Intervention Accounting Research Series · Exploration Phase GHG Emissions
A comparative inventory of greenhouse gas emissions across three archetypal long-term oil & gas exploration programs — remote Arctic, resource-town supported, and deepwater offshore — with hypothetical scenario calculators for each category. All quantified values are derived from published literature, OPGEE v3.0 default factors, EPA GHGRP methodology, and operator disclosures. Estimates are indicative; field-specific monitoring data should be used where available.
The Prudhoe Bay discovery involved seismic surveys from the late 1950s, dozens of dry holes drilled under extreme cold (−65 °F) over permafrost reaching 2,000 ft depth, and ultimately the Prudhoe Bay State #1 well spudded in April 1967. The remote, roadless environment meant every litre of diesel, every rig component, and every crew member had to be flown or barged in. Permafrost disturbance released biogenic soil carbon across pad and road footprints. No town pre-existed; a temporary exploration camp supported operations.
GHG estimates below cover the pre-production exploration phase (1964–1977). Values are constructed from OPGEE v3.0 defaults scaled to documented well counts and footage, with Arctic multipliers for mobilization and heating fuel.
~80 exploration/delineation wells drilled 1964–1977; avg depth 9,500 ft. Diesel-powered rigs in Arctic conditions require heating fuel adding ~35% premium over temperate defaults. OPGEE v3.0 factor: 0.20 kg CO₂e/m (ground-accessible), scaled to helicopter-supported majority at 15 kg CO₂e/m median. Estimated total footage: ~760,000 m × blended factor ~0.64 kg CO₂e/m. Generator sets, mud pumps, and camp power included.
No road to Deadhorse existed until 1974. Pre-1974 logistics: fixed-wing and helicopter resupply from Fairbanks (~600 km). Post-1974 Dalton Highway trucking. Fuel transport alone estimated at 95,000 t CO₂e. Crew rotations, seismic vehicles, and barge-in rig components account for balance. Seismic survey vessels and vibrator trucks: ~3 major 2D programs 1964–1968.
December 1967 gas flare during drilling confirmed reservoir presence. Well testing on discovery well and ~12 subsequent delineation test wells, each estimated 30–90 day test periods. 1960s practice was open flaring with no capture. GOR and reservoir pressure data from AAPG 1970 paper used to estimate gas volumes. CH₄ content ~89% of produced gas. CO₂e at GWP100 = 28 applied to unflared vents.
Arctic tundra and permafrost carbon stock: 800–1,200 t C/ha in upper 1 m. Estimated 3,200 ha disturbed (pads, winter roads, staging areas) over exploration phase. Permafrost thaw releases both CO₂ and CH₄ from organic layer. 30-year OPGEE land use factor applied; permanent infrastructure loss counted at 150-year horizon. NASA GSOC database: ~950 t C/ha soil organic carbon for this region.
Mud gas separator venting, gas kicks during overpressured zones, and drilling mud volatilization. OPGEE default: ~0.5 g CH₄/m drilled for conventional Arctic well, scaled to 760,000 m total footage. Blowout events (no confirmed major blowouts in Prudhoe exploration phase) not included. GWP100 = 28 applied. Underestimation likely given 1960s–70s measurement limitations.
Sources: OPGEE v3.0 (Stanford EAO); AAPG Bulletin 1970 (Morgridge); BP 40th Anniversary Release (2017); USGS North Slope Survey Records; NASA GSOC; EPA AP-42 Ch.5; Alaska Division of Oil & Gas annual reports.
⟳ Hypothetical Scenario Calculator — Remote Arctic Exploration
Fort McMurray's transformation from a fur-trade outpost to a resource town was built directly on the decades-long, multi-operator exploration and pilot extraction program in the Athabasca oil sands. Population swelled and contracted with exploration activity. The town grew to provide logistics, crew housing, fuel depots, and equipment yards — itself becoming an emission source directly linked to the exploration program through crew transport, urban energy use, and freight movements.
The exploration phase here is distinctively high in land disturbance (boreal forest clearing, test pits, pilot plant operations) and includes Steam-Assisted Gravity Drainage (SAGD) pilot tests from the 1950s, which involve significant natural gas combustion for steam generation — a category not present in conventional oil exploration programs.
Approx. 400 core holes and test wells drilled 1920–1967, avg depth ~300 m (shallow bitumen target). Diesel rigs supplemented by natural gas power post-1950. Pilot plant operations (Clearwater River plant 1929–30; Bitumount 1944–50; GCOS construction 1964–67) included heavy equipment fleets, conveyor drives, and process vessels. OPGEE ground-transport factor 0.2–0.64 kg CO₂e/m. Steam generation for SAGD pilots: ~82,000 t CO₂e (natural gas combustion).
Fort McMurray road-accessible by Highway 63 from Edmonton (~440 km). Truck freight dominant from 1950s onward. Earlier barge transport on Athabasca River. Town-originated crew transport to sites adds a community-displacement component unique to this scenario. Estimated 1,200 crew-years of activity; weekly 880 km round-trip Edmonton ↔ McMurray freight cycles factored at 35 trucks/week peak.
Bitumen does not gas-test in the same manner as conventional oil; well testing emissions are lower. However, pilot plants operated hot-water separation with associated vapour losses (bitumen froth processing) and tail gas stacks. GCOS plant commissioning 1967 involved flaring of associated gas during startup. Venting from bitumen froth processing estimated at ~12 kg CO₂e/tonne bitumen processed across pilot scale.
