1 / 46

Sampling, Preserving and Testing Heavy Oil Sand Cores

Sampling, Preserving and Testing Heavy Oil Sand Cores. Maurice Dusseault. Canadian Experience. Heavy oil core samples exhibit expansion of 1% to as much as 12% Lab values of  = 34-40% are quite common Porosities in the ground, calculated from geophysical logs, are consistent – 29-31%

austin-wilson
Télécharger la présentation

Sampling, Preserving and Testing Heavy Oil Sand Cores

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. Sampling, Preserving and Testing Heavy Oil Sand Cores Maurice Dusseault

  2. Canadian Experience • Heavy oil core samples exhibit expansion of 1% to as much as 12% • Lab values of  = 34-40% are quite common • Porosities in the ground, calculated from geophysical logs, are consistent – 29-31% • Reservoir parameters based on expanded core samples can give serious problems • The expansion cannot be fully reversed by using overburden pressures on specimens

  3. International Experience • Kazakhstan - Karazhanbas - largest heavy oil field in the FSU – core damage issues • Venezuela – Orinoco Extra Heavy Oil Sands – largest extra heavy oil deposit in the world – severe core damage issues • China – Liaohe and Karamay – damaged heavy oil sands core leads to problems • Colombia – Magdalena heavy oil fields – damage leads to poor choice of technology • Oman, Ecuador, USA, …

  4. KARAZHANBASMUNAI - KZ Kashagan Tengiz Karazhanbasmunai (i.e. Karazhanbas Oilfield) Aktau

  5. Study Area

  6. The Problems • Data, based on core analyses only, gave… • Porosities of 33-38% (~31%) • Permeabilities of 4-8 D (~2-3D) • Gas saturation of 1-8% (Sg = 0) • High kw (low kw) • The field was operated on a 50% production share basis. Issues… • Service company problems (core tests…) • Regulatory agency problems (KZ - CDC) • Poor predictions of recovery and rates • Poor choice of technology

  7. Faja del Orinoco (XH Oil) • Extra-heavy crude oil deposits • > 1.21012 BOIP •  ~ 0.30, z ~ 450-800 m, So ~ 0.88 • Unconsolidated • Estimated 25% recoverable with current methods • SAGD – CHOPS – HWCS …

  8. Faja del Orinoco -On the order of 200109 m3 OOIP -1000-6000 cP oil, <10ºAPI -f = 30%, k = 1-15 D -z = 300-700 m

  9. A B C1 C2 D1 D2 D3 E1 E2 F Faja Stratigraphy . Base level Seq . Architecture GR Strat cycles Ma 16.8 MFS M1 M9 MFS 17.0 Upper delta plain Long term base level fall MFS M12 17.1 DELTAIC MFS M14 17.3 Lower delta plain TS/ 19.1 Top D1 MFS Top D2 Top D3 Long term base level rise FLUVIAL Top E1 Alluvial/Upper delta plain 200 ft Top E2 Top F Base F. Cambrian/Cretaceous sedimentary rocks Unconformity 23.8

  10. The Problems • Core damage led to: • Excessively high permeabilities • High lab compressibilities (40-10010-6 psi-1) • This led to a “belief” in compaction drive • Lake Maracaibo heavy oil reservoirs benefit substantially from compaction drive • Vast sums of money and field experiments • Based on expanded core properties • Finally, in the 1990’s, the issue disappeared, but only after much time and money was spent

  11. Typical value, good heavy oil sands: 31% Evidence of Core Damage EDAM Field, Well 15-29

  12. Edam Core, Well 7-30 Typical value, good heavy oil sands: 31%

  13. Well 13-29 – Edam Field Typical value, good heavy oil sands: 31%

  14. Edam Well 6-29 Typical value, good heavy oil sands: 31%

  15. Conclusions from Edam Core • Lab porosities are consistently too high • The “correction factor” is not consistent among different wells • Different coring practices and operators • Different hardware • Different treatment in transport, storage, lab • The differences are not trivial • We may expect other properties to be affected, often to the detriment of the company • Can these issues be resolved?

