Evaluation
Volumetrics
GEOL 4233 Class
Dan Boyd
Oklahoma Geological Survey
Fall 2011 Semester
Volumetrics
1) Definitions / Conversions (Handy Facts)
2) Assumptions (The ‘Art’ of Volumetrics)
3) Mechanics (Input Variables)
4) Reserves (Recovery Factors / Probabilistic Calculations)
Volumetrics
Definitions / Conversions
OOIP
OGIP
RF
FVF: (Bo, Bg)
Saturations / Residual Saturations (So, Sg, Sw – Soirr, Sgirr, Swirr)
EUR
Resources (In-Place) vs. Reserves (Economically Producible)
Definitions / Conversions (I)
14.7 psi = Atmospheric Pressure (@ S.L.)
5,280 feet per mile
43,560 sq ft per acre
640 acres per sq mile = Section (160 ac per quarter section) 247 ac/sqkm
3.281 ft per meter (39.37 inches per meter)
1.609 kilometers per mile
2.54 centimeters per inch
35.32 cubic feet per cubic meter
7,758 STBarrels per acre-foot
Specific Gravity (crude); .80 - .97
Btu value for gas: avg ~1 Btu / cubic foot (1000Btu/MCF), rich - higher, a lot of
non-hydrocarbons - lower
API gravity: 25 = specific gravity .904, 42 = specific gravity .816
BOE: 6,000 cubic feet per barrel (average)
Definitions / Conversions (Ia)
Gas Liquids:
Condensate – hydrocarbon liquids that condense from a gas production stream as
pressure and temperature are reduced from reservoir to surface conditions. These
are collected on the wellsite.
Natural Gas Liquids (NGL) – hydrocarbon liquids that remain in gas at surface
temperature and pressure. These must be stripped from the ‘wet’ gas production
stream at a central processing facility to bring its heating capacity to pipeline
specifications. These are shorter chain hydrocarbons than condensate, consisting
primarily of ethane, with smaller amounts of propane and butane.
Generalized Conversion of Natural Gas Btu Content to NGL Yield
14
Gallons/Mcf Ethane+
12
y = 0.0202x - 19.981
1400 Btu gas = ~ 8 gallons/MCF ~ 200 Barrels NGL/MMCF
10
8
6
4
2
0
1000
1000 Btu gas ~ 100% methane
1200 Btu gas = ~ 4 gallons/MCF ~ 100 Barrels NGL/MMCF
1100 Btu gas = ~ 2 gallons/MCF ~ 50 Barrels NGL/MMCF
1200
1400
BTU
1600
1800
Courtesy Dr. Jeffery Callard
Definitions / Conversions (Ib)
Gas – Other Acronyms:
CNG – Compressed Natural Gas: Gas compressed to <1% of its volume at
atmospheric pressure, requiring storage at 2,900-3,600 psi. Used as substitute fuel
for gasoline/diesel, but because still gaseous has 42% energy equivalency per unit
volume.
LNG – Liquefied Natural Gas: Methane gas cooled to -260 degrees F (-162 C) at
atmospheric pressure, making it 1/600th the volume as a gas. This makes LNG the
preferred global transport method for natural gas. Energy density is 60% that of
diesel fuel.
LPG – Liquefied Petroleum Gas / Liquefied Propane Gas: Various mixes of
propane and butane used for heating, motor fuel, refrigeration, and aerosol
propellants. Derived through the refining process of ‘wet’ gas. Energy density is
about 70% that of diesel fuel.
Definitions / Conversions (II)
To calculate pressure (if mud weight balanced precisely):
Under vs. Over Balanced
Mud Weight (in ppg) x .052(conversion factor) x depth (in feet) = (BH)Pressure (in
psi)
If mud is exactly balanced with formation pressure:
Calculated Pressure = BHP (reservoir)
Hydrostatic pressure gradient = 0.43 psi/ft (43 psi/100’)
Volumetric Parameters
Definitions / Conversions (III)
FVFs: Bo - Oil (dead) ~ 1.0 (RSB/STB), oil moderately gassy ~1.2RSB/STB, very
gassy ~ 1.4 RSB/STB
Bg – Normally pressured (hydrostatic) FVF = Depth (in ft)/36.9
Example @ 5,000’ FVF = 136 SCF/RCF
Underpressured (Brooken Field example): .23 psi/ft (normal = .43 psi/ft)
@ 1,400’ Bgi = 28 SCF/RCF (38 SCF/RCF if normally pressured)
Overpressured
The ‘Art’ of Volumetrics
(Assumptions)
• Wells drilled are representative of reservoir as a whole
• Average Porosity, Sw, So, and Sg are accurate
• Reservoir homogeneous and all parts will be swept
• The size, thickness and structure of the reservoir is correctly mapped
• The area is calculated precisely
• The OWC and GOC are sharp and known precisely, or …. the
porosity saturation cutoffs for pay are accurate, with good sweep
above and no feed-in from below these cutoffs
Well Log of Incised Valley-Fill Sandstone
Oklahoma’s Brooken Field (Booch)
Average Porosity = ?
