Every leak survey an operator pays for is a bet that the method will find the methane the site is losing. At 326 British Columbia sites, aerial surveys found 12 times more methane than the regulated ground programme, four times excluding potential combustion and venting [1]. Where federal and state rules set how often sites are surveyed, the method chosen helps decide how long an emission runs before anyone finds it. The federal rules are in flux as well: an October 2026 proposal reopens the federal methane standards, fugitive-emission requirements included, with comments due December 16, 2026 [2].

Leak detection is the work of finding gas escaping from equipment that should be sealed, such as valves, connectors, seals and tank hatches. Operators usually run it as a leak detection and repair (LDAR) program, a schedule of surveys after which each leak found is fixed. Optical gas imaging (OGI) is one such method: an infrared camera that shows escaping gas as a visible plume. Handheld lasers, fixed continuous monitors, and aerial and satellite surveys are others, and each detects a different minimum emission rate under different conditions.

Controlled-release testing measures how far apart those rates are. Controlled release is a direct test of what a method finds, because the emitted rate is metered on each release. One 2024 single-blind test found the five continuous-monitor systems that reported a rate underestimated by about 74 per cent on average [3].

This post is for operators and compliance teams choosing a leak detection method or survey contractor. It covers, in order, what controlled releases show each method detects, why methods disagree, and where detection ends and inventory begins.

Quick Answer: Controlled-release testing of optical gas imaging measured detection rates well below what earlier camera studies implied [4]. The leak size needed for a 90 per cent probability of detection was an order of magnitude larger than earlier camera-focused studies [4]. Operator and contractor surveyors who had covered more than 551 sites detected 1.7 times more leaks than less experienced surveyors [4]. Four quarterly survey visits, at an assumed four hours each, observe under a fifth of one per cent of the year.

What Controlled Releases Show Each Method Detects

A detection method is characterised by the smallest emission it reliably finds, not the smallest it can ever find. Probability of detection rises with emission rate, so a method is usually described by the rate at which it finds a set share of releases. Instrument specifications describe the sensor and controlled releases describe the survey.

Controlled release is the method behind the two studies that follow. Gas is released at a known rate from a known component, and the surveyor works the site normally.

MethodWhat it sensesWhat a controlled release measures
Optical gas imagingInfrared absorption, viewed as a plumeWhether a surveyor finds a release of known size
Handheld laserPath-integrated methane concentrationThe rate below which detection becomes unreliable
Fixed continuous monitorsConcentration at fixed points, or plume images, over timeDetection, localisation and quantification across changing wind
Aerial survey, source levelA plume resolved and tied to one emitter, by laser or by sunlight absorptionThe rate found from altitude in one overpass
Aerial survey, mass balanceDownwind flux for a whole site or basin, with no attributionThe total the flight recovers against a known release
Satellite surveyColumn methane averaged over a pixel, revisited on an orbit or targetedThe smallest rate the satellite detects, which varies with its pixel size and sensitivity

Aerial is not one method. A source-level survey resolves individual emitters and ties them to equipment; in one study, compressors, controlled tanks and separators were most common [1]. It does that either by active laser, as in an airborne gas-mapping LiDAR, a laser scanner flown over the site [5]. A passive imaging spectrometer instead reads sunlight absorption [5].

A mass-balance flight instead measures the net flux leaving a whole site or basin, without attributing it to individual sources. The two are not substitutes: one tells you which unit to fix, the other tells you the total you are missing.

Each row answers a different question, so the methods are not substitutes for one another.

Optical Gas Imaging Depends on the Surveyor, Not Only the Camera

One controlled-release test of optical gas imaging scored the surveyor and camera together, not the camera alone [4]. Professional surveyors from 16 oil and gas companies and 8 regulatory agencies completed 488 tests over ten months [4]. Surveyors used their own cameras and their own protocols at an outdoor facility built to resemble upstream operations [4].

Two findings from that study reframe the detection question. Detection rates were significantly lower than in earlier studies that focused on camera performance [4]. The leak size needed for a 90 per cent probability of detection was an order of magnitude larger than those earlier studies reported [4].

