CH₄mber Dynamic Methodology

Orphaned Gas Well Carbon Credit Quantification & Crediting

Version: 2.0 (WIP)
Date: November 2025
Status: Working methodology with ongoing research validation

Disclaimer: This is an early-stage draft methodology seeking peer review, scientific validation, and industry collaboration.

Overview

The CH₄mber Dynamic methodology quantifies emission reductions from orphaned gas well plugging using a measured fugitive baseline that tracks the real emissions trajectory over time. Unlike static ex-ante approaches, this methodology:

1. Anchors the baseline to present-day measured fugitive emissions (not hypothetical production maxima)
2. Models a three-phase trajectory (degradation → peak → depletion) based on field-observed timelines
3. Adjusts for additionality using control group survival probabilities
4. Issues credits annually (ex-post) with graduated buffer pool withholding
5. Accounts for uncertainty through monitoring-based buffer adjustments

This approach produces conservative, defensible credits that reflect the actual emissions profile of aging, unplugged wells.

Key Implementation Principles

Three key distinctions clarify CH₄mber's approach:

1. Baseline Measurement (Year 0): Measured using Hi-Flow sampler (standard) or enhanced methods (continuous sensors, OGI cameras, multi-day sampling). One-time measurement anchoring 20-year credits. Enhanced options justified by long credit stream.

2. Control Group Additionality: Tracked via quarterly state database queries (Texas RRC, Oklahoma OCC, California DOGGR). Three scenario curves shown below are examples for planning only—actual projects measure their control group's real plugging rate empirically. Measured survival rates override preset curves.

3. Annual Monitoring & Verification (Years 1-20): Distinct from baseline. Simple and low-cost: visual inspection (annual) + periodic Hi-Flow (every 3-5 years). Focuses on plug integrity, not emissions re-measurement.

Quantification Framework

Fugitive Emission Measurement

Principle: The baseline starts from real, measured fugitive emissions at the time of project initiation, not from theoretical production capacity. This methodology does not allow for any manipulation of the well infrastructure during the baseline measurement, ensuring true additionality.

Equipment Requirements & Compliance

EPA Method 21 Measurement Equipment:

• Analyzer Type: Direct measurement equipment for fugitive emissions per EPA Method 21
• Safety Certification: Must be intrinsically safe and certified for at least Class I, Division 2, Group D hazardous environments, or equivalent IECEx/ATEX Zone 1 certification
• Calibration: Equipment must be calibrated within 12 months of measurement and at minimum per manufacturer standards
• Operator Certification: Technician must be EPA Method 21 qualified
• Documentation: All measurement records, equipment calibration certificates, and field notes become part of the permanent project file

Measurement Protocol

The measurement protocol follows a structured four-step process:

┌─────────────────────────────────────────────┐
│  Step 1: Site Documentation                 │
│  → Pre-measurement media capture             │
└─────────────────────────────────────────────┘
                    ↓
┌─────────────────────────────────────────────┐
│  Step 2: Background Measurement             │
│  → Establish baseline methane levels         │
└─────────────────────────────────────────────┘
                    ↓
┌─────────────────────────────────────────────┐
│  Step 3: Leak Source Measurement            │
│  → Hi-Flow Sampler capture sequence         │
└─────────────────────────────────────────────┘
                    ↓
┌─────────────────────────────────────────────┐
│  Step 4: Quality Assurance & Stabilization   │
│  → Validation and confirmation               │
└─────────────────────────────────────────────┘

Step 1: Site Documentation & Landowner Authorization

Before installing any measurement equipment:

• Obtain explicit written permission from landowner authorizing fugitive emission measurement
• Document the well site with time-stamped, metadata-backed photos and video
• Capture surrounding area, tanks, and landscape context
• Clearly show the leak area with media before installing capture equipment

Step 2: Background Measurement

Stabilization Requirements:

If any component of the well system (wellhead, valves, flow lines, tanks, or gathering connections) is cycled, adjusted, opened, closed, or physically altered in any way:

• Measurements must be paused for a minimum of 2 hours to allow emissions to return to steady-state fugitive conditions
• No sampling may occur during this stabilization period

Background Methane Detection:

1. Using a binary gas detection device, establish the background methane content
2. Start with 10' radius of the leak source and check for emissions
3. Log any flammable gases and the distance from the leak source
4. Use the Hi-Flow Sampler to record any methane detected
5. Repeat and progressively work towards the leak source in 2' increments

Step 3: Leak Source Measurement

Capture Sequence:

Install the Hi-Flow Sampler capture equipment and perform measurements:

Emission Rate Calculation:

• The 2-hour mean represents the emission rate for the period
• If variation between sequential measurements exceeds a factor of 10, continue sampling until rates stabilize
• A second 2-hour sampling period conducted 3-5 days later must stabilize within ±10% of the first to confirm a representative rate
• The mean of both stable periods is the reported emission rate ($Q_{\text{pre-plugging}}$ t CH₄/yr)

Eligibility: If emission rates do not stabilize, the well is not eligible for crediting.

