Pore pressure and stress regime in a thick extensional basin with active shale diapirism (western Mediterranean)

AAPG Bulletin ◽  
2017 ◽  
Vol 101 (02) ◽  
pp. 233-264 ◽  
Author(s):  
Fermín Fernández-Ibáñez ◽  
Juan I. Soto
Keyword(s):  
Pore Pressure ◽  
Western Mediterranean ◽  
Stress Regime ◽  
Extensional Basin ◽  
Shale Diapirism

scholarly journals The Messinian Salinity Crisis as a trigger for high pore pressure development in the Western Mediterranean

2021 ◽  
Author(s):  
Michael S. Dale ◽  
Héctor Marín‐Moreno ◽  
Ismael Himar Falcon‐Suarez ◽  
Carlos Grattoni ◽  
Jonathan M. Bull ◽  
...  
Keyword(s):  
Pore Pressure ◽  
Western Mediterranean ◽  
Messinian Salinity Crisis ◽  
Pressure Development

Joint Application of Diagenetic, Petrophysical and Geomechanical Data for Selecting Hydraulic Fracturing Candidate Zone

2021 ◽  
Vol 8 ◽  
pp. 55-79
Author(s):  
E. Bakhshi ◽  
A. Shahrabadi ◽  
N. Golsanami ◽  
Sh. Seyedsajadi ◽  
X. Liu ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Pore Pressure ◽  
Earth Model ◽  
Reservoir Properties ◽  
Stress Regime ◽  
Geomechanical Properties ◽  
Hydrocarbon Reservoir ◽  
Diagenetic Processes ◽  
Mechanical Earth Model ◽  
New Equation

The more comprehensive information on the reservoir properties will help to better plan drilling and design production. Herein, diagenetic processes and geomechanical properties are notable parameters that determine reservoir quality. Recognizing the geomechanical properties of the reservoir as well as building a mechanical earth model play a strong role in the hydrocarbon reservoir life cycle and are key factors in analyzing wellbore instability, drilling operation optimization, and hydraulic fracturing designing operation. Therefore, the present study focuses on selecting the candidate zone for hydraulic fracturing through a novel approach that simultaneously considers the diagenetic, petrophysical, and geomechanical properties. The diagenetic processes were analyzed to determine the porosity types in the reservoir. After that, based on the laboratory test results for estimating reservoir petrophysical parameters, the zones with suitable reservoir properties were selected. Moreover, based on the reservoir geomechanical parameters and the constructed mechanical earth model, the best zones were selected for hydraulic fracturing operation in one of the Iranian fractured carbonate reservoirs. Finally, a new empirical equation for estimating pore pressure in nine zones of the studied well was developed. This equation provides a more precise estimation of stress profiles and thus leads to more accurate decision-making for candidate zone selection. Based on the results, vuggy porosity was the best porosity type, and zones C2, E2 and G2, having suitable values of porosity, permeability, and water saturation, showed good reservoir properties. Therefore, zone E2 and G2 were chosen as the candidate for hydraulic fracturing simulation based on their E (Young’s modulus) and ν (Poisson’s ratio) values. Based on the mechanical earth model and changes in the acoustic data versus depth, a new equation is introduced for calculating the pore pressure in the studied reservoir. According to the new equation, the dominant stress regime in the whole well, especially in the candidate zones, is SigHmax>SigV>Sighmin, while according to the pore pressure equation presented in the literature, the dominant stress regime in the studied well turns out to be SigHmax>Sighmin>SigV.  

scholarly journals Static and dynamic effective stress coefficient of chalk

Geophysics ◽  
2012 ◽  
Vol 77 (2) ◽  
pp. L1-L11 ◽  
Author(s):  
M. Monzurul Alam ◽  
Ida Lykke Fabricius ◽  
Helle Foged Christensen
Keyword(s):  
Pore Pressure ◽  
Effective Stress ◽  
Mechanical Strain ◽  
Mechanical Tests ◽  
Differential Stress ◽  
Stress Regime ◽  
Hydrocarbon Reservoir ◽  
Stress Coefficient ◽  
The Difference ◽  
Stress Dependent

