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SPE Distinguished Lecturer Program PowerPoint Presentation
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SPE Distinguished Lecturer Program

SPE Distinguished Lecturer Program

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SPE Distinguished Lecturer Program

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  1. SPE Distinguished Lecturer Program Primary funding is provided by The SPE Foundation through member donations and a contribution from Offshore Europe The Society is grateful to those companies that allow their professionals to serve as lecturers Additional support provided by AIME Society of Petroleum Engineers Distinguished Lecturer Program

  2. Maximizing the Value of an Asset through the Integration of Log and Core data Tim OSullivan Cairn India Ltd • Colleagues: Hal Warner • Dick Woodhouse • Dennis Beliveau • Ron Zittel • Stuart Wheaton Society of Petroleum Engineers Distinguished Lecturer Program

  3. Where is the data area ? 2004 Discovery Well Mangala, Aishwariya & Bhagyam Fields ( about 2 Billion Barrels STOOIP) 150m - 350m oil columns

  4. The Reservoir - Excellent Quality Sandstone Porosity: 26% 33% 17% Permeability: 20 Darcies 5 D 200md Clastic Fluvial Reservoirs Upper Fatehgarh Lower Fatehgarh

  5. What’s Interesting? (to Reservoir Teams) Fatehgarh Sand Reservoirs Excellent Reservoir Quality Sands * Porosity 17-33% (average ~26%) * Permeability up to 20 Darcies (average ~5D) * Weakly-to-Moderately Oil-Wet * VERY LOW Water Saturations – Field Avg. 5% Quite a LOT of Interesting Oil * Mangala Field – Over 1 Billion Barrels Oil In Place * An Economic Incentive for Petrophysical ACCURACY * Very Waxy, Sweet Crude – 27 o API Avg. An EXCELLENT Dataset * All Wells with Full “Basic” Logging Suites * Many Wells with “Specialty” Logs – CMR+, etc. * 1.7 km of Core in MBA

  6. 100,000 10,000 1,000 100 10 Permeability (OBC), md 1 0% 10% 20% 30% 40% Porosity (OBC), % Fatehgarh Sand Reservoirs Routine Core Analysis – Mangala Field Coarse Sand Silt

  7. Oil Wet Intermediate Water Wet 10 1 5 4 Capillary Pressure (psi) 0 2 3 1 • Initial Oil Drive • Free Imbibition of Brine • Brine Drive • Free Imbibition of Oil • Oil Drive 2 3 4 5 -10 0 Average Sw 100 IAH = WWI - OWI Fatehgarh Sand Reservoirs Wettability Index Data – Mangala Field Combined Amott/USBM Wettability Experiment No Relationship with Permeability! WWI= water wetting index WWI= proportion of the total oil production produced spontaneously ~ -0.35 Weakly oil wet OWI= oil wetting index OWI = proportion of the total brine production produced spontaneously

  8. Wettabilityvs. Various Parameters No Relationship with K/Phi! No Relationship with Vol Clay No Relationship with Grain Size No Relationship with Depth Probably Wettability predominantly a function of oil composition, with some natural variation/heterogeneity

  9. Hydrophobic (Oil Wet) Neutral Wetting 0 Hydrophilic (Water Wet) 0 0 Cos0 < 0 Cos0 = 0 Cos0 > 0 Wettability, Transition Zones and Saturation Ht Functions Wettability impacts the contact angle in conversions from laboratory to reservoir conditions PcR = PcL * (TCos0)R/(TCos0)L T = Interfacial Tension 0 = Contact Angle At Mangala, OWC & small Transition Zone below FWL due to Weakly Oil Wet Rock !! OWC Below FWL OWC above FWL OWC ~ FWL OWC FWL (FOL !) FWL OWC OWC FWL

  10. Fatehgarh Sand Reservoirs PVT Data – Mangala Field Variation in oil composition Mangala-5 oil Looks VERY interesting Mangala-5 oil Looks EXTREMELY interesting Mangala-5 oil looks interesting • High pour point - solid at ambient temperatures

  11. 600km heated pipeline – world’s longest SEHMS = Skin Effect Heat Management System (also known as STS/SECT) • SEHMS ensures temperature maintenance above 65 deg

  12. What’s Interesting? (to Management) Fatehgarh Sand Reservoirs Quite a LOT ofOil….But…. EXACTLY How Much? Oil= V * Porosity* (1 –Sw) Sw )

  13. An Exercise in Classical Petrophysics Or… “How to Get to Sw” Conventional “Archie” Log Analysis NMR Logging Capillary PressureSaturation-HeightFunctions Direct Measurement Calculation And Assumptions Swn = Rw/Rt *a/phitm With only log data, and using a value of n of 2.3 (oil wet reservoir) – Sw of 15% Dean-Stark Core Analysis Sw!! Sw ? Swn = Rw/Rt *a/phitm Are low Sw’s 5% and less possible ?

