Optimized Drilling Fluid and Tailored Drilling Practices Help Successfully Drill and Complete Wells Along the Minimum Horizontal Stress Direction in Khuff Reservoirs

2018 ◽  
Author(s):  
Mohamed Hegazy ◽  
Sunil Sharma ◽  
Khaled Fares ◽  
Alok Dave
Keyword(s):  
Drilling Fluid ◽  
Horizontal Stress ◽  
Stress Direction ◽  
Minimum Horizontal Stress

Real-Time Wellbore Stability and Hole Quality Evaluation Using LWD Azimuthal Photoelectric Measurements

2021 ◽  
Author(s):  
Khaqan Khan ◽  
Mohammad Altwaijri ◽  
Ahmed Taher ◽  
Mohamed Fouda ◽  
Mohamed Hussein
Keyword(s):  
Real Time ◽  
Drilling Fluid ◽  
Horizontal Wells ◽  
Horizontal Stress ◽  
Wellbore Stability ◽  
Fluid Density ◽  
Stress Regime ◽  
Borehole Breakout ◽  
Photoelectric Measurements ◽  
Minimum Horizontal Stress

Abstract Horizontal and high-inclination deep wells are routinely drilled to enhance hydrocarbon recovery. To sustain production rates, these wells are generally designed to be drilled in the direction of minimum horizontal stress in strike slip stress regime to facilitate transverse fracture growth during fracturing operations. These wells can also cause wellbore instability challenges due to high stress concentration due to compressional or strike-slip stress regimes. Hence, apart from pre-drill wellbore stability analysis for an optimum mud weight design, it is important to continuously monitor wellbore instability indicators during drilling. With the advancements of logging-while-drilling (LWD) techniques, it is now possible to better assess wellbore stability during drilling and, if required, to take timely decisions and adjust mud weight to help mitigate drilling problems. The workflow for safely drilling deep horizontal wells starts with analyzing the subsurface stress regime using data from offset wells. Through a series of steps, data is integrated to develop a geomechanics model to select an optimum drilling-fluid density to maintain wellbore stability while minimizing the risks of differential sticking and mud losses. Due to potential lateral subsurface heterogeneity, continuous monitoring of drilling events and LWD measurements is required, to update and calibrate the pre-well model. LWD measurements have long been used primarily for petrophysical analysis and well placement in real time. The use of azimuthal measurements for real-time wellbore stability evaluation applications is a more recent innovation. Shallow formation density readings using azimuthal LWD measurements provide a 360° coverage of wellbore geometry, which can be effectively used to identify magnitude and orientation of borehole breakout at the wellbore wall. Conventional LWD tools also provide auxiliary azimuthal measurements, such as photoelectric (Pe) measurement, derived from the near detector of typical LWD density sensors. The Pe measurement, with a very shallow depth of investigation (DOI), is more sensitive to small changes in borehole shape compared with other measurements from the same sensor, particularly where a high contrast exists between drilling mud and formation Pe values. Having azimuthal measurements of both Pe and formation density while drilling facilitates better control on assess wellbore stability assessment in real time and make decisions on changes in mud density or drilling parameters to keep wellbore stable and avoid drilling problems. Time dependency of borehole breakout can also be evaluated using time-lapse data to enhance analysis and reduce uncertainty. Analyzing LWD density and Pe azimuthal data in real time has guided real-time decisions to optimize drilling fluid density while drilling. The fluid density indicated by the initial geo-mechanical analysis has been significantly adjusted, enabling safe drilling of deep horizontal wells by minimizing wellbore breakouts. Breakouts identified by LWD density and photoelectric measurements has been further verified using wireline six-arm caliper logs after drilling. Contrary to routinely used density image, this paper presents use of Pe image for evaluating wellbore stability and quality in real time, thereby improving drilling safety and completion of deep horizontal wells drilled in the minimum horizontal stress direction.

Tunnel Ground Stress Test and Rock Burst Prediction Based on Hydraulic Fracturing Method

2013 ◽  
Vol 368-370 ◽  
pp. 1830-1837
Author(s):  
Xin Zhe Li ◽  
Geng Feng Wang ◽  
Jun Mei Li
Keyword(s):  
Hydraulic Fracturing ◽  
Rock Burst ◽  
Stress Test ◽  
Large Angle ◽  
Horizontal Stress ◽  
Stress Direction ◽  
Ground Stress ◽  
The Stability ◽  
Minimum Horizontal Stress ◽  
Maximum Horizontal Stress

The hydraulic fracturing method is a common method to measure the ground stress. This article describes the principles of the hydraulic fracturing method, studies the distribution and the value of the ground stress in a tunnel area with the hydraulic fracturing method, and predicts rock burst by using the Russenes discriminance and the Turchaninov discriminance. The results show that the maximum horizontal stress is between 4.7MPa and 11.1MPa, and the minimum horizontal stress is between 4.0MPa and 8.0MPa. The maximum horizontal stress direction of the drilling is between N63 °W and N72 °W, and it is not conducive to the stability of the tunnel surrounding rocks because the large angle intersection of the tunnel axis direction and the maximum horizontal stress direction.

