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.

Lithology-controlled stress variations and pad-scale faults: A case study of hydraulic fracturing in the Woodford Shale, Oklahoma

Geophysics ◽  
2017 ◽  
Vol 82 (6) ◽  
pp. ID35-ID44 ◽  
Author(s):  
Xiaodong Ma ◽  
Mark D. Zoback
Keyword(s):  
Hydraulic Fracturing ◽  
Horizontal Wells ◽  
Horizontal Stress ◽  
Strike Slip ◽  
Woodford Shale ◽  
Stress Regime ◽  
Component Content ◽  
Microseismic Events ◽  
Minimum Horizontal Stress ◽  
Stress Variations

We have conducted an integrated study to investigate the petrophysical and geomechanical factors controlling the effectiveness of hydraulic fracturing (HF) in four subparallel horizontal wells in the Mississippi Limestone-Woodford Shale (MSSP-WDFD) play in Oklahoma. In two MSSP wells, the minimum horizontal stress [Formula: see text] indicated by the instantaneous shut-in pressures of the HF stages are significantly less than the vertical stress [Formula: see text]. This, combined with observations of drilling-induced tensile fractures in the MSSP in a vertical well at the site, indicates that this formation is in a normal/strike-slip faulting stress regime, consistent with earthquake focal mechanisms and other stress indicators in the area. However, the [Formula: see text] values are systematically higher and vary significantly from stage to stage in two WDFD wells. The stages associated with the abnormally high [Formula: see text] values (close to [Formula: see text]) were associated with little to no proppant placement and a limited number of microseismic events. We used compositional logs to determine the content of compliant components (clay and kerogen). Due to small variations in the trajectories of the horizontal wells, they penetrated three thin, but compositionally distinct WDFD lithofacies. We found that [Formula: see text] along the WDFD horizontals increases when the stage occurred in a zone with high clay and kerogen content. These variations of [Formula: see text] can be explained by various degrees of viscous stress relaxation, which results in the increase in [Formula: see text] (less stress anisotropy), as the compliant component content increases. The distribution of microseismic events was also affected by normal and strike-slip faults cutting across the wells. The locations of these faults were consistent with unusual lineations of microseismic events and were confirmed by 3D seismic data. Thus, the overall effectiveness of HF stimulation in the WDFD wells at this site was strongly affected the abnormally high HF gradients in clay-rich lithofacies and the presence of preexisting, pad-scale faults.

A Novel Method to Determine the Drilling Fluid Density for Gypsum-Salt Layer

2021 ◽  
Author(s):  
Jitong Liu ◽  
Wanjun Li ◽  
Haiqiu Zhou ◽  
Yixin Gu ◽  
Fuhua Jiang ◽  
...  
Keyword(s):  
Drilling Fluid ◽  
In Situ Stress ◽  
Wellbore Stability ◽  
Shrinkage Rate ◽  
Fluid Density ◽  
Salt Layer ◽  
Rock Creep ◽  
Key Factor ◽  
Well Abandonment

Abstract The reservoir underneath the salt bed usually has high formation pressure and large production rate. However, downhole complexities such as wellbore shrinkage, stuck pipe, casing deformation and brine crystallization prone to occur in the drilling and completion of the salt bed. The drilling safety is affected and may lead to the failure of drilling to the target reservoir. The drilling fluid density is the key factor to maintain the salt bed’s wellbore stability. The in-situ stress of the composite salt bed (gypsum-salt -gypsum-salt-gypsum) is usually uneven distributed. Creep deformation and wellbore shrinkage affect each other within layers. The wellbore stability is difficult to maintain. Limited theorical reference existed for drilling fluid density selection to mitigate the borehole shrinkage in the composite gypsum-salt layers. This paper established a composite gypsum-salt model based on the rock mechanism and experiments, and a safe-drilling density selection layout is formed to solve the borehole shrinkage problem. This study provides fundamental basis for drilling fluid density selection for gypsum-salt layers. The experiment results show that, with the same drilling fluid density, the borehole shrinkage rate of the minimum horizontal in-situ stress azimuth is higher than that of the maximum horizontal in-situ stress azimuth. However, the borehole shrinkage rate of the gypsum layer is higher than salt layer. The hydration expansion of the gypsum is the dominant reason for the shrinkage of the composite salt-gypsum layer. In order to mitigate the borehole diameter reduction, the drilling fluid density is determined that can lower the creep rate less than 0.001, as a result, the borehole shrinkage of salt-gypsum layer is slowed. At the same time, it is necessary to improve the salinity, filter loss and plugging ability of the drilling fluid to inhibit the creep of the soft shale formation. The research results provide technical support for the safe drilling of composite salt-gypsum layers. This achievement has been applied to 135 wells in the Amu Darya, which completely solved the of wellbore shrinkage problem caused by salt rock creep. Complexities such as stuck string and well abandonment due to high-pressure brine crystallization are eliminated. The drilling cycle is shortened by 21% and the drilling costs is reduced by 15%.

