1 / 54

Evaluation Volumetrics GEOL 4233 Class April 23, 2008 Dan Boyd Oklahoma Geological Survey Norman, Oklahoma

Evaluation Volumetrics GEOL 4233 Class April 23, 2008 Dan Boyd Oklahoma Geological Survey Norman, Oklahoma. Volumetrics 1) Definitions / Conversions (Handy Facts) 2) Assumptions (The ‘Art’ of Volumetrics) 3) Mechanics (Input Variables)

kendall
Download Presentation

Evaluation Volumetrics GEOL 4233 Class April 23, 2008 Dan Boyd Oklahoma Geological Survey Norman, Oklahoma

An Image/Link below is provided (as is) to download presentation Download Policy: Content on the Website is provided to you AS IS for your information and personal use and may not be sold / licensed / shared on other websites without getting consent from its author. Content is provided to you AS IS for your information and personal use only. Download presentation by click this link. While downloading, if for some reason you are not able to download a presentation, the publisher may have deleted the file from their server. During download, if you can't get a presentation, the file might be deleted by the publisher.

E N D

Presentation Transcript

  1. Evaluation Volumetrics GEOL 4233 Class April 23, 2008 Dan Boyd Oklahoma Geological Survey Norman, Oklahoma

  2. Volumetrics 1) Definitions / Conversions (Handy Facts) 2) Assumptions (The ‘Art’ of Volumetrics) 3) Mechanics (Input Variables) 4) Reserves (Recovery Factors / Probabilistic Calculations)

  3. 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)

  4. Definitions / Conversions (I) 14.7 psi = Atmospheric (@ 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 ~1Btu / 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)

  5. 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’)

  6. 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 RCF/SCF Underpressured (Brooken Field example): .23 psi/ft (normal = .43 psi/ft) @ 1,400’ Bgi = 28 RCF/SCF (38 RCF/SCF if normally pressured) Overpressured

  7. 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 (planimeters +- 5%) • 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

  8. Well Log of Incised Valley-Fill Sandstone Oklahoma’s Brooken Field (Booch) Average Porosity = ?

  9. ‘Sharp’ Fluid Contacts ?

  10. B-184 Horizontal Lateral (Elan Plus Interpretation) ‘Sharp’ Fluid Contacts ?

  11. Badak-185 Horizontal Lateral (Elan Plus Interpretation) ‘Sharp’ Fluid Contacts ?

  12. Pressure Gradients ‘Sharp’ Fluid Contacts ? Here: + or – 5’ Oil rim estimate: + or – 10% Gas cap estimate: + or – 15%

  13. Transition Zone Transition Zone

  14. 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 = OIIP (STB)

  15. Volumetric Mechanics (Gross Reservoir Volume) AREA: Productive area (map view), in acres Subdivide overall area into components that are calculated (planimetered) separately 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

  16. Volumetric Mechanics (Pore Volume) GROSS RESERVOIR VOLUME (AcFt) x Average Porosity (%) within productive reservoir = GROSS STORAGE (PORE) VOLUME (AcreFeet)

  17. 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

  18. 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)

  19. 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)

  20. 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

  21. Recovery Factors • (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 (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.)

  22. 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 80 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

  23. 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

  24. 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

  25. 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 has the edge

  26. 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

  27. 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

  28. Blanket 40’ Reservoir with 80’ of Closure Slab Area + Wedge Area / 2 = Gross Reservoir Volume In this example reservoir ~40’ thick Slab Area Net Pay maximum line Wedge Area Net Pay zero-line Assume OWC @ Base of reservoir

  29. Net Oil Reservoir Isopach (Well control good, Zero line conforms to OWC) Planimeter 2-3 areas: ~ 0-20, 20-30, 30+

  30. Volumetric Map Set Rigorous ‘By the Book’ (This is usually overkill)

  31. Brooken Field Net Sandstone Isopach

  32. Reams Southeast Field Middle Booch Structure Map Trapping Fault

  33. Reams Southeast Field Study PS-0 Net Sand Isopach

  34. Reams Southeast Field Study PS-2 Net Sand Isopach

  35. Reams Southeast Field Middle Booch Net Sandstone Isopach (Showing Combination Trap) Fault Contact Water Contact Reservoir Limits

  36. Reams Southeast Field Study Volumetric Input

  37. Reams Southeast Field Study Gas Volumes

  38. Exercises

  39. Exercise 1a: Calculate OGIP

  40. Exercise 1b: (Alternative Interpretation) Calculate OGIP

  41. Exercise 1c: (Yet another alternative Interpretation) Calculate OGIP

  42. 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).

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

  44. With production history, the geologic model can be refined (and then used as a template elsewhere)

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

  46. 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

  47. Exercise 3 Location Map

  48. 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

  49. 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

  50. Exercise 4 Schematic Cross-Section

More Related