‘Sharp’ Fluid Contacts ?
B-184 Horizontal Lateral
(Elan Plus Interpretation)
‘Sharp’ Fluid Contacts ?
Badak-185 Horizontal Lateral
(Elan
Plus
Interpretation)
‘Sharp’
Fluid
Contacts ?
Pressure Gradients
‘Sharp’ Fluid Contacts ?
Here: + or – 5’
Oil rim estimate: + or – 10%
Gas cap estimate: + or – 15%
Transition Zone
Transition Zone
Volumetric Mechanics
(Equations)
GAS:
Area (Ac) x Thickness (Ft) x Avg Porosity (%) x Avg Sgi (%) x Bgi
(SCF/RCF) x 43,560 sqft/ac = OGIP (SCF)
OIL:
Area (Ac) x Thickness (Ft) x Avg Porosity (%) x Avg Soi (%) / Boi
(RB/STB) x 7758.4 Bbls/AcFt = OOIP (STB)
Volumetric Mechanics
(Gross Reservoir Volume)
AREA: Productive area (map view), in acres
Subdivide overall area into components that are calculated individually
based on similar average reservoir thickness
THICKNESS: From reservoir or fluid top to contact or saturation cutoff, in feet
SUMMED (AREA(S) X THICKNESS) =
GROSS RESERVOIR VOLUME in AcreFeet
Volumetric Mechanics
(Pore Volume)
GROSS RESERVOIR VOLUME (AcFt) x Average Porosity (%) within
productive reservoir =
GROSS STORAGE (PORE) VOLUME (AcreFeet)
Volumetric Mechanics
(Gross Oil/Gas Volume)
GROSS STORAGE (PORE) VOLUME (AcreFeet) x
AVERAGE OIL (Soi) or GAS (Sgi) SATURATION (%) =
GROSS OIL or GAS VOLUME (AcreFeet)
===========================
Conversion to standard units of RBbls or RCF
AcreFeet x 7,758 Bbls/AcreFoot = Oil in Reservoir Barrels
AcreFeet x 43,560 Cubic Feet/AcreFoot = Gas in Reservoir Cubic Feet
Volumetric Mechanics (Oil)
(Conversion to Stock Tank Barrels)
FORMATION VOLUME FACTOR (Bo):
Rules of Thumb
‘Dead’ Oil (no dissolved gas): Bo ~ 1.0 (RB/STB)
‘Gassy’ (deepish) Oil: Bo ~ 1.4 (RB/STB)
‘Typical’ (shallower) Oil: Bo ~ 1.2 (RB/STB)
Oil Volume (RB) / Bo (RB/STB) = OOIP
(STB)
Volumetric Mechanics (Gas)
(Conversion to Standard Cubic Feet)
FORMATION VOLUME FACTOR (Bg):
Rules of Thumb
• Bg – If normally pressured (hydrostatic)
Bg = Depth (in feet) / 36.9 Example: @ 5,000’ FVF = 136 SCF/RCF
-----------------------------
• Underpressured (Brooken Field example): .23 psi/ft (normal = .43 psi/ft)
@ 1,400’ Bgi = 28 SCF/RCF (38 SCF/RCF if normally pressured)
----------------------• Overpressured
Gas Volume (RCF) X Bg (SCF/RCF) = OGIP
(SCF)
Reserves
From OOIP / OGIP
(What can you take to the bank ?)
RECOVERY FACTOR (RF): Function of –
• Reservoir Quality, Depth, Pressure, Temperature
• Fluid Properties
• Drive Mechanism(s)
• Reservoir Management
Rules of Thumb
The better the reservoir, the better the recovery factor
• Even fluid movement
• Larger pore throats (better sweep, more moveable oil/gas)
• Better water support (if any to be had)
• Better effectiveness in secondary/ tertiary recovery projects
Recovery Factors
(Ballpark Rules of Thumb)
OIL:
• Poor reservoir (low poro-perm):
• Dual Porosity (low matrix reservoir quality):
• Good Poro-Perm (Primary = Secondary):
• Excellent reservoir (good water support):
• Ideal (good reservoir quality, management):
• Tar Sands (mined):
< 10%
~ 20%
~ 30%
~ 40-50%
~ 60-70%
~ 100%
GAS:
• CBM, Shale Gas:
• Good Quality (depletion):
• Excellent Reservoir (depletion, + compression):
< 10% (generally)
~ 70% (GOM average)
90%+ (Lake Arthur Ex.)