Geomechanical Approach in Classification of Borehole Failures in Fractured Carbonates of Boca De Jaruco Field

2021 ◽  
Author(s):  
Anna Vladimirovna Norkina ◽  
Iaroslav Olegovich Simakov ◽  
Yuriy Anatoljevich Petrakov ◽  
Alexey Evgenjevich Sobolev ◽  
Oleg Vladimirovich Petrashov ◽  
...  
Keyword(s):  
Stress State ◽  
Horizontal Wells ◽  
Horizontal Stress ◽  
In Situ Stress ◽  
Vertical Wells ◽  
Stress Regime ◽  
Geophysical Information ◽  
The Republic ◽  
Maximum Horizontal Stress

Abstract This article is a continuation of the work on geomechanically calculations for optimizing the drilling of horizontal wells into the productive reservoir M at the Boca de Haruco field of the Republic of Cuba, presented in the article SPE-196897. As part of the work, an assessment of the stress state and direction was carried out using geological and geophysical information, an analysis of the pressure behavior during steam injections, cross-dipole acoustics, as well as oriented caliper data in vertical wells. After the completion of the first part of the work, the first horizontal wells were successfully drilled into the M formation. According to the recommendations, additional studies were carried out: core sampling and recording of micro-imager logging in the deviated sections. Presence of wellbore failures at the inclined sections allowed to use the method of inverse in-situ stress modeling based on image logs interpretation. The classification of wellbore failures by micro-imager logging: natural origin and violations of technogenic genesis is carried out. The type of breakout is defined. The result of the work was the determination of the stress state and horizontal stresses direction. In addition, the article is supplemented with the calculation of the maximum horizontal stress through the stress regime identifier factor.

scholarly journals Geomechanical Analysis to Avoid Serious Drilling Hazards in Zubair Oilfield, Southern Iraq

2020 ◽  
pp. 1994-2003
Author(s):  
Shaban Dharb Shaban ◽  
Hassan Abdul Hadi
Keyword(s):  
Gamma Ray ◽  
Mechanical Test ◽  
Horizontal Wells ◽  
Failure Criteria ◽  
Horizontal Stress ◽  
Wellbore Instability ◽  
Geomechanical Analysis ◽  
Safe Mud Window ◽  
Rock Mechanical Properties ◽  
Minimum Horizontal Stress