Diagnostic Plots of Pressure Transient, Rate-Transient, and Diagnostic Fracture-Injection/Falloff Tests

2021 ◽  
Author(s):  
David Craig ◽  
Thomas Blasingame
Keyword(s):  
Flow Regimes ◽  
Horizontal Stress ◽  
Test Theory ◽  
Pressure Transient ◽  
Diagnostic Plots ◽  
Diagnostic Plot ◽  
New Ideas ◽  
Characteristic Features ◽  
Pressure Transient Test ◽  
Minimum Horizontal Stress

Abstract All transient test interpretation methods rely on or utilize diagnostic plots for the identification of wellbore or fracture storage distortion, flow regimes, and other parameters (e.g., minimum horizontal stress). Although all "test" interpretations of interest are transient test data (i.e., those involving an "event"), the associated diagnostic plots are not interchangeable between such tests. The objective of this work is to clearly define the appropriate diagnostic plot(s) for each type of transient test. The work applies the appropriate transient test theory to demonstrate the applicability of each diagnostic plot along with clearly defining the characteristic features that make a given plot "diagnostic." For pressure transient testing, the material is largely a review, but for rate transient tests and diagnostic fracture-injection/falloff tests, new ideas are introduced and documented to justify appropriate diagnostic plots. Data examples are provided for illustration and application. In general, pressure transient test diagnostic plots are not misused, but the same cannot be said for diagnostic fracture-injection/falloff tests (or DFITs) where it is common to ascribe flow regimes and/or draw other erroneous conclusions based on observations from an inappropriately constructed or interpretated diagnostic plot. The examples provided illustrate both the correct diagnostic plot and interpretations, but also illustrate how data can be easily misinterpreted in common practice.

Geodynamic implications of the Cenozoic stress field on Seymour Island, West Antarctica

2008 ◽  
Vol 20 (2) ◽  
pp. 173-184 ◽  
Author(s):  
A. Maestro ◽  
J. López-Martínez ◽  
F. Bohoyo ◽  
M. Montes ◽  
F. Nozal ◽  
...  
Keyword(s):  
Stress Field ◽  
Antarctic Peninsula ◽  
Horizontal Stress ◽  
Weddell Sea ◽  
Scotia Sea ◽  
Compressional Stress ◽  
The North ◽  
Stress States ◽  
Bransfield Basin ◽  
Minimum Horizontal Stress

AbstractPalaeostress inferred from brittle mesostructures in Seymour (Marambio) Island indicates a Cenozoic to Recent origin for an extensional stress field, with only local compressional stress states. Minimum horizontal stress (σ3) orientations are scattered about two main NE–SW and NW–SE modes suggesting that two stress sources have been responsible for the dominant minimum horizontal stress directions in the north-western Weddell Sea. Extensional structures within a broad-scale compressional stress field can be linked to both the decrease in relative stress magnitudes from active margins to intraplate regions and the rifting processes that occurred in the northern Weddell Sea. Stress states with NW–SE trending σ3are compatible with back-arc extension along the eastern Antarctic Peninsula. We interpret this as due to the opening of the Larsen Basin during upper Cretaceous to Eocene and to the spreading, from Pliocene to present, of the Bransfield Basin (western Antarctic Peninsula), both due to former Phoenix Plate subduction under the Antarctic Plate. NE–SW σ3orientations could be expressions of continental fragmentation of the northern Antarctic Peninsula controlling eastwards drifting of the South Orkney microcontinent and other submerged continental blocks of the southern Scotia Sea.

scholarly journals Rupture Directivity in 3D Inferred From Acoustic Emissions Events in a Mine-Scale Hydraulic Fracturing Experiment

2021 ◽  
Vol 9 ◽  
Author(s):  
José Ángel López-Comino ◽  
Simone Cesca ◽  
Peter Niemz ◽  
Torsten Dahm ◽  
Arno Zang
Keyword(s):  
Hydraulic Fracturing ◽  
Acoustic Emissions ◽  
Local Stress ◽  
Horizontal Stress ◽  
Monitoring Networks ◽  
Rupture Directivity ◽  
Shallow Subsurface ◽  
Minimum Horizontal Stress ◽  
Directivity Effects ◽  
Full Waveforms

Rupture directivity, implying a predominant earthquake rupture propagation direction, is typically inferred upon the identification of 2D azimuthal patterns of seismic observations for weak to large earthquakes using surface-monitoring networks. However, the recent increase of 3D monitoring networks deployed in the shallow subsurface and underground laboratories toward the monitoring of microseismicity allows to extend the directivity analysis to 3D modeling, beyond the usual range of magnitudes. The high-quality full waveforms recorded for the largest, decimeter-scale acoustic emission (AE) events during a meter-scale hydraulic fracturing experiment in granites at ∼410 m depth allow us to resolve the apparent durations observed at each AE sensor to analyze 3D-directivity effects. Unilateral and (asymmetric) bilateral ruptures are then characterized by the introduction of a parameter κ, representing the angle between the directivity vector and the station vector. While the cloud of AE activity indicates the planes of the hydrofractures, the resolved directivity vectors show off-plane orientations, indicating that rupture planes of microfractures on a scale of centimeters have different geometries. Our results reveal a general alignment of the rupture directivity with the orientation of the minimum horizontal stress, implying that not only the slip direction but also the fracture growth produced by the fluid injections is controlled by the local stress conditions.

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.

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