  14. Mangala, Aishwariya and Bhagyam FieldsAn EXCELLENT Dataset Summary - Available Core Analysis Data • SIXTEEN Cored Wells • Routine Core Analysis • Mostly Drilled with WBM • Mangala 1ST • First Core – Early 2004 • Water-Based Mud • Initial SCAL Data • Dean-Stark Cores • Bhagyam 5 • Mangala 7ST Company Culture of taking CORES!

  15. Mercury Injection Capillary Pressure DataMangala Field Low Sw ! Sw < 10% Oil Column

  16. Validity of MICP data? Probably reasonable in high quality clean reservoirs (Honarpour - 2004 ) Main issues : Hg may not replicate reservoir fluid displacement : destructive – normally conducted on small chips : remove the effects of quartz compression Quartz compression can account for 3 to 4 Sw units, as modern MICP machines can reach up to 60,000 psi. Straight line Tails Quartz compression

  17. Dean-Stark Fluid Saturations Plugs cut at wellsite SCAL Plug Dean Stark Extraction Horizontal Plug Vertical Plug Oil based mud cores Plugs cut at wellsite Minimize fluid loss Minimize surfactants Minimize core exposure to air and to sun 1 inch Minimize invasion of mud Maximize retaining of fluids in plugs Uninvaded core centre

  18. Dean-Stark Fluid Saturations Contamination Plot –Bhagyam 5 Horizontal Plug 30% X80m 25% X15m X78m 20% X32m 15% OBM Filtrate Contamination in Oil% 10% 5% 0% A B C D E F G H I Plug Location A BC D E F G H I

  19. Dean-Stark Water SaturationsMangala Field Laboratory Apparatus Dean Stark Extraction Avoid any water loss in laboratory Toluene 110°C Collect all water even droplets

  20. xx50 xx00 Lab A Lab B xx50 <-- Depth xx00 xx50 0% 2% 4% 6% 8% 10% Dean-Stark Water Saturation, % Dean-Stark Water SaturationsMangala Field Plugs sent to 2 independent laboratories One lab had consistently lower Sw’s by about 1 unit (Lab A)

  21. Oil-Brine Capillary Pressure Data (porous plate)Mangala 1ST Laboratory Apparatus Oil-Brine Capillary Pressure and Resistivity Index N2 Pressure Crude oil Core Plug Ultra fine Fritted glass disk Brine

  22. 300 250 200 150 100 50 0 0 10 20 Oil-Brine Capillary Pressure DataMangala 1ST Sw < 10% 2A 18A 28A 38A 45A 60A 65A 74A  Oil Column  Height Above FWL, m 89A 96A 110A 114A 124A 131A 143A 148A 30 40 50 Water Saturation, pct.

  23. Cementation Exponent “m” Mangala 1ST “m” ~ 1.75 Archie’s original paper 1942 Swn = Rw/Rt *a/phitm

  24. Saturation Exponent “n”Mangala 1ST 1000 Conducted on aged, restored samples 100 Even though rocks are intermediate-wet to oil-wet, “n” is less than 2 !! High perms and low salinity water Resistivity index, RI “n” ~ 1.8 10 1 Swn = Rw/Rt *a/phitm 0.01 0.10 1.00 Water Saturation, v/v

  25. Water Saturation CalculationsMangala 7ST Note scale from 0 to 0.2 Good agreement with Archie, Dean Stark core data & Saturation Ht Sw’s

  26. Saturation Ht Function Divide the capillary pressure data into permeability bins Model the capillary pressure curves according to the Skelt equation (Harrison 2002) SWcap_press = 1-A*exp(-((B/(HAFWL+D))^C)) Establish relationships as to how A,B,C,D vary with permeability Actual Data Modeled Pressure vs Saturation Pressure vs Saturation Mercury Pressure (psia) Mercury Pressure (psia) Saturation Saturation