Zubair oilfield is an efficient contributor to the total Iraqi produced hydrocarbon. Drilling vertical wells as well as deviated and horizontal wells have been experiencing intractable challenges. Investigation of well data showed that the wellbore instability issues were the major challenges to drill in Zubair oilfield. These experienced borehole instability problems are attributed to the increase in the nonproductive time (NPT). This study can assist in managing an investment-drilling plan with less nonproductive time and more efficient well designing.       To achieve the study objectives, a one dimension geomechanical model (1D MEM) was constructed based on open hole log measurements, including Gamma-ray (GR), Caliper (CALI), Density (RHOZ), sonic compression (DTCO) and shear (DTSM) wave velocities , and Micro imager log (FMI). The determined 1D MEM components, i.e., pore pressure, rock mechanical properties, in-situ principal stress magnitudes and orientations, were calibrated using the data acquired from repeated formation test (RFT), hydraulic fracturing test (Mini-frac), and laboratory rock core mechanical test (triaxial test). Then, a validation model coupled with three failure criteria, i.e., Mohr-Coulomb, Mogi-Coulomb, and Modified lade, was conducted using the Caliper and Micro-imager logs. Finally, sensitivity and forecasting stability analyses were implemented to predict the most stable wellbore trajectory concerning the safe mud window for the planned wells.    The implemented wellbore instability analysis utilizing Mogi-Coulomb criterion demonstrated that the azimuth of 140o paralleling to the minimum horizontal stress is preferable to orient deviated and horizontal wells. The vertical and slightly deviated boreholes (1ess than 30o) are the most stable wellbores, and they are recommended to be drilled with 11.6 -12 ppg mud weight. The highly deviated and horizontal wells are recommended to be drilled with a mud weight of 12-12.6 ppg.

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.

THE OTWAY BASIN: EARLY CRETACEOUS RIFTING TO NEOGENE INVERSION

1995 ◽  
Vol 35 (1) ◽  
pp. 494 ◽  
Author(s):  
A.J. Buffin ◽  
A.J. Sutherland ◽  
J.A. Gorski
Keyword(s):  
Stress Field ◽  
Normal Fault ◽  
Horizontal Wells ◽  
Horizontal Stress ◽  
Natural Fracture ◽  
Water Flooding ◽  
Hydraulic Fractures ◽  
Vertical Wells ◽  
Minimum Horizontal Stress ◽  
Maximum Horizontal Stress

Borehole breakouts and hydraulic fractures in­ferred from dipmeter and formation microscanner logs indicate that the minimum horizontal stress (σh) is oriented 035°N in the South Australian sector of the Otway Basin. Density and sonic check-shot log data indicate that vertical stress (σv) increases from approximately 20 MPa at a depth of one km to 44 MPa at two km and 68 MPa at three km. Assum­ing a normal fault condition (i.e. σy > σH > σh), the magnitude of σh is 75 per cent of the magnitude of the maximum horizontal stress (σH), and the magni­tude of σH is close to that of av. Sonic velocity compaction trends for shales suggest that pore pressure is generally near hydrostatic in the Otway Basin.Knowledge of the contemporary stress field has a number of implications for hydrocarbon produc­tion and exploration in the basin. Wellbore quality in vertical wells may be improved (breakouts sup­pressed) by increasing the mud weight to a level below that which induces hydraulic fracture, or other drilling problems related to excessive mud weight. Horizontal wells drilled in the σh direction (035°N/215°N) should be more stable than those drilled in the σH direction, and indeed than vertical wells. In any EOR operations where water flooding promotes hydraulic fracturing, injectors should be aligned in the aH (125°N/305°N) direction, and off­set from producers in the orthogonal σh direction. Any deviated/horizontal wells targeting the frac­tured basement play should be oriented in the σh (035°N/215°N) direction to maximise intersection with this open, natural fracture trend. Hydrocar­bon recovery in wells deviated towards 035°N/215°N may also be enhanced by inducing multiple hydrau­lic fractures along the wellbore.Considering exploration-related issues, faults following the dominant structural trend, sub-paral­lel to σH orientation, are the most prone to be non-sealing during any episodic build-up of pore pres­sure. Pre-existing vertical faults striking 080-095°N and 155-170°N are the most prone to at least a component of strike-slip reactivation within the contemporary stress field.