  16. 95 mm Oil-rich sample expands to completely fill the liner Evidence of Core Expansion Observed Expansions of 89mm Core: • Ironstone 89 mm • Basal clays, clayey silts 89-91 mm • Oil-poor to oil-free silty sands 90-93 mm • Fine-grained oil-rich sand 91-95 mm • Coarse-grained oil-rich sand 94-95 mm Radially Axially Core has expanded from 120.7mm to 127mm diameter and is now acting like a piston in a cylinder Schematic Diagram of Expansion of an 89 mm Core 89 mm 90-91 mm Oil sand PVC liner 127 mm Corrugated surface characteristic of thinly-bedded and laminated fine-grained sands of variable oil saturation Oil-poor to oil-free silty sands, expansion much less than other material Ironstone band, no expansion Cores separate readily along cracks which form between zones of differing expansion potential Gas pressure inside liner ref. Dusseault (1980) Fig. 5 & 6

  17. Reasons for Core Expansion • CH4 present in solution, exsolves during the Δp in bringing core to surface • The high oil content means a lot of gas • High μ oil means gas cannot drain; no continuous gas phase is formed without ΔV • The sand is cohesionless (To = 0); it cannot resist internal expansion • The core barrel liners are 7%-13% oversize, allowing a lot of expansion

  18. Heavy Oil Cores, MR Scans Courtesy of Glen Brook, Nexen and Apostolos Kantzas, U of Calgary

  19. decreasing density CT-Scan Evidence of Damage in Heavy Oil Cores Courtesy of Glen Brook, Nexen and Apostolos Kantzas, U of Calgary

  20. Core Damage Consequences • Porosity overestimated • Permeability measurements in the lab are too high by a factor of ~1.5 to 2 • Laboratory data for So, Sw, Sg are wrong • Reserve estimation can be out by 5-10% • Predicted productivity index by factor of 2 • All rock mechanics data are in error • Compressibilities are too high by a factor of >10 • Rock strength predictions far too low • Etc…

  21. History… • “Evaluation of the Alberta Tar Sands”Sah, Chase, & WellsSPE 5034 (1974) • Old Problems… • These issues are “re-discovered” repeatedly • However, the issue is relatively well-documented (SPE, CJPT, conferences…)

  22. Table 3. Comparison of results from core analysis alone and density from logs, Lease 13, average data Core Analysis Density Log Difference Percent change Porosity 35.5 32.0 -3.5 -10 Tar Saturation 69 81 +12 +17 Water Saturation 31 19 -12 -39 Empirical EvidenceZwicky and Eade (Shell) UNITAR, 1977

  23. Log Derived Porosity • Neutron porosity is not a true measure of porosity (it actually is a measure of H) • Determine the true density using a gamma-gamma density log (average over 1 m) • Calculate  based on this density number • Heavy oil sands in situ are almost always liquid saturated (i.e.: Sg = 0) • Determine saturations from cores • Some factors (grain size, mineralogy, liquid densities…) are not affected by expansion

  24. Density Relationship Intact rock rlog = Sorof + Swrwf + (1 – f) Gm Where: So = oil saturation Sw = water saturation rlog= density from logs ro = density of oil rw = density of water Gm = matrix density } f (1 - f)

  25. f = Gm - rlog Gm - Soro - Swrw Calculate Porosity from gg Log • So, Sw, ro, rw from core (Sg = 0) • Gm is measured on a grain sample • Then, do quality control assessments

  26. Quality Control Assessments • Obtain So and Sw from log analyses, compare to lab data to decide if saturations are correct • Perhaps some water invasion occurred • Always assume Sg = 0, but check on logs • Decide which to use • When you have lab-derived porosities and geophysical-derived porosities: • Cross plot of the two • Examine the data to see what is happening • Make decisions…

  27. Porosity Cross Plot 0.40 “Typical” heavy oil case Porosity in serious error Is it valid to apply an “average” correction factor to core data?? Probably not… Best is to use individual values of log-derived porosity information Adjust your core data as required 0.38 0.36 0.34 Log-derived porosity Reasonable data, acceptable scatter 0.32 0.30 “average” error in f 0.28 0.30 0.32 0.34 0.36 0.38 0.40 0.28 Core-derived porosity

  28. Quality Control • X-plots are useful • Careful with “average” corrections • You can even check using neutron porosity, but you must be careful! • CNL log numbers may be wrong in heavy oils, which tend to be deficient in hydrogen, as compared to conventional oil correlations • If there is a lot of clay, the CNL data may also be off the mark somewhat (1-2 porosity units) • Get your logging company to help calibrate your field case

  29. More Methods • Needle penetrometer for core consistency • Use of sonic travel time transducers in the laboratory as a QC method • Visual examination • Extrusion when core is cut and boxed? • Extrusion from cut ends in the lab? • Core recoveries of 100% always reported? • Gas bubbling from core surface, fluids extruding? • And so on…

  30. “Correcting” the Data - A • Clearly, permeability overestimated as well • This is considerably harder to correct • If you have some oil-free, undamaged core with similar characteristics in your field • Do lab tests on undisturbed specimens (check) • Use these to determine f k equation • Compare log k values with core values • Is there a useful “correction factor”? • Can log data be considered reliable enough? • Find some other way to correct • E.g. Kozeny-Carman correlation, Archie plot…

