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.

scholarly journals In Situ Stress Prediction in Subsurface Rocks: An Overview and a New Method

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-11
Author(s):  
Yushuai Zhang ◽  
Shangxian Yin ◽  
Jincai Zhang
Keyword(s):  
Horizontal Stress ◽  
In Situ Stress ◽  
New Method ◽  
Alternative Methods ◽  
Tensile Fracture ◽  
In Situ Stresses ◽  
Stress Estimation ◽  
Minimum Horizontal Stress ◽  
Polygon Method

Methods for determining in situ stresses are reviewed, and a new approach is proposed for a better prediction of the in situ stresses. For theoretically calculating horizontal stresses, horizontal strains are needed; however, these strains are very difficult to be obtained. Alternative methods are presented in this paper to allow an easier way for determining horizontal stresses. The uniaxial strain method is oversimplified for the minimum horizontal stress determination; however, it is the lower bound minimum horizontal stress. Based on this concept, a modified stress polygon method is proposed to obtain the minimum and maximum horizontal stresses. This new stress polygon is easier to implement and is more accurate to determine in situ stresses by narrowing the area of the conventional stress polygon when drilling-induced tensile fracture and wellbore breakout data are available. Using the generalized Hooke’s law and coupling pore pressure and in situ stresses, a new method for estimating the maximum horizontal stress is proposed. Combined it to the stress polygon method, a reliable in situ stress estimation can be obtained. The field measurement method, such as minifrac test, is also analyzed in different stress regimes to determine horizontal stress magnitudes and calibrate the proposed theoretical method. The proposed workflow combined theoretical methods to field measurements provides an integrated approach for horizontal stress estimation.

scholarly journals In Situ Stress and Stress Regime in the Onshore Part of the Northeast Java Basin

2021 ◽  
Vol 44 (2) ◽  
pp. 95-105
Author(s):  
Agus M. Ramdhan
Keyword(s):  
Petroleum Industry ◽  
Horizontal Stress ◽  
In Situ Stress ◽  
Vertical Stress ◽  
Stress Regime ◽  
Severe Erosion ◽  
Tectonically Active ◽  
Minimum Horizontal Stress ◽  
Maximum Horizontal Stress

In situ stress is importance in the petroleum industry because it will significantly enhance our understanding of present-day deformation in a sedimentary basin. The Northeast Java Basin is an example of a tectonically active basin in Indonesia. However, the in situ stress in this basin is still little known. This study attempts to analyze the regional in situ stress (i.e., vertical stress, minimum and maximum horizontal stresses) magnitude and orientation, and stress regime in the onshore part of the Northeast Java Basin based on twelve wells data, consist of density log, direct/indirect pressure test, and leak-off test (LOT) data. The magnitude of vertical (  and minimum horizontal (  stresses were determined using density log and LOT data, respectively. Meanwhile, the orientation of maximum horizontal stress  (  was determined using image log data, while its magnitude was determined based on pore pressure, mudweight, and the vertical and minimum horizontal stresses. The stress regime was simply analyzed based on the magnitude of in situ stress using Anderson’s faulting theory. The results show that the vertical stress ( ) in wells that experienced less erosion can be determined using the following equation: , where  is in psi, and z is in ft. However, wells that experienced severe erosion have vertical stress gradients higher than one psi/ft ( . The minimum horizontal stress ( ) in the hydrostatic zone can be estimated as, while in the overpressured zone, . The maximum horizontal stress ( ) in the shallow and deep hydrostatic zones can be estimated using equations: and , respectively. While in the overpressured zone, . The orientation of  is ~NE-SW, with a strike-slip faulting stress regime.