Experience then moved the result again [4]. Surveyors from operators and contractors who had surveyed more than 551 sites detected 1.7 times more leaks [4]. The reported confidence interval on that ratio runs from 1.5 to 1.8 [4]. Experienced surveyors adjusted their speed and examined components from several viewpoints [4].

A camera specification cannot express any of that. The same survey requirement can therefore return materially different detection rates depending on who carries the camera.

Handheld Lasers Were Tested the Same Way

All four handheld-laser devices in the 2025 controlled-release study showed preliminary lower detection limits below 0.6 kilograms per hour [6]. The tests ran at METEC, the Methane Emissions Technology Evaluation Center, a leak-detection test facility run by the Energy Institute of Colorado State University (CSU) [7]. The devices went through a controlled-release assessment of 279 natural gas releases across 20 days [6]. Thirty surveyors and ten operators took part [6].

That study is still underway and its authors describe the results as preliminary [6]. The 0.6 kilogram figure is a rate rather than a concentration, which makes it comparable, though it states no wind conditions.

The contrast with concentration-based screening matters here. A concentration threshold tells a surveyor that gas is present at a component. A rate-based detection limit can be set against how much a site is expected to emit.

The controlled-release literature is larger than those two studies. The table lists controlled-release tests by method class, most of them single-blind. Rates and results are quoted as each study states them.

StudyWhat was testedRelease ratesHeadline result
Ravikumar et al. 2018Infrared camera, controlled distanceg/h methane50 per cent detection near 20 g/h at 6 metres
Zimmerle et al. 2020Optical gas imaging, 488 surveyor testsnatural gas, scfh90 per cent detection near 7 (5.52 to 16.4) scfh, about 132 g/h if pure methane, for high-experience LDAR surveyors, an order of magnitude above a camera study at 2.7 metres
Sherwin et al. 2021Airplane hyperspectral imaging18 to 1,025 kg/h methane182 of 200 releases found, no false positives in 21 blanks
Bell et al. 2022Aircraft LiDAR, 650 passeskg/h methane87 per cent of quantifications within a factor of two
Conrad, Tyner and Johnson 2023Airborne LiDAR, 495 releases, plus published data for two platforms0.4 to 66 kg/h methaneDetection curves fitted to rate, wind and altitude
Bell et al. 2023Eleven continuous monitors0.4 to 6,400 g/h methane90 per cent detection 3 to 30 kg/h for 8 of 11, upper end extrapolated, false positives 0 to 79 per cent
Sherwin et al. 2024Nine satellite systems0.03 to 1.48 t/h methane55 per cent of estimates within 50 per cent of the metered value, no false positives across 134 estimates
Chen et al. 2024Eight continuous monitors, high volume0.037 to about 2,830 kg/h methaneAll five systems that quantified the daily average release underestimated it, by about 74 per cent on average
Day, Levin and Zimmerle 2025Four handheld lasers, 279 natural gas releaseskg/hAll four with lower detection limits below 0.6 kg/h, preliminary
Cheptonui et al. 2025Thirteen continuous monitors0.08 to 6.75 kg/h methane90 per cent detection 0.5 to 6.7 kg/h for six of thirteen

Controlled-release studies, by the method class each one tested.

Probability of detection curve for aircraft LiDAR, plotted against methane release rate on a logarithmic axis from 0.5 to 20 kilograms per hour. Detection rises as an S-curve, reaching 50 per cent at 1.2 kilograms per hour and 90 per cent at 2.3 kilograms per hour. A note records that in the same study an airborne imaging spectrometer (AVIRIS-NG) reached 90 per cent at 16 to 33 kilograms per hour at 3,000 metres, and a fixed-wing imaging system at 44 to 51 kilograms per hour at 900 metres, each range spanning whether partial detections are counted.

Published probability of detection for an airborne gas-mapping LiDAR at 175 metres and 3 metres per second, from the fitted equation in Conrad, Tyner and Johnson 2023. The curve moves with altitude and wind, which is why a detection limit quoted without both is incomplete.

Detection limits are reported in more than one convention, and the numbers are not directly comparable. Some studies report a wind-normalised limit, in kilograms per hour per metre per second [8]. Others fit detection as a function of rate, wind and altitude together [5]. For aerial platforms, a detection limit quoted without a wind speed and an altitude is therefore incomplete.