Boreal forest carbon stock ~400 t C/ha above and below ground combined. Estimated 2,800 ha cleared for exploration seismic lines, test pits, open-pit pilot mines, access roads, and plant construction (1920–1967). 30-year biogenic release: ~70% of disturbed stock emitted as CO₂. Notably higher per-hectare impact than tundra due to above-ground biomass. Peat depth in this region averages 0.8–1.5 m; peat carbon loss included.
Fugitive methane from bitumen core handling and gas-phase drilling emissions are relatively low (bitumen is very low volatility). However, Fort McMurray as a supported town introduces secondary community emissions: heating of worker camps and housing, municipal power generation, and waste. Estimated town-attributable community emissions allocated to exploration program: ~28,000 t CO₂e over 47 years at 1950s–60s activity levels.
Sources: OPGEE v3.0 (Stanford); Oil Sands Magazine History Series; Alberta Heritage / Energy Heritage; Canadian Encyclopedia Oil Sands entry; Research Council of Alberta 1930 plant reports; Alberta Energy Regulator historical well database; OPGEE Land Use Module (Yeh et al.); GHG Protocol Community-Scale Inventory (GPC) for town-attributed emissions.
⟳ Hypothetical Scenario Calculator — Resource-Town Supported Exploration
The Macondo Prospect (Mississippi Canyon Block 252) was mapped by BP in 2008–2009 using 3D seismic. MMS approved the exploration plan April 6, 2009. Drilling began October 7, 2009 using the Transocean Marianas semi-submersible; it was halted by Hurricane Ida damage November 2009. The Deepwater Horizon — a dynamically positioned, ultra-deepwater semi-submersible — resumed drilling February 6, 2010. The catastrophic blowout April 20, 2010 resulted in 4–4.9 million barrels of oil and an estimated 250,000 metric tonnes of hydrocarbon gases released over 87 days.
GHGs here split into two distinct categories: normal exploration operations (rig fuel burn, seismic vessel emissions, crew transport) and the blowout event (uncontrolled fugitive gas and combustion from the rig fire). Both are quantified separately.
Deepwater Horizon: 9-year BP contract rig (~2001–2010); prior wells at Tiber and Kaskida fields. For Macondo specifically: Marianas rig 34 days active + Deepwater Horizon ~75 days before blowout. Semi-submersible fuel consumption: ~100–130 t diesel/day underway/drilling. ~109 rig-days × 115 t/day × 3.17 t CO₂e/t diesel = ~39,800 t CO₂e (Macondo-specific). Remaining estimate allocated from Deepwater Horizon's prior deepwater exploration in GoM (2001–2010) at reported fleet-level fuel intensity.
3D seismic survey 2008–2009: estimated 60-day vessel program. A single offshore seismic survey ship emits ~100+ t CO₂/day (JOUAV, 2025). Seismic program: ~6,000 t CO₂e. Supply vessel logistics (Gulf of Mexico base: Port Fourchon, LA): 2–3 supply boats servicing daily, avg 160 km round-trip, diesel-powered. 109 active days: ~18,000 t CO₂e in supply runs. Helicopter crew rotations: ~14,000 t CO₂e. Guard vessel: ~4,000 t CO₂e.
This category dominates all others by orders of magnitude. 50 billion cubic feet of methane reported released (patent literature; NRDC estimates). 250,000 metric tonnes of hydrocarbon gases discharged (Joye 2015, ScienceDirect). CH₄ component at GWP100 = 28: ~6.6 Mt CO₂e from gas alone. 36-hour rig fire combustion of surface hydrocarbons: ~180,000 t CO₂e. Atmospheric combustion of flared oil during 87-day burn-off operations: ~420,000 t CO₂e. This figure represents a catastrophic tail-risk scenario, not typical exploration.
Deepwater sediment carbon: ~8–15 mg C/g dry sediment across affected Gulf benthos. Physical disturbance from drill cuttings, anchor chains, and blowout debris over ~35 km² documented impact area (DWH footprint analysis, PMC7326171). ~50% of discharged oil entrained in deepwater plume (Joye 2015), where anaerobic degradation produces CH₄ and CO₂. Benthic oxidation of settled hydrocarbons: long-term diffuse emission estimated at ~190,000 t CO₂e over 5-year post-event horizon.
Under normal (non-blowout) deepwater drilling operations: mud gas separator venting, gas kicks in high-pressure Macondo reservoir (encountered multiple pore-pressure exceedances documented in BP accident investigation report). Deepwater fugitive rates lower than onshore due to pressurized marine riser systems. OPGEE deepwater default: ~0.3 g CH₄/m drilled. Total depth 18,360 ft (5,596 m) × factor = ~1.7 t CH₄ = ~47 t CO₂e normal operations. Adjusted upward to ~114 t CH₄ for documented kick events × GWP100 = 28.
Sources: BP Accident Investigation Report (2010); Joye (2015) ScienceDirect; Wikipedia / Macondo Prospect; National Academies Press — Macondo Well Blowout (2012); JOUAV Seismic Survey Guide (2025); EPA Deepwater Horizon enforcement record; NRDC gas volume estimates; PMC7326171 (DWH benthic footprint); OPGEE v3.0 deepwater defaults; patent literature (CH₄ volume estimates).
⟳ Hypothetical Scenario Calculator — Offshore Deepwater Exploration