Estimation of

Oil & Gas

Reserves• Reserves are those quantities of petroleum which are

anticipated to be commercially recovered from known accumulations from a given date forward.

• All reserve estimates involve some degree of uncertainty. • The uncertainty depends chiefly on the amount of reliable

geologic and engineering data available at the time of the estimate and the interpretation of these data.

• The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved.

• Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability.

Proven Reserves

• Proven reserves are those reserves claimed to have a reasonable certainty (normally at least 90% confidence) of being recoverable under existing economic and political conditions, with existing technology. Industry specialists refer to this as P90 i.e., having a 90% certainty of being produced. Proven reserves are also known in the industry as 1P

• Proven reserves are further subdivided into "proven developed" (PD) and "proven undeveloped" (PUD).

• PD reserves are reserves that can be produced with existing wells and perforations, or from additional reservoirs where minimal additional investment (operating expense) is required.

• PUD reserves require additional capital investment e.g., drilling new wells to bring the oil to the surface.

Proven Reserves

• Proven reserves can further be categorized on the basis of status of wells and reservoirs as developed and Undeveloped; producing and nonproducing

Developed:

Developed reserves are expected to be recovered from existing wells. Improved recovery reserves are considered developed only after the necessary equipment has been installed, or when the costs to do so are relatively minor. Developed reserves may be subcategorized as producing or non-producing.

Producing: – Reserves subcategorized as producing are expected to be

recovered from completion intervals which are open and producing at the time of the estimate.

Proven Reserves

Non-producing: Reserves subcategorized as non-producing include shut-in

and behind-pipe reserves.Shut-in reserves are expected to be recovered from (1)completion intervals which are open at the time of the

estimate but which have not started producing, (2)wells which were shut-in for market conditions or

pipeline connections, or (3)wells not capable of production for mechanical

reasons. Behind-pipe reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future recompletion prior to the start of production.

Proven Reserves

Undeveloped Reserves:

Undeveloped reserves are expected to be recovered: (1) from new wells on undrilled acreage,

(2) from deepening existing wells to a different reservoir, or

(3) where a relatively large expenditure is required to (a) recomplete an existing well or

(b) install production or transportation facilities for primary or improved recovery projects.

Unproven Reserves

• Unproven reserves are based on geological and/or engineering data similar to that used in estimates of proven reserves, but technical, contractual, or regulatory uncertainties make such reserves being classified as unproven.

• Unproven reserves may be used internally by oil companies and government agencies for future planning purposes but are not routinely compiled. They are sub-classified as probable and possible

Probable:

Probable reserves are attributed to known accumulations and claim a 50% confidence level of recovery. Industry specialists refer to them as P50 i.e., having a 50% certainty of being produced. These reserves are also referred to in the industry as 2P (proven plus probable).

Unproven Reserves

Possible:

Possible reserves are attributed to known accumulations that have a less likely chance of being recovered than probable reserves. This term is often used for reserves which are claimed to have at least a 10% certainty of being produced (P10).

Reasons for classifying reserves as possible include varying interpretations of geology, reserves not producible at commercial rates, uncertainty due to reserve infill (seepage from adjacent areas) and projected reserves based on future recovery methods. They are referred to in the industry as 3P (proven plus probable plus possible).

Classification of Reserves

Reserves

Proven Unproven

Probable Possible

Developed Undeveloped

Producing Nonproducing

Cross section View of a Reservoir structure as suggested from Seismic and Geological data

After Exploration well was drilled

After Delineation

Final Delineation

Estimation of Reserves

• The amount of oil in a subsurface reservoir is called oil initial in place (OIIP)

• There are a number of different methods of calculating oil reserves. These methods can be grouped into four general categories:

A. volumetric, B. material balanceC. production performance. D. Comparative methods where comparison is made with

those of offset properties of other fields having same geologic and other reservoir conditions.

Estimation of Reserves

• The different methods mentioned can be applied in the following time periods

Time period % of reserves Produced

Methods of Estimation

Reasonable range of error

Prior to Drilling 0 D 10-100 %

After completion 0 A & D 5-50 %

During production 1-10 % A, B & C 5-30 %

During production 10-30 % A, B & C 5-20 %

During production 30-60 % B & C 5-10 %

During production 60 & over C About 5 %

Volumetric Estimation

• Volumetric estimation is the only means available to assess hydrocarbons in place prior to acquiring sufficient pressure and production information.