Different Methods Find Different Emissions

Two methods run over the same sites do not return the same picture [1]. Wilde et al. (2025) analysed three years of British Columbia LDAR data and compared 2021 surveys with independent aerial surveys of the same sites [1]. At 326 sites covered by both, the aerial surveys detected twelve times more methane than the ground LDAR program [1].

That twelvefold figure counts everything the aircraft saw, including potential combustion and intentional vent sources a component survey does not target [1]. Conservatively excluding potential combustion and vent sources still leaves a fourfold difference, the closer like-for-like comparison [1].

The same study measures what the ground programme does achieve [1]. At fully compliant facilities, three comprehensive surveys a year appeared to reduce detected emission sources by 51 per cent [1]. Counting the sites that fell short of the survey schedule, the programme achieved an estimated 40 per cent reduction in detected emissions overall [1]. The authors caution that this apparent reduction in detected emissions does not necessarily equate to an actual cut in overall emissions [1].

Ground LDAR found 2.7 times more individual sources than the aerial survey did [1]. Those sources emitted at 33 times lower rates each [1].

Sources per siteMean rate per source
Ground LDAR survey3.90.34 kg/hr
Aerial survey1.411 kg/hr

Ground surveys found numerous small sources and the aerial survey found fewer, larger ones, over the same sites. [1]

Grouped comparison of ground LDAR surveys against aerial surveys over the same 326 sites, which held 386 facilities and 815 wells. The left pair shows sources found per site: 3.9 for ground LDAR and 1.4 for aerial. The right pair shows the mean emission rate per source on a logarithmic scale: 0.34 kilograms per hour for ground LDAR and 11 kilograms per hour for aerial, a factor of 33. A label notes that the aerial surveys detected twelve times more total methane despite finding fewer sources.

Over the same sites, the two methods found mostly different populations of sources.

Neither result makes the other wrong. Eighty-two per cent of the sources ground LDAR found were connectors, valves, regulators, meters or unspecified sources [1]. Connectors and valves are exactly what a walking survey is built to inspect.

What a survey programme cannot do is see the rest of the year.

What a Periodic Survey Observes of the Year

Detection limit answers what a survey can see, and it leaves open when the survey is looking. A periodic survey observes a site for a few hours and then leaves. An emissions inventory covers 8,760 hours.

The arithmetic is unflattering. Four quarterly surveys of four hours each observe 16 hours of a year. The four hour figure is an assumption rather than a measured average. That is under a fifth of one per cent of the year.

Raising survey frequency moves that number less than intuition suggests. Moving from annual to monthly surveys multiplies observed time by twelve. It still leaves observed time near half a per cent of the year.

Why the Gap Matters When Emissions Are Episodic

Sampling gaps matter in proportion to how uneven the emissions are. Zavala-Araiza et al. (2017) found that super-emitters in natural gas infrastructure are caused by abnormal process conditions [9].

Abnormal conditions are by definition not the state a site is usually in. They arise unpredictably, so a survey observing under a fifth of one per cent of the year catches a short-lived one only by chance. Satellite and aerial surveys extend coverage across area rather than across time, and their trade-offs are covered in Why Satellites Show About 2x More Methane Than Inventories.

Continuous monitoring changes the observation problem rather than the detection problem. A fixed monitor sees the whole year at whatever rate it can resolve. Get regulatory updates and emissions data insights in your inbox. Subscribe to the TetraSoft newsletter.

Where Detection Ends and Inventory Begins

Detection and inventory are different products of different processes. A leak detection and repair program finds and fixes individual leaks. An inventory states how much a site emitted over a reporting period.

The US Environmental Protection Agency (EPA), the federal environmental regulator, finalised its oil and gas methane standards in March 2024 [10]. Its subpart OOOOb, the section of that rule for new, modified and reconstructed sources, sets standards for those sources [10]. Its subpart OOOOc, the section of that rule for existing sources, sets guidelines states follow for them [10].

OOOOb sets survey frequency for new, modified and reconstructed sites, effective May 2024; OOOOc reaches existing sites via state plans or a federal plan. EPA extended deadlines twice in 2025 (90 FR 35966; 90 FR 55671) and finalised narrow flaring and flare-monitoring amendments in April 2026 (91 FR 18056). An October 2026 proposal would change the fugitive-emission requirements.

