scholarly journals Constraining tectonic components during a geomechanics-aided successful hydrofracturing campaign of tight gas exploration field

2021 ◽  
Author(s):  
Rajeev Ranjan Kumar ◽  
Menno Mathieu Molenaar ◽  
Surej Kumar Subbiah
Keyword(s):  
Tensile Strength ◽  
Fracture Initiation ◽  
Horizontal Stress ◽  
Fracture Analysis ◽  
Wellbore Stability ◽  
Stress Profile ◽  
Strain Component ◽  
Tight Gas ◽  
Horizontal Strain ◽  
Regional Tectonics

AbstractThe horizontal stress profile plays an important role, extending from wellbore stability analysis to well completion optimization of tight gas reservoirs. When considering exploration fields with planned wells being drilled to 5500-m TVD, it is imperative to quantify tectonic effects at the well location. In addition, accurately predicting stress profile and fracture initiation values in vertical wells is required to identify sweet zones and barriers. This paper presents the details of a pre-fracture geomechanical model using breakouts and advanced acoustic data for post-fracture analysis. The analysis contains a history match of fracture initiation pressure, which consider the effects of filter cake around permeable sand, variation in tensile strength, and quantification of horizontal stress contrast in the different fields. Overall, three reservoirs have been analyzed, each containing more than eight wells with operations history. Core tests were used to calibrate dynamic-to-static rock elastic and mechanical properties, both of which reduced uncertainty in the model. The poroelastic horizontal strain method was used to build a continuous stress profile. Typically, the rock fabric found in the cores, images, and anisotropy data from the three reservoirs is different and required various dynamic-to static conversions. The Aeolian deposits-based reservoir has a wide variation in horizontal stress, and fracture height is typically governed by the stiffness of the layers. The lower permeability zones have relatively higher tensile strength, compared with higher permeability zones leading to relatively higher fracture initiation values. Overall, the ratio of maximum horizontal stress-to-minimum horizontal stress varies between 1.20 and 1.28 based on post-fracture analysis, which correlates well with regional tectonics and structural data. Depending on lithological variation and structure changes, the horizontal strain component varies at the layer level within regional tectonics. Inversion of fracturing data helped to constrain horizontal strain and stress variations in the field.

Effect of Layered Heterogeneity on Fracture Initiation in Tight Gas Shales

2006 ◽  
Author(s):  
Roberto Suarez-Rivera ◽  
Sidney J. Green ◽  
John McLennan ◽  
Mao Bai
Keyword(s):  
Fracture Initiation ◽  
Tight Gas ◽  
Gas Shales

Beyond Volumetrics: Unconventional Petrophysics for Efficient Resource Appraisal (Example from the Khazzan Field, Sultanate of Oman)

2015 ◽  
Author(s):  
David R. Spain ◽  
German D. Merletti ◽  
William Dawson
Keyword(s):  
Gas Permeability ◽  
Stress Profile ◽  
Tight Gas ◽  
Well Performance ◽  
Flow Properties ◽  
Dynamic Flow ◽  
Stress Regime ◽  
Flow Units ◽  
Fluid Saturation ◽  
Rock Typing

