Proactive Decision-Making Through Real-Time Geomechanical Support Leveraging Drilling a Long Horizontal Section Through a Tight Unconventional Reservoir of an Oil and Gas Field: Middle East

2021 ◽  
Author(s):  
Sankhajit Saha ◽  
Prajit Chakrabarti ◽  
Johannes Vossen ◽  
Sourav Mitra ◽  
Tuhin Podder
Keyword(s):  
Stability Analysis ◽  
Gamma Ray ◽  
Horizontal Stress ◽  
Wellbore Stability ◽  
Drilling Fluids ◽  
Geomechanical Model ◽  
Well Location ◽  
Multi Stage ◽  
Minimum Horizontal Stress ◽  
Density Image

Abstract This paper discusses the Integrated Role of Geomechanics and Drilling Fluids Design for drilling a well oriented towards the minimum horizontal stress direction in a depleted, yet highly stressed and complex clastic reservoir. There are multiple challenges related to such a well that need to be addressed during the planning phase. In this case, the well needs to be drilled towards the minimum horizontal stress direction (Shmin) to benefit multi-stage hydraulic fracturing. At the same time, the most prominent challenge is that this well orientation is more prone to wellbore failure and requires a maximum mud weight, due to the present strike slip stress environment. Well planning challenges in such an environment include (a) the determination of formation characteristics and rock properties, (b) the anticipation of higher formation collapse pressure during the course of drilling the lateral section within the reservoir, (c) the determination of the upper bound mud weight to prevent lost circulation due to a low fracture gradient against depleted sections, or due to the presence of pre-existing natural fractures, d) mitigating the higher risk of differential sticking against depleted porous layers, and determining appropriate bridging in the drilling fluids, (e) recognizing the prolonged exposure time of the formation due to the length of the lateral and the lower rate of penetration against the tight highly dense formations. For successful drilling, and to mitigate the above risks, the first step is to prepare a predrill GeoMechanical model along with adequate fluid design and drillers action plans to be considered during drilling. Offset well petrophysical logs and core data are considered for the preparation of the predrill GeoMechanical model, along with the drilling experiences in the offset locations. Based on the above, a predrill GeoMechanical model is prepared, a risk matrix is being established, and a representative mud weight window is recommended (Wellbore Stability Analysis). In most cases, the offset well locations considered are vertical- or inclined-, or lateral wells of different trajectory azimuth than the target well location and the predrill GeoMechanical model can incorporate such variations easily; however, any Geology uncertainty, leading to a different rock property- and stress set-up (or even different pore pressure than expected), at the actual well location will be part of the uncertainty of the predrill GeoMechanical model and Wellbore Stability Analysis. This is where the real time monitoring is playing out its full potential: giving an updated model and wellbore stability analysis during drilling. While drilling the lateral section, the wellbore condition is being monitored using LWD (logging while drilling) tools, e.g. Gamma Ray, Density, Neutron, Acoustic Caliper, Azimuthal density image and ECD (equivalent circulating density). While gamma ray helps in determining the lithology, density logs help to understand the formation hardness, and they can be used to generate a calibrated pseudo acoustic log. Based on this pseudo acoustic log, the rock strength and other rock mechanical properties of the pre- GeoMechanical model can be updated as soon as they become available. This gives insight into the model differences and helps to understand model variations and adjust Wellbore Stability recommendations accordingly. While the neutron log helps to determine the zones of high porosity, and thus potential risk zones for differential sticking, the azimuthal density image clearly indicates the breakout zones caused by the shear failure of the wellbore. The presence of wellbore failure (breakout) is further confirmed by acoustic caliper data, and accordingly wellbore stability related recommendations are communicated to the operator, for an increase in the specific gravity of the mud, and thus, to balance the wellbore. From a mud rheology perspective, high performance OBM (oil-based mud) parameters are maintained consistent with the formation properties, to minimize fluid loss, optimize wellbore strengthening characteristics and minimize at the same time solids concentrations in order to avoid excessive ECD (equivalent circulating density) which may open pre-existing natural fractures resulting in downhole losses and in consequence might lead to differential sticking. In the case study presented herein, the proactive implementation of GeoMechanics and its Wellbore Stability application as well as the integration of drilling fluids services, resulted in the smooth and successful drilling of the lateral section, and also in the delivery of an in gauge hole necessary for multi-stage fracturing (MSF) completion optimization.

