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Evaluation Volumetrics GEOL 4233 Class Dan Boyd Oklahoma Geological Survey Fall 2011 Semester

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## Evaluation Volumetrics GEOL 4233 Class Dan Boyd Oklahoma Geological Survey Fall 2011 Semester

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1) Definitions / Conversions (Handy Facts)

2) Assumptions (The ‘Art’ of Volumetrics)

3) Mechanics (Input Variables)

4) Reserves (Recovery Factors / Probabilistic Calculations)

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)

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

1400 Btu gas = ~ 8 gallons/MCF ~ 200 Barrels NGL/MMCF

1200 Btu gas = ~ 4 gallons/MCF ~ 100 Barrels NGL/MMCF

1100 Btu gas = ~ 2 gallons/MCF ~ 50 Barrels NGL/MMCF

1000 Btu gas ~ 100% methane

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’)

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

- (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

‘Sharp’ Fluid Contacts ?

Here: + or – 5’

Oil rim estimate: + or – 10%

Gas cap estimate: + or – 15%

Transition Zone

- (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)

(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

(Pore Volume)

GROSS RESERVOIR VOLUME (AcFt) x Average Porosity (%) within productive reservoir =

GROSS STORAGE (PORE) VOLUME (AcreFeet)

(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

(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)

- (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)

- 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

- (Ballpark Rules of Thumb)
- OIL:
- Poor reservoir (low poro-perm): < 10%
- Dual Porosity (low matrix reservoir quality): ~ 20%
- Good Poro-Perm (Primary = Secondary): ~ 30%
- Excellent reservoir (good water support): ~ 40-50%
- Ideal (good reservoir quality, management): ~ 60-70%
- Tar Sands (mined): ~ 100%
- GAS:
- CBM, Shale Gas: < 10% (generally)
- Good Quality (depletion): ~ 70% (GOM average)
- Excellent Reservoir (depletion, + compression): 90%+ (Lake Arthur Ex.)

- (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

- (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

(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

- (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

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

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

(Well control good, Zero line conforms to OWC)

Planimeter 2-3 areas: ~ 0-20, 20-30, 30+

PS-0 Net Sand Isopach

PS-2 Net Sand Isopach

Middle Booch Net Sandstone Isopach

(Showing Combination Trap)

Fault Contact

Water Contact

Reservoir Limits

Calculate OGIP

- (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).

(One penetration)

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)

Calculate OGIP

North Dome Field

(Qatar/Iran)

North Dome Field

Ghawar Field

From Fredrick Robelius

Uppsala Universitet, 2005

Regional Location Map

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

Location Map

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

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

Schematic Cross-Section

20’

- 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

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