Valuation of hydraulic fracturing potentials of organic-rich shales from the Anambra basin using rock mechanical properties from wireline logs

2021 ◽  
Vol 19 (3) ◽  
pp. 45-44
Author(s):  
Homa Viola Akaha-Tse ◽  
Michael Oti ◽  
Selegha Abrakasa ◽  
Charles Ugwu Ugwueze
Keyword(s):  
Mechanical Properties ◽  
Hydraulic Fracturing ◽  
Horizontal Stress ◽  
Shale Formations ◽  
In Situ Stresses ◽  
Anambra Basin ◽  
Wireline Logs ◽  
Rock Mechanical Properties ◽  
Minimum Horizontal Stress

This study was carried out to determine the rock mechanical properties relevant for hydrocarbon exploration and production by hydraulic  fracturing of organic rich shale formations in Anambra basin. Shale samples and wireline logs were analysed to determine the petrophysical, elastic, strength and in-situ properties necessary for the design of a hydraulic fracturing programme for the exploitation of the shales. The results obtained indicated shale failure in shear and barreling under triaxial test conditions. The average effective porosity of 0.06 and permeability of the order of 10-1 to 101 millidarcies showed the imperative for induced fracturing to assure fluid flow. Average Young’s modulus and Poisson’s ratio of about 2.06 and 0.20 respectively imply that the rocks are favourable for the formation and propagation of fractures during hydraulic fracking. The minimum horizontal stress, which determines the direction of formation and growth of artificially induced hydraulic fractures varies from wellto-well, averaging between 6802.62 to 32790.58 psi. The order of variation of the in-situ stresses is maximum horizontal stress>vertical stress>minimum horizontal stress which implies a reverse fault fracture regime. The study predicts that the sweet spots for the exploration and development of the shale-gas are those sections of the shale formations that exhibit high Young’s modulus, low Poisson’s ratio, and high brittleness. The in-situ stresses required for artificially induced fractures which provide pore space for shale gas accumulation and expulsion are adequate. The shales possess suitable mechanical properties to fracture during hydraulic fracturing. Application of these results will enhance the potentials of the onshore Anambra basin as a reliable component in increasing Nigeria’s gas reserves, for the improvement of the nation’s economy and energy security. Key Words: Hydraulic Fracturing, Organic-rich Shales, Rock Mechanical Properties, Petrophysical Properties, Anambra Basin

Hydraulic fracturing experiment at the University of Regina Campus

1986 ◽  
Vol 23 (4) ◽  
pp. 548-555 ◽  
Author(s):  
J. D. McLennan ◽  
H. S. Hasegawa ◽  
J -C Roegiers ◽  
Alan M. Jessop
Keyword(s):  
Hydraulic Fracturing ◽  
Stress Component ◽  
Horizontal Stress ◽  
Depth Range ◽  
Precambrian Basement ◽  
Breakdown Pressure ◽  
Overburden Pressure ◽  
Minimum Horizontal Stress ◽  
The University

A hydraulic fracturing stress determination was carried out during May and June, 1979, in a water well intended for the Geothermal Feasibility Project on the campus of the University of Regina, Saskatchewan. Four intervals between depths of 2062 and 2215 m were fractured successfully, one in the Winnipeg Formation (2034–2083 m), two in the Deadwood Formation (2083–2209 m), and one under the Phanerozoic sequence near the top of the Precambrian basement (2209–2215 m).Over the depth range (2062–2215 m) covered by this hydrofracture experiment, the results and inferences are as follow. Downhole breakdown pressure ranges from 42 to 45 MPa, and downhole shut-in pressure from 35 to 42 MPa. The minimum horizontal stress component, σhmin, is taken as being equal to the corresponding shut-in pressure. The vertical stress component, σv, is assumed to be essentially equal to the overburden pressure and varies from 51 to 56 MPa. Whereas σv and σhmin apparently vary smoothly across the Deadwood Formation, the maximum horizontal component, σhmax, appears to undergo a discontinuity in the upper part of the Deadwood Formation, as σHMAX varies from 40 MPa in the Winnipeg Formation to 53 MPa in the upper part of the Precambrian basement. In so far as seismotectonics is concerned, the physical implications of these measurements are that normal faulting should prevail in the Winnipeg (and overlying) formations whereas strike-slip faulting could occur in the Precambrian basement; however, the latter inference has not been firmly established. Breakdown pressure is a useful guide (upper limit) for the potential geothermal demonstration project. Key words: hydraulic fracture, fracture mechanics, faulting, stresses, in situ, breakdown, shut-in pressure, seismotectonics.

scholarly journals In Situ Stress and Stress Regime in the Onshore Part of the Northeast Java Basin

