RRRRReeeeesssssererererervvvvvoir Engoir Engoir Engoir Engoir Engininininineeeeeering for Gering for Gering for Gering for Gering for GeeeeeolooloolooloologggggistsistsistsistsistsArticle 3 Volumetric Estimation by Lisa Dean, P. Geol., Fekete Associates Inc..

You have been asked to:

Evaluate the properties that are forsale in a data room.

Determine whether to participate in aprospect.

Calculate the potential reservesencountered by a discovery well.

Identify the upside potential in amature field.

In all these situations, the bottom line ishow much oil or gas exists and can beproduced, and what will be the return oninvestment? This article addresses thisquestion.

Volumetric estimation is the only meansavailable to assess hydrocarbons in placeprior to acquiring sufficient pressure andproduction information to apply materialbalance techniques. Recoverablehydrocarbons are estimated from the inplaceestimates and a recovery factor that isestimated from analogue pool performanceand/or simulation studies.

Therefore, volumetric methods are primarilyused to evaluate the in-place hydrocarbonsin new, non-producing wells and pools andnew petroleum basins. But even afterpressure and production data exists,volumetric estimates provide a valuable checkon the estimates derived from materialbalance and decline analysis methods (to bediscussed in upcoming Reservoir issues).

VVVVVOLOLOLOLOLUMEUMEUMEUMEUMETRIC ETRIC ETRIC ETRIC ETRIC ESSSSSTIMATIMATIMATIMATIMATIONTIONTIONTIONTIONVolumetric estimation is also known as thegeologists method as it is based on cores,analysis of wireline logs, and geological maps.Knowledge of the deposit ionalenvironment, the structural complexities,the trapping mechanism, and any fluidinteraction is required to:

Estimate the volume of subsurface rockthat contains hydrocarbons. Thevolume is calculated from thethickness of the rock containing oil orgas and the areal extent of theaccumulation (Figure 3.1).

Determine a weighted average effectiveporosity (See Figure 3.2).

Obtain a reasonable water resistivityvalue and calculate water saturation.

With these reservoir rock properties andutilizing the hydrocarbon fluid properties,

Figure 3.1. Areal estent of rock volume accumulation.

Figure 3.2. Weighted average effective porosity.

Sand Grain

CementingMaterial

Interconnected orEffective Porosity

25%

Isolated orNoneffective

Porosity5%

Total Porosity30%

original oil-in-place or original gas-in-placevolumes can be calculated.

For OIL RESERVOIRS the original oil-inplace (OOIP) volumetric calculation is:

Metric:OOIP (m3) =Rock Volume * * (1 - Sw) * 1/Bo

Where: Rock Volume (m3) = 104 * A * hA = Drainage area, hectares (1 ha =

104m2)h = Net pay thickness, metres = Porosity, fraction of rock

volume available to store fluidsSw = Volume fraction of porosity

filled with interstitial waterBo = Formation volume factor (m

3/m3) (dimensionless factor forthe change in oil volumebetween reservoir conditionsand standard conditions atsurface)

1/Bo = Shrinkage (Stock Tank m3/

reservoir m3) = volume changethat the oil undergoes whenbrought to the earths surfacedue to solution gas evolvingout of the oil.

Imperial:OOIP (STB) =Rock Volume * 7,758 * * (1 - Sw) * 1/Bo

Where: Rock Volume (acre feet) = A * hA = Drainage area, acresh = Net pay thickness, feet7,758 = API Bbl per acre-feet (converts

acre-feet to stock tank barrels) = Porosity, fraction of rock

volume available to store fluidsSw = Volume fraction of porosity

filled with interstitial waterBo = Formation volume factor

(Reservoir Bbl/STB)1/Bo = Shrinkage (STB/reservoir Bbl)

To calculate recoverable oil volumes theOOIP must be multiplied by the RecoveryFactor (fraction). The recovery factor is oneof the most important, yet the most difficultvariable to estimate. Fluid properties suchas formation volume factor, viscosity, density,and solution gas/oil ratio all influence therecovery factor. In addition, it is also afunction of the reservoir drive mechanismand the interaction between reservoir rockand the fluids in the reservoir. Some industrystandard oil recovery factor ranges forvarious natural drive mechanisms are listedbelow:

Solution gas drive 2 30%Gas cap drive 30 60%Water drive 2 50%Gravity Up to 60%

For GAS RESERVOIRS the original gas-in-place (OGIP) volumetric calculation is:

Metric:OGIP (103m3) =Rock Volume * * (1-Sw) * ((Ts * Pi) / (Ps * Tf * Zi))

Where: Rock Volume (m3) = 104 * A * h

A = Drainage area, hectares (1 ha =104m2)

h = Net pay thickness, metres = Porosity, fraction of rock volume

available to store fluidsSw = Volume fraction of porosity filled

with interstitial water

Ts = Base temperature, standardconditions, Kelvin (273 +15C)

Ps = Base pressure, standard conditions,(101.35 kPaa)

Tf = Formation temperature, Kelvin(273 + C at formation depth)

Pi = Initial Reservoir pressure, kPaaZi = Compressibility at Pi and Tf

Imperial:OGIP (MMCF) =Rock Volume * 43,560 * * (1-Sw) * ((Ts * Pi)/ (Ps * Tf * Zi))

Figure 3.3. Volumetric rules: Trapezoidal, pyramidal, and cone.