Abstract The Middle East region holds substantial resources of unconventional tight gas and shale gas. The efficient extraction of these resources requires significant technology and expertise across numerous disciplines, including reservoir description and geomechanical characterization, hydraulic fracture modelling and design, advanced numerical simulation capabilities, sensor and surveillance technologies, and tightly integrated workflows. The effective application of these integrated subsurface and completion workflows leads to improved capital efficiency and well performance through increased well potential, increased ultimate recovery, and reduced costs. Key elements include dynamic rock typing to highlight potential flow units that will maximize gas deliverability, geomechanical modelling to provide a calibrated stress profile, and an integrated model that demonstrates the importance of understanding both dynamic flow properties and geomechanical response in complex tectonic environments. Dynamic rock typing focuses on using both depositional and petrophysical properties including rock type, porosity, and effective gas permeability at reservoir conditions to divide the reservoir into flow units in the context of their saturation history. The geomechanical profiling generates a tectonics-corrected minimum horizontal stress (SHmin) and the net confining stress (NCS). The rock-log-test calibration requires the evaluation and integration of subsurface fracture tests, including After-Closure Analysis (ACA), Data Fracs and Micro Fracs. All three involve different injection volumes and sampled reservoir volumes. Tight gas petrophysical studies must go “beyond volumetrics”, and should consider not only the static (storage) and dynamic (flow) properties within the context of the petroleum system and evolution of the current day pore geometry and fluid saturation distribution, but also the geomechanical stress regime and its implications for efficient completion optimization. Alternative interpretations test the range of uncertainty and are useful in designing field trials and surveillance strategies to reduce the subsurface uncertainty and to mitigate development risks.

A Novel Method and its Application to Define Maximum Horizontal Stress and Stress Path

2021 ◽  
Author(s):  
Jianguo Zhang ◽  
Karthik Mahadev ◽  
Stephen Edwards ◽  
Alan Rodgerson
Keyword(s):  
Fracture Initiation ◽  
Stress Path ◽  
Horizontal Stress ◽  
Geomechanical Model ◽  
Breakdown Pressure ◽  
In Situ Stresses ◽  
Fracture Closure ◽  
Minimum Horizontal Stress ◽  
Maximum Horizontal Stress

Abstract Maximum horizontal stress (SH) and stress path (change of SH and minimum horizontal stress with depletion) are the two most difficult parameters to define for an oilfield geomechanical model. Understanding these in-situ stresses is critical to the success of operations and development, especially when production is underway, and the reservoir depletion begins. This paper introduces a method to define them through the analysis of actual minifrac data. Field examples of applications on minifrac failure analysis and operational pressure prediction are also presented. It is commonly accepted that one of the best methods to determine the minimum horizontal stress (Sh) is the use of pressure fall-off analysis of a minifrac test. Unlike Sh, the magnitude of SH cannot be measured directly. Instead it is back calculated by using fracture initiation pressure (FIP) and Sh derived from minifrac data. After non-depleted Sh and SH are defined, their apparent Poisson's Ratios (APR) are calculated using the Eaton equation. These APRs define Sh and SH in virgin sand to encapsulate all other factors that influence in-situ stresses such as tectonic, thermal, osmotic and poro-elastic effects. These values can then be used to estimate stress path through interpretation of additional minifrac data derived from a depleted sand. A geomechanical model is developed based on APRs and stress paths to predict minifrac operation pressures. Three cases are included to show that the margin of error for FIP and fracture closure pressure (FCP) is less than 2%, fracture breakdown pressure (FBP) less than 4%. Two field cases in deep-water wells in the Gulf of Mexico show that the reduction of SH with depletion is lower than that for Sh.

Geomechanical Model as the Key Step to Proppant Fracturing Success in Shallow Carbonate Reservoir of Bahrain

2021 ◽  
Author(s):  
Ahmed AlJanahi ◽  
Feras Altawash ◽  
Hassan AlMannai ◽  
Sayed Abdelredy ◽  
Hamed Al Ghadhban ◽  
...  
Keyword(s):  
High Resolution ◽  
Horizontal Wells ◽  
Carbonate Reservoir ◽  
Rock Properties ◽  
Stress Profile ◽  
Geomechanical Model ◽  
Breakdown Pressure ◽  
Matrix Permeability ◽  
Geomechanical Analysis ◽  
Horizontal Strain