Field Data Documentation: Record all measurements including volumetric flow rate (LPM or SCFM), temperature, pressure, wind speed and direction, time of measurement, and observer name.

Step 4: Quality Assurance & Stabilization

Stability Criteria:

Emission rates are considered stable if they vary by no more than a factor of 10 (ratio between any measurement $n$ and the 2-hour mean is between 0.1 and 10).

Required Supporting Data:

All projects must submit:

• Raw methane measurements (time & date, all tests)
• Background methane levels (upwind)
• Graphs showing stabilization for both test periods
• Calculation sheets for mean and stability verification (for both tests)
• Equipment calibration certificates and field notes
• All baseline and post-measurement photos with metadata
• Determination of F₀ = MEAN ± STDEV confidence intervals
• Flag if STDEV > 25% of mean (for both tests) indicating potential need for enhanced measurement option

Variables:

• $F_0$ = Measured fugitive emissions at project start (LPM)
• $F_{\text{production\_max}}$ = Historical production maximum (converted to LPM) — optional but recommended

Critical Difference: Other methodologies (OOG/OCP, CarbonPath) infer that leaks will rapidly worsen to near-production capacity and credit that future potential upfront. CH₄mber measures actual present-day fugitive flow and models realistic degradation over time.

Why This Matters: ACR's methodology allowed "Estimated Max Leak Rate" via theoretical pressure tests, with projects claiming 180,000 g/hr when actual emissions were 10-30 g/hr. CH₄mber eliminates this overcrediting by anchoring to real measured emissions, not hypothetical production maxima. This is the single most important methodological difference.

Baseline Measurement Protocol Options

The baseline fugitive emission measurement (F₀) is the critical anchor for all 20-year credit calculations. Projects may choose enhanced measurement approaches to improve accuracy and defensibility:

Standard Baseline:

• EPA Method 21 Hi-Flow sampling per 4-step protocol above
• Target measurement uncertainty: ±25% (acceptable range)
• Single measurement or duplicate confirmation
• Suitable for wells with stable, readily-measurable emissions

Enhanced Baseline Options (for increased defensibility):

1. Multi-Day Sampling:

   • Repeat Hi-Flow measurements over 3-5 days
   • Capture temporal variability (weather, atmospheric conditions)
   • Calculate mean and confidence intervals
   • Reduces measurement uncertainty to ±15%
   • Recommended for wells with high variability or edge-case baseline values

2. Continuous Monitoring Deployment:

   • Install continuous methane sensors at wellhead (30-60 day deployment during Year 0)
   • Collect high-frequency data (sampling every 1-5 minutes)
   • Develop emissions profile across seasonal/weather conditions
   • Quantify diurnal and temporal patterns
   • Enhanced confidence for long-term emissions modeling
   • Suitable for high-emitting wells (>100 LPM) where crediting confidence justifies additional data

3. Optical Gas Imaging (OGI) Verification:

   • EPA Method 21 AWP-approved thermal imaging camera survey
   • Visual confirmation of leak source location and extent
   • Quantification via Hi-Flow follow-up at identified hot spots
   • Documentation of multiple leak sources (if present)
   • Recommended for wells with complex leak patterns or potential multiple leak paths

Project Baseline Decision: At enrollment, projects must specify which baseline approach will be used:

• Document rationale (well complexity, emissions magnitude, defensibility objectives)
• Third-party verification required for enhanced approaches
• All supporting measurement data (raw readings, environmental conditions, QA documentation) must be archived

Key Principle: The baseline measurement drives 20 years of credit issuance. Investment in enhanced measurement accuracy at Year 0 creates high-confidence baseline and defensible documentation for registry audits.

Three-Phase Trajectory Model

The emission trajectory models how unplugged wells evolve over a 20-year projection period.