  31. “Correcting” the Data - B • Recalculate your reserves, volumes, etc. • You can eventually develop a better empirical log equation to determine porosity, volume factors, etc. directly • Always test out relationships on specimens that are undisturbed (if this is possible) • I used outcrop samples to do this • High quality coring may help, but… • Can’t avoid expansion in heavy oil sands • Even core plugging at room temp is damaging • Nevertheless, do the best possible…

  32. A Few More Slides…

  33. Index of Disturbance A quantitative measure of core disturbance. e.g.: Dusseault, 1980, used by others, e.g. Settari, et al. (1993) ID = [10.2%, 18.4%]

  34. Index of Disturbance 40 Sample quality adequate for most petrophysical research Suitable only for qualitative or descriptive purposes 35 Samples suitable for high-quality geomechanical tests POROSITY (%) - Laboratory 30 ID = 40% ID < 10%Intact or slightly disturbed 10% < ID < 20%Intermediate disturbance 20% < ID < 40%Highly disturbed 40% < IDDisrupted generally ID = 30% A negative value of ID indicates poor correlation to the logs ID = 20% ID = 10% ID = 0% 25 Dusseault & van Domselaar (1982) Fig. 2 35 40 20 25 30 POROSITY (%) - Geophysical Density Log

  35. ID - Oldakowski Table 4.3 40 35 POROSITY - Laboratory (%) 30 ID = 40% ID = 30% ID = 20% ID = 10% ID = 0% 25 Oldakowski (1994) POROSITY - Geophysical Density Log (%) 35 40 20 25 30

  36. Heavy Oil Core Data • Weight percent bitumen • Mining application • Summation of fluids • Grain weight and Total weight • Dean-Stark water • (sometimes) Dean-Stark bitumen – corrections • Do not correlate with well logs because of the core dilation problem…

  37. Core Porosityv.Log Porosity“Evaluation of the Alberta Tar Sands”Sah, Chase, & WellsSPE 5034 (1974) !!

  38. Low Disturbance Samples • Dr. Amin Touhidi-Baghini, PhD thesis (1998) • McMurray sample from river valley outcrop • Minimal disturbance: no gas ex-solution • Absolute Permeability measured: • at low confining stress • during shear failure • Best laboratory data available (to the present time)

  39. Experimental Kozeny-Carmen Chardabellas B=2 Chardabellas B=5 Absolute Permeability Increase 6x Vertical 6 5 4 3 2.5x 1.6x Horizontal 2 Ka Multiplier K2 / K1 5% 5% 1 Vertical core specimens with an average porosity of 33.9% Horizontal core specimens with an average porosity of 33.7% -4 -2 0 2 4 6 8 10 -2 0 2 4 6 Volumetric Strain ev (%) Volumetric Strain ev (%) ref. Touhidi-Baghini (1998) Fig.8.21 & 8.22

  40. What Has Been Tried? • Pressure core barrels • Non-invasive fluids • Special core catchers • Special freezing during transport • Re-stressing before testing • And so on and so forth • None of these methods has been satisfactory. • The best results have been obtained by…

  41. Best Results • Sampling in a tunnel through an outcrop where gas pressure was depleted • In other outcrops (but Sw is incorrect) • In very shallow boreholes where pgas is low • Core barrels of short L, small potential for radial expansion, + axial restraint • Use of analogue materials from outcrops (e.g. the oil-free outcrops along riverbanks) • Intact samples of deep heavy oil UCS sands is highly problematic. Is it worth doing??

  42. Then What? • If “successful” core has been brought to surface… • Freeze to dry ice T for transport • Keep fully sealed • Prepare test specimens in cold room (-25°C) • Do not plug with a fluid (heat–expansion–etc) • Slow lathes for trimming to diameter OK • Trim ends flat in the lathe as well • Mount specimens while cold, thaw only when under pressure…

  43. Coring • Only very shallow cores (<100 m) have achieved any reasonable ID values • A specialized, short length core barrel is advised • Internal flush (no radial expansion) • Protruding cutting edge (avoid fluid contact) • Some method for axial restraint • “Rigid” core sleeve • Etc.

  44. Conclusions • Core damage can be a very serious issue • Mis-estimation of reserves by 10-15% • Over-estimate permeabilities by factor of 2 to 4 • And so on… • Geophysical log-derived f is best • Use lab or log So, Sw? • Calibrated neutron porosity is “OK” • Put into place quality control measures on coring, testing, lab procedures, log analysis • Then, just do the best you can…

More Related