Estmation of oil & gas proven probable posiible

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

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 balance
C. 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 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.

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

• 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
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 (103
m3
) = Rock Volume * Ø * (1-Sw) * (Ts * Pi) /(Ps * Tf * Zi)
Where: Rock Volume (m3
) = 104
* A * h
A = Drainage area, hectares (1 ha = 104
m2
)
h = Net pay thickness, meters
Ts = 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
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
very low or no oil saturation
Gross
pay
very low or no oil saturation,
Gross
pay
high oil saturation,
Gross &
net pay
high water saturation,
Non pay
Gross thickness = A+B+C+D+E+F = 6 m, Gross reservoir = B+C+D+E+F = 5 m
Gross pay = B+C+D+E = 4 m , Net thickness = Net reservoir = B+E+F = 3 m
Net 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 Gas GC F GAS Oil Cond Sol Gas GC F GAS Oil Cond Sol Gas GC F GAS Oil Cond Sol Gas GC 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
Enugapalli
PD 0.01 378.9 227.3 89.7 137.7
PS 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

Oil present
in the reservoir
initially
(st. vol.)
Oil
produced
(st. vol
Oil remaining
in the reservoir
finally
(st. vol.)
-
Equation 1: Oil material balance
N Boi = (N-Np)Bo
N = Bo*Np/Bo-Boi

water present
in the reservoir
initially
(st. vol.)
Water
produced
(st. vol)
water remaining
in the reservoir
finally
(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

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.

Estmation of oil & gas proven probable posiible

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