scholarly journals Numerical Investigation of Wellbore Stability in Deepwater Shallow Sediments

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-14
Author(s):  
Wei Liu ◽  
Hai Lin ◽  
Hailong Liu ◽  
Chao Luo ◽  
Guiping Wang ◽  
...  
Keyword(s):  
Drilling Fluid ◽  
Horizontal Stress ◽  
Wellbore Stability ◽  
Gas Wells ◽  
Shallow Sediments ◽  
Deformation Stress ◽  
The Stability ◽  
Fluid Penetration ◽  
Mud Pressure ◽  
Oil Gas

An elaborate poro-elastoplastic numerical model has been developed in this paper to explore the stability characteristics of wellbore in shallow sediments of deepwater oil/gas wells. The combined Drucker-Prager/