Know Before You Go How GeoPrediction helps with Production Optimization and Assessing the Size of the Prize Steve O Connor Global Technical Lead, Geopressure Bryony Youngs Reservoir Portfolio Development Manager
Agenda 2 AIM: an integrated modeling solution to reconcile virgin and production pressures and account for stress changes during depletion Phase 1 Understand pre-production overpressures within reservoir. Study the effects of lateral and vertical fluid drainage. Phase 2 Understand the effects of production effects on the reservoir. Understand the static reservoir pressure modelling to model effects of field production on the pressure depletion. Production history matching Phase 3 Dynamic GeoFlow modelling.
Modeling Geological vs. Production Pressure 14/18a-7 13/22a-1, 2, 6 and 7 15/22-3 13/30-3 14/29a-3 ALDER MACCALLAN 16/28-8 21/2-4 20/6-1 20/7-1 20/4-1 21/3a-7 21/4-1 O Connor and Swarbrick, 2008
Geological Time Virgin Pressure State 4 1. Collate all relevant virgin fluid or pore pressure data (RFT, DST, Kick), with particular focus on the Cetaceous data (Upper and Lower) and Jurassic, 2. Identify fluid gradients (gas, oil and water) and Free-Water Levels (FWL s), 3. Compare FWL s with Hydrocarbon-water contacts from logs, 4. Understand the regional picture, including the geological evolution of the region using supplied and public seismic, stratigraphy, lithology and regional data, 5. Use structural data to understand fault patterns and their likelihood for reservoir compartmentalisation 6. Explaining fluid distributions e.g. Spill point maps for Fields X, Y, Z etc 7. Construct theoretical pressure model for Kopervik Fairway
1D Production Time Static Modeling 5 1. Construct summary of production history in the area including all satellite fields 2. Does Field X and Field Y production explain Field Z pressures? 3. Has there had to have been some other depletion e.g. Jurassic communication? 4. Update spill point maps for Fields X, Y, Z etc
3D/4D Production Time Dynamic Modeling 6 1. Using a Geomechanical flow simulator to capture and model fluid flow in a reservoir affected by stress changes during depletion 2. How fast is regional and local pressure waves? 3. Effect of future Field X production on Field Y reservoir pressure depletion 4. What is the predicted pressure with time at Field Y (with and without Field X production, before and after Field Z production)?
Geological Time Virgin Pressure State 7
Challenge of variable hydrocarbon-water contacts HYDRAULIC? SEDIMENTOLOGICAL? Any Questions? Thank you PRODUCTION? STRUCTURAL? RECENT TILTING?
Static vs. Dynamic Systems Flat fluid contacts Tilted fluid contacts HC outlines are parallel to structure and are within structure Same GOC & OWC for all wells HC outlines are not parallel to structure and may be outside structure Different GOC & OWC for each well Dennis et al, 1998
Conventional : Groundwater Flow 300 km Legend Direction of groundwater flow Recharge area Spring Concentration of springs Alice Springs Eromanga Basin Cooper Basin Lake Eyre Surat Basin Brisbane Lake Torrens Lake Frome Webster et al., 2007
Artesian Water Drive/Support 11 11 Pressure remains high GOR remains steady EOR up to 60% of OIP
Unconventional Hydrodynamics
Modeling Geological vs. Production Pressure 14/18a-7 13/22a-1, 2, 6 and 7 15/22-3 13/30-3 14/29a-3 ALDER MACCALLAN 16/28-8 21/2-4 20/6-1 20/7-1 20/4-1 21/3a-7 21/4-1
Britannia Field, North Sea 15/27 15/28 15/29 15/30 16/26 16/27 16/28 16/29 Kopervik Fairway 400 300 200 3 7 8 6 5 11 10 7 6 9 3 21Z 4Z 4Y 7 4Z 100 100 24 6 2Z 6 12 3 5 16 Renee Ridge 21/2 21/3 21/4 21/5 22/1 22/2 22/3 22/4 2 100 200 4 200 100 4 500 5Z 7km 5 2 2 1000 1000 1500 0 o 36 E 1 o 00 E Control well Britannia Field outline Britannia Sandstone Limit 1000 Overpressure (psi)
Britannia Field, North Sea Common Gas Gradient East 16/27 16/26 West 15/30
Shale pressures and shoulder effects 16 Shale pressures calculated using data from O Connor et al. (2008). Shale pressures above and below are higher than the reservoir pressure and the shales are slowly draining overpressure into the reservoir resulting in shoulder effects.