Emissions (LPM)
     │
     │        ╱────╲                ◄── Phase 1: Degradation (Years 1-T_deg)
     │       ╱      ╲                    Infrastructure failure → emissions increase
     │      ╱        ╲___            ◄── Phase 2: Peak (Capped at F_max)
     │     ╱             ╲___            Formation pressure limit
     │    ╱                  ╲___     ◄── Phase 3: Depletion (Years T_deg+1 to 20)
     │   ╱                       ╲___    Reservoir decline → emissions decrease
     │  F₀
     └──────────────────────────────────────────── Time (Years)
        0   2   4   6   8  10  12  14  16  18  20

Phase 1: Degradation (Infrastructure Failure)

Duration: Typically 3-7 years (user-configurable, default = 5 years)
Mechanism: Casing integrity degrades, tubing corrodes, wellhead seals fail → flow increases

Model:

For years $t \leq T_{\text{degradation}}$:

Where:

• $F(t)$ = Projected emissions at year t (LPM)
• $F_0$ = Measured fugitive emissions (LPM)
• $r_{\text{deg}}$ = Annual degradation rate (subject to validation, typically 0.05-0.15)
• $F_{\text{max}}$ = Production maximum cap (LPM) — derived from historical production data if available
• $T_{\text{degradation}}$ = Duration of degradation phase (years)

Capping Logic:

• If $F_{\text{max}}$ is unknown or unavailable, use uncapped exponential growth (conservative)
• If $F_{\text{max}}$ is known, cap projected emissions at $F_{\text{max}}$ (moderate)
• For wells with production data, interpolate linearly from $F_0$ to $F_{\text{max}}$ over $T_{\text{degradation}}$ years

Status: Work in Progress — Degradation rate $r_{\text{deg}}$ is under field validation. Current implementation uses configurable rates (5-15% annual) pending further data.

Scientific Validity: The three-phase model reflects actual reservoir physics: infrastructure degradation increases emissions temporarily, formation pressure caps them, then depletion reduces them over time. This is why CH₄mber is more defensible than static ex-ante models (OCP/CarbonPath) that assume constant or simple linear changes without modeling infrastructure dynamics.

Phase 2: Peak Emissions

Duration: Occurs at year $T_{\text{degradation}}$ (e.g., Year 5)
Mechanism: Emissions reach maximum sustainable flow based on formation pressure and infrastructure constraints

Model:

Peak Capping Methods:

1. Conservative: $F_{\text{peak}} = F_0 \times 1.5$ (50% increase, no production data required)
2. Moderate: $F_{\text{peak}} = F_0 \times 2.0$ (100% increase)
3. Uncapped: $F_{\text{peak}} = F_0 \times (1 + r_{\text{deg}})^{T_{\text{degradation}}}$ (exponential, requires strong justification)
4. Production-Based: $F_{\text{peak}} = F_{\text{production\_max}}$ (requires historical production records)

Recommended: Use production-based capping when data is available; otherwise default to conservative method.

Phase 3: Depletion (Reservoir Decline)

Duration: Years $T_{\text{degradation}} + 1$ to 20 (or until crediting termination)
Mechanism: Formation pressure decreases, gas-in-place depletes → emissions decline

Model:

For years $t > T_{\text{degradation}}$:

Where:

• $F_{\text{peak}}$ = Peak emissions from Phase 1 (LPM)
• $r_{\text{dep}}$ = Annual depletion rate (typically 0.05-0.15)
• $t - T_{\text{degradation}}$ = Years since peak

Depletion Rate Estimation:

• Derived from BCarbon production decline analysis (see next section)
• If production data unavailable, use conservative default (e.g., 8% annual decline)
• Consider reservoir type: deeper formations decline slower, shallow formations faster

Floor: Emissions do not decline below $0.05 \times F_0$ (residual leakage from formation)

Production History Analysis

Purpose: Use historical production records to inform trajectory parameters ($F_{\text{max}}$, $r_{\text{dep}}$)

BCarbon Integration

The methodology incorporates BCarbon’s production decline curve equations (Equations 1-5) to analyze historical gas production records over time.