  27. Nuclear Magnetic ResonanceNative State Plug - Mangala 1ST Note T2 distributions of native state plug and oil almost identical 0.12 Crude, DST 2, 70 Degrees C 0.10 Crude, DST 2, Ambient Plug, Ambient Plug, 70 Degrees C 0.08 Conclusion: 0.06 T2 dist almost entirely due to bulk oil response Normalised Amplitude 0.04 0.02 0.00 Applying cut-off for bound fluid as defined in lab, will give Sw 0.1 1 10 100 1000 10000 T2 (ms) Relaxation Time

  28. Defining the T2 cut-off for Bound Water Cumulative T2 distribution for Saturated Sample Swi (5%) from Capillary Pressure Bound fluid cut-off 1.9 Relaxation Time

  29. Wireline NMR Sw and Dean-Stark SwMangalaField All Data support low Sw’s Data from very different sources Sw’s 5% or less !!!! Such low Sw’s are possible ….. Further confirmation of low Sw NMR Archie Dean Stark Saturation Ht Bound water cut-off of 1.9ms

  30. Current STOIIP Estimate + ~350 million barrels = Economic ImplicationsMangala, Aishwariya, and Bhagyam Initial STOIIP Estimate

  31. 120 wells drilled to date Multi well pad concept Rapid rig design Purpose built wheel mounted rigs capable of moving easily between slots on a pad without rigging down ST-80 Iron Roughneck

  32. Large Savings $$

  33. Start of Chemical Injection Coreflood recovery nearly 95% of STOIIP Additional oil from ASP EOR Pilot Stage MANGALA COREFLOOD RESULT (Post waterflood result displayed) PHASE BEHAVIOR EVALUATION % Sodium Carbonate 0.0 0.5 0.75 1.0 1.25 1.5 1.75 2.0 2.25 2.5 2.75 3.0 3.5 4.0 Type-I Type-II Type-III 0.2% Surfactant; 0.6% NaCl; 30% Oil

  34. Conclusions • Archie “n” in Oil-Wet Reservoir • Contrary to “conventional wisdom”, moderately oil-wet reservoirs can exhibit Archie “n” values NOT significantly above 2.0. • Very Low Water Saturations • As evidenced here, very low water saturations (avg. 5%) exist in Mangala, Aishwariya and Bhagyam Fields • Model “Case Study” of the VALUE Of PETROPHYSICS • This is a case-study illustrating the economic worth of “Doing it Right” in initial petrophysics studies of high-value fields. • VALUE Of Taking Cores & Technology Culture

  35. CONTACT DETAILS Petrophysics – Tim OSullivan - Provide a “free” 5 day petrophysics course to NOC’s Drilling – AbhishekUpadhyay- Pipeline – Marty Hamill - EOR – AmitabhPandey-

  36. 10 1 5 4 Capillary Pressure (psi) 0 2 3 1 • Initial Oil Drive • Free Imbibition of Brine • Brine Drive • Free Imbibition of Oil • Oil Drive 2 3 4 5 -10 0 Average Sw 100 IAH = WWI - OWI Wettability Index Principle -the wetting phase will tend to spontaneously imbibe into a pore system, while an applied pressure is necessary to push the non-wetting phase into the pores. Combined Amott/USBM Wettability Experiment Capillary Pressure” (Pc) is defined as the pressure of the non-wetting phase minus the pressure of the wetting phase, and thus is always a positive number. In petroleum engineering typically define Pc as the pressure in the oil phase minus the pressure in the water phase (Pc = Po – Pw); so Pc would be positive for a water-wet system and negative for an oil-wet system. The experiment starts with a core at initial oil saturation and looks at how much water will spontaneously imbibe (“spontaneous production”), as shown on step 2 of Figure 2. This is followed by a measurement of how much water enters the core under an applied pressure gradient as the core is flooded to the residual oil saturation (Sorw). This is the “forced production” shown in step 3 of Figure 2. Note that the production measured is actually oil, since for each unit of water that enters the core an equivalent amount of oil is produced into a collection device. Obviously if the core was strongly water-wet, most of the oil production would happen spontaneously, with little need to apply an external pressure. The water-wetting index (WWI) is defined as the proportion of the total oil production that is produced spontaneously, and would be 1.0 for a strongly water-wet system and 0.0 for an oil-wet system. WWI= proportion of the total oil production produced spontaneously OWI = proportion of the total brine production produced spontaneously