The federal rule is not the whole of the requirement. Colorado’s Regulation 7, the state’s air rule for oil and gas operations, sets its own tiered inspection schedule for well production facilities [11]. That schedule runs from annual to monthly by facility category [11].

An operator in a state with its own programme must meet both schedules, and What Is Subpart W Suspension? State Rules Still Apply covers why the state layer outlives federal change. Subpart W, named in that title, is the section of EPA’s greenhouse gas reporting rule covering petroleum and natural gas systems [12]. The scope of the OOOOb standards and OOOOc guidelines is covered in OOOOb and OOOOc Explained: Coverage and January 2027 Deadlines. Those standards set how often a site is visited rather than how much it emitted between visits.

What a Detection Program Cannot Tell You

A repair log is not an emissions total, and treating it as one hides the gap. Counting leaks found says nothing about the mass released before they were found. It also says nothing about emissions below the detection limit.

Reporting frameworks separate the two deliberately. OGMP 2.0, the Oil and Gas Methane Partnership, is the United Nations Environment Programme’s flagship oil and gas reporting and mitigation programme [13]. The distinction between survey-based and quantified reporting is covered in OGMP 2.0 Level 4 and Level 5 Reporting Explained.

Where a Measurement-Informed Inventory Fits

TetraSoft does not run leak detection surveys, and TetraSoft MAES, our physics-based Mechanistic Air Emissions Simulator, does not detect leaks either. It cannot tell an operator that a specific valve is leaking now.

MAES is a mechanistic emissions model developed at CSU and the University of Texas at Austin, which TetraSoft uses through a partnership with CSU [14]. A survey returns a rate at one moment, and an inventory needs a mass across a year. Bridging the two takes how often a source sits in its failed state, which the study estimates from snapshots of many similar units [15]. The model produces the normal-operation distribution each detection is judged against, then turns an observed failure frequency into an annual figure [15].

That method has been run on real sites [15]. Across 19 partner midstream facilities in the Appalachian Basin, measured abnormal-process emissions were added to a calibrated baseline [15]. The study, first-authored by Arthur Santos, this post’s author, put modelled emissions 58.9 per cent above operators’ 2022 GHGRP reports for normal operation [15].

Against their total reported inventory, fugitives included, the increase was 40.0 per cent [15]. The revision sat in produced water tanks and compressor crankcases, neither of which the 2022 reporting rules required [15]. The revision also sat in compressor seals found to have failed during the field surveys [15].

EPA’s 2024 Subpart W amendments added reporting requirements for produced water tanks and compressor crankcases [16]. That requirement may not last. In September 2025, EPA proposed suspending Subpart W reporting for production and the other remaining segments until reporting year 2034; that proposal is not final.

Three cautions belong with the 58.9 per cent figure. The authors report it as the contribution of previously unreported sources, not as an independent discrepancy between two estimates [15]. Nineteen facilities from two operators are not a representative sample [15].

The third caution is scope: the model omits emergency shutdowns and maintenance blowdowns, which the authors say makes the reported revision a lower bound [15].

No survey schedule covers the hours when nobody is on site, which is the gap the MAES platform is built to estimate. The same method was applied earlier in the Denver-Julesburg Basin, where it is documented in full [17].

Frequently Asked Questions

Why is the real-world detection limit of an OGI camera higher than its specification?

Because a specification and a field test measure different things. Camera-focused tests typically use a tripod-mounted camera under controlled conditions [4]. A blind controlled release measures a surveyor finding unknown releases on a simulated field site [4].

How should an operator choose an LDAR survey contractor?

Ask how many sites the assigned surveyors have personally covered. The published test split surveyors at a cutoff of 551 sites; no operator or contractor surveyor had covered between 200 and 700 [4]. A bid priced per site says nothing about who will be holding the camera.

What is LDAR, and what does it cover?

LDAR stands for leak detection and repair, a program of scheduled surveys rather than a single instrument. It covers components that leak when they wear or seat badly, such as valves, connectors, flanges, compressors and thief hatches. Each detected leak must be repaired within the deadline the applicable regulation sets, which delay-of-repair provisions can extend. EPA’s OOOOb methane standards set how often new, modified and reconstructed sites are surveyed [10].

