Presentation on theme: "SPE Distinguished Lecturer Program Primary funding is provided by The SPE Foundation through member donations and a contribution from Offshore Europe The."— Presentation transcript:
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
Maximizing the Value of an Asset through the Integration of Log and Core data Tim OSullivan Cairn India Ltd Society of Petroleum Engineers Distinguished Lecturer Program Colleagues:Hal Warner Dick Woodhouse Dennis Beliveau Ron Zittel Stuart Wheaton
Where is the data area ? Discovery Well Mangala, Aishwariya & Bhagyam Fields 150m - 350m oil columns 2004 ( about 2 Billion Barrels STOOIP)
What’s Interesting? (to Reservoir Teams) Fatehgarh Sand Reservoirs Quite a LOT of Interesting Oil An EXCELLENT Dataset 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% * Mangala Field – Over 1 Billion Barrels Oil In Place * An Economic Incentive for Petrophysical ACCURACY * Very Waxy, Sweet Crude – 27 o API Avg. * All Wells with Full “Basic” Logging Suites * Many Wells with “Specialty” Logs – CMR+, etc. * 1.7 km of Core in MBA
Oil WetWater WetIntermediate Fatehgarh Sand Reservoirs Wettability Index Data – Mangala Field Average Sw Initial Oil Drive Free Imbibition of Brine Brine Drive Free Imbibition of Oil Oil Drive I AH = WWI - OWI Capillary Pressure (psi) Combined Amott/USBM Wettability Experiment WWI = proportion of the total oil production produced spontaneously OWI = proportion of the total brine production produced spontaneously ~ Weakly oil wet No Relationship with Permeability! WWI = water wetting index OWI = oil wetting index
Wettability vs. Various Parameters Probably Wettability predominantly a function of oil composition, with some natural variation/heterogeneity No Relationship with K/Phi! No Relationship with Vol Clay No Relationship with Grain Size No Relationship with Depth
Wettability, Transition Zones and Saturation Ht Functions Wettability impacts the contact angle in conversions from laboratory to reservoir conditions Pc R = Pc L * (TCos0) R /(TCos0) L Hydrophobic (Oil Wet) 0 Hydrophilic (Water Wet) 0 Neutral Wetting 0 Cos0 > 0Cos0 = 0Cos0 < 0 FWL (FOL !) FWL OWC above FWL OWC Below FWL OWC ~ FWL OWC At Mangala, OWC & small Transition Zone below FWL due to Weakly Oil Wet Rock !! OWC T = Interfacial Tension 0 = Contact Angle OWC
Mangala-5 oil looks interesting Mangala-5 oil Looks VERY interesting Mangala-5 oil Looks EXTREMELY interesting Mangala Field Well Name Sample TypeR. PrB RP MDT/BHSpsig DegreescP Mangala-1 BHS MDT MDT Mangala-1ST MDT Mangala-2 MDT Mangala-3 MDT MDT Mangala-4 MDT MDT Not Measured Mangala-5 MDT MDT Mangala-5 BHS BHS BHS Fatehgarh Sand Reservoirs PVT Data – Mangala Field Variation in oil composition High pour point - solid at ambient temperatures
600km heated pipeline – world’s longest SEHMS = Skin Effect Heat Management System (also known as STS/SECT) SEHMS ensures temperature maintenance above 65 deg
Quite a LOT of Oil…. But…. EXACTLY How Much? What’s Interesting? (to Management) Fatehgarh Sand Reservoirs Oil = V * Porosity * (1 – Sw) Sw )
Conventional “Archie” Log Analysis Calculation And Assumptions SwSw An Exercise in Classical Petrophysics Or… “How to Get to Sw” Direct Measurement S w !! Dean-Stark Core Analysis Capillary Pressure Saturation-Height Functions NMR Logging ? With only log data, and using a value of n of 2.3 (oil wet reservoir) – Sw of 15% Sw n = Rw/Rt *a/phit m Are low Sw’s 5% and less possible ?
Mangala, Aishwariya and Bhagyam Fields An EXCELLENT Dataset 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 Summary - Available Core Analysis Data Company Culture of taking CORES!
Mercury Injection Capillary Pressure Data Mangala Field Sw < 10% Oil Column Low Sw !
Straight line Tails Quartz compression Validity of MICP data? Probably reasonable in high quality clean reservoirs (Honarpour ) 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.