Trapezoidal Volume V = h * ((A1 + A2) / 2)

Frustum of a pyramid V = (h/3) * (A1 + A2 + A1 * A2)

Frustum of a cone V = (h/3) * * (r2 + rR + R2)

Where: Rock Volume (acre feet) = A * hA = Drainage area, acres (1 acre =

43,560 sq. ft)h = Net pay thickness, feet = Porosity, fraction of rock volume

available to store fluidsSw = Volume fraction of porosity filled

with interstitial waterTs = Base temperature, standard

conditions, Rankine (460 +60F)

Ps = Base pressure, standard conditions,14.65 psia

Tf = Formation temperature, Rankine(460 + F at formation depth)

Pi = Initial Reservoir pressure, psiaZi = Compressibility at Pi and Tf

To calculate recoverable gas volumes, theOGIP is multiplied by a recovery factor.Volumetric depletion of a gas reservoir withreasonable permeability at conventionaldepths in a conventional area will usuallyrecover 70 to 90% of the gas-in-place.However, a reservoirs recovery factor canbe significantly reduced by factors such as:low permeability, low production rate ,overpressure, soft sediment compaction,fines migration, excessive formation depth,water influx, water coning and/or behind pipecross flow, and the position and number ofproducing wells. As an example, a 60%recovery factor might be appropriate for agas accumulation overlying a strong aquiferwith near perfect pressure support.

Rock Volume Calculations (A * h)Reservoir volumes can be calculated fromnet pay isopach maps by planimetering toobtain rock volume (A * h). To calculatevolumes it is necessary to find the areasbetween isopach contours. Planimetering canbe performed by hand or computergenerated. Given the areas betweencontours, volumes can be computed using;Trapezoidal rule, Pyramidal rule, and/or thePeak rule for calculating volumes (see Figure3.3).

Net payNet pay is the part of a reservoir from whichhydrocarbons can be produced at economicrates, given a specific production method.The distinction between gross and net pay ismade by applying cut-off values in thepetrophysical analysis (Figure 3.4). Net paycut-offs are used to identify values belowwhich the reservoir is effectively non-productive.

In general, the cut-off values are determinedbased on the relationship between porosity,permeability, and water saturation from coredata and capillary pressure data. If core isunavailable, estimation of a cut-off can bederived from offset well information and

comparative log signatures.

Porosity and Water SaturationPorosity values are assigned as an averageover a zone (single well pool) or as aweighted average value over the entire payinterval using all wells in a pool. Similarly,the average thickness-weighted watersaturation using all wells in the pool iscommonly assumed as the pool averagewater saturation.

Drainage AreaDrainage area assignments to wells shouldbe similar to offset analogous poolsdepending on the geological similarities andproductivity of the wells within the analog.Pressure information is useful in estimatingpool boundaries and if any potential barriersexist between wells. Seismic analysis usuallyimproves the reservoir model and providesfor more reliability in reserve or resourceestimates.

Formation Volume FactorThe volumetric calculation uses the initialoil or gas formation volume factor at theinitial reservoir pressure and temperature.Both Bo and Bg are functions of f luidcomposit ion, reservoir pressure and

temperature and consequently of reservoirdepth. The Bo and Bg values from analogousoffset pools are often used as an initialestimate for the prospect underconsideration.

VVVVVOLOLOLOLOLUMEUMEUMEUMEUMETRIC UNCETRIC UNCETRIC UNCETRIC UNCETRIC UNCERRRRRTTTTTAINAINAINAINAINTTTTTYYYYYA volumetric estimate provides a staticmeasure of oil or gas in place. The accuracyof the estimate depends on the amount ofdata available, which is very limited in theearly stages of exploration and increases aswells are drilled and the pool is developed.Article 8, entitled Monte Carlo Analysis, willpresent a methodology to quantify theuncertainty in the volumetric estimate basedon assessing the uncertainty in inputparameters such as:

Gross rock volume reservoirgeometry and trapping

Pore volume and permeabilityDistribution

Fluid contacts

The accuracy of the reserve or resourceestimates also increases once production datais obtained and performance type methodssuch as material balance and decline analysiscan be utilized. Finally, integrating all the

Figure 3.4. Gross and net pay distinction (Etris and Stewar