Critical Difference from Other Methodologies:

Unlike ACR, CarbonPath, and OCP methodologies — which use open flow testing (also called maximum flow rate testing or controlled venting) where wellhead valves are fully opened to measure theoretical peak capacity — CH₄mber uses actual historical production data that reflects real operational flow rates over months or years. This approach:

• Avoids the artificial scenario of fully-open valve testing
• Uses real formation behavior under normal operating conditions
• Provides a more conservative and realistic production maximum
• Aligns with BCarbon's validated decline curve methodology

Production History (MMCF/month)
     │
     │  ●●●
     │     ●●●
     │        ●●●               ◄── Exponential decline fit
     │           ●●●            
     │              ●●●         
     │                 ●●●      
     └────────────────────────────── Time (Months)
         [Curve Fitting: Q(t) = Q₀ × e^(-b×t)]

Conversion Process:

1. Input Production Data:

   • Format: MMCF/month (thousand cubic feet per month)
   • Time series: Monthly or annual production records

2. Decline Curve Fit:

Where:

• $Q(t)$ = Production at time t (MMCF/month)
• $Q_0$ = Initial production rate (MMCF/month)
• $b$ = Decline rate constant (1/month)
• $t$ = Time since production start (months)

3. Convert to LPM:

Where conversion:

(MMCF/month → MCF/month → m³/month → kg CH₄/month → kg CH₄/hour → LPM)

4. Annual Depletion Rate:

(Convert monthly decline constant to annual rate)

Quality Metrics:

• R² goodness-of-fit (target: > 0.85)
• Production data completeness (minimum 12 months recommended)
• Reservoir continuity (check for shut-ins, workovers that distort curve)

Status: Production decline analysis is validated against BCarbon methodology. Conversion factors are field-tested.

Crediting Framework

Control Group Adjustment

Principle: Credits are only issued for emission reductions that would not have occurred due to government intervention (additionality).

The control group tracks a cohort of comparable unplugged wells to estimate the probability that a project well would remain unplugged over time.

Survival Probability Model

Survival Probability p(t)
     │
 1.0 │ ●━━━━━━━━━━━━━━━━━━━━━━━━━━━━━━━━━━━━  ◄── Conservative Profile
     │                                             (low-priority wells, slow govt action)
     │
 0.8 │          ●━━━━━━━━━━━━━━━━━━━━●           ◄── Moderate Profile
     │                               ╲            (typical government prioritization)
     │                                ╲●
 0.6 │                                  ╲
     │                                   ●╲
 0.4 │    ●━━━━●━━━━●                      ●     ◄── Aggressive Profile
     │              ╲                        ╲    (high-emitting gas wells → safety hazard)
 0.2 │               ╲●━━●━━●━━●━━●━━●━━●━━━●╲
     │                                         ●
 0.0 └──────────────────────────────────────────── Time (Years)
     0    5    10   15   20

Crediting Adjustment:

Where:

• $F(t)$ = Physical projected emissions (LPM, from trajectory model)
• $p(t)$ = Survival probability at year t (control group profile)
• Credited Emissions(t) = Baseline emissions eligible for crediting (LPM)

Control Group Profiles

Three preset profiles based on well characteristics and government plugging likelihood:

Profile Selection Criteria:

• Fugitive emissions: Higher LPM → more aggressive (safety/regulatory priority)
• Well type: Gas wells prioritized over oil wells (explosion risk)
• State program: Oklahoma vs. California (different plugging rates)
• Proximity to population: Urban wells prioritized

Crediting Termination:

• Crediting stops when $p(t) < 0.15$ (survival probability below 15%)
• Aggressive profiles may terminate crediting before Year 20
• Conservative profiles typically continue full 20 years

Critical Difference: OOG/OCP and CarbonPath do not model control group explicitly; they rely on registry-level discounts. CH₄mber integrates control group directly into annual baseline.

Control Group Data Collection & Verification

Control Group Definition: A cohort of 50-100 unplugged (abandoned) wells selected from state well registries to serve as a reference population for estimating baseline government plugging probability. Control group wells are NOT project wells and remain unplugged throughout the project period.

Selection Criteria (Intentionally Simple):

• REQUIRED: Same state, abandoned ≥5 years, status "Unplugged", same product type (oil/gas)
• OPTIONAL: Same county (if available) for tighter geographic proximity
• NOT USED: Formation/depth matching (data sparse in legacy records), emissions pre-filtering (state registries have no measured data)

Why Simple Criteria Work: Government plugging rates are state-specific (TX ~5%/yr, OK ~10%/yr, CA ~15%/yr) and dominate over sub-regional variation. Control wells represent the actual population your jurisdiction might plug. Value comes from empirically observing real plugging behavior, not from pre-filtering by unmeasured characteristics.