A Geomechanical Model and Workflow for Calibrating Elastic Moduli and Min/Max Horizontal Stress from Well Logs in the Nahr Umr Shale

2021 ◽  
Author(s):  
Michael Alexander Shaver ◽  
Gilles Pierre Michel Segret ◽  
Denya Pratama Yudhia ◽  
Suhail Mohammed Al Ameri ◽  
Erwan Couziqou ◽  
...  
Keyword(s):  
Pore Pressure ◽  
Drilling Fluid ◽  
Well Logging ◽  
Wellbore Stability ◽  
Rock Properties ◽  
Lateral Strain ◽  
Fluid Density ◽  
Geomechanical Model ◽  
Stability Problems ◽  
Stress Models

Abstract Thin layering and micro-fracturing of the thin laminated layers are some possible reasons for the wellbore stability problems of the Nahr Umr shale. If the drilling fluid density is too low, collapsing of the borehole is possible, and if the drilling fluid density is too high, invasion of the shale can occur, weakening the shale, making boreholes prone to instability. These effects can be semi-quantified and assessed through the development of a geomechanical model. The application of a geomechanical model of a reservoir and overlaying formations can be very useful for addressing ways to select a sweet spot and optimize the completion and development of a reservoir. The geomechanical model also provides a sound basis for addressing unforeseen drilling and borehole stability problems that are encountered during the life cycle of a reservoir. Key components of any geomechanical model are the principal stresses at depth: overburden, minimum horizontal principle stress, and maximum horizontal principle stress. These determine the existing tectonic fault regime: normal, strike-slip, and reverse. Additional components of a geomechanical model are pore pressure, unconfined compressive strength (UCS) rock strength, tilted anisotropy, and fracture and faults from image logs and seismic. Unfortunately, models used to make continuous well logging depth-based stress predictions involve some parameters that are derived from laboratory tests, fracture injection tests, and the actual fracturing of a well—all contributing to the uncertainty of the model predictions. This paper addresses ways to obtain these key parameter components of the geomechanical model from well logging data calibrated to ancillary data. It is shown how stress, UCS, and pore pressure prediction and interpretation can be improved by developing and applying models using wellbore acoustic, triple combo, and borehole image data calibrated to laboratory and field measurements. The nahr umr shale and other organic mudstone formations exhibit vertical transverse isotropic (VTI) anisotropy in the sense that rock properties are different in the vertical and horizontal directions (assuming non-tilted flatbed layering), the horizontal acoustic velocity is different from that of vertical velocity. This necessitates the building of anisotropic moduli and stress models. The anisotropic stress models require lateral strain, which as shown in the paper, can be obtained from micro-frac tests and/or borehole breakout data.

Application of Real-Time Geomechanical Modeling to Prevent Wellbore Instability While Drilling Horizontal Wells with Extended Reservoir Contact

2021 ◽  
Author(s):  
Ernesto Gomez Samuel Gomez ◽  
Raider Rivas ◽  
Ebikebena Ombe ◽  
Sajjad Ahmed
Keyword(s):  
Real Time ◽  
Planning Process ◽  
Horizontal Wells ◽  
Gas Production ◽  
Wellbore Stability ◽  
Productivity Index ◽  
Rock Properties ◽  
Wellbore Instability ◽  
Hydrocarbon Reservoir ◽  
Cap Rock