What is the difference between LDAR and optical gas imaging?

LDAR is the program and optical gas imaging is one way to carry it out. Other methods, such as a handheld laser or aerial survey, can serve it. Under OOOOb, though, a technology other than AVO (audio, visual and olfactory) checks, OGI or Method 21, EPA’s portable-analyser test, generally needs EPA approval. The program sets how often you look and the method what you find, though under OOOOb screening frequency depends on the method’s detection threshold.

Can a survey tell whether an emission is persistent or intermittent?

Not from one visit. A detection records that gas was escaping while the surveyor was present, not how long it had been. This matters because the highest-emitting sites tend to owe their emissions to abnormal process conditions rather than routine operation [9]. Repeat visits or a continuous monitor are what separate a persistent source from an excursion.

Interested in building a Measurement-Informed Inventory for your operations? Contact us to learn about our MAES-based estimation services.

References

  1. Wilde et al., 2025, ACS ES&T Air, 2, 2527-2536, DOI 10.1021/acsestair.5c00195. “The Efficacy of Methane Leak Detection and Repair (LDAR) Programs in Practice.” https://doi.org/10.1021/acsestair.5c00195
  2. US EPA, 91 FR 68234, October 29, 2026. “Additional Reconsideration Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review.” Proposed rule; comments due December 16, 2026. https://www.govinfo.gov/content/pkg/FR-2026-10-29/html/2026-22082.htm
  3. Chen et al., 2024, ACS ES&T Air, 1, 871-884, DOI 10.1021/acsestair.4c00015. “Comparing Continuous Methane Monitoring Technologies for High-Volume Emissions: A Single-Blind Controlled Release Study.” https://doi.org/10.1021/acsestair.4c00015
  4. Zimmerle et al., 2020, Environmental Science and Technology, 54, 11506-11514, DOI 10.1021/acs.est.0c01285. “Detection Limits of Optical Gas Imaging for Natural Gas Leak Detection in Realistic Controlled Conditions.” https://doi.org/10.1021/acs.est.0c01285
  5. Conrad, Tyner and Johnson, 2023, Remote Sensing of Environment, 288, 113499, DOI 10.1016/j.rse.2023.113499. “Robust probabilities of detection and quantification uncertainty for aerial methane detection: Examples for three airborne technologies.” https://doi.org/10.1016/j.rse.2023.113499
  6. Day, Levin and Zimmerle, 2025, CSU Energy Institute METEC, handheld laser controlled-release assessment, pre-peer-review, not yet final. “Handheld Laser-Based Methane Leak Detection Device Performance During Controlled Natural Gas Releases.” Research poster summary; the authors state results are preliminary and the study is ongoing. https://metec.colostate.edu/handheld-laser/
  7. Colorado State University Energy Institute, METEC home page. “Methane Emissions Technology Evaluation Center”: test and research facility for emissions leak detection and quantification. https://metec.colostate.edu/
  8. Bell et al., 2022, Elementa, 10, 00080, DOI 10.1525/elementa.2022.00080. “Single-blind determination of methane detection limits and quantification accuracy using aircraft-based LiDAR.” https://doi.org/10.1525/elementa.2022.00080
  9. Zavala-Araiza et al., Nature Communications, 8, 14012, 2017. “Super-emitters in natural gas infrastructure are caused by abnormal process conditions.” https://doi.org/10.1038/ncomms14012
  10. US EPA, 89 FR 16820, March 8, 2024. “Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review.” Final rule, 40 CFR part 60. https://www.govinfo.gov/content/pkg/FR-2024-03-08/pdf/2024-00366.pdf
  11. Colorado AQCC Regulation Number 7, 5 CCR 1001-9. Control of Emissions from Oil and Gas Emissions Operations. Formerly titled Control of Ozone via Ozone Precursors and Control of Hydrocarbons via Oil and Gas Emissions. Colorado Air Quality Control Commission; leak detection and repair inspection frequencies for well production facilities.
  12. US EPA, GHGRP Subpart W page. “Subpart W: Petroleum and Natural Gas Systems,” Greenhouse Gas Reporting Program. https://www.epa.gov/ghgreporting/subpart-w-petroleum-and-natural-gas-systems