Probabilistic Volumetrics
(Because there is no single answer)
• Calculate a range of values based on confidence in variables.
P = Probability Factor
P 100 – dead certainty
P 70 to 90 – high confidence
P 10 to 30 – low confidence
• For each variable with significant uncertainty
Assign P 90 , P 50, and P 10 values to create distribution
Example: Productive area – P 90 = smallest reasonable area, P 50 = most
likely area, and P 10 = maximum area (but not unreasonable)
• Qualitative (‘fudgability’ - what do you want it to be ?)
Usefulness a function of experience in area
Requires objective assessment
Most beneficial when comparing large projects in which data is sparse
Probabilistic Reserves
(Taking Credit Now for Future Additions)
(P + P + P)
• Proved.
Highest level of certainty (assigned $ value)
PDP – Proved-Developed-Producing (decline curve)
PUD – Proved-Undeveloped (Nonproducing)
• Probable.
Undrilled, but based on known areas has high likelihood of producing
Examples:
Undrilled fault-block in area where faults do not seal
Area adjacent to existing production with quantifiable DHI
• Possible.
Higher risk, but based on incomplete information meets known requirements
for production
Volumetric Computations
(1)
Prerequisites –
Net Pay Isopach (which requires)
Structure Map (on top of the pay)
Elevation of fluid contacts
Net Reservoir Isopach
Accurate Pay Cutoffs (Porosity, Sw, Shale Content ie: k measure)
Knowledge of Potential Flow-Barriers (each compartment calculated separately)
Structure Map - identify isolated fault blocks
Cross-Section(s) – identify potential stratigraphic barriers
Volumetric Computations
(2)
Mechanics –
Work Station (high-tech, but still just a tool)
Log analyses, tops, net pay thicknesses are usually digital and internal
Computer-generated maps/cross-sections must be ‘truthed’ and edited
Advantage – can sift vast amounts of data and quickly analyze wide range of
possibilities
Disadvantage – GIGO (garbage in, garbage out) – but it’s nice looking garbage
Paper (much slower, but often results in better geological understanding )
PC computer aid only, interpretation on paper (hand-contouring & log analysis)
Planimeter usually used for calculating areas, or………….
Eyeball entire pay map with an average pay thickness, or box-out into bite-size chunks
Given the assumptions – the experienced eyeballer always has the edge
Reservoir Volume
Mechanics
(Work station’s crashed &/or planimeter’s been stolen)
Bite-Size Chunks Technique
• Box out areas into rectangles-triangles
• Calculate areas
• Assign each area an average thickness
• Sum the volumes calculated
Reservoir Volume
Mechanics
Slab and Wedge Technique
(Useful in areas of shallow dip)
• Reservoir thickness ~ constant
• Area inside of where water contact is at reservoir bottom
assigned full thickness value
• Area outside of this, to the edge of the water contact, is
assigned half of the full thickness value
Blanket 40’ Reservoir with 80’ of Closure
Slab Area + Wedge Area / 2
= Gross Reservoir Volume
Slab Area
Net Pay maximum line
Wedge Area
Net Pay zero-line
Assume OWC @ Base of reservoir
Net Oil Reservoir Isopach
(Well control good, Zero line conforms to OWC)
Planimeter 2-3 areas: ~ 0-20, 20-30, 30+
Volumetric Map Set
Rigorous ‘By the Book’
(This is usually overkill)
Brooken Field Net Sandstone Isopach
Reams Southeast Field
Middle Booch Structure Map
Trapping Fault
Reams Southeast Field Study
PS-0 Net Sand Isopach
Reams Southeast Field Study
PS-2 Net Sand Isopach
Reams Southeast Field
Middle Booch Net Sandstone Isopach
(Showing Combination Trap)
Fault Contact
Reservoir Limits
Water Contact
Reams Southeast Field Study Volumetric Input
Reams Southeast Field Study Gas Volumes
Exercises
Exercise 1a:
Calculate OGIP
Exercise 1b:
(Alternative Interpretation)
Calculate OGIP
Exercise 1c:
(Yet another alternative Interpretation)
Calculate OGIP
Exercise 1
(Sparse Data)
Volumetrics Sensitivity:
• Gross Reservoir Volume - varies by a factor of 4 (at least) in 3
reasonable interpretations that honor all data. This is made possible
both by changing the productive area and the thickness within it. If the
porosity cutoff (8%) for reservoir were moved up or down, results
would vary even more.
