A Case Study in Integrating Core into an Oil Field Development Mike Millar With acknowledgements to: Ichron Ltd; Rob Newbould, James Gifford and other colleagues at Petro-Canada. Aberdeen Formation Evaluation Society What is so Special about Core Analysis? 28 th March 2007 1
Case Study in Integrating Core into a Field Development Outline Field summary Core to log calibrations for reservoir properties Core Analyses Database Porosity and saturation parameters Establish STOOIP Understanding variability of reservoir quality from core concerns over PLT result and productivity related to grain size and facies Planning development wells well placement and sidetrack options completions Core to log calibrations for estimating permeability Facies based porosity-permeability transform Real-time permeability thickness calculations 2
Integrating Core into a Field Development - Field Location Clapham Field Sub-sea tie back to Triton FPSO 4 5 19/1 2a 3 4 5b 20/1N 2b 3b 4b 5c 21/1a 2 3a 3b 4c 4b 4a 5a 1b 2a 3b 4b 4a 5a5b 3a 9 10 6 7 8 2c 1S 5a 9 10b 10a 6 7a 3a 2a Ettrick 8 3c 4c 9 4a 5d 5a 5b 10a 1b 6a 7 3c 8 9 10 5c 5b 22/1a 1c 6a6b 2b 7 3a 8b 9 10a 3b 10b Buzzard 7b 6b Forties 8a 10b 11 12 13 14 15 11 12 13 14 15 11 12 13a 14c 14a 15b 11 12a 13a 13b 14a 15 St. Fergus 13c 14b 14d 15a 12b 13c 14b 17 18 19 20 16 17 18 13b 19 20 16c 16a 17a 18a 19 15c 12a 20b 20c 20a 16c 16a 17 18 19b 20 Cruden Bay 16 16b 17b Kittiwake 18b 16b 19a Aberdeen 30 26 21 22 27 23 28 24 25 21 22 23 24 25 21 22 23a 24 25 21 22a 23a 23b Pict Teal Gannet D Saxon Clapham Teal South 22b 22c 23b Gannet B Gannet A 29 30 26 27 28 29 30 26 27a 27b 28a Fyne 26a 27a 28d Guillemot A 27b Gannet C Dandy 28b 29a Gannet F Gannet E 28b 28a 28c 24a 24c25d25b 25a 24b 25c 25e 24d 29 30a 30c 30b 3 5 4 0 26/1 2 3 4 5 Kilometres 30 27/1 2 3 4 5 28/1 27c 29b 2 3 4b 4a 30 5a 5b 26b 29/1a 1c 2c 2a 3b 1b 2b 3a 4b 4c 4a 4d 5b 5a 5c NWE1134 10 6 7 8 9 10 6 7 8 9 10 6 7 8 9 10a 6b 6a 7 8a 9c 10
Integrating Core into a Field Development - Field Outline Top reservoir structure map Jurassic, Fulmar Formation reservoir (+/- 7000 ft) Four- Way dip closed structure Characterised by middle shoreface (high perm) to distal lower shoreface sands (low perm) Undersaturated, medium gravity 33º API oil and Low GOR (100 scf/stb) Water flood is primary drive mechanism 4
Core to Log Calibration - Core Analyses Database 203ft of core recovered 220ft from offset well Conventional core analysis Electrical properties Capillary pressure Dean-Stark Saturation Petrography and Sedimentology Rock strength Sieve analysis Formation damage 5
Core to Log Calibration - Estimating Porosity Correcting core porosity for net overburden stress most core analyses at ambient conditions compare to sub-set measured at net overburden stress correction factor 0.964 OB Porosity Core Porosity Reduction at Net Overburden Pressure 35 30 25 y = 0.9635x R 2 = 0.997 20 15 10 5 0 0 5 10 15 20 25 30 35 AmbientPorosity 6
Core to Log Calibration - Estimating Porosity Calculating Density Porosity Matrix density from core grain density Fluid density from cross-plot of log bulk density vs. corrected core porosity φ = ρ ρ ma ma ρb ρ f 7
Core to Log Calibration - Estimating Water Saturation Formation Resistivity Factor Archie Saturation Equations 2.0 Sw n = F.Rw /Rt log10 FRF 1.8 1.6 1.4 1.2 1.0 0.8 y = -1.7916x Saturation (electrical) Parameters Resisitivity Index for n RI = Rt /Ro and RI = 1 / Sw n Resistivity Index 0.6 2 0.4 1.8 0.2 1.6 0.0 1.4-1.0-0.9-0.8-0.7-0.6-0.5-0.4-0.3-0.2-0.1 0.0 log10 Porosity - % Formation resistivity factor for m F = Ro / Rw and log10 RI 1.2 1 0.8 0.6 y = -1.9249x R 2 = 0.994 F = 1 / Φ m Forced regression; a = 1 0.4 0.2 0 0 0.2 0.4 0.6 0.8 1 1.2 1.4 1.6 1.8 2 8 log10 Sw
Core to Log Calibration - Estimating Water Saturation 450 400 Capillary Pressure with Log data Water Saturation from Dean-Stark Extraction, compared to log derived Sw 350 Height above FWL -TVDss Ft 300 250 200 150 100 50 0 0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1 Water Saturation - v/v Water Saturation from Capillary pressure, compared to log derived Sw 9
Core to Log Calibration Estimating STOOIP Core calibrated log analyses Porosity, Sw and Net-gross used to estimate oil in-place STOOIP = (GRV * N:G * Φ * Sh) / Bo 10
Variability of Reservoir Quality Discovery Well Test Tested whole Fulmar Production logging showed that most production from lower most interval Best production from highest permeability Core Analysis data 10000.00 21246 Best Flow 1000.00 Air Permeability md 100.00 10.00 11 1.00 0.0 5.0 10.0 15.0 20.0 25.0 30.0 35.0 Helium Porosity %