2021 ◽  
Vol 44 (2) ◽  
pp. 83-95
Author(s):  
Agus M. Ramdhan
Keyword(s):  
Petroleum Industry ◽  
Horizontal Stress ◽  
In Situ Stress ◽  
Vertical Stress ◽  
Stress Regime ◽  
Severe Erosion ◽  
Tectonically Active ◽  
Minimum Horizontal Stress ◽  
Maximum Horizontal Stress

In situ stress is importance in the petroleum industry because it will significantly enhance our understanding of present-day deformation in a sedimentary basin. The Northeast Java Basin is an example of a tectonically active basin in Indonesia. However, the in situ stress in this basin is still little known. This study attempts to analyze the regional in situ stress (i.e., vertical stress, minimum and maximum horizontal stresses) magnitude and orientation, and stress regime in the onshore part of the Northeast Java Basin based on twelve wells data, consist of density log, direct/indirect pressure test, and leak-off test (LOT) data. The magnitude of vertical (  and minimum horizontal (  stresses were determined using density log and LOT data, respectively. Meanwhile, the orientation of maximum horizontal stress  (  was determined using image log data, while its magnitude was determined based on pore pressure, mudweight, and the vertical and minimum horizontal stresses. The stress regime was simply analyzed based on the magnitude of in situ stress using Anderson’s faulting theory. The results show that the vertical stress ( ) in wells that experienced less erosion can be determined using the following equation: , where  is in psi, and z is in ft. However, wells that experienced severe erosion have vertical stress gradients higher than one psi/ft ( . The minimum horizontal stress ( ) in the hydrostatic zone can be estimated as, while in the overpressured zone, . The maximum horizontal stress ( ) in the shallow and deep hydrostatic zones can be estimated using equations: and , respectively. While in the overpressured zone, . The orientation of  is ~NE-SW, with a strike-slip faulting stress regime.

Predicting the azimuth of natural fractures and in-situ horizontal stress: A case study from Sichuan Basin, China

Geophysics ◽  
2021 ◽  
pp. 1-97
Author(s):  
kai lin ◽  
Bo Zhang ◽  
Jianjun Zhang ◽  
Huijing Fang ◽  
Kefeng Xi ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Seismic Data ◽  
Sichuan Basin ◽  
Horizontal Stress ◽  
Seismic Attributes ◽  
Seismic Events ◽  
Natural Fractures ◽  
Microseismic Data ◽  
Maximum Horizontal Stress

The azimuth of fractures and in-situ horizontal stress are important factors in planning horizontal wells and hydraulic fracturing for unconventional resources plays. The azimuth of natural fractures can be directly obtained by analyzing image logs. The azimuth of the maximum horizontal stress σH can be predicted by analyzing the induced fractures on image logs. The clustering of micro-seismic events can also be used to predict the azimuth of in-situ maximum horizontal stress. However, the azimuth of natural fractures and the in-situ maximum horizontal stress obtained from both image logs and micro-seismic events are limited to the wellbore locations. Wide azimuth seismic data provides an alternative way to predict the azimuth of natural fractures and maximum in-situ horizontal stress if the seismic attributes are properly calibrated with interpretations from well logs and microseismic data. To predict the azimuth of natural fractures and in-situ maximum horizontal stress, we focus our analysis on correlating the seismic attributes computed from pre-stack and post-stack seismic data with the interpreted azimuth obtained from image logs and microseismic data. The application indicates that the strike of the most positive principal curvature k1 can be used as an indicator for the azimuth of natural fractures within our study area. The azimuthal anisotropy of the dominant frequency component if offset vector title (OVT) seismic data can be used to predict the azimuth of maximum in-situ horizontal stress within our study area that is located the southern region of the Sichuan Basin, China. The predicted azimuths provide important information for the following well planning and hydraulic fracturing.