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 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 Multiscale Assessment of Caprock Integrity for Geologic Carbon Storage in the Pennsylvanian Farnsworth Unit, Texas, USA

Energies ◽  
2021 ◽  
Vol 14 (18) ◽  
pp. 5824
Author(s):  
Natasha Trujillo ◽  
Dylan Rose-Coss ◽  
Jason E. Heath ◽  
Thomas A. Dewers ◽  
William Ampomah ◽  
...  
Keyword(s):  
Carbon Storage ◽  
Oil Recovery ◽  
Gamma Ray ◽  
Noble Gas ◽  
Mercury Porosimetry ◽  
Injection Pressure ◽  
Horizontal Stress ◽  
Gas Analysis ◽  
Water Flooding ◽  
Minimum Horizontal Stress

Leakage pathways through caprock lithologies for underground storage of CO2 and/or enhanced oil recovery (EOR) include intrusion into nano-pore mudstones, flow within fractures and faults, and larger-scale sedimentary heterogeneity (e.g., stacked channel deposits). To assess multiscale sealing integrity of the caprock system that overlies the Morrow B sandstone reservoir, Farnsworth Unit (FWU), Texas, USA, we combine pore-to-core observations, laboratory testing, well logging results, and noble gas analysis. A cluster analysis combining gamma ray, compressional slowness, and other logs was combined with caliper responses and triaxial rock mechanics testing to define eleven lithologic classes across the upper Morrow shale and Thirteen Finger limestone caprock units, with estimations of dynamic elastic moduli and fracture breakdown pressures (minimum horizontal stress gradients) for each class. Mercury porosimetry determinations of CO2 column heights in sealing formations yield values exceeding reservoir height. Noble gas profiles provide a “geologic time-integrated” assessment of fluid flow across the reservoir-caprock system, with Morrow B reservoir measurements consistent with decades-long EOR water-flooding, and upper Morrow shale and lower Thirteen Finger limestone values being consistent with long-term geohydrologic isolation. Together, these data suggest an excellent sealing capacity for the FWU and provide limits for injection pressure increases accompanying carbon storage activities.

Stress Magnitudes from Logs: Effects of Tectonic Strains and Temperature

1999 ◽  
Vol 2 (01) ◽  
pp. 62-68 ◽  
Author(s):  
T.L. Blanton ◽  
J.E. Olson
Keyword(s):  
Horizontal Stress ◽  
Tectonic Stress ◽  
In Situ Stress ◽  
Wellbore Stability ◽  
Stress Tests ◽  
Industry Standard ◽  
Stress Profiles ◽  
Fracture Height ◽  
Minimum Horizontal Stress ◽  
Maximum Horizontal Stress

