OOIP, Oil & Gas Glossary

What Is OOIP?

OOIP (Original Oil in Place) is the total volume of crude oil estimated to exist in a reservoir at the time of discovery, expressed in stock tank barrels (STB) or cubic metres at surface conditions, and represents the upper bound on what can ever be produced from the accumulation — with the actually recoverable fraction determined by reservoir drive mechanism, rock and fluid properties, and the recovery methods deployed across the life of the field from primary production through enhanced oil recovery.

Key Takeaways

OOIP is calculated volumetrically as: OOIP = (Pore Volume × Oil Saturation) / Formation Volume Factor — where pore volume is derived from reservoir area, net pay thickness, and porosity; oil saturation is 1 minus water saturation; and the formation volume factor converts reservoir-condition volumes to surface stock tank conditions.
Recovery factor — the fraction of OOIP that is ultimately produced — ranges from 5 to 15% for heavy oil primary recovery (Cold Lake, Peace River), 20 to 40% for conventional light oil with waterflood, and up to 60 to 70% for high-quality carbonate reservoirs under gas injection, as seen in Saudi Aramco's Arab Formation fields at Ghawar.
OOIP is not the same as reserves: reserves are the commercially recoverable subset of OOIP under current economics and technology; a large OOIP with a low recovery factor can have smaller reserves than a smaller OOIP with an efficient recovery scheme.
OOIP uncertainty is quantified through probabilistic volumetric analysis using Monte Carlo simulation of the input parameters — area, thickness, porosity, water saturation, and formation volume factor — producing P90 (proved), P50 (best estimate), and P10 (optimistic) OOIP distributions that underpin reserve classification under SPE-PRMS.
National regulators including AER (Alberta), BSEE (US), Sodir (Norway), and NOPSEMA (Australia) require OOIP estimates as part of field development plan submissions and annual reserve reporting to ensure that production forecasts and royalty calculations are grounded in volumetrically defensible resource estimates.

How OOIP Is Calculated

The standard volumetric OOIP equation is:

OOIP (STB) = 7758 × A × h × φ × (1 − Sw) / Bo

Where: 7758 is the conversion factor (barrels per acre-foot); A is reservoir area in acres; h is net pay thickness in feet; φ is average porosity (fraction); Sw is average water saturation (fraction); and Bo is the oil formation volume factor (reservoir barrels per stock tank barrel). In metric units, the conversion factor 7758 is replaced by 1000 × area in hectares × thickness in metres.

Each input carries uncertainty. Reservoir area is defined by seismic mapping and well control — sparsely drilled fields have wide area uncertainty ranges. Net pay thickness depends on petrophysical cutoffs applied to porosity and shale volume logs. Porosity is measured from core and calibrated to wireline logs. Water saturation is calculated from resistivity logs using Archie's equation or the Waxman-Smits model for shaly sands. The formation volume factor is measured in PVT lab analysis of reservoir fluid samples and corrects for gas-in-solution shrinkage as oil is produced to surface conditions. In tight oil plays like the Montney and Duvernay in Alberta, matrix porosity of 3 to 8% combined with high water saturation reduces OOIP per unit volume compared to conventional sandstone reservoirs, but the vast areal extent of the play compensates for low recovery factors per well.

OOIP Estimation Across International Jurisdictions

In Canada, OOIP estimation for Alberta wells is governed by AER Directive 065 (Resources Applications for Conventional Oil and Gas Reservoirs), which requires volumetric calculations supported by petrophysical analysis and geological mapping in all field development applications. The AER's Reserves Assessment Group reviews OOIP estimates submitted in pool establishment applications. For oil sands, AER Directive 023 governs resource assessment; the Athabasca Oil Sands Area contains approximately 166 billion barrels of OOIP under assessment by operators including Suncor, Cenovus, and Canadian Natural Resources, of which approximately 10% is recoverable by in-situ methods (SAGD) under current technology and economics.

In the United States, BSEE and BOEM require OOIP estimates in field development plans for OCS leases; the SEC's reserve disclosure rules (Rule 4-10 of Regulation S-X) set the standard for how OOIP and reserves are reported to investors, with proved reserves requiring 90% confidence recovery under existing economic conditions. In Norway, Sodir's annual resource accounts compile OOIP by field across the Norwegian Continental Shelf; the Johan Sverdrup Field, the largest discovery on the NCS in 30 years, has an OOIP of 12 to 17 billion barrels with a recovery factor targeting 70% through pressure maintenance and polymer flooding, according to operator Equinor. In Australia, NOPSEMA's production measurement and reporting framework requires OOIP estimates to be submitted with development plan applications for offshore petroleum fields; the North West Shelf joint venture's Rankin complex in the Carnarvon Basin contains multi-trillion cubic feet gas equivalent, with original hydrocarbon in place underpinning Woodside's long-term LNG production. In the Middle East, Saudi Aramco has assessed the Ghawar Field's OOIP at approximately 70 to 75 billion stock tank barrels, making it the largest single oil accumulation ever discovered; sustained recovery factors above 50% are achieved through peripheral water injection that maintains reservoir pressure above the bubble point, preventing gas breakout that would reduce ultimate recovery.