PRESENT-DAY STATE-OF-STRESS OF SOUTHEAST AUSTRALIA

2006 ◽  
Vol 46 (1) ◽  
pp. 283 ◽  
Author(s):  
E. Nelson ◽  
R. Hillis ◽  
M. Sandiford ◽  
S. Reynolds ◽  
S. Mildren
Keyword(s):  
Focal Mechanism ◽  
Horizontal Stress ◽  
Strike Slip ◽  
Focal Mechanism Solutions ◽  
Southeast Australia ◽  
State Of Stress ◽  
Earthquake Focal Mechanism ◽  
Minimum Horizontal Stress ◽  
Maximum Horizontal Stress ◽  
Gippsland Basin

There have been several studies, both published and unpublished, of the present-day state-of-stress of southeast Australia that address a variety of geomechanical issues related to the petroleum industry. This paper combines present-day stress data from those studies with new data to provide an overview of the present-day state-of-stress from the Otway Basin to the Gippsland Basin. This overview provides valuable baseline data for further geomechanical studies in southeast Australia and helps explain the regional controls on the state-of-stress in the area.Analysis of existing and new data from petroleum wells reveals broadly northwest–southeast oriented, maximum horizontal stress with an anticlockwise rotation of about 15° from the Otway Basin to the Gippsland Basin. A general increase in minimum horizontal stress magnitude from the Otway Basin towards the Gippsland Basin is also observed. The present-day state-of-stress has been interpreted as strike-slip in the South Australian (SA) Otway Basin, strike-slip trending towards reverse in the Victorian Otway Basin and borderline strike-slip/reverse in the Gippsland Basin. The present-day stress states and the orientation of the maximum horizontal stress are consistent with previously published earthquake focal mechanism solutions and the neotectonic record for the region. The consistency between measured present-day stress in the basement (from focal mechanism solutions) and the sedimentary basin cover (from petroleum well data) suggests a dominantly tectonic far-field control on the present-day stress distribution of southeast Australia. The rotation of the maximum horizontal stress and the increase in magnitude of the minimum horizontal stress from west to east across southeast Australia may be due to the relative proximity of the New Zealand segment of the plate boundary.

Laboratory evaluation of K0 for overconsolidated clays

1991 ◽  
Vol 28 (5) ◽  
pp. 650-659 ◽  
Author(s):  
Vinod K. Garga ◽  
Mahbubul A. Khan
Keyword(s):  
Axial Stress ◽  
Axial Strain ◽  
Stress Path ◽  
Horizontal Stress ◽  
In Situ Stress ◽  
Laboratory Method ◽  
Laboratory Evaluation ◽  
Triaxial Apparatus ◽  
Overconsolidated Clays

Most of the laboratory testing methods available for the evaluation of in situ horizontal stresses are applicable to normally consolidated or lightly overconsolidated clays. This paper describes a new laboratory method for the determination of in situ horizontal stresses of heavily overconsolidated clays using a stress-path triaxial apparatus. The proposed method is based on the concept that if the radial stress exceeds the in situ horizontal stress, while maintaining the axial stress constant and equal to the in situ vertical effective stress, only then will the sample experience significant axial strain. The results obtained for undisturbed samples of an overconsolidated clay crust are found to be in agreement with some available methods. For verification of the applicability of the proposed method, K0 was determined for artificially prepared samples that had been subjected to known stress paths simulating field stress history. Key words: K0, overconsolidation, in situ stress, in situ test, clay crust, laboratory test.

The Effect of Geological and Geomechanical Parameters on Reservoir Stress Path and Its Importance in Studying Permeability Anisotropy

2000 ◽  
Vol 3 (05) ◽  
pp. 394-400 ◽  
Author(s):  
M. Khan ◽  
L.W. Teufel
Keyword(s):  
Boundary Condition ◽  
Pore Pressure ◽  
Effective Stress ◽  
Stress Path ◽  
Horizontal Stress ◽  
Uniaxial Strain ◽  
Reservoir Conditions ◽  
Permeability Anisotropy ◽  
Sandstone Reservoirs