Summary An improved method of calibrating in-situ stress logs was validated with data from two wells. Horizontal stress profiles are useful for hydraulic fracture design, wellbore stability analysis, and sand production prediction. The industry-standard method of estimating stresses from logs is based on overburden, Poisson's ratio, and pore pressure effects and gives an estimate of minimum horizontal stress. The model proposed here adds effects of temperature and tectonics and outputs of minimum and maximum horizontal stress magnitudes, which are particularly important to the successful completion of horizontal and deviated wells. This method was validated using data collected from a GRI research well and a Mobil well. Seven microfrac stress tests in GRI's Canyon Gas Sands Well of Sutton County, Texas, provided a means of comparing the predictive capability of different methods. First, one of the seven stress tests was selected as a calibration standard for the stress log. Then the results obtained from the two calibration methods were compared to stress magnitudes from the other six stress tests. This process was repeated using each of the seven stress tests as a calibration standard and comparing predictions to the other six. In every case, the method incorporating tectonic strain and thermal effects produced significantly more accurate values. The Mobil well is located in the Lost Hills Field in California, and pre-frac treatment breakdown tests were used to calibrate a log-derived stress profile. All of the data were used simultaneously to get a best fit for the log-derived stress. The log and its fracture height growth implications compared favorably with available fracture diagnostic data, and maximum horizontal stress values were consistent with published values for a similar, nearby reservoir. Introduction Advances in well completion technology have made accurate profiles of horizontal stresses more important to successful field development. Data on in-situ stress have always been important to hydraulic fracture design, wellbore stability analysis, and sand production prediction. More recent work has shown that accurate stress profiles can be used to optimize fracturing of horizontal wells and designing multizone fracture treatments. In fracturing horizontal wells, stress profiles can be used to select zones for the horizontal section that optimize fracture height.1 For multizone fracturing, the success of advanced limited-entry techniques depends on having accurate profiles of horizontal stresses.2 Theory Conventional Method. The industry-standard method3-9 of calculating stresses from logs is based on the following equation: σ h m i n = μ 1 − μ ( σ v e r t − α p p ) + α p p . ( 1 ) The shmin formula is obtained by solving linear poroelasticity equations for horizontal stress with vertical stress set equal to the overburden and horizontal strains set to zero. The only deformation allowed is uniaxial strain in the vertical direction. Overburden stress, svert, is determined from an integrated density log. Poisson's ratio, m, is calculated from compressional and shear wave velocities given by an acoustic log. When independent measures of horizontal stress magnitudes are available from microfracs or extended leak-off tests, there is often a discrepancy between the log-derived and measured values, leading to the conclusion that the uniaxial strain assumption inherent to Eq. (1) is inadequate. In order to improve the estimated stress values, an adjustment (calibration) is made by adding an additional stress term to Eq. (1), thereby shifting the profile to match the measured values.4-8 For the purposes of this article, a constant shift with depth is used, stect which in some cases has been referred to as tectonic stress.5 Eq. (1) then becomes what we term here the conventional method stress equation: σ h m i n = μ 1 − μ ( σ v e r t − α p p ) + α p p + σ t e c t , ( 2 ) where σ t e c t = { σ h m i n ′ − μ ′ 1 − μ ′ ( σ v e r t ′ − α p ′ p ′ ) − α p ′ p ′ } . ( 3 ) The primes indicate parameter values at the calibration depth, z¢ where a measure of the minimum horizontal stress, σhmin′, is available. When measured values are available for several zones, slightly different calibration techniques are used, such as multiplying the log-based stress by a constant factor and adding a "tectonic" gradient.6 These calibrations have physical implications. When horizontal stress is applied as in Eq. (2), the zero lateral strain boundary conditions used to derive Eq. (1) are no longer appropriate. If we assume the strain in the direction orthogonal to the applied tectonic stress is zero (plane strain), the normal strain in the direction of the applied calibration stress, [epsiv] (z), can be written as ε ( z ) = E ( z ) 1 − μ ( z ) 2 σ t e c t , ( 4 ) where E and m are functions of depth. Given that typical geologic sequences are layered in elastic moduli, Eq. (4) implies that a constant tectonic stress calibration [exemplified in Eqs. (2) and (3)] results in horizontal strains that may be discontinuous across layer boundaries, which is a nonphysical consequence of the conventional log-derived stress calibration approach.

Coupled Thermal-Hydro-Mechanical-Chemical Modeling for Time-Dependent Anisotropic Wellbore Stability Analysis

2021 ◽  
Author(s):  
Jingyou Xue ◽  
Kenji Furui
Keyword(s):  
Stability Analysis ◽  
Chemical Potential ◽  
Bedding Plane ◽  
Wellbore Stability ◽  
Time Dependent ◽  
Drilling Fluids ◽  
Shale Formations ◽  
Wellbore Instability ◽  
Bedding Planes ◽  
Stress Changes

<p>Wellbore instability is one of the most serious drilling problems increasing well cost in well construction processes. It is widely known that many wellbore instability problems are reported in shale formations where water sensitive clay mineral exist. The problems become further complicated when the shale exhibits variation in strength properties along and across bedding planes. In this study, a coupled thermal-hydro-mechanical-chemical (THMC) model was developed for time-dependent anisotropic wellbore stability analysis considering chemical interactions between swelling shale and drilling fluids, thermal effects, and poro-elastoplastic stress-strain behaviors.</p><p>The THMC simulator developed in this work assumes that the shale formation behaves as an ion exchange membrane where swelling depends on chemical potential of drilling fluids invading from the wellbore to the pore spaces. The time-dependent chemical potential changes of water within the shale are evaluated using an analytical diffusion equation resulting in the evolution of swelling strain around the wellbore. On the other hand, the thermal and pressure diffusion equations are evaluated numerically by finite differences. The stress changes associated with thermal, hydro, and chemical effects are coupled to the 3D poroelastoplastic finite element model. The effects of bedding planes are also taken into account in the FEM model through the crack tensor method in which the normal and tangential stiffnesses of the bedding planes have stress dependency. The failure of the formation rock is judged based on the critical plastic strain limit.</p><p>The numerical analysis results indicate that the rock strength anisotropy induced by the existence of bedding planes is the most important factor influencing the stability of the wellbore among various THMC process parameters investigated in this work. The numerical results also reveal that an established theory to orient the wellbore in the direction of the minimum principal stress is not always a favorable option when the effect of the anisotropy of in-situ stresses and the distribution angle of bedding planes cancel out each other. Depending on both the distribution angle of bedding plane and ratio of the vertical to the horizontal stress, the trend of minimum mud pressure showed a great variation as predicted by the yield and failure criterion implemented in the model. Furthermore, the analysis results reveal that the distribution and evolution of plastic strains caused by the THMC processes have the time dependency, which can be controlled by the temperature and salinity of the drilling fluids.</p><p>The numerical wellbore stability analysis model considering shale swelling and bedding plane effects provides an effective tool for designing optimum well trajectories and determining safe mud weight windows for drilling complex shale formations. The time-dependent margins of safe mud weight window of drilling can be fine-tuned when the interaction among various parameters is fully considered as the THMC processes.</p>

