Oil Formation Volume Factor (Bo)
Compute the oil formation volume factor (Bo) by dividing the volume the oil occupies at reservoir conditions by the volume it occupies at the surface (stock-tank barrels). Bo is always greater than 1 because, in the reservoir, the oil is hot and has dissolved gas, occupying more space; as it rises and loses gas and heat, it shrinks. It is essential to convert reservoir volumes into surface production. Enter the volumes at reservoir and surface conditions.
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Oil formation volume factor (Bo)
A barrel of oil measured down in the reservoir does not yield a barrel at the surface — it yields less. The formation volume factor Bo = reservoir volume / surface volume captures that shrinkage, and it is always greater than 1 (typically 1.1 to 1.8). Why? Down in the reservoir the oil sits hot (tens to hundreds of degrees) and, crucially, carries a great deal of dissolved gas under high pressure — much like a sealed bottle of soda. On the way up the wellbore and through the separators it cools down and releases the gas (which becomes separate gas production), shrinking the liquid that remains. Bo is measured in the laboratory by PVT (pressure-volume-temperature) analysis of fluid samples, and it varies with pressure (rising up to the bubble point, falling below it). It is indispensable for turning reservoir volumes into sellable stock-tank barrels — it shows up in the OOIP calculation and in material balance. Enter the volumes at reservoir and at surface conditions.
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Recoverable Oil Reserves
Compute the recoverable oil reserves by multiplying the original oil in place (OOIP) by the recovery factor (%). While the OOIP is the total volume present in the rock, only a fraction is technically and economically extractable — those are the reserves that actually have value and enter oil companies' books. It is the number behind asset valuations and investment decisions. Enter the OOIP and the recovery factor.
Reservoir Recovery Factor
Compute a reservoir's recovery factor, RF = (Np/N)·100%, the fraction of the original oil (N, or OOIP) that will actually be produced (Np). It is one of the most important — and uncertain — numbers in the industry: primary recovery (natural energy) is usually 5–15%; with secondary recovery (water/gas injection) it rises to 30–50%; and advanced methods (EOR) can go further. It defines the field's economic value. Enter the cumulative production and the original oil in place.
Oil in Place (OOIP)
Compute a reservoir's original oil in place (OOIP) by the volumetric method, OOIP = 7758·A·h·φ·(1−Sw)/Boi, in stock-tank barrels (STB). It combines the reservoir area (acres), the porous thickness (ft), the porosity (φ), the water saturation (Sw) and the oil formation volume factor (Boi). The constant 7758 converts acre-feet into barrels. It is the basis of any oil-field evaluation. Enter the area, thickness, porosity, water saturation and Boi.
Gas-Oil Ratio (GOR)
Compute the gas-oil ratio (GOR) by dividing the produced gas volume by the oil volume, in scf/STB (standard cubic feet per barrel). It is a central petroleum-production parameter: it indicates how much gas accompanies the oil, characterizes the reservoir fluid type (black oil, volatile, gas-condensate) and sizes the surface separation equipment. A rising GOR can signal gas-cap breakthrough at the well. Enter the gas and oil volumes.
Fire Water Reserve (RTI)
Calculate the fire water reserve volume, V = flow × time ÷ 1000, multiplying the system's required flow (L/min) by the required autonomy time (min) and converting to cubic metres. The result, in m³, is the water volume the tank must keep reserved exclusively for firefighting — sized to feed hydrants and/or sprinklers for the minimum time set by codes (typically 30 to 60 min, depending on risk). It is a central calculation in building firefighting installation design. Enter the flow and the autonomy time.
Shale Volume from Gamma Ray (Larionov)
Estimates the shale volume of a formation from the gamma ray log, the first step in any petrophysical well evaluation. The calculation normalizes the zone reading between the cleanest sand and the most radioactive shale in the interval, giving the gamma ray index IGR = (GR − GR min) ÷ (GR max − GR min), and then applies the non-linear Larionov curve, Vsh = 0.083 × (2^(3.7 × IGR) − 1). The result is the fraction of rock volume occupied by clay, as a percentage: intervals above 30 to 40% are usually discarded as reservoir, and the value later feeds the porosity and water saturation corrections for shaly sands. The Larionov curve for Tertiary, poorly consolidated rocks was adopted, which is the usual one in young sedimentary basins; for Mesozoic or older rocks the literature uses Vsh = 0.33 × (2^(2 × IGR) − 1), which returns far larger volumes for the same IGR. Enter the zone gamma ray reading, the minimum reading and the maximum reading of the interval.
The results provided by this tool are for general informational and educational purposes only and do not constitute professional, financial, medical, legal, tax or accounting advice. Always confirm important decisions with a qualified professional and official sources.