Virgin Pressure Model for Britannia Sands 17 Tertiary Laterally-drained sands Theoretical shale pore pressure Pressure transition zone in chalk matched by kicks Cretaceous Variable amounts of drainage in reservoir Overpressured sands Jurassic/Triassic (after Ikon Science/IHS/PGS, 2010)
Case Study#2 Central Graben Pressure Study O/P < O/P 50 psi < 50 psi Distribution Map of Overpressures Hydrodynamic flow directions Andrew Formation Contours of overpressure in psi Andrew Sandstone limit O/P > 2000 psi Close to shale pressures? Ramp - OWC tilt Distance: 10km Difference in o/p: 200 psi dp/dx: 20 psi/km Tilt (oil): 180 ft/km (55m)
To close the spill point there 8220 8210 8200 8190 8170 must be a minor readjustment of then 8210 ft contour in the saddle point. 8150 8130 8220 Oil Shows Dry Holes Oil & Gas 25 ft / km 8210 Structural Spill Point 500 m 8200 8190 8170 8150 8130 Hydrodynamic Spill Point
A Field X Hydrodynamic Oil Pool Outlines 8800 8770 8740 8710 8610 8590 8830 8800 8770??? 8740 8710 A OWC structure ft structural closure 8680 hydrodynamic closure seismic amplitude 8650 8650 8630 8610 anomaly
A A NW Trap structural spill to the north E 8550 Seismic Impedance Response 8600 8650 8700 8750 8800 25 ft per km 60% increase in reserve by applying this approach 8850 1km Forties Surface Structural Closure Hydrodynamic Closure
Seismic Attributes Arbroath and Montrose fields. LHS is the structural relief map (red =high). RHS is seismic impedance (brine-filled = blue, red colour = oil-filled channels. Arrow is the regional flow defined by overpressure gradient.
Artesian Water Drive/Support 23 Pressure remains high GOR remains steady EOR up to 60% of OIP
Conclusions Different fluid contacts in fields? Eliminate other competing explanations (faults, production, recent tilting, capillarity etc.) Affect migration and can increase reserves estimates Can enhance water support and recovery Provide new exploration models as well as the ability to reassess existing acreage without drilling anymore wells Best approach is undertake regional studies to map pressure and reservoir connectivity. Hard to do using only local acreage.
1D Production Time Static Modeling 25
Viking Graben, North Sea Palaeocene 26 Map of the Frigg Field area showing Palaeocene wells affected by production related pressure depletion surrounding the Frigg Field. The yellow dashed line shows the area affected by the Frigg Effect. NOR 25/1-3 The black dashed line shows the extent of the Palaeocene basinal sands. The colour shading indicates the relative magnitude of overpressure- Red is positive overpressure; Blue is under-pressure (bars below hydrostatic).
Frigg Main Field, Little Frigg and East Frigg Pressure-Depth Plot PressureView 4 GeoPressure Technology Ltd 1800 25/1-1 25/1-2 ST 25/1-3 25/1-5 25/1-7 25/1-8 S 25/2-1 25/2-10 S 25/2-11 25/2-2 25/2-8 25/2-9 30/10-1 Depth (m) TVDSS 1900 2000 2100 2200 2300 2400 2500 Frigg Sandstone Member Balder and Sele Formations Lista Formation Sele Formation 2600 Ty Formation 0.12 bar/m 140 160 180 200 220 240 260 280 300 320 Pressure (bar) abs.