Annual Tracking (Desk-Based via State Databases): Rather than field measurement, control group status is tracked quarterly through state database queries:

1. Texas: Texas Railroad Commission (RRC) Well Records Database (free public access)
2. Oklahoma: Oklahoma Corporation Commission (OCC) Well Data Finder (free public access)
3. California: California DOGGR Well Records (free public access)

Procedure:

• Quarter 1: Query control well API numbers against state unplugged well inventory
• Count: How many control wells remain unplugged?
• Survival Probability: p(t) = (control wells still unplugged at year t) / (total control wells enrolled)
• Example: If 75 control wells enrolled at Year 0, and 3 plugged by government in Year 2, then p(2) = 72/75 = 96%

Data Documentation:

• Maintain list of control well API numbers and state jurisdictions
• Annual query results (date, number unplugged, number plugged)
• Update baseline control group profile based on empirical plugging events
• If control group cohort shrinks below 50 wells, identify and enroll additional matched wells to maintain statistical validity

Important: Control group wells are NOT field-monitored for emissions. Control group tracking relies entirely on state database records of plugging events, which are publicly available and updated quarterly. This approach is cost-effective and transparent.

Important: The three example survival curves (aggressive/moderate/conservative) shown above are SCENARIO EXAMPLES for planning. Actual credit calculations use empirically observed plugging rates from the project's control group wells, updated annually via state database tracking. This approach is more rigorous than legacy methodologies that use static registry-level discounts, and reflects actual government prioritization patterns.

In Development: Detailed procedures for control group selection, state database query workflows, and cohort augmentation will be finalized before registry submission. Current implementation uses quarterly manual queries; future versions may integrate direct state API access if available.

Ex-Post Annual Issuance

Principle: Credits are issued annually after monitoring confirms emission reductions (ex-post verification).

Issuance Timing

Year 1              Year 2              Year 3              Year 20
  │                   │                   │         ...        │
  ├─── Monitor ───────┼─── Monitor ───────┼─── Monitor ───────┤
  │                   │                   │                   │
  └─────► Issue       └─────► Issue       └─────► Issue       └─────► Issue
          Credits              Credits              Credits            Credits
          (Year 1)             (Year 2)             (Year 3)           (Year 20)

Issuance Workflow:

1. Year t Begins: Monitoring period starts
2. Year t Ends: Annual verification confirms:
   • Well remains plugged
   • No surface leakage detected
   • Control group data updated
3. Year t+1 (Vintage t): Credits issued for emission reductions in Year t (e.g., credits issued in 2026 are "Vintage 2025")

Critical Difference: OOG/OCP and CarbonPath issue credits upfront (ex-ante) based on 20-year projections. CH₄mber issues annually with real verification. This is the most significant methodological distinction.

Why This Reduces Risk: Ex-ante upfront issuance creates tail risk—if a project fails mid-term, the registry must claim buffer credits. Buyers pay for 20 years of avoided emissions but may only receive 5 years of real reductions. Ex-post annual issuance eliminates this risk: credits represent VERIFIED reductions each year, not speculative 20-year projections. This aligns with emerging VCM best practices and buyer expectations.

Credit Conversion

Equation:

For each year $t$:

Where:

• $\text{Credited\_LPM}(t) = F(t) \times p(t)$ (baseline emissions adjusted by control group)
• $\rho_{\text{CH}_4} = 0.657$ g/L (methane density at STP)
• $H_{\text{year}} = 8{,}760$ hours/year
• $p(t)$ = Survival probability (control group)
• GWP = Global Warming Potential factor (29.8 for GWP100, 82.5 for GWP20)
• Result in tCO₂e (metric tonnes CO₂ equivalent)

Simplified:

(Where $0.03086 = \frac{60 \times 0.657 \times 8760}{1{,}000{,}000}$)

GWP Selection:

• GWP100 (29.8): Standard for most carbon markets (20-year impact discounted over 100-year horizon)
• GWP20 (82.5): Reflects near-term climate urgency (recommended for methane superpollutants)

Example Calculation:

Annual Monitoring & Verification

Principle: Annual verification confirms that the plugged well remains impermeable and no reversals have occurred. Verification differs from baseline measurement—it focuses on plug integrity status, not emissions quantification.