Abstract Geomechanics play an important role in stimulation design, especially in complex tight reservoirs with very low matrix permeability. Robust modelling of stresses along with rock mechanical properties helps to identify the stress barriers which are crucial for optimum stimulation design and proppant allocation. Complex modeling and calibration workflow showcased the value of geomechanical analysis in a large stimulation project in the Ostracod-Magwa reservoir, a complicated shallow carbonate reservoir in the Bahrain Field. For the initial model, regional average rock properties and minimum stress values from earlier frack campaigns were considered. During campaign progression, advanced cross dipole sonic measurements of the new wells were incorporated in the geomechanical modeling which provided rock properties and stresses with improved confidence. The outputs from wireline-conveyed microfrac tests and the fracturing treatments were also considered for calibration of the minimum horizontal stress and breakdown pressure. The porepressure variability was established with the measured formation pressure data. The geomechanically derived horizontal stresses were used as input for the frack-design. Independent fracture geometry measurements were run to validate the model. The poro-elastic horizontal strain approach was taken to model the horizontal stresses, which shows better variability of the stress profile depending on the elastic rock properties. The study shows variable depletion in porepressure across the field as well as within different reservoir layers. The Ostracod reservoir is more depleted than Magwa, with porepressure values lower than hydrostatic (∼7 ppg). The B3 shale layer in between the Magwa and Ostracod reservoirs is a competent barrier with 1200-1500psi closure pressure. The closure pressures in the Ostracod and Magwa vary from 1000-1500psi and 1100-1600psi, respectively. There is a gradual increasing trend observed in closure pressure in Magwa with depth, but no such trend is apparent in the shallower Ostracod formation. High resolution stress profiles help to identify the barriers within each reservoir to place horizontal wells and quantify the magnitude of hydraulic fracture stress barriers along horizontal wells. The geomechanical model served as a key part of the fracturing optimization workflow, resulting in more than double increase in wells productivity compared to previous stimulation campaigns. The study also helped to optimize the selection of the clusters depth of hydraulic fracturing stages in horizontal wells. The poroelastic horizontal strain approach to constrain horizontal stresses from cross dipole sonic provides better variability in the stress profile to ultimately yield high resolution. This model, calibrated with actual frac data, is crucial for stimulation design in complex reservoirs with very low matrix permeability. The geomechanical model serves as one of the few for shallow carbonates rock in the Middle East region and can be of significant importance to many other shallow projects in the region.

scholarly journals Numerical Simulation of Rock Failure Process with a 3D Grain-Based Rock Model

2020 ◽  
Vol 2020 ◽  
pp. 1-11
Author(s):  
Zengwei Zhang ◽  
Fan Chen ◽  
Chao Zhang ◽  
Chao Wang ◽  
Tuo Wang ◽  
...  
Keyword(s):  
Numerical Simulation ◽  
Tensile Strength ◽  
Compressive Strength ◽  
Mechanical Characteristics ◽  
Failure Process ◽  
Wellbore Stability ◽  
Rock Excavation ◽  
Rock Failure Process ◽  
Rock Model ◽  
Walled Cylinder

A grain-based rock model was developed and applied to study mechanical characteristics and failure micromechanics in thick-walled cylinder and wellbore stability tests. The rock is represented as an assembly of tetrahedral blocks with bonded contacts. Material heterogeneity is modeled by varying the tensile strength at the block contacts. This grain-based rock model differs from previous disk/sphere particle-based rock models in its ability to represent a zero (or very low) initial porosity condition, as well as highly interlocked irregular block shapes that provide resistance to movement even after contact breakage. As a result, this model can reach higher uniaxial compressive strength to tensile strength ratios and larger friction coefficients than the disk/sphere particle-based rock model. The model captured the rock fragmentation process near the wellbore due to buckling and spalling. Thin fragments of rock similar to onion skins were produced, as observed in laboratory breakout experiments. The results suggest that this approach may be well suited to study the rock disaggregation process and other geomechanical problems in the rock excavation.