Overpressure Overpressure date vs. production date 28 Field X came online Simplistic approach but doesn t take into account distance A B C D E F Year
Multivariate linear modelling 29 Amount of pressure depletion depends on both time since production began and distance from producing field. Not possible to create a model only using one or the other. Combining the two variants as a ratio and plotting them against pressure depletion will give a model to allow prediction of blind tests. A ratio of distance/time will be used. Distance in km from producing field / time in days since production of field began. Typical flow simulators do not allow for stress changes in the reservoir and overburden
Depletion psi Results of using a ratio of Time/Distance 30 100 psi Field X wells Blind Test Wells Real Tested Values A resulting trend line will generate an equation which can be used to predict the blind test well depletion values. A lower ratio will result in a larger depletion value. The ratio value will decrease with time but increase with distance from the producing field. 1 psi 0.1 1 Distance (km)/time (days) 10
Production Effects As the time since the beginning of production increases and more is produced from the field, the pressure depletion is expected to increase. Assumptions in this modelling are: 1D model, necessitating homogenous pressure front in the 1D model. No radial flow near the pressure sink Homogenous properties (porosity, permeability, viscosity and compressibility) Fixed pressure in the pressure sink at the centre of the model that is turned on at time=0 As the distance from the producing field increases, the amount of pressure depletion decreases rapidly close to the field but slowly much further from the field.
Validity of pressure depletion models To test the validity of the theory behind the schematic time/depth plots we create a theoretical 1-D fluid flow model. 1-D fluid flow in porous media can be modelled using the following partial differential equation (Smalley and Muggeridge, 2010): Typical flow simulators do not allow for stress changes in the reservoir and overburden. These changes affect fluid flow, compaction, permeability, drive etc
Dynamic Geomechanics
Understand multiple reservoir systems Reservoirs can be connected geomechanically even though they are isolated from a fluid standpoint
Geomechanics and Production Optimization Is there a risk of seal breach during injection? Will reservoir compaction have an effect on production? What is the maximum drawdown before sanding occurs? Is a time-lapse seismic study feasible? If so, what is the optimal interval?
Geomechanical flow simulation Geomechanics simulation Solve for stress state and rock deformation. Flow simulation Solve for fluid saturations and pressure distribution Benefits Understand how the stress state (and potential for failure) evolves with production Understand how geomechanical behaviour effects fluid flow
Governing equations Stress tensor Mechanics: C e u ε p Ap = 0 Flow: u t + A e u t + β p t + p λ p H = q Porosity change Darcy flow
Multi-scale simulation Well scale Reservoir scale Basin scale Benefits Appropriate resolution at each scale Understand connections and interactions between processes at different scales
Workflow Build input model Stress determination Model calibration Geomechanical applications Every step in the workflow needs to be good to ensure a successful study
Build input model Stress determination Model calibration Geomechanical applications Initial pressure Rock & fluid properties Initial stress field
Build input model Stress determination Model calibration Geomechanical applications Run simulator Output Fluid pressure Fluid saturations Solid displacements Mechanical stress tensor Well production data Fluid velocities Effective stress Change in porosity
Build input model Stress determination Model calibration Geomechanical applications Observed data used to constrain uncertain input parameters 4D seismic History matching (well production data) Surface displacement data
Build input model Stress determination Model calibration Geomechanical applications Existing well information Wellbore centric analytic models Geomechanical Flow Simulation Image logs, drilling reports Calibrate 1D well scale models Calibrate 3D well, reservoir and basin scale models
Build input model Stress determination Model calibration Geomechanical applications Caprock integrity studies Avoiding surface subsidence Optimize hydraulic fractures Maintaining wellbore stability
Well pressure (MPa) Reservoir compaction effects on production Does reservoir compaction increase production via compaction drive? Or does it decrease production as a result of reduced permeability? 45 40 35 With full mechanics Without full mechanics 30 25 20 15 10 5 0 0 1 2 3 4 5 6 Time (years)
Predict fault reactivation σ 1 Shear failure criterion: Fault slip initiates if shear failure t exceeds a critical stress τ fail > S 0 + μ σ n β Fault plane Normal to fault plane With: S 0 Cohesion m friction coefficient t σ n σ 1 σ 3 β
Determine maximum injection pressures Friction coefficient m=0.4 Friction coefficient m=0.5 Friction coefficient m=0.6 Reservoir 1000psi = 6.89MPa Additional pressure required above initial conditions for fault re-activation to occur
Summary Naturally hydrodynamic aquifers enhance production rates, provide water support and aid pressure decline. Out of closure potential. Understanding the dynamic geomechanical behaviour of your reservoir is a key ingredient in production optimization Geomechanical flow simulation enables us to predict how both the stress field and fluid pressure evolve with production and determine the answers to questions such as: Will depleting reservoir X effect reservoir Y? What is the maximum injection pressure without compromising the cap rock? Will reservoir compaction have a positive or negative impact on production? What is the maximum drawdown before sanding occurs?