Dean-Stark Fluid Saturations SCAL Plug Dean Stark Extraction Oil based mud cores Plugs cut at wellsite Minimize fluid loss Minimize surfactants Minimize core exposure to air and to sun Uninvaded core centre Horizontal Plug Vertical Plug Minimize invasion of mud Maximize retaining of fluids in plugs Plugs cut at wellsite 1 inch
Dean-Stark Fluid Saturations Contamination Plot – Bhagyam 5 0% 5% 10% 15% 20% 25% 30% ABCDEFGHI Plug Location OBM Filtrate Contamination in Oil% X80m X15m X78m X32m A B C D E F G H I Horizontal Plug
Laboratory Apparatus Dean Stark Extraction Dean-Stark Water Saturations Mangala Field Toluene 110°C Avoid any water loss in laboratory Collect all water even droplets
Dean-Stark Water Saturations Mangala Field Plugs sent to 2 independent laboratories One lab had consistently lower Sw’s by about 1 unit (Lab A)
Laboratory Apparatus Oil-Brine Capillary Pressure and Resistivity Index Oil-Brine Capillary Pressure Data (porous plate) Mangala 1ST Brine Crude oil N 2 Pressure Ultra fine Fritted glass disk Core Plug
Oil-Brine Capillary Pressure Data Mangala 1ST Water Saturation, pct. Height Above FWL, m A18A 28A38A 45A60A 65A74A 89A96A 110A114A 124A131A 143A148A Sw < 10% Oil Column
Cementation Exponent “ m ” Mangala 1ST “m” ~ 1.75 Archie’s original paper 1942 Sw n = Rw/Rt *a/phit m
Saturation Exponent “ n ” Mangala 1ST Water Saturation, v/v Resistivity index, RI “n” ~ 1.8 Conducted on aged, restored samples Even though rocks are intermediate-wet to oil- wet, “n” is less than 2 !! High perms and low salinity water Sw n = Rw/Rt *a/phit m
Water Saturation Calculations Mangala 7ST Note scale from 0 to 0.2 Good agreement with Archie, Dean Stark core data & Saturation Ht Sw’s
Saturation Ht Function Divide the capillary pressure data into permeability bins Model the capillary pressure curves according to the Skelt equation (Harrison 2002) S W cap_press = 1-A*exp(-((B/(HAFWL+D)) ^C)) Establish relationships as to how A,B,C,D vary with permeability Pressure vs Saturation Saturation Mercury Pressure (psia) Actual DataModeled
Nuclear Magnetic Resonance Native State Plug - Mangala 1ST T 2 (ms) Normalised Amplitude Crude, DST 2, 70 Degrees C Crude, DST 2, Ambient Plug, Ambient Plug, 70 Degrees C Note T2 distributions of native state plug and oil almost identical T2 dist almost entirely due to bulk oil response Applying cut-off for bound fluid as defined in lab, will give Sw Relaxation Time Conclusion:
Defining the T2 cut-off for Bound Water Bound fluid cut-off 1.9 Cumulative T2 distribution for Saturated Sample Relaxation Time Swi (5%) from Capillary Pressure
Wireline NMR Sw and Dean-Stark Sw Mangala Field Bound water cut-off of 1.9ms Further confirmation of low Sw Archie Dean Stark Saturation Ht NMR All Data support low Sw’s Data from very different sources Sw’s 5% or less !!!! Such low Sw’s are possible …..
Initial STOIIP Estimate Current STOIIP Estimate + ~350 million barrels = Economic Implications Mangala, Aishwariya, and Bhagyam
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
Large Savings $$
Additional oil from ASP Coreflood recovery nearly 95% of STOIIP Start of Chemical Injection PHASE BEHAVIOR EVALUATION % Sodium Carbonate % Surfactant; 0.6% NaCl; 30% Oil Type-IType-III Type-II EOR Pilot Stage MANGALA COREFLOOD RESULT (Post waterflood result displayed)
Very Low Water Saturations As evidenced here, very low water saturations (avg. 5%) exist in Mangala, Aishwariya and Bhagyam Fields Archie “n” in Oil- Wet Reservoir Contrary to “conventional wisdom”, moderately oil- wet reservoirs can exhibit Archie “n” values NOT significantly above 2.0. 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. Conclusions VALUE Of Taking Cores & Technology Culture
CONTACT DETAILS Petrophysics – Tim OSullivan - Drilling – Abhishek Upadhyay- Provide a “free” 5 day petrophysics course to NOC’s Pipeline – Marty Hamill - EOR – Amitabh Pandey-
Wettability Index Average Sw Initial Oil Drive Free Imbibition of Brine Brine Drive Free Imbibition of Oil Oil Drive I AH = WWI - OWI Capillary Pressure (psi) Combined Amott/USBM Wettability Experiment WWI = proportion of the total oil production produced spontaneously OWI = proportion of the total brine production produced spontaneously 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. 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 (S orw ). 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.