Abstract Background Drilling deviated and horizontal high-pressure, high-temperature (HPHT) wells is associated with unique drilling challenges, especially when formation heterogeneity, variation in formation thickness as well as formation structural complexities are encountered while drilling. One of the major challenges encountered is the difficulty of landing horizontal lateral within the thin reservoir layers. Geomechanical modeling has proven to be a vital tool in optimizing casing setting depths and significantly increasing the possible lateral length within hydrocarbon bearing reservoirs. This approach ultimately enhanced the production output of the wells. In a particular field, the horizontal wells are constructed by first drilling 8 3/8" hole section to land about 5 to 10’ into the impervious cap rock just above the target reservoir. The 7" casing is then run and cemented in place, after which the horizontal hole section, usually a 5 7/8" lateral, is drilled by geosteered within the target reservoir to access its best porosity and permeability. Due to the uncertainty of the cap rock thickness, setting the 7" liner at this depth was necessary to avoid drilling too deep into the cap rock and penetrating the target reservoir. This approach has its disadvantages, especially while drilling the 5-7/8" lateral. Numerous drilling challenges were encountered while drilling the horizontal lateral across the hard cap rock. like severe wellbore instability, low ROP and severe drillstring vibration. To mitigate the challenges mentioned above, geomechanical modelling was introduced into the well planning process to optimize the 8 3/8" hole landing depth within the cap rock, thereby reducing the hard caprock interval to be drilled in the next section. Firstly, actual formation properties and in-situ rock stress data were obtained from logs taken in previously drilled wells in the field. This information was then fed into in the geomechanical models to produce near accurate rock properties and stresses values. Data from the formation fracture strength database was also used to calibrate the resulting horizontal stresses and formation breakdown pressure. In addition to this, the formation pore pressure variability was established with the measured formation pressure data. The porosity development information was also used to determine the best landing depths to isolate and case-off the nonreservoir formations. Combined with in-depth well placement studies to determine the optimal well trajectory and wellbore landing strategy, geomechanical modelling enabled the deepening of the 8 3/8" landing depth without penetrating the hydrocarbon reservoir. The geomechanical models were also updated with actual well data in real time and allowed for the optimization of mud weight on the fly. This strategy minimized near wellbore damage across the reservoir section and ultimately improved the wells productivity index. Deepening of the 8 3/8" landing depth and minimizing the footage drilled across the hard and unstable caprock positively impacted the overall well delivery process from well planning and drilling operations up to production. The following achievements were realized in recent wells where geomechanical modelling was applied: The initiative helped in drilling more stable, in-gauge holes across the reservoir sections, which were less prone to wellbore stability problems during drilling and logging operations.Downhole drilling tools were less exposed to harsh drilling conditions and delivered higher performance along with longer drilling runs.Better hole quality facilitated the running of multistage fracture completions which, in turn, contributed to increase the overall gas production, fulfilling the objectives of the reservoir development team.The net-to-gross ratio of the pay zone was increased, thereby improving the efficiency of the multistage fracture stages, and allowing the reservoir to be produced more efficiently.

Design of Horizontal Wellbore in Dadas Shales of Turkey by Considering Wellbore Stability and Reservoir Geomechanics

2021 ◽  
Author(s):  
Sukru Merey ◽  
Can Polat ◽  
Tuna Eren
Keyword(s):  
Hydraulic Fracturing ◽  
Horizontal Well ◽  
Oil And Gas ◽  
Horizontal Wells ◽  
Horizontal Stress ◽  
Wellbore Stability ◽  
Horizontal Drilling ◽  
Horizontal Wellbore ◽  
Reservoir Geomechanics ◽  
Maximum Horizontal Stress

Abstract Currently, many horizontal wells are being drilled in Dadas shales of Turkey. Dadas shales have both oil (mostly) and gas potentials. Thus, hydraulic fracturing operations are being held to mobilize hydrocarbons. Up to 1000 m length horizontal wells are drilled for this purpose. However, there is not any study analyzing wellbore stability and reservoir geomechanics in the conditions of Dadas shales. In this study, the directions of horizontal wells, wellbore stability and reservoir geomechanics of Dadas shales were designed by using well log data. In this study, the python code developed by using Kirsch equations was developed. With this python code, it is possible to estimate unconfined compressive strength in along wellbore at different deviations. By analyzing caliper log, density and porosity logs of Dadas shales, vertical stress of Dadas shales was estimated and stress polygon for these shale was prepared in this study. Then, optimum direction of horizontal well was suggested to avoid any wellbore stability problems. According to the results of this study, high stresses are seen in horizontal directions. In this study, it was found that the maximum horizontal stress in almost the direction of North-South. The results of this study revealed that direction of maximum horizontal stress and horizontal well direction fluid affect the wellbore stability significantly. Thus, in this study, better horizontal well design was made for Dadas shales. Currently, Dadas shales are popular in Turkey because of its oil and gas potential so horizontal drilling and hydraulic fracturing operations are being held. However, in literature, there is no study about horizontal wellbore designs for Dadas shales. This study will be novel and provide information about the horizontal drilling design of Dadas shales.

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