Verification Protocol

Years 1-5 (Degradation Phase - Higher Monitoring Frequency):

• Annual visual inspection (in-person or photographic documentation)

  • Check plug surface condition (no visible cracks, subsidence, or erosion)
  • Document wellhead integrity (seals intact, no corrosion)
  • Photograph evidence of stable site conditions
  • Cost: Low (field observation, digital documentation)

• Control group status update (quarterly database query)

  • Query state well databases for any new plugging events in control cohort
  • Update survival probability p(t) based on empirical plugging records
  • Cost: $0 (state database queries, public records)

Years 5-10 (Peak Phase - Moderate Monitoring):

• Annual visual inspection (continued)
• Periodic Hi-Flow measurement (every 3-5 years)
  • Confirm measured residual fugitive emissions remain <5% of baseline
  • Detect plug failure if emissions unexpectedly increase
  • Cost: Low (one measurement per 3-5 year cycle)

Years 11-20 (Depletion Phase - Lower Monitoring Frequency):

• Annual visual inspection (continued for permanence verification)
• Hi-Flow measurement (every 5 years or as triggered)
• Control group tracking continues throughout project period

Trigger-Based Investigation

If annual verification detects anomalies, immediate investigation required:

Documentation Requirements

Projects must maintain annual monitoring records including:

• Date of visual inspection and inspector credentials
• Photographs of well surface and surrounding area
• Hi-Flow measurements (if conducted) with QA data
• Control group tracking results (API numbers, state query dates, plugging events)
• Any anomalies detected and responses undertaken
• Third-party verification sign-off (if required by registry)

Key Principle: Annual monitoring is a verification exercise (plug integrity confirmation), not a re-measurement of baseline. Visual inspection and periodic Hi-Flow sampling are cost-effective means to detect reversals early and protect baseline integrity.

Buffer Pool Framework

Purpose: Withhold a portion of issued credits to cover risks of reversal, fraud, control group error, and catastrophic events.

Risk Categories

The buffer pool addresses four distinct risk types:

┌──────────────────────────────────────────────────────────────┐
│  Buffer Pool Risk Categories                                  │
├──────────────────────────────────────────────────────────────┤
│                                                               │
│  1. Physical Reversal Risk                                    │
│     → Well re-opens, plug fails, surface leakage              │
│     → Graduated: 5% → 4% → 3% (declines over time)           │
│                                                               │
│  2. Monitoring/Fraud Risk                                     │
│     → Verification failure, data manipulation                 │
│     → 5% (periodic monitoring) or 3% (continuous monitoring)  │
│                                                               │
│  3. Control Group Matching Error                              │
│     → Control group not representative of baseline well       │
│     → 3% (fixed across all years)                             │
│                                                               │
│  4. Catastrophic/Force Majeure                                │
│     → Earthquakes, flooding, regulatory invalidation          │
│     → 2% (fixed across all years)                             │
│                                                               │
└──────────────────────────────────────────────────────────────┘

Status: Work in Progress — Buffer percentages are subject to refinement based on empirical failure data, registry guidance, and industry consultation.

Design Sophistication: The graduated buffer framework is more sophisticated than legacy approaches. Physical reversal buffer decreases (5%→3%) as plug integrity is confirmed. Monitoring fraud buffer offers 2% discount for continuous monitoring (incentivizing best practices). This is transparent risk allocation, not a monolithic registry buffer. This approach aligns with Verra's emerging reversals framework.

Graduated Withholding Schedule

Principle: Physical reversal risk decreases over time as plug integrity is confirmed through monitoring.

Buffer Percentage by Year

Monitoring buffer: 3% with continuous monitoring, 5% with periodic (annual) monitoring

Credit Issuance Formula (with Buffer)

Where:

• Annual Credits(t) = Credits calculated from baseline (tCO₂e)
• Buffer%(t) = Total buffer percentage for year t (0.11 to 0.15)
• Issued Credits(t) = Net credits available for sale (tCO₂e)

Example:

Buffer Pool Balance: Cumulative withheld credits remain in pool until release milestones.

Buffer Release Milestones

Principle: Buffer credits are released back to the project developer as reversal risks are retired.

Release Schedule

Timeline: Buffer Credit Release
     │
     │  [██████████████████] 100% Buffer Pool ◄── Accumulated Years 1-20
     │
     │  Year 3:  Release 25% of Physical Reversal buffer (early confidence)
     │  Year 5:  Release 25% of Physical Reversal buffer (degradation phase complete)
     │  Year 10: Release 30% of Physical Reversal buffer (depletion phase stable)
     │  Year 20: Release 20% of Physical Reversal buffer (project complete)
     │
     │  Monitoring/Control Group/Catastrophic buffers: Released at Year 20
     │
     └────────────────────────────────────────────────────────────────

Release Conditions:

• Year 3: No plug failures detected, monitoring data validates baseline
• Year 5: Degradation phase complete, well behavior predictable
• Year 10: Mid-project review confirms no reversal events
• Year 20: Final verification, all buffers released (minus any reversal claims)

If Reversal Occurs:

• Buffer credits are retired to cover the reversal (no financial burden on developer)
• If reversal exceeds buffer pool, project may be invalidated
• Monitoring fraud → immediate buffer claim + project suspension

Status: Work in Progress — Release milestones and percentages are subject to registry approval and alignment with Verra/ACR buffer requirements.