• Porosity - for each percent the average value goes up or down, the
OGIP estimate is changed by 10%. In heterogeneous reservoirs the
porosity range can be large (8 - 18% not unusual).
118° 40'
118° 50'
118° 45'
S B -6 -2 4
S B -6
Real Life Example
-1 3
S
B
-6
-3
0
(One penetration)
S B -6 -2 5
NYM PHE
NORTH 1
B E N R IN N E S 1
5° 50'
5° 50'
K91
-6 -
-4 8
SB
12
-6
-5
S
B
-6
-2
7
SB
NYM PHE 1
S B -6 -2 6
KUDA
TE RB AN G 1
SB
5° 45'
S p ill P o in t
4
-4
91
K
0
2
2
-4
ARCO
NYM PHE
SO UTH 1
1:50000
0
5° 45'
-6
118° 40'
4 Kilometers
P h illip in e s
N
118° 45'
N ym p h e A r e a
T ra p p in g S tyle
T o p M 2 D e p th S t ru c t u re
C .I. = 2 0 0 m
4 Miles
J W /D B
Dec, 1999
Interpretation based on inferred environment of deposition and analog comparisons (in some cases seismic DHI’s can help)
With production history, the geologic model can be refined
(and then used as a template elsewhere)
Exercise 2:
Calculate OGIP
North Dome Field
(Qatar/Iran)
North Dome Field
Ghawar Field
Regional Location Map
From Fredrick Robelius
Uppsala Universitet, 2005
Exercise 2
North Dome Field:
Productive Area: ~ 40 x 70 mi
Average Thickness: ~ 510’
Average Porosity: ~ 20%
Average Swi: ~ 20%
DEPTH ~ 11,000’ (assume normal pressure)
Carbonate reservoir
Calculate:
OGIP_______________
Reserves (assuming 65% RF)
__________________________
Get ready for a lot of zeros
Exercise 3
Location Map
Exercise 3
Greater Ghawar Field
Area: ~ 110 x 15 miles
Avg thickness: ~ 185’
Avg porosity: ~ 18%
Average Swi: ~ 11%
Boi – 1.32
Avg perm: ~ 350 md
API-32 degrees
GORi = 550
Depth -6600’OWC
Calculate:
OOIP________________
EUR_________________
(given various RF’s)
Get ready for a lot more zeros
Exercise 4
Assume: Depth ~ 8,000’ (normally pressured)
Reservoir – 20’ blanket SS (no wedges)
Avg por – 15%, Avg Sw 10% (gas cap), 20% (oil rim)
Bo – 1.20 RB/STB
Calculate:
OGIP (up/downthrown)
OOIP
Exercise 4
Schematic Cross-Section
Exercise 5
20’
Lessons Learned:
• Outcome sensitive to reasonable changes to input
• Where data are sparse, a wide range of OGIP/OOIP values possible
• Structural Issues: attic oil, undrained fault blocks
• Stratigraphic Issues: depositionally or structurally isolated ‘pods’
• How to improve the quality of volumetrics ? (The Value of Experience)
• Mapping of analog areas where more data available
• If in rank area, may need to go far afield
• Comparison to fields with production history (material balance ?)
• Improved understanding of reservoir architecture
• Thickening rates
• Reservoir heterogeneities
• Pay cutoffs
• Recovery factors
Geological Objectivity (Ethics)
• The company needs drillable prospects / reserve adds, but……..
• The play you’re assigned is weak economically
Be Objective Without Being Pessimistic
• Understand your area as completely as possible
• Geologic history (petroleum system)
• Environments of deposition (log-core-outcrop)
• Reservoir properties (keys to pay quality)
• Successful explorationists understand and map producing fields
• Integrate geological interpretation into engineering data
• Pressures
• Drive mechanisms
• Fluid properties (do they change ?)
• Justify and document all assumptions (data mining)
• Keep an eye out for ‘upside’
• Explaining anomalies is the key to new geologic plays
• Shallower objective(s)
• Deeper objective(s)
• A different way to drill, complete (?)
Remember: Quality work will be recognized
May Mother Nature Smile Upon You
Cushing Field