Results of hydraulic fracturing design improvements and changes in execution strategies for unconventional tight gas targets in the Cooper Basin, Australia

2019 ◽  
Vol 59 (1) ◽  
pp. 244
Author(s):  
Raymond Johnson Jr ◽  
Ruizhi Zhong ◽  
Lan Nguyen
Keyword(s):  
Machine Learning ◽  
Hydraulic Fracturing ◽  
Horizontal Stress ◽  
Learning Model ◽  
Hydraulic Fractures ◽  
Tight Gas ◽  
Machine Learning Model ◽  
Wellbore Pressure ◽  
Gas Targets ◽  
Cooper Basin

Tight gas stimulations in the Cooper Basin have been challenged by strike–slip to reverse stress regimes, adversely affecting the hydraulic fracturing treatment. These stress conditions increase borehole breakout and affect log and cement quality, create more tortuous pathways and near-wellbore pressure loss, and reduce fracture containment. These factors result in stimulation of lower permeability, low modulus intervals (e.g. carbonaceous shales and interbedded coals) versus targeted tight gas sands. In the Windorah Trough of the Cooper Basin, several steps have been employed in an ongoing experiment to improve hydraulic fracturing results. First, the wellbore was deviated in the maximum horizontal stress direction and perforations shot 0 to 180° phased to better align the resulting hydraulic fractures. Next, existing drilling and logging-while-drilling data were used to train a machine learning model to improve reservoir characterisation in sections with missing or poor log data. Finally, diagnostic fracture injection tests in non-pay and pay sections were targeted to specifically inform the machine learning model and better constrain permeability and stress profiles. It is envisaged that the improved well and perforation alignment and better targeting of intervals for the fracturing treatment will result in lowered tortuosity, better fracture containment, and higher concentrations of localised proppant, thereby improving conductivity and targeting of desired intervals. The authors report the process and results of their experimentation, and the results relative to the offsetting vertical well where a typical five-stage treatment was employed.

Time-Dependent Initiation of Multiple Hydraulic Fractures in a Formation With Varying Stresses and Strength

SPE Journal ◽  
2015 ◽  
Vol 20 (06) ◽  
pp. 1317-1325 ◽  
Author(s):  
Andrew P. Bunger ◽  
Guanyi Lu
Keyword(s):  
Tensile Strength ◽  
Hydraulic Fracture ◽  
Fracture Initiation ◽  
Time Frame ◽  
Hydraulic Fractures ◽  
Static Fatigue ◽  
Breakdown Pressure ◽  
Initiation Point ◽  
Delayed Failure ◽  
Wellbore Pressure

Summary The premise of classical hydraulic-fracture-breakdown models is that hydraulic-fracture growth can only start when the wellbore pressure reaches a critical value that is sufficient to overcome the tensile strength of the rock. However, rocks are well-known to exhibit static fatigue; that is, delayed failure at stresses less than the tensile strength. In this paper, we explore the consequences of delayed failure on axially oriented initiation of multiple hydraulic fractures. Specifically, given a certain breakdown pressure, we investigate the conditions under which subsequent hydraulic fracture(s) can begin within the time frame of a stimulation treatment in regions of higher stress and/or strength because of delayed-failure mechanisms. The results show that wells completed in shallower formations are more sensitive to variations in strength, whereas wells completed in deeper formations are more sensitive to variations in stress. Furthermore, cases in which all hydraulic fractures break down according to the same pressurization regime—that is, all are “fast” (nonfluid-penetrating) pressurization or else all are “slow” (uniformly pressurized fluid-penetrating) pressurization cases—are highly sensitive to small stress/strength variability. On the other hand, if the first hydraulic-fracture initiation is in the “fast”-pressurization regime and subsequent fracture(s) are in the “slow”-pressurization regime, then the system is robust to a much-higher degree of variability in stress/strength. Practically, this work implies that methods aimed at moderately reducing the variability in stress/strength among the possible initiation points (i.e., perforation clusters) within a particular stage can have a strong effect on whether multiple hydraulic fractures will begin. In addition, this analysis implies that pumping strategies that encourage “fast,” nonpenetrative breakdown of the first initiation point followed by the opportunity for fluid-penetrating, “slow” breakdown of subsequent initiation points could be effective at encouraging multiple-hydraulic-fracture initiation.

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