardness) that affect fluid chemistry onsite.
• Identify any lab or QC testing you require onsite (for example: viscosity curve, pH, polymer concentration) and sampling frequency.
• Indicate lead times for key fluid chemical deliveries and any storage capacity limits at the pad (days of inventory).

Cementing and Squeeze Operations for Zonal Isolation

• Provide casing shoe and annular geometries for each interval requiring cementing or squeeze operations (casing size, annular clearance in inches).
• Specify cement class, density (ppg), and required compressive strength schedule you expect for zonal isolation jobs.
• Identify any contamination or formation chemistry concerns that would affect spacer or cement formulation (shale-reactive zones, CO2).
• Indicate required verification tests after cement placement (for example: cement bond log, pressure-hold test duration in minutes). Options: Cement bond log, Pressure-hold test, Tracer run, No verification required
• What evidence will validate a cementing or squeeze operation as accepted (for example: successful pressure-hold for X minutes at Y psi or a cement bond log showing Z% coverage)?

Sand Control Installation (Screens and Gravelpack)

• Which sand control strategy do you prefer for each well (standalone screens, gravel pack, frac-pack), and at which intervals? Options: Standalone screens, Gravel pack, Frac-pack, Mixed strategy
• Specify screen slot size, outside diameter requirements, and preferred screen material for your completion design.
• Provide the expected sand production risk assessment or offset well evidence that drives the need for sand control.
• Indicate handling and disposal requirements for return gravel and sand during installation and cleanup. Options: Vendor disposes, You dispose, Joint plan
• Identify the schedule constraints that affect gravel-pack pump-in windows and mobilization of gravel-pack equipment.

Install Artificial Lift Equipment and Commissioning

• Which artificial lift method do you plan for initial commissioning (electric submersible pump, gas lift, rod lift, plunger lift)? Options: Electric submersible pump (ESP), Gas lift, Rod lift, Plunger lift, Undecided
• Provide target production rates and drawdown parameters that the artificial lift installation must support (bbl/day and allowable bottomhole pressure).
• Identify the installation depth, pump intake setting depth, or mandrel setting depths (MD/TVD) for lift equipment.
• Indicate required commissioning tests and acceptance documentation for the lift system (for example: motor amperage curve, wellhead VFD alarms, baseline performance test).
• Who on your operations team will approve the lift commissioning checklist and take ownership of day-1 operations?

Production Flowback and Well Testing Services

• Provide the planned flowback schedule per well (choke schedule, days on flowback, target IP24 or IP30 sampling windows).
• Specify required fluid and gas sampling analysis (for example: BTEX, chlorides, GOR, water cut) and required labs.
• List the surface testing and separation equipment you expect to be onsite for flowback and who supplies it.
• Indicate telemetry or reporting cadence for flowback and testing data (real-time, hourly, daily). Options: Real-time, Hourly, Daily, End-of-job report
• What acceptance criteria constitute formal production handover after flowback (for example: sustained choke-open production above X bbl/d for Y days or IP30 >= target)?

Mill or Drill-Out Composite Plugs and Cleanup

• How many composite plugs per well do you expect will require milling or drill-out during cleanup?
• Estimate hours required per plug for milling or drill-out based on offset experience or vendor guidance.
• Identify cuttings handling and disposal requirements for mill/drill-out operations at the pad. Options: Onsite containment, Haul to disposal, Containment + sampling
• Specify any restrictions on downhole milling equipment due to narrow ID, tight dogleg, or ESP presence.
• Provide the logging or verification runs you require after plug drill-out to confirm cleanup (for example: caliper, gamma, CT). Options: Caliper, Gamma, CT/sonic log, No logging required

Proppant Flowback Mitigation Hardware Installation

• Which flowback mitigation devices do you want considered (for example: downhole retention valves, inflow control devices, surface sand separators)? Options: Downhole retention valves, Inflow control devices, Surface sand separators, Other
• Specify the depth and interval where mitigation hardware must be installed and any tubing or completion constraints.
• Indicate any offset well evidence showing proppant flowback history that motivates hardware selection.
• Identify spare parts or redundancy requirements for mitigation hardware for the program (number of spare valves per rig).
• Provide preferred commissioning checks for installed flowback mitigation hardware (for example: low-rate leak checks, valve function test).

• Master Services Agreement (MSA)
• Statement of Work (SOW)
• Order Form & Commercial Terms
• Mobilization & Equipment Availability Schedule
• Acceptance Milestones & Test Protocols
• Change Order Agreement
• Insurance & Liability Certificate
• Health, Safety & Environmental (HSE) Addendum
• Equipment Warranty & Performance Commitment

• Go-live Health Check
• First Measurement Review
• Acceptance Gate Review (Day 90)
• Quarterly Operational Review
• Monthly Operational Check-in

• Publish the prioritized enhancement backlog with clear acceptance criteria and expected metric impact.
• Remediation items for unmet criteria captured with verification steps and firm deadlines.
• Publish the acceptance decision document including signatory and per-criterion pass/fail status.
• Execute the incumbent decommission checklist and archive or migrate legacy data as recorded.
• Open remediation tickets for any failed criteria with verification tests and target completion dates.
• Trend review of production response
• Prioritized list of persistent issues and enhancement requests with acceptance criteria and expected impact.
• Safety and reliability items closed or on a tracked remediation path.
• At least one experiment or pilot scheduled to address a top operational issue.
• Reconfirm success criteria and owners
• Schedule the pilot test for any approved stage-design modification and define success metrics.
• Open corrective-action items for safety or reliability events with target close dates and verification steps.
• Validate and restore any broken telemetry or data feeds required for reporting.
• Execution status snapshot
• Agree immediate fixes required to restore average stage cycle time toward target.
• Contain and document any well-control incidents with corrective steps and timelines.
• Confirm data readiness for the next first-measurement or quarterly review.
• Open high-priority remediation tasks for any execution issues identified this month.
• Document incident reports for any well-control or safety events and list required follow-up actions.
• All operational owners confirmed and aligned on the deployment checklist.
• High-priority blockers captured with remediation tasks and timelines.
• Data feeds and dashboards required for the first measurement are validated and scheduled.
• Publish the go-live validation checklist and current equipment/permit status for async review.
• Document each open blocker with evidence, severity, and a target resolution date.
• Enable or confirm telemetry and production data feeds required for the first measurement window.
• Present first measurement data versus Program Scope targets
• Determine whether current trends meet the Program Scope trajectory or require corrective work.
• Document a prioritized list of corrective actions with target completion dates.
• Confirm the date and data requirements for the Acceptance Gate review.
• Publish the measurement report with raw data sources and calculation method for each metric.
• Create a corrective-action tracker with milestones and verification criteria.
• Schedule any additional instrumentation or microseismic analyses required before the acceptance review.
• Restate acceptance criteria and data sources
• A documented acceptance decision is recorded with a named signatory where required.
• Incumbent wind-down status confirmed and next steps recorded.
• Efficiency and cost review
• Diagnose root causes for deviations
• Incident triage
• Present outcome data against each criterion
• Deployment and mobilization validation
• Early operational signals
• Document pass/fail per criterion and capture signatory
• Agree corrective actions and timelines
• Operational issues and enhancement backlog
• Open issue triage and quick wins
• Incumbent wind-down confirmation
• Open issues and blockers
• Data integrity and next snapshot
• Confirm readiness for Acceptance Gate
• Safety, well control, and equipment reliability review
• Agree immediate remediation actions
• Agree experiments and next quarter objectives
• Agree remediation plan for any failed criteria