Ichron Facies Model Fulmar Shallow Marine Shoreface Sands Increasing reservoir quality decreasing water depth increasing grain size 12
Facies Influence on Reservoir Quality Middle Shoreface - Strongly oil-stained, clean, well sorted fine grained sandstone. Bioturbation level is probably no greater than moderate. The mottled fabric reflects a combination of local cementation adjacent to bivalve shells, plus Palaeophycus burrows. 889mD and 30% 13 Proximal Lower Shoreface - Moderately to locally poorly sorted, moderately to highly bioturbated, slightly silty fine grained sandstone. Note the prominent clayreplaced bivalve shells forming a lag deposit at the base of the unit (B). 238mD and 27% Increasing reservoir quality decreasing water depth increasing grain size Distal Lower Shoreface - Moderately to well sorted, highly bioturbated, silty very fine to fine grained sandstone. Note the prominent Teichichnus zigzag burrow (T) and clay-replaced bivalve shell debris (B). 21mD and 26.2%
Facies Influence on Reservoir Quality Grain size relationship to air permeability 14
Reservoir Quality Influence on Saturation Distal Lower Shoreface Low Perm - 14.3mD High Phi - 28% 400 Air_brine Capillary Pressure 350 300 2B 2J Scale Bar is 0.5mm Proximal Lower Shoreface High Perm - 648mD High Phi - 24.7% Height TVDSS - feet 250 200 150 100 50 0 0 10 20 30 40 50 60 70 80 90 100 Sw - % 15
Planning development wells By using the core we have proved that the Fulmar at Clapham has variable facies and therefore reservoir quality Horizontal wells can t be guaranteed to target best reservoir. Strategy was to drill high angle wells penetrating the whole Fulmar, thus guaranteeing intersection of some of the best reservoir in each well. Modelling suggests that high borehole angles reduce skin The general objectives are: To drill and complete two oil production wells (with a sustained production capacity of at least 7500 bopd) and two water injector wells (with a capacity of 8250 bwpd) To minimise the formation damage to reduce skin effects during the drilling and completion process. To acquire a full set of logs through the reservoir to facilitate reservoir characterisation, including permeability estimate. 16
Geosection along an oil producer well - Reservoir Section Strategy was to drill high angle wells penetrating the whole Fulmar, thus guaranteeing intersection of some of the best reservoir in each well. Well success based on estimate of permeability-thickness, therefore quick-look facies and porosity is required A geological sidetrack was considered if the cumulative permeability estimate through the reservoir is such that it is considered unlikely that the target production rate could be sustained. 17
Facies Influence on Reservoir Quality Anticipated PI is based on permeability-thickness and estimated skin. These determined by reference to E&A wells Well success based on estimated permeability-thickness Permeability estimate depends on an interpretation of the facies 18
Estimating Permeability by Facies Facies based poro-perm transforms Using Y-on-X regression Using air permeability Permeability on the log10 scale 19
Estimating Permeability by Facies - the E&A wells Shows the significance of the MSF and PLSF 20
Real-time Evaluation and Decision Making Water Injector Sidetracked original well PLSF and DLSF sidetrack MSF, PLSF and DLSF original well 12,500 md/ft sidetrack 24,000 md/ft 21
Planning Completions Rock Strength and Grain Size Sieve Analysis Grain Size Distribution 120 100 80 Proximal Lower Shoreface Distal Lower Shoreface 60 Cumulative Wt (%) 40 Sieve Analyses 20 1000 100 0 10 Grain Size (µm ) 22 Sand Exclusion Screens and Gravel Pack used in Completions Rock strength studies on core plugs
Case Study in Integrating Core into a Field Development Summary Core to log calibrations for reservoir properties Core Analyses Database Porosity and saturation parameters Establish STOOIP Understanding variability of reservoir quality from core concerns over PLT result and productivity related to grain size and facies Planning development wells well placement and sidetrack options completions Core to log calibrations for estimating permeability Facies based porosity-permeability transform Real-time permeability thickness calculations Reservoir Management Used core in evaluations of development well logs to revise models Using core to help understand field performance 23