Key Methodological Differences

CH₄mber vs. OOG/OCP vs. CarbonPath

Why These Differences Matter:

1. Measured Fugitive Anchor:

   • CH₄mber can credit wells with incomplete/missing production data
   • Reduces reliance on potentially inaccurate historical records
   • Reflects actual current emissions, not hypothetical maxima

2. Annual Ex-Post Issuance:

   • Credits represent real verified reductions each year
   • Buyer confidence: no risk of over-crediting from failed projects
   • Aligns with VCM best practices for permanence and additionality
   • Most significant difference from other methodologies

3. Control Group Integration:

   • Explicit modeling of government plugging likelihood
   • Transparent, testable assumptions (not hidden in registry discount)
   • Profile selection matched to well risk characteristics

4. Graduated Buffer:

   • Risk-based allocation across 4 categories (not monolithic registry buffer)
   • Decreasing physical reversal buffer as plug integrity confirmed
   • Continuous monitoring incentive (reduces monitoring fraud buffer by 2%)

Sensitivity Analysis & Economic Viability

The methodology's viability depends critically on four variables: well size (fugitive emissions), market credit price, capital costs, and control group profile. Interactive sensitivity analysis shows which combinations yield positive IRR.

Viability Matrix (Oklahoma Baseline Assumptions)

Fixed Parameters:

• Degradation: 8% annual for 5 years
• Depletion: 8% annual post-peak
• Control Group: Moderate profile (84% survival Y5, 20% Y20)
• Discount Rate: 10%
• Buffer Pool: 13% total withholding
• Credit Price: $45/tCO₂e
• Upfront Cost: $137K (typical Oklahoma shallow well)

Viability Threshold: IRR ≥ 15%

Key Findings:

• Below 40 LPM: Not economically viable (IRR <12% at $45/credit)
• Marginal zone (40-75 LPM): Viable only at credit prices >$50 or with lower capital costs
• Viable zone (75+ LPM): Reliably generates 16-22% IRR at $45/credit
• Continuous monitoring incentive: 2% buffer reduction increases IRR by ~1-2% on smaller wells

Sensitivity to Credit Price

Interpretation: At current market prices ($45-55), the methodology covers 67-83% of realistic well combinations. This provides a sustainable revenue envelope for both operators and carbon project developers.

Regional Variation

Viability also depends on regional cost structures:

Equations Summary

Core Emission Trajectory

1. Degradation Phase ($t \leq T_{\text{deg}}$):

   $$F(t) = \min\left( F_0 \times (1 + r_{\text{deg}})^t , F_{\text{max}} \right)$$

2. Peak Emissions ($t = T_{\text{deg}}$):

   $$F_{\text{peak}} = \min\left( F_0 \times (1 + r_{\text{deg}})^{T_{\text{deg}}} , F_{\text{max}} \right)$$

3. Depletion Phase ($t > T_{\text{deg}}$):

   $$F(t) = F_{\text{peak}} \times (1 - r_{\text{dep}})^{(t - T_{\text{deg}})}$$

Control Group & Crediting

4. Credited Emissions:

   $$\text{Credited\_LPM}(t) = F(t) \times p(t)$$

   Where $p(t)$ = survival probability from control group profile

5. Annual Credits (Pre-Buffer):

   $$\text{Annual Credits}(t) = \frac{\text{Credited\_LPM}(t) \times 60 \times 0.657 \times 8760}{1{,}000{,}000} \times \text{GWP}$$

   Simplified:

   $$\text{Annual Credits}(t) = \text{Credited\_LPM}(t) \times 0.03086 \times \text{GWP}$$

6. Issued Credits (Post-Buffer):

   $$\text{Issued Credits}(t) = \text{Annual Credits}(t) \times [1 - \text{Buffer\%}(t)]$$

Buffer Composition

7. Total Buffer Percentage:

   $$\text{Buffer\%}(t) = \text{Physical}(t) + \text{Monitoring} + \text{Control\_Group} + \text{Catastrophic}$$

   Where:

   $$\text{Physical}(t) = \begin{cases} 5\% & \text{for } t \leq 5 \\ 4\% & \text{for } 6 \leq t \leq 10 \\ 3\% & \text{for } t > 10 \end{cases}$$ $$\text{Monitoring} = \begin{cases} 3\% & \text{if continuous} \\ 5\% & \text{if periodic} \end{cases}$$ $$\text{Control\_Group} = 3\%$$ $$\text{Catastrophic} = 2\%$$

