Mitigating Wellbore Stability Problems while Drilling with Water-Based Muds in Deepwater Environments

2002 ◽  
Author(s):  
U. Tare ◽  
F. Mody ◽  
C. Tan
Keyword(s):  
Wellbore Stability ◽  
Stability Problems ◽  
Water Based

Interdisciplinary Approach for Wellbore Stability During Slimhole Drilling at Volga-Urals Basin Oilfield

2021 ◽  
Author(s):  
Anna Vladimirovna Norkina ◽  
Sergey Mihailovich Karpukhin ◽  
Konstantin Urjevich Ruban ◽  
Yuriy Anatoljevich Petrakov ◽  
Alexey Evgenjevich Sobolev
Keyword(s):  
Drilling Fluid ◽  
Interdisciplinary Approach ◽  
Wellbore Stability ◽  
Vertical Wells ◽  
Wellbore Instability ◽  
Water Based ◽  
Chemical Studies ◽  
Fluid Rheology ◽  
Selection Of

Abstract The design features and the need to use a water-based solution make the task of ensuring trouble-free drilling of vertical wells non-trivial. This work is an example of an interdisciplinary approach to the analysis of the mechanisms of instability of the wellbore. Instability can be caused by a complex of reasons, in this case, standard geomechanical calculations are not enough to solve the problem. Engineering calculations and laboratory chemical studies are integrated into the process of geomechanical modeling. The recommendations developed in all three areas are interdependent and inseparable from each other. To achieve good results, it is necessary to comply with a set of measures at the same time. The key tasks of the project were: determination of drilling density, tripping the pipe conditions, parameters of the drilling fluid rheology, selection of a system for the best inhibition of clay swelling.

Wellbore-Stability Performance of Water-Based Mud Additives

2009 ◽  
Vol 24 (03) ◽  
pp. 390-397 ◽  
Author(s):  
Russell T. Ewy ◽  
E. Keith Morton
Keyword(s):  
Wellbore Stability ◽  
Stability Performance ◽  
Water Based

scholarly journals Laponite: a promising nanomaterial to formulate high-performance water-based drilling fluids

2020 ◽  
Author(s):  
Xian-Bin Huang ◽  
Jin-Sheng Sun ◽  
Yi Huang ◽  
Bang-Chuan Yan ◽  
Xiao-Dong Dong ◽  
...  
Keyword(s):  
High Performance ◽  
Drilling Fluid ◽  
Nitrogen Adsorption ◽  
Drill String ◽  
Wellbore Stability ◽  
Fluid Loss ◽  
Drilling Fluids ◽  
Mechanism Analysis ◽  
Water Based ◽  
Inhibition Performance

Abstract High-performance water-based drilling fluids (HPWBFs) are essential to wellbore stability in shale gas exploration and development. Laponite is a synthetic hectorite clay composed of disk-shaped nanoparticles. This paper analyzed the application potential of laponite in HPWBFs by evaluating its shale inhibition, plugging and lubrication performances. Shale inhibition performance was studied by linear swelling test and shale recovery test. Plugging performance was analyzed by nitrogen adsorption experiment and scanning electron microscope (SEM) observation. Extreme pressure lubricity test was used to evaluate the lubrication property. Experimental results show that laponite has good shale inhibition property, which is better than commonly used shale inhibitors, such as polyamine and KCl. Laponite can effectively plug shale pores. It considerably decreases the surface area and pore volume of shale, and SEM results show that it can reduce the porosity of shale and form a seamless nanofilm. Laponite is beneficial to increase lubricating property of drilling fluid by enhancing the drill pipes/wellbore interface smoothness and isolating the direct contact between wellbore and drill string. Besides, laponite can reduce the fluid loss volume. According to mechanism analysis, the good performance of laponite nanoparticles is mainly attributed to the disk-like nanostructure and the charged surfaces.

scholarly journals A laboratory approach to predict the water-based drill-in fluid damage on a shale formation

2020 ◽  
Vol 38 (6) ◽  
pp. 2579-2600
Author(s):  
Rui Wang ◽  
Xinmim Wu ◽  
Weifeng Li ◽  
Haitao Bai ◽  
Linsheng Qiao
Keyword(s):  
Liquid Phase ◽  
Shale Gas ◽  
Gas Diffusion ◽  
Solid Particles ◽  
Wellbore Stability ◽  
Working Fluid ◽  
Water Sensitivity ◽  
Water Based ◽  
Shale Reservoir ◽  
Water Block