Fast Facts

The global conventional OOIP is estimated at approximately 9 to 12 trillion barrels — of which only 1 to 1.5 trillion barrels (roughly 10 to 15%) is economically recoverable with today's technology and prices. Enhanced oil recovery (EOR) methods — CO₂ flooding, polymer flooding, thermal SAGD — are the primary mechanisms being deployed to improve recovery factors toward the theoretical maximum, particularly in mature fields where the easy barrels have already been produced.

OOIP and Reserve Classification

Under the SPE Petroleum Resources Management System (SPE-PRMS), OOIP sits above the reserve classification hierarchy as the total resource endowment. From OOIP, petroleum resources are classified into: Reserves (discovered, commercial, recoverable under current conditions); Contingent Resources (discovered, not yet commercial — requires further appraisal or improved economics); and Prospective Resources (undiscovered — exploration upside). The recovery factor applied to OOIP to produce reserves is not a fixed number but varies with development scheme: a conventional waterflood on a North Sea sandstone may recover 40 to 50% of OOIP; a cold production scheme on Lloydminster heavy oil may recover only 5 to 8%; and a SAGD project on Athabasca bitumen targets 50 to 70% of OOIP after multiple cycles of steam injection.

Tip: When comparing OOIP estimates between fields or vintages of a study, always check whether the volumes are stated at reservoir conditions or stock tank conditions — the difference is the formation volume factor (Bo), which ranges from 1.05 for heavy oil to 1.8 or higher for high-GOR condensate-rich oils. A field with a high Bo reported at reservoir conditions will have a substantially lower OOIP in stock tank barrels, which is the conventional commercial basis for reserve reporting. Mixing reservoir-condition and stock-tank-condition volumes in the same analysis is a common source of error in resource reconciliation.

OOIP is also known as:

Original Oil in Place — the full form; used in AER submissions, SPE-PRMS reserve reports, and investor disclosures
STOIIP — Stock Tank Oil Initially In Place; the more precise term specifying that volumes are at surface (stock tank) conditions rather than reservoir conditions; dominant in UK North Sea, Norwegian, and Australian technical literature
OIP — Oil in Place; the shortened form used in field operations and informal reserve discussions
HIIP — Hydrocarbon Initially in Place; the combined oil and gas equivalent used when both phases are present in the same accumulation

Frequently Asked Questions

What is the difference between OOIP and reserves?

OOIP is the total oil estimated to exist in the reservoir before any production. Reserves are the portion of OOIP that is technically and commercially recoverable under current prices, costs, and technology. The ratio of reserves to OOIP is the recovery factor. A large OOIP with a low recovery factor (e.g., 10%) can have the same reserves as a smaller OOIP with a high recovery factor (e.g., 60%) — which is why OOIP alone does not determine a field's commercial value.

How is OOIP uncertainty quantified?

OOIP uncertainty is modelled using Monte Carlo simulation: each input parameter (area, thickness, porosity, water saturation, formation volume factor) is assigned a probability distribution reflecting geological and petrophysical uncertainty, and thousands of random samples through these distributions generate a probabilistic OOIP range. The P90 (low), P50 (mid), and P10 (high) cases from this distribution correspond approximately to proved, best estimate, and optimistic OOIP — which then underpin 1P, 2P, and 3P reserve classifications under SPE-PRMS.

What is a typical recovery factor for oil fields?

Recovery factors range widely: 5 to 15% for primary recovery only (solution gas drive, gravity drainage); 20 to 40% for conventional light oil fields with waterflooding; 50 to 70% for high-quality carbonate reservoirs under pressure maintenance; and 40 to 60% for heavy oil SAGD projects after multiple steam cycles. The global average recovery factor for conventional oil is approximately 35 to 40%, meaning roughly 60 to 65% of all OOIP ever discovered remains in the ground.

Why OOIP Matters in Oil and Gas

OOIP is the foundation of every reserve estimate, every field development plan, and every royalty and fiscal regime calculation in the oil and gas industry. A well-supported OOIP estimate — grounded in quality petrophysics, 3D seismic, and representative core and fluid samples — enables operators to design the right recovery scheme, size facilities correctly, and commit capital with confidence. An overstated OOIP leads to oversized, stranded facilities; an understated OOIP leaves commercial hydrocarbons undeveloped. In Alberta, where the AER requires pool establishment volumes for every new pool declaration, OOIP governs royalty tier calculations affecting the economics of thousands of wells. In the Middle East, where Aramco's OOIP estimates for Ghawar, Safaniya, and Shaybah are national strategic assets, the accuracy of these numbers shapes decades of sovereign investment planning. Understanding what is in the ground — and how much of it can realistically be recovered — is the starting point for every decision the industry makes.