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.

scholarly journals Geomechanical model and wellbore stability analysis utilizing acoustic impedance and reflection coefficient in a carbonate reservoir

2021 ◽  
Author(s):  
Hassan Bagheri ◽  
Abbas Ayatizadeh Tanha ◽  
Faramarz Doulati Ardejani ◽  
Mojtaba Heydari-Tajareh ◽  
Ehsan Larki
Keyword(s):  
Stability Analysis ◽  
Reflection Coefficient ◽  
Acoustic Impedance ◽  
Shear Failure ◽  
Normal Fault ◽  
Carbonate Reservoir ◽  
Wellbore Stability ◽  
Tensile Failure ◽  
Geomechanical Model ◽  
Gas Drilling

AbstractOne of the most important oil and gas drilling studies is wellbore stability analysis. The purpose of this research is to investigate wellbore stability from a different perspective. To begin, vertical stress and pore pressure were calculated. The lowest and maximum horizontal stress were calculated using poroelastic equations. The strike-slip to normal fault regime was shown by calculated in situ stress values. The 1-D geomechanical model was utilized to investigate the failure mechanisms and safe mud window estimation using the Mohr–Coulomb failure criterion. Using density and sonic (compressional and shear slowness) logs, the acoustic impedance (AI) and reflection coefficient (RC) logs were determined subsequently. The combination of layers with different AI indicates positive and negative values for the RC, zones prone to shear failure or breakout, and the mud weight in these zones should be increased, according to the interpretation of the AI and RC readings and the results of the geomechanical model. Furthermore, the zones with almost constant values of AI log and values close to zero for RC log are stable as homogeneously lithologically, but have a lower tensile failure threshold than the intervals that are sensitive to shear failure, and if the mud weight increases, these zones are susceptible to tensile failure or breakdown. Increased porosity values, which directly correspond with the shear failure threshold and inversely with the tensile failure threshold, cause AI values to decrease in homogenous zones, but have no effect on the behavior of the RC log. This approach can determine the potential zones to kick, loss, shear failure, and tensile failure in a short time.

Stability Analysis of Highly Deviated Boreholes to Minimize Drilling Risks and Nonproductive Time

2019 ◽  
Vol 141 (8) ◽  
Author(s):  
Ahmed K. Abbas ◽  
Ralph E. Flori ◽  
Mortadha Alsaba
Keyword(s):  
Stability Analysis ◽  
Shear Failure ◽  
Cost Effective ◽  
Failure Criteria ◽  
Horizontal Stress ◽  
Rock Failure ◽  
Wellbore Stability ◽  
Tensile Failure ◽  
Drilling Performance ◽  
Deviated Wells

The Lower Cretaceous Zubair Formation is a regionally extended gas- and oil-producing sandstone sequence in Southern Iraq. Due to the weak nature of the Zubair Formation, the lack of wellbore stability is one of the most critical challenges that continuously appears during the drilling development operations. Problems associated with lack of wellbore stability, such as the tight hole, shale caving, stuck pipe, and sidetracking, are both time-consuming and expensive. This study aimed to construct a geotechnical model based on offset well data, including rock mechanical properties, in situ stresses, and formation pore pressure, coupled with suitable rock failure criteria. Mohr–Coulomb and Mogi–Coulomb failure criteria were used to predict the potential rock failure around the wellbore. The effect of the inclination and azimuth of the deviated wells on the shear failure and tensile failure mud weights was investigated to optimize the wellbore trajectory. The results show that the best orientation to drill highly deviated wells (i.e., inclinations higher than 60 deg) is along to the minimum horizontal stress (140 deg). The recommended mud weight for this selected well trajectory ranges from 1.45 to 1.5 g/cc. This study emphasizes that a wellbore stability analysis can be applied as a cost-effective tool to guide future highly deviated boreholes for better drilling performance by reducing the nonproductive time.

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