Deformation of a hydrocarbon reservoir can ideally be used to estimate the effective stress acting on it. The effective stress in the subsurface is the difference between the stress due to the weight of the sediment and a fraction (effective stress coefficient) of the pore pressure. The effective stress coefficient is thus relevant for studying reservoir deformation and for evaluating 4D seismic for the correct pore pressure prediction. The static effective stress coefficient [Formula: see text] is estimated from mechanical tests and is highly relevant for effective stress prediction because it is directly related to mechanical strain in the elastic stress regime. The corresponding dynamic effective stress coefficient [Formula: see text] is easy to estimate from density and velocity of acoustic (elastic) waves. We studied [Formula: see text] and [Formula: see text] of chalk from the reservoir zone of the Valhall field, North Sea, and found that [Formula: see text] and [Formula: see text] vary with differential stress (overburden stress-pore pressure). For Valhall reservoir chalk with 40% porosity, [Formula: see text] ranges between 0.98 and 0.85 and decreases by 10% if the differential stress is increased by 25 MPa. In contrast, for chalk with 15% porosity from the same reservoir, [Formula: see text] ranges between 0.85 and 0.70 and decreases by 5% due to a similar increase in differential stress. Our data indicate that [Formula: see text] measured from sonic velocity data falls in the same range as for [Formula: see text], and that [Formula: see text] is always below unity. Stress-dependent behavior of [Formula: see text] is similar (decrease with increasing differential stress) to that of [Formula: see text] during elastic deformation caused by pore pressure buildup, for example, during waterflooding. By contrast, during the increase in differential stress, as in the case of pore pressure depletion due to production, [Formula: see text] increases with stress while [Formula: see text] decreases.

scholarly journals Geomechanical Analysis for Deep Shale Gas Exploration Wells in the NDNR Blocks, Sichuan Basin, Southwest China

Energies ◽  
2020 ◽  
Vol 13 (5) ◽  
pp. 1117 ◽  
Author(s):  
Majia Zheng ◽  
Hongming Tang ◽  
Hu Li ◽  
Jian Zheng ◽  
Cui Jing
Keyword(s):  
Pore Pressure ◽  
Shale Gas ◽  
Sichuan Basin ◽  
In Situ Stress ◽  
Wellbore Stability ◽  
Geomechanical Model ◽  
Stress Regime ◽  
Xujiahe Formation ◽  
Geomechanical Analysis

The abundant reserve of shale gas in Sichuan Basin has become a significant natural gas component in China. To achieve efficient development of shale gas, it is necessary to analyze the stress state, pore pressure, and reservoir mechanical properties such that an accurate geomechanical model can be established. In this paper, Six wells of Neijiang-Dazu and North Rongchang (NDNR) Block were thoroughly investigated to establish the geomechanical model for the study area. The well log analysis was performed to derive the in-situ stresses and pore pressure while the stress polygon was applied to constrain the value of the maximum horizontal principal stress. Image and caliper data, mini-frac test and laboratory rock mechanics test results were used to calibrate the geomechanical model. The model was further validated by comparing the model prediction against the actual wellbore failure observed in the field. It was found that it is associated with the strike-slip (SS) stress regime; the orientation of SHmax was inferred to be 106–130° N. The pore pressure appears to be approximately hydrostatic from the surface to 1000 m true vertical depth (TVD), but then becomes over-pressured from the Xujiahe formation. The geomechanical model can provide guidance for the subsequent drilling and completion in this area and be used to effectively avoid complex drilling events such as collapse, kick, and lost circulation (mud losses) along the entire well. Also, the in-situ stress and pore pressure database can be used to analyze wellbore stability issues as well as help design hydraulic fracturing operations.

Modeling Time-Dependent Pore Pressure Due to Capillary and Chemical Potential Effects and Resulting Wellbore Stability in Shales

2003 ◽  
Vol 125 (3) ◽  
pp. 169-176 ◽  
Author(s):  
M. K. Rahman ◽  
Zhixi Chen ◽  
Sheik S. Rahman
Keyword(s):  
Pore Pressure ◽  
Chemical Potential ◽  
Normal Fault ◽  
Wellbore Stability ◽  
Time Dependent ◽  
Analytical Models ◽  
Analysis Model ◽  
Stress Regime ◽  
Dependent Change ◽  
Drilling Operations

During drilling operations, the mud filtrate interacts with the pore fluid around the wellbore and changes pore pressure by capillary and chemical potential effects. Thus the change in pore pressure around borehole becomes time-dependent, particularly in extremely low permeability shaley formations. In this paper, the change in pore pressure due to capillary and chemical potential effects are investigated experimentally. Analytical models are also developed based on the experimental results. A wellbore stability analysis model incorporating the time-dependent change in pore pressure is applied to a vertical well in a shale formation under normal fault stress regime.