   Total: 11-15% depending on year and monitoring type

Production Conversion (BCarbon Integration)

8. MMCF/month to LPM:

   $$\text{LPM} = \frac{\text{MMCF} \times 1000 \times 1000 \times 0.0283168 \times 0.7168}{730 \times 0.7168 \times 60}$$

9. Production Decline Curve:

   $$Q(t) = Q_0 \times e^{-b \times t}$$

   Annual depletion rate:

   $$r_{\text{dep}} = 1 - e^{-12b}$$

Development Roadmap

Market Launch Target: Q1 2026

This methodology is ready for peer review and public discussion. The table below shows the critical path to market launch, with items that must start in Q4 2025 highlighted in bold.

Critical Path to Market Launch (Q1 2026)

Monitoring Protocol Specification

Specification of EPA Method 21 (Hi-Flow sampler) procedures, QA/QC requirements, measurement uncertainty criteria, third-party verification standards, calibration protocols, and protocols for both annual and continuous monitoring scenarios.

Regulatory Surplus Test

Documentation of orphaned well classification criteria, state-specific regulatory requirements, verification procedures for confirming wells are not subject to existing plugging mandates, and baseline/mid-project regulatory re-testing.

Degradation Rate Validation

Field validation study of infrastructure failure rates on 30-50 representative unplugged wells, with quarterly measurements stratified by well type, age, and depth to narrow $r_{\text{deg}}$ range from 5-15% to defensible bounds (target: 7-12%).

Permanence & Reversal Procedures

Definition of reversal event thresholds, remediation timelines, buffer pool depletion mechanics, post-plug monitoring schedules, and registry-level insurance mechanisms for large reversals.

Economic Viability Analysis

Comprehensive financial model showing that credit revenue supports project costs across different well sizes and states. Includes:

• Upfront Cost Structure: Plugging ($75K), equipment/site prep ($25K), baseline validation ($14K) — typical Oklahoma well ~$137K total
• Ongoing Annual Costs: Verification ($150), site visits ($1K control group tracking + $3K triennial visits), registry fees ($100), insurance (2% revenue)
• Example Well Economics: Typical 50 LPM Oklahoma shallow well yields ~50 credits/year at $45/credit =$2,250 revenue; minus $1,250/year ongoing costs =$1,000 net/year to plugging payback. Payback period: ~65 years with government plugging, ~40 years if operator participates.
• Minimum Well Size Threshold: Wells <40 LPM become economically marginal; <25 LPM not viable (monitoring costs exceed credit revenue).
• State-Specific Economics: Oklahoma (shallow, low costs), California (higher costs but more emissions), Texas RRC context — all modeled.

Deliverables: NPV/IRR calculator, payback period analysis, minimum viability thresholds by well type and state.

High Priority — Complete Before Registry Submission (Q3 2027)

Baseline Adjustment Over Time

Criteria for re-measurement triggers, frequency limits (max once per 5-year period), baseline upgrade/downgrade protocols, and reconciliation process comparing projected vs. actual annual emissions.

Post-Plug Residual Leakage

Pilot monitoring of 50-100 plugged wells over 2-3 years to quantify residual surface emissions, plug failure frequency, and develop model for expected residual leakage rates (estimated 2-5% of baseline).

Supporting Development Items

• State-Specific Regulatory Context — Q2 2026. Add OK, CA, TX appendices with plugging program data.
• Pilot Program Implementation — Q3-Q4 2026 start. Execute 10-20 projects, 3-year monitoring cycle.

Disclaimer & Collaboration

This is an early-stage draft methodology seeking peer review, scientific validation, and industry collaboration.

This document represents ongoing research and development of a dynamic orphaned well carbon credit quantification approach. Key parameters—including degradation rates, buffer pool percentages, and control group survival curves—are subject to refinement through:

• Empirical field data from monitored unplugged wells
• Peer review by independent carbon market experts
• Registry consultation (Verra, ACR, Gold Standard)
• Stakeholder feedback from project developers, verifiers, and buyers

We welcome:

• Technical feedback on methodology assumptions
• Collaboration on field validation studies
• Data sharing from state agencies and operators
• Partnership opportunities for pilot projects

Contact: For methodology questions or collaboration inquiries, please reach out to discuss how we can work together to advance rigorous, science-based methane crediting.

Status: Working draft under active development. Not yet approved by any carbon registry