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).

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

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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 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’)

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

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

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+

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).

Real Life Example (One penetration) Interpretation based on inferred environment of deposition and analog comparisons (in some cases seismic DHI’s can help)

Exercise 2: Calculate OGIP North Dome Field (Qatar/Iran) North Dome Field Ghawar Field From Fredrick Robelius Uppsala Universitet, 2005 Regional Location Map

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