scholarly journals Three-Dimensional Geomechanical Modeling and Analysis of Refracturing and “Frac-Hits” in Unconventional Reservoirs

Energies ◽  
2020 ◽  
Vol 13 (20) ◽  
pp. 5352 ◽  
Author(s):  
Shahla Masouleh ◽  
Dharmendra Kumar ◽  
Ahmad Ghassemi
Keyword(s):  
Pore Pressure ◽  
Horizontal Well ◽  
Dynamic Models ◽  
Three Dimensional ◽  
Hydraulic Fractures ◽  
Fluid Viscosity ◽  
Production Well ◽  
Total Stress ◽  
Stress Regime ◽  
The Impact

Field experience has demonstrated that infill well fractures tend to propagate towards the primary well, resulting in well-to-well interference, or so-called “frac-hits”. Frac-hits are a major concern in horizontal well refracturing because they adversely affect the productivity of both wells. This paper provides a 3D geomechanical study of the problem for the first time in order to better understand frac-hits in horizontal well refracturing and its mitigating solutions. To our knowledge, this is the only refracturing study focused on fracture mechanics and within the context of coupled proroelasticity using a single model. The modeling is based on the fully coupled 3D model, GeoFrac-3D, which is capable of simulating multistage fracturing of multiple horizontal wells. The model couples pore pressure to stresses, and makes it possible to create dynamic models of fracture propagation. The modeling results show that production from production well fractures leads to a nonuniform reduction of the reservoir pore pressure around the production well and in between fractures, leading to an anisotropic decrease of the total stress, potentially resulting in stress reorientation and/or reversal. The decrease in the total stress components in the vicinity of the production fractures creates an attraction zone for infill well hydraulic fractures. The infill well fractures tend to grow asymmetrically towards the lower stress zone. The risk of frac-hits and the impact on the “parent” and “infill” well production vary according to the reservoir stress regime, in situ stress anisotropy, and production time. By optimizing well and fracture spacing, fracturing fluid viscosity, and the timing of refracturing job, frac-hit problems can be minimized. The simulation results demonstrate that the risks of frac-hits can be potentially mitigated by repressurization of the production well fractures before fracturing the infill well.

Overburden characterization with formation pore pressure and anisotropic stress field estimation in the Athabasca Basin, Canada

2019 ◽  
Vol 7 (4) ◽  
pp. T761-T771
Author(s):  
Carmen C. Dumitrescu ◽  
Draga A. Talinga
Keyword(s):  
Pore Pressure ◽  
Elastic Stiffness ◽  
Seismic Inversion ◽  
Efficient Production ◽  
Oil Sand ◽  
Principal Stresses ◽  
Stress Regime ◽  
Athabasca Basin ◽  
Effective Principal ◽  
Formation Pore Pressure

One of the challenges encountered during the life cycle of an oil-sand thermal-production reservoir is the prediction of the formation pore pressure and in situ stress regime during the assessment phase of the reservoir development and, more importantly, during the development phase. We have investigated the state of formation pore pressure and stress in the overburden — represented by the Clearwater Formation, Grand Rapids Formation, and Colorado Group — of a preproduction oil-sands reservoir situated in the Athabasca Basin of Alberta, Canada. Our methodology integrates pressure data from piezometers, stress data from mini-frac (MF), dipole sonic logs, and elastic properties obtained from multicomponent 3D seismic inversion data. It combines the Terzaghi effective stresses with the Schoenberg and Sayers elastic stiffness matrix for horizontal transversely isotropic fractured materials. The total principal stresses (vertical, minimum, and maximum horizontal stresses) are expressed as functions of the normal fracture weakness (anisotropic correction factor), formation pore pressure, seismic data (Lamé constants), and the Biot-Willis coefficient. The effective principal stresses are estimated from the equivalent total principal stresses and the formation pore pressure multiplied by the Biot-Willis coefficient. On all three overburden intervals analysed, the relations between principal stresses indicate a normal stress regime. The estimated total minimum horizontal stress matches the MF values within 10%. The formation pore pressure, along with the 3D seismically derived estimates of the total and effective principal stresses, allows for better assessment of the caprock integrity and for operational savings based on a reduced number of MF tests. It can also be used for stress estimation within the formations hosting aquifers, which is so important for thermal production. Understanding the subsurface on the reservoir area is important for efficient production, but knowing the subsurface of the overburden is equally important for reducing potential issues due to production.

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