• Volumetric methods are primarily used to evaluate the in-place hydrocarbons in new, non-producing wells and pools and new petroleum basins. But even after pressure and production data exists, volumetric estimates provide a valuable check on the estimates derived from material balance and decline analysis methods.

• Volumetric estimation is also known as the “geologist’s method” as it is based on cores, analysis of wireline logs, and geological maps.

Volumetric Estimation

Volumetric estimation requires determination of following reservoir parameters.

a)Estimation of volume of sub surface rock that contains hydrocarbons. The volume is calculated from the thickness of the rock containing oil or gas and the areal extent of the accumulation.

b)Determination of a weighted average effective porosity.

c)Obtaining a reasonable water resistivity value to calculate water saturation.

With these reservoir rock properties and utilizing the hydrocarbon fluid properties, original oil-in-place or original gas-in-place volumes can be calculated.

Volumetric Estimation

For OIL RESERVOIRS the oil initial in-place (OIIP) volumetric calculation is. •Metric:•OIIP (m3) = Rock Volume * Ø * (1- Sw) * 1/BoWhere: Rock Volume (m3) = 104 * A * hA = Drainage area, hectares (1 ha = 104m2)h = Net pay thickness, metersØ= Porosity, fraction of rock volume available to store fluidsSw = Volume fraction of porosity filled with interstitial waterBo = Formation volume factor (m3/m3) (dimensionless factor for the change in oil volume between reservoir conditions and standard conditions at surface)

Volumetric Estimation

• Imperial:

OIIP (STB) = Rock Volume * 7,758 * Ø * (1- Sw) * 1/Bo

Where: Rock Volume (acre feet) = A * h

A = Drainage area, acres

h = Net pay thickness, feet

7,758 = Bbl per acre-feet (converts acre-feet to stock tank barrels)

Ø = Porosity, fraction of rock volume available to store fluids

Sw = Volume fraction of porosity filled with interstitial water

Bo = Formation volume factor (Reservoir Bbl/STB)

1/Bo = Shrinkage (STB/reservoir Bbl)

Oil Recovery Factor• The recovery factor is one of the most important, yet the

most difficult variable to estimate.

• Fluid properties such as formation volume factor, viscosity, density, and solution gas/oil ratio all influence the recovery factor.

• In addition, it is also a function of the reservoir drive mechanism and the interaction between reservoir rock and the fluids in the reservoir.

Oil Recovery Factor•The approximate oil recovery range is tabulated below for various driving mechanisms.

•Note that these calculations are approximate and, therefore, oil recovery may fall outside these ranges

Estimation of Gas in place

Gas in reservoir occurred as

• Non associated gas

• Associated gas

• Solution gas.

Volumetric Estimation of Non Associated Gas

For GAS RESERVOIRS the gas initial in-place (GIIP) volumetric calculation is:•Metric:GIIP (103m3) = Rock Volume * Ø * (1-Sw) * (Ts * Pi) /(Ps * Tf * Zi)Where: Rock Volume (m3) = 104 * A * hA = Drainage area, hectares (1 ha = 104m2)h = Net pay thickness, metersØ = Porosity, fraction of rock volume available to store fluidsSw = Volume fraction of porosity filled with interstitial waterTs = Base temperature, standard conditions, °Kelvin (273° + 15°C)Ps = Base pressure, standard conditions, (1.01 kg/cm2)Tf = Formation temperature, °Kelvin (273° + °C at formation depth)Pi = Initial Reservoir pressure, kg/cm2

Zi = Compressibility at Pi and Tf

Volumetric Estimation of Non Associated GAS• Imperial:

GIIP (MMCF) = Rock Volume * 43,560 * Ø * (1-Sw) * (Ts * Pi)/(Ps * Tf * Zi)

Where: Rock Volume (acre feet) = A * h

A = Drainage area, acres (1 acre = 43,560 sq. ft)

h = Net pay thickness, feet

Ø = Porosity, fraction of rock volume available to store fluids

Sw = Volume fraction of porosity filled with interstitial water

Ts = Base temp., standard conditions, °Rankine (460° + 60°F)

Ps = Base pressure, standard conditions, 14.65 psia

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

Pi = Initial Reservoir pressure, psia

Zi = Compressibility at Pi and Tf

Volumetric Estimation of Associated Gas

Associated Gas• Gas associated with oil as gas cap is known as

associated gas.

• During oil production period this remained shut in.

• Once most of the oil is produced, gas from gas cap is produced.

• Estimation method is same as described for Non associated gas.

