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A Geomechanical Evaluation of Fault Reactivation Using Analytical Methods and Numerical Simulation

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Abstract

One of the main problems related to mature oilfields is the decreased pore pressure due to hydrocarbon production. Therefore, to maintain the production rate of a reservoir, the lost pressure must be compensated. A very traditional method to increase the pressure is to inject natural gas into the reservoir. This technique is widely used in SW Iranian reservoirs because of the readily available supply of this type of gas. Reactivation of pre-existing faults and inducing new fractures into the reservoir and cap rock are some of the potential risks regarding gas injection. In this article, using data such as well logs, pore pressure estimates, and rock mechanical test results, the geomechanical simulation of the Asmari reservoir in the Gachsaran oilfield, SW Iran has been carried out. For this purpose, the current stress field was determined using elastic moduli of reservoir rocks and formation integrity test (FIT) results. Then, by applying analytical methods such as Mohr diagrams and slip tendency, the reactivation possibility of four faults in the field was analyzed, and the maximum sustainable pore pressures were estimated. In the next step, numerical simulations were conducted using ABAQUS software to investigate the injected gas flow path, leakage potential through the cap rock, possible fault reactivation due to gas injection, and shear stress build-up and plastic strain development in different parts of the reservoir. Results of Mohr diagrams and slip tendency showed that all the faults are stable in the current stress state, and fault F2 has the potential to sustain a maximum pore pressure of 55 MPa in the field. On the other hand, fault F3 has the proper conditions (i.e., strike and dip referring to σHmax orientation) for reactivation. Results of numerical simulations suggested that an injection pressure of 30 MPa would not induce any new fracture or fault slip within 5 years of injection. In this period, the injected gas plume moves upward through the damage zone and reaches the shallower parts of the cap rock. It was also shown that by applying an injection pressure of 60 MPa, slip would occur on fault F4 after 10 days of injection.

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source rock. Due to the higher permeability of the damage zone, the pore pressure plume first penetrates the Pabdeh source rock, and at the end of 5 years, it also infiltrates the cap rock (pore pressure in Pa). Furthermore, the ascending gasses from the reservoir-cap rock interface slightly infiltrate the lower part of the cap rock

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Abbreviations

FIT:

Formation integrity test

API:

American Petroleum Institute gravity, °

c :

Cohesion strength of rock, MPa

μ s :

Coefficient of static friction

σ 1, σ 2, σ 3 :

The maximum, the intermediate, and the minimum principal stresses, MPa

σ V :

Vertical stress, MPa

σ Hmax :

Maximum horizontal stress, MPa

σ hmin :

Minimum horizontal stress, MPa

\(\rho\) :

Overburden density, kg/m3

\(\bar{\rho}\) :

Mean overburden density, kg/m3

g :

Gravitational acceleration, m/s2

z :

Depth, m

LOT:

Leak-off test

XLOT:

Extended leak-off test

LT:

Limited test

LOP:

Leak-off point

ν s :

Static Poisson’s ratio

E s :

Static Young’s modulus, GPa

P P :

Pore pressure, MPa

α :

Biot’s coefficient

ε x :

Magnitude of the rock deformation in the x plane

ε y :

Magnitude of the rock deformation in the y plane

DST:

Drill stem test

RFT:

Repeat formation test

P pg :

Formation pressure gradient, MPa/m

P ng :

Hydrostatic pore pressure gradient, MPa/m

Δt :

Measured sonic transit time by well logging, µs/ft

x :

Exponent constant

S g :

Overburden pressure gradient, MPa/m

ρ b :

Bulk density of rock, kg/m3

K :

Permeability, mD

rfn:

Rock fabric number

Φ ip :

Interparticle porosity

S wi :

Initial water saturation

PHIE:

Effective porosity log

n, Φ :

Porosity, %

PHIT:

Total porosity log

ν d :

Dynamic Poisson’s ratio

E d :

Dynamic Young’s modulus, GPa

UCS:

Uniaxial compressive strength, MPa

σ t :

Tensile strength, MPa

φ :

Friction angle, °

NPHI:

Neutron porosity

V sh :

Shale volume

θ :

Angle between the normal to the fracture plane of and σ1, °

GR:

Gamma ray

σ n :

Normal stress, MPa

τ :

Shear stress, MPa

β1, β2, β3:

Angles between plane normal and the axes of σ1, σ2, and σ3, °

Ts:

Slip tendency

σ′n :

Effective normal stress, MPa

P C :

Critical pore pressure, MPa

q :

Slope of the σ′1 versus σ′3 line

T d :

Dilation tendency

σ′1, σ′3 :

The maximum and the minimum effective principal stresses, MPa

k :

Hydraulic conductivity, m/s

σ′ni :

Effective normal stress on the fault plane (prior to gas injection), MPa

P pi :

Initial pore pressure of the reservoir (prior to gas injection), MPa

P pmax :

The maximum sustainable pore pressure due to gas injection, MPa

σ′nf :

Effective normal stress at the failure point, MPa

ΔP p :

The maximum pore pressure increase needed for fault reactivation, MPa

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Acknowledgements

The authors gratefully acknowledge the National Iranian South Oil Company (NISOC) for sharing the data. We hereby acknowledge that some parts of the numerical computations were performed on the HPC center of the Ferdowsi University of Mashhad. We would also like to thank Dr. Mohsen Ezati from SeaLand Engineering and Well Services Company for his valuable guidance.

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Authors and Affiliations

  1. Department of Geology, Faculty of Science, Ferdowsi University of Mashhad, Mashhad, Iran

    Majid Taghipour, Mohammad Ghafoori, Gholam Reza Lashkaripour & Nasser Hafezi Moghaddas

  2. National Iranian South Oil Company (NISOC), Ahwaz, Iran

    Abdullah Molaghab

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  1. Majid Taghipour
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  3. Gholam Reza Lashkaripour
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Taghipour, M., Ghafoori, M., Lashkaripour, G.R. et al. A Geomechanical Evaluation of Fault Reactivation Using Analytical Methods and Numerical Simulation. Rock Mech Rock Eng 54, 695–719 (2021). https://doi.org/10.1007/s00603-020-02309-7

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