Summary Reservoir stress path is defined as the ratio of change in effective horizontal stress to the change in effective vertical stress from initial reservoir conditions during pore-pressure drawdown. Measured stress paths of carbonate and sandstone reservoirs are always less than the total stress boundary condition (isotropic loading) and are either greater or less than the stress path predicted by the uniaxial strain boundary condition. Clearly, these two boundary-condition models that are commonly used by the petroleum industry to calculate changes in effective stresses in a reservoir and to measure reservoir properties in the laboratory are inaccurate and can be misleading if applied to reservoir management problems. A geomechanical model that incorporates geologic and geomechanical parameters was developed to more accurately predict the reservoir stress path. Numerical results show that reservoir stress path is dependent on the size and geometry of the reservoir and on elastic properties of the reservoir rock and bounding formations. In general, stress paths become lower as the aspect ratio of reservoir length to thickness increases. Lenticular sandstone reservoirs have a higher stress path than blanket sandstone reservoirs that are continuous across a basin. This effect is enhanced when the bounding formations have a lower elastic modulus than the reservoir and when the reservoir is transversely isotropic. In addition, laboratory experiments simulating reservoir depletion for different stress path conditions demonstrate that stress-induced permeability anisotropy evolves during pore-pressure drawdown. The maximum permeability direction is parallel to the maximum principal stress and the magnitude of permeability anisotropy increases at lower stress paths. Introduction Matrix permeability and pore volume compressibility are fundamentally important characteristics of hydrocarbon reservoirs because they provide measures of reservoir volume and reservoir producibility. Laboratory studies have shown that these properties are stress sensitive and are usually measured under hydrostatic (isotropic) loads that do not truly reflect the anisotropic stress state that exists in most reservoirs and do not adequately simulate the evolution of deviatoric stresses in a reservoir as the reservoir is produced. Recent laboratory studies1–3 have shown that permeability and compressibility are dependent on the deviatoric stress and change significantly with reservoir stress path. In-situ stress measurements in carbonate and clastic reservoirs indicate that the reservoir stress path is not isotropic loading (equal to 1.0) and can range from 0.14 to 0.76. 4 The measured reservoir stress paths are also inconsistent with the elastic uniaxial strain model5 commonly used to calculate horizontal stress and changes in horizontal stress with pore-pressure drawdown. The calculated uniaxial strain stress path can be significantly less or greater than the measured stress path.4 Knowledge of the stress path that reservoir rock will follow during production and how this stress path will affect reservoir properties is critical for reservoir management decisions necessary to increase reservoir producibility. However, in-situ stress measurements needed to determine reservoir stress path are difficult and expensive to conduct, and may take several years to collect. Various analytical models have been proposed to calculate in-situ horizontal stresses and they could be applied to the prediction of reservoir stress path during pore-pressure drawdown.5–9 However, none of these models addresses all of the essential geological and geomechanical factors that influence reservoir stress path, such as reservoir size and geometry or the coupled mechanical interaction between the reservoir and the bounding formations. Accordingly, a geomechanical model was developed to more accurately predict reservoir stress path. The model incorporates essential geological and geomechanical factors that may control reservoir stress path during production. In addition, laboratory results showing the effect of reservoir stress path on permeability and permeability anisotropy in a low-permeability sandstone are also presented. These experiments clearly demonstrate that during pore-pressure drawdown permeability decreases and that permeability parallel and perpendicular to the maximum stress direction decreases at different rates. The smallest reduction in permeability is parallel to the maximum principal stress. Consequently, stress-induced permeability anisotropy evolves with pore-pressure drawdown and the magnitude of permeability anisotropy increases at lower stress paths. Field Measurements of Stress Path in Lenticular Sandstone Reservoirs Salz10 presented hydraulic fracture stress data and pore-pressure measurements from reservoir pressure build-up tests in low-permeability, lenticular, gas sandstones of the Vicksburg formation in the McAllen Ranch field, Texas (Table 1). This work was one of the first studies to clearly show that the total minimum horizontal stress is dependent on the pore pressure. Hydraulic fractures were completed in underpressured and overpressured sandstone intervals from approximately 3100 to 3800 m. Some of the sandstones (9A, 10A, 11A, 12A, 13A, and 14A) were later hydraulically fractured a second time to improve oil productivity after several years of production. For initial reservoir conditions before production, the total minimum horizontal stress shows a decrease with decreasing pore pressure for different sandstone reservoirs. The effective stress can also be determined from these data. Following Rice and Cleary11 effective stress is defined by σ = S − α P , ( 1 ) where ? is the effective stress, S is the total stress, ? is a poroelastic parameter, and P is the pore pressure. For this study ? is assumed to equal unity. A linear regression analysis of the minimum horizontal and vertical effective stress data shows that at initial reservoir conditions the ratio of change in minimum effective horizontal stress to the change in effective vertical stress with increasing depth and pore pressure is 0.50.

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