Reservoir 3D Model
Interactive WebGL grid · Drag to rotate · Scroll to zoom · Colour by property
12×12×4 = 576 cells
STOIIP: —
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Permeability kh (mD)
102000
Grid Dimensions
Ni × Nj × Nk12×12×4
Active cells576
Cell Δx·Δy·Δz120·120·8 m
Areal extent1.44 km²
Gross thickness32 m
Volumetrics
Bulk volume—
Pore volume—
HCPV—
STOIIP—
STOIIP (MMbbl)—
Vertical Heterogeneity
Kv/Kh0.10
Dykstra-Parsons0.40
k range (layers)—
Avg layer kh200 mD
3D Continuity — Six-Point Stencil (TPFA)
∂(φSₚρₚ)/∂t = ∑[face=x±,y±,z±] Tface·λₚ·(Pₙₑᵢ − Pᵢ) + qₚ
Tz = 2·Kv·Δx·Δy / Δz · Kv = (Kv/Kh)·kh · vertical cross-flow couples layers
Tz = 2·Kv·Δx·Δy / Δz · Kv = (Kv/Kh)·kh · vertical cross-flow couples layers
Layer Properties
Per-layer porosity, permeability & net-to-gross · editable · drives 3D heterogeneity
4 layers
Layer properties are auto-generated from base rock and the Dykstra-Parsons heterogeneity coefficient, ordered fining-upward. Edit any cell directly — values feed the 3D model and simulation immediately. A high-perm "thief zone" can be created by setting one layer's kh well above the others.
Layer Property Table click values to edit
Permeability Profile vs Depth
Porosity Profile vs Depth
Fluid PVT Properties
Black oil formulation · Standing / Beal correlations · pressure-dependent tables
UndersaturatedPb=190 bar
Black Oil PVT Relations
Bₒ(P)=Bₒb·exp[−cₒ(P−Pb)] for P>Pb · Rₛ(P)=Rₛᵢ(P/Pb)^1.2 for P≤Pb · μₒ(P)=μₒb(Pb/P)^0.6
Oil FVF Bₒ vs P
BₒPb
Solution GOR Rₛ vs P
Rₛ
Oil Viscosity μₒ vs P
μₒ
Gas FVF Bᵍ vs P
Bᵍ
PVT Table
Rock & SCAL
Corey relative permeability · capillary pressure · endpoint saturations
Water-wetCorey
Corey Relative Permeability
kᵣₒ=kᵣₒ(Swi)[(1−Sw−Sor)/(1−Swi−Sor)]^nₒ · kᵣw=kᵣw(Sor)[(Sw−Swi)/(1−Swi−Sor)]^nw
Oil-Water Rel Perm
kᵣₒkᵣw
Gas-Oil Rel Perm
kᵣₒgkᵣg
Oil/Water Endpoints
Swi0.20
Sor0.28
kᵣₒ(Swi)0.85
kᵣw(Sor)0.30
nₒ / nw3.0 / 2.5
Gas/Oil Endpoints
Sgc0.05
Slr0.20
kᵣg(Slr)0.75
ng / nog2.0 / 2.5
Compressibility
cr rock4.5e-5 bar⁻¹
cw water4.6e-5 bar⁻¹
ct total~1.5e-4 bar⁻¹
Well Configuration
Peaceman model · BHP control · multi-layer completions
5 wellsBHP
Peaceman Well Model (per perforated layer)
qₚ = WI·(kᵣₚ/μₚBₚ)·(Pblock−Pwf) · WI=2π·kh·Δz/(ln(r₀/rw)+S) · r₀=0.28√(Δx²+Δy²)/2
Well Register
Inflow Parameters
rw0.11 m
Skin S3.0
Peaceman r₀—
CompletionsAll layers
Constraints
Prod BHP min90 bar
Inj BHP max360 bar
ControlBHP
Aquifer Model
Analytical influx · Fetkovich / Carter-Tracy · bottom & edge water
Fetkovich
Fetkovich Aquifer
dWe/dt=Jaq·(Paq−Pr) · Paq=Pᵢ(1−We/Wei) · strength multiplier scales Jaq and Wei
Aquifer Influx We vs Time
We cumulative
Aquifer Parameters
ModelFetkovich
Strength ×1.0
DriveEdge + bottom
Connects toLowest layer
Numerical Solver
IMPES · 3D seven-diagonal pressure system · explicit saturation update
IMPES—
IMPES Sequence
1. Assemble 3D pressure matrix (7-diag) → solve P implicitly (Gauss-Seidel)
2. Update Sw, Sg explicitly per cell from inter-block fluxes
3. CFL: Δt ≤ φΔx²cₜμ/(2k) · ΔSmax ≤ 0.05 per step
2. Update Sw, Sg explicitly per cell from inter-block fluxes
3. CFL: Δt ≤ φΔx²cₜμ/(2k) · ΔSmax ≤ 0.05 per step
Configuration
MethodIMPES
Pressure solverGauss-Seidel
Tolerance1e-5 bar
Max sweeps200
Timestepping
Δt30 d
Horizon12 yr
Est. steps~146
Status
StateIdle
Steps done0
CPU time—
Simulation Log
Awaiting run command…
Simulation Results
Production forecast · pressure depletion · 3D saturation evolution · well performance
No results — run simulation
Cum Oil Np
—
10³ m³ SC
Cum Water Wp
—
10³ m³ SC
Avg Res P
—
bar
Final WOR
—
m³/m³
Recovery
—
% STOIIP
Field Rates vs Timem³/d SC
QₒQw
Avg Reservoir Pressurebar
P̄Pb
Cumulative Production10³ m³
NpWp
WOR & GOR vs Time
WORGOR×0.1
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Water Saturation Sw
OilTransitionWater
Timeline
t = 0 yr