Shale gas production after drill-in, completion, and hydraulic fracturing is strongly affected by formation damage. In order to determine the damage mechanisms for nonmarine shale reservoir, a series of assessments of sensitivity damage, water block damage, water-based drill-in fluids damage, and water damage to gas diffusion on 20 shale samples obtained from Chang 7 Formation were conducted and analyzed. Results indicate that, in the Chang 7 Formation shale, there is extremely strong stress sensitivity and moderately weak water sensitivity damage. Although the liquid phase invasion depth is shallow and the water block damage is limited, the liquid phase and solid particles would enter the microfractures in the reservoir.The P-1 water-based drill-in fluid is compatible with the Chang 7 Formation shale reservoir which can meet the requirement of Chang 7 Formation shale damage controlling, the effect of water-based drill-in fluid on wellbore stability should be paid more attention. The diffusion coefficient of the shale decreases with the presence of water.A systematic damage evaluation method of working fluid considering the multi-mechanism and multi-scale mass transfer process of shale gas is needed to establish.

scholarly journals Experimental study on the influence of coal powders on the performance of water-based polymer drilling fluid

2020 ◽  
Vol 38 (5) ◽  
pp. 1515-1534
Author(s):  
Lei Zhang ◽  
Xiaoming Wu ◽  
Shuaifeng Lyu ◽  
Penglei Shen ◽  
Lulu Liu ◽  
...  
Keyword(s):  
Surface Tension ◽  
Contact Angle ◽  
Coalbed Methane ◽  
Drilling Fluid ◽  
Wellbore Stability ◽  
Filtration Loss ◽  
Water Based ◽  
Natural Degradation ◽  
Tension Increase ◽  
Powder Content

Coal powders, as cuttings, invade the drilling fluid along a coal seam during coalbed methane development, thereby changing the properties of the drilling fluid. Therefore, this work aims to investigate the influence of coal powders on drilling fluid performance. The powders of lignite, anthracite, and contrasting shale were added to a water-based polymer drilling fluid. Then, the rheology, filtration, lubricity, and adhesiveness were measured, and the natural degradation, as well as the wettability were further evaluated. The results show that some parameters of the drilling fluid, including viscosity, lubrication coefficient, adhesion coefficient, contact angle, and surface tension, increase after adding coal powders, while other parameters, such as filtration loss and natural degradation, decrease. Compared with lignite and shale, anthracite powders, with the lowest mineral content, exhibit the smallest change in the rheological property, lubricity, adhesion, and natural degradation of the drilling fluid. Moreover, the content and size of the coal powders generally have opposing effects on the drilling fluid. When the coal powder content reaches 3 wt.%, the surface tension and contact angle of the drilling fluid show more evident changes than other parameters. Based on the analysis of the stress intensity factor, the drilling fluid with coal powders exceeding 100 mesh can reduce the capillary force in microfractures, and in combination with other factors (such as reduced filtration loss and sealing and supporting of the microfractures), improves wellbore stability. Therefore, coal powders with suitable particle sizes and concentration levels are expected to become a new drilling fluid material to protect coal field reservoirs.

Four-well comparison in Papua New Guinea: high-risk, high-angle wells demonstrate extended wellbore stability and faster drilling time with inhibitive high-performance water-based fluid

2011 ◽  
Vol 51 (1) ◽  
pp. 119
Author(s):  
Angus Florence ◽  
Mike Dow ◽  
George Shieh ◽  
JV Babu
Keyword(s):  
High Risk ◽  
Papua New Guinea ◽  
High Performance ◽  
Cost Savings ◽  
New Guinea ◽  
Wellbore Stability ◽  
Drilling Fluids ◽  
Water Based ◽  
Performance Decline ◽  
Glycol Fluid

A four-well project located onshore Papua New Guinea provided an opportunity to compare the performance of two inhibitive drilling fluids in the problematic 12¼” interval. Wells A and B were drilled using a conventional KCl/glycol fluid. Wells C and D used a high-performance water-based fluid (HPWBF) containing a shale inhibitor that also provides lubricity. All four wells were drilled with the same rig. The base brine for both fluids was KCl. All hole sections were directionally drilled from vertical to near horizontal by section TD through a claystone interval. Tectonic wellbore breakout was present in all four wells, and the position of the breakout in the wellbore varied from well to well. Well A was regarded as the easiest well to drill due to the breakout being on the sides on the inclined well bore (horizontal), and Well D was regarded as being the most difficult well to drill due to the breakout being located directly on the top and bottom of the wellbore (vertical). Performance comparisons were made using on bottom rates of penetration, tripping times, casing running times, and overall hole section costs. These data have been normalised to remove non hole related NPT events. The KCl/glycol system provided sufficient wellbore stability in Wells A and B with horizontal breakouts and with non-optimal breakouts with very limited openhole exposure. For higher risk wells C and D with non-optimal breakout positions however, the HPWBF offered improved reliability and ensured there was no performance decline. Outstanding performance occurred in Well D where the HPWBF maintained good wellbore stability over a 56-day exposure. Although the KCl/glycol fluid had a lower cost/bbl, improved overall cost savings were achieved by using the HPWBF in the high-risk wells. This paper addresses all operations performed while drilling and casing the 12¼” interval. Possible causes for performance differences are evaluated, taking into account that mud systems represent only one variable. As other variables were introduced progressively, it was possible to back these out to determine mud system effectiveness.

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.

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