  13. UNEP, OGMP 2.0 home page. “The flagship oil and gas reporting and mitigation programme of the United Nations Environment Programme (UNEP).” https://ogmpartnership.org/
  14. Mollel et al., 2025, ACS ES&T Air, 2, 723-735, DOI 10.1021/acsestair.4c00168. “Using Prototypical Oil and Gas Sites to Model Methane Emissions in Colorado’s Denver-Julesburg Basin Using a Mechanistic Emission Estimation Tool.” https://doi.org/10.1021/acsestair.4c00168
  15. Santos et al., 2026, Gases, 6, 44, DOI 10.3390/gases6030044. “Beyond Snapshots: Building Methane Measurement-Informed Inventories for Midstream Oil and Gas Sites in the Appalachian Basin.” https://doi.org/10.3390/gases6030044
  16. US EPA, 89 FR 42062, May 14, 2024. “Greenhouse Gas Reporting Rule: Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems.” Final rule, 40 CFR part 98. https://www.federalregister.gov/documents/2024/05/14/2024-08988/greenhouse-gas-reporting-rule-revisions-and-confidentiality-determinations-for-petroleum-and-natural
  17. Santos et al., 2025, ACS ES&T Air, 2, 1598-1611, DOI 10.1021/acsestair.5c00089. “Using Measurement-Informed Inventory to Assess Emissions in the Denver-Julesburg Basin.” https://doi.org/10.1021/acsestair.5c00089
  18. Sherwin et al., 2021, Elementa, 9, 00063, DOI 10.1525/elementa.2021.00063. “Single-blind test of airplane-based hyperspectral methane detection via controlled releases.” https://doi.org/10.1525/elementa.2021.00063
  19. Ravikumar et al., 2018, Environmental Science and Technology, 52, 2368-2374, DOI 10.1021/acs.est.7b04945. ""Good versus Good Enough?” Empirical Tests of Methane Leak Detection Sensitivity of a Commercial Infrared Camera.” https://doi.org/10.1021/acs.est.7b04945
  20. Bell et al., 2023, Environmental Science and Technology, 57, 5794-5805, DOI 10.1021/acs.est.2c09235. “Performance of Continuous Emission Monitoring Solutions under a Single-Blind Controlled Testing Protocol.” https://doi.org/10.1021/acs.est.2c09235
  21. Sherwin et al., 2024, Atmospheric Measurement Techniques, 17, 765-782, DOI 10.5194/amt-17-765-2024. “Single-blind test of nine methane-sensing satellite systems from three continents.” https://doi.org/10.5194/amt-17-765-2024
  22. Cheptonui et al., 2025, Elementa, 13, 00020, DOI 10.1525/elementa.2025.00020. “Assessing the performance of emerging and existing continuous monitoring solutions under a single-blind controlled testing protocol.” https://doi.org/10.1525/elementa.2025.00020
  23. US EPA, 91 FR 18056, April 9, 2026. “Reconsideration of Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review.” Final rule, effective June 8, 2026; discrete technical changes to the temporary flaring provisions and to vent gas net heating value monitoring for flares and enclosed combustion devices. https://www.federalregister.gov/documents/2026/04/09/2026-06808/reconsideration-of-standards-of-performance-for-new-reconstructed-and-modified-sources-and-emissions

This post is for informational purposes only and does not constitute legal or compliance advice. Consult qualified legal counsel or a compliance professional for guidance specific to your operations and jurisdiction.

Interactive tool

How much of the year does your survey see?

A periodic leak survey observes a site for a few hours and then leaves. This works out what share of the year that is, and how long a new leak waits on average.

Survey frequency

Share of the year observed

0.18%

Hours observed
16
Hours unobserved
8,744
Mean wait to detection
46 days

Against continuous monitoring

This programme 0.18%
Continuous 100%

Continuous observation covers 548 times more of the year.

A year is 8,760 hours. Hours observed is simply surveys times hours each. The mean wait to detection is half the interval between surveys, which assumes a leak is equally likely to begin at any moment. This tool makes no claim about what a survey detects when it is on site: minimum detectable emission rate is a separate property, and the published controlled-release studies are the place to read it. Nothing leaves your browser.