Volumetric Estimation of Solution Gas

Solution Gas• Gas liberated from the reservoir during oil

production. • To estimate the volume of this gas following

formula is applied.

GIIP(soln.) = N(OIIP) x GOR

Gas Recovery Factor• Volumetric depletion of a gas reservoir with reasonable

permeability at conventional depths in a conventional area will usually recover 70 to 90% of the gas-in-place.

• However, a reservoir’s recovery factor can be significantly reduced by factors such as:

low permeability, low production rate, soft sediment compaction, fines migration, excessive formation depth, water influx, water coning and/or behind pipe cross flow, and the position and number of producing wells.

• As an example, a 60% recovery factor might be appropriate for a gas accumulation overlying a strong aquifer with near perfect pressure support.

Reservoir Rock

Sand Grain

Cementing material

Interconnected or effective

porosity

Isolated or non effective porosity

Calculations of Rock Volume• The projected surface area of a hydrocarbon deposit can be

completely defined only by the drill• Reservoir volumes can be calculated from net pay isopach

maps by planimetering to obtain rock volume (A * h). • To calculate volumes it is necessary to find the areas between

isopach contours. • Planimetering can be performed

by hand or computer generated.• Given the areas between contours,

volumes can be computed using;

Trapezoidal rule, Pyramidal rule,

and/or the Peak rule for calculating

volumes

Calculations of Rock Volume

Following methods can be used to evaluate the rock volume

Trapezoidal Volume

V = h (A1+ A2/2)

Frustum of pyramid

V = h/3 (A1+A2+ A1*A2)

Net Pay

• Net pay is the part of a reservoir from which hydrocarbons can be produced at economic rates, given a specific production method.

• The distinction between gross and net pay is made by applying cut-off values in the petrophysical analysis.

• Net pay cut-offs are used to identify values below which the reservoir is effectively non-productive.

In general, the cut-off values are determined based on the relationship between porosity, permeability, and water saturation from core data and capillary pressure data.

Net Pay

A

B

C

D

E

F

low porosity, low permeability,very low/ no oil saturation,

Non Pay

high porosity, high permeability,high oil saturation,

Gross & net pay

low porosity, low permeability,very low or no oil saturation

Gross pay

low porosity, low permeability,very low or no oil saturation,

Gross pay

high porosity, high permeability,high oil saturation,

Gross & net pay

high porosity, high permeability,high water saturation,

Non pay

Gross thickness = A+B+C+D+E+F = 6 m, Gross reservoir = B+C+D+E+F = 5 mGross pay = B+C+D+E = 4 m , Net thickness = Net reservoir = B+E+F = 3 mNet pay = B+E = 2 m

Porosity and water saturation

• In evaluation of porosity of individual wells, the weighted average porosity values are computed.

• Porosity values are assigned as an average over a zone (single well pool) or as a weighted average value over the entire pay interval using all wells in a pool.

• If all the intervals sampled from a well are of uniform thickness, the weighted average and the arithmetic average are identical.

• If the intervals differ in both thickness and the values then the two averages will be different.

• Similarly, the average thickness-weighted water saturation using all wells in the pool is commonly assumed as the pool average water saturation.

Weighted average Porosity Depth (Ft) h Ø (%) Øh

3690-3691 1 20 20

3691-3693 2 23 46

3693-3694 1 21 21

3694-3697 3 26 78

Total 7 90 165

Arithmetic average Ø = 90/4 = 22.5%

Weighted average Ø = 165/7= 23.5%

    Inplace Ultimate Cumm Prod Reserve

        Gas     Gas     Gas     Gas

Field Cat Oil  Cond Sol GasGC F GAS Oil  Cond Sol GasGC F GAS Oil  Cond Sol GasGC F GAS Oil  Cond Sol GasGC F GAS

Bandamurlanka

PD   0.06    157.6   0.03     23.7 0.01       5.2   0.01    18.5

PDPB                   70.9 0.03           0.03    70.9

PB                                        

PS                                        

Bhimanapalli PB         21.8        13.1                   13.1

Endamuru PD   0.06    3214.9   0.05     2175.3 0.02       1484  0.03    691.3

EnugapalliPD   0.01    378.9         227.3         89.7         137.7PS         220.6                              

Gedanapalli PD 0.75         0.08                   0.07       

Mandapetta

PD 0.02 1.04    18330  0.73     12820.1   0.05     1842.4   0.68    10977.6

PB   0.3     9060.8   0.21     6394.2             0.21    6394

Mummidivaram

PD         58.7                             

PBPB                   35.2                   35.2

Penugonda PS         2364.6                              

Rangapuram

PD         240.8         144.5         7         137.4

PB         37.9        22.8                   22.8

PS         75.4                             

Table of Reserve

Oil & Gas Reserves

Oil (MMt)

Cond. (MMt)

SG+GCG(MMm3)

Free Gas(MMm3)

Oil +OEG(MMt)

As on 01.04.2010

Inplace 4793.81 73.94 1277448 994668 7139.87

Ultimate 1323.26 67.22 725965.8 394915.8 25112.36

Reserves 531.55 31.87 301313.7 310181.3 1174.92

As on 01.04.2011

Inplace 4888.1 72.54 1302975.1 113158.5 7376.79

Ultimate 1337.19 66.88 746115.2 445952.9 2596.14

Reserves 523.29 30.15 303661.6 356117.1 1213.22

Material Balance

• When an oil and gas reservoir is put on production it produces oil, gas and some time water also thereby reducing the reservoir pressure.

• If the oil and gas bearing strata is hydro dynamically connected with water strata or aquifer water encroaches in to the reservoir and accordingly retarding the declining in pressure.

• The material balance equation is derived as a volume balance which equates the cumulative observed production, expressed as an underground withdrawal, to the expansion of the fluids in the reservoir resulting from finite pressure drop

Principle of Material Conservation

Amount of fluids

present in the

reservoir initially

(st. vol)

Amount of fluids produced(st. vol)

Amount of fluids remaining in the reservoir finally (st. vol.)

-

The material balance equations are based on simple mass balance of the fluids in the reservoir, and may be formulated as

Material Balance Analysis

OIL OIL

Initial stage (1) Final stage (2)

N*Boi (N-Np)*Bo

Material Balance Analysis

Oil present

in the reservoir

initially

(st. vol.)

Oilproduced(st. vol

Oil remainingin the reservoirfinally(st. vol.)

-

Equation 1: Oil material balance

N Boi = (N-Np)BoN = Bo*Np/Bo-Boi

Material Balance Analysis

water present

in the reservoir

initially

(st. vol.)

Waterproduced(st. vol)

water remainingin the reservoirfinally(st. vol.)

-

Equation 2: Water material balance

Vp1Sw1/Bw1 - Wp + Wi + We= Vp2 Sw2 /Bw2

+Water

inj.+

Aquifer influx

Material Balance Equation for a Closed Gas Reservoir

• The material balance equation for a closed gas reservoir is very simple. Applying the mass balance principle to a closed reservoir with 100% gas, we may derive the general eguation

• GBg1 = (G − Gp )Bg 2• where• G is gas initially in place,• Gp is cumulative gas production, and• Bg is the formation-volume-factor for gas. Since Bg is given

by the real gas law• Bg = (constant)Z/P• (here temperature is assumed to be constant)

Material Balance Equation for a Closed Gas Reservoir

The material balance equation may be rewritten as

G (Z1/P1) =(G-Gp) (Z2/P2)

(P2/Z2)= (1- Gp/G)(P1/Z1)

This equation represents a

straight line relationship on

a P2/Z2 vs. Gp plot.

The straight-line relationship

is very useful in estimating

the initial volume of

gas-in-place (G) from limited

production history

P/Z

Production decline Analysis

• Production decline analysis is a basic tool for forecasting production from a reservoir once there is sufficient production to establish a decline trend as a function of time.

• The technique is more accurate than volumetric methods when sufficient data is available to establish a reliable trend and is applicable to both oil and gas wells.

• Accordingly, production decline analysis is most applicable to producing pools with well established trends.

• The rate versus time plot is commonly used to diagnose well and reservoir performance as shown in the example plot.

• Arps (1945, 1956) developed the initial series of decline curve equations to model well performance. The equations were classified as exponential, hyperbolic, or harmonic, depending on the value of the exponent

Production decline Analysis

Conclusions•Estimation of reserves is done under conditions of uncertainty•The principal uncertainties associated with the performance of the

overall reservoir model. •The type of data which is most important to define the reservoir.• Reservoir structure• Reservoir properties• Reservoir sand connectivity• Impact of faults• Relative permeability etc• Fluid properties• Aquifer behavior• Well productivity (fractures, well type, condensate drop out etc.)•The impact of each of these parameters will vary according to the

particular field.•It is important that the company is not ignorant of the magnitude of

the contributing uncertainties, so that resources can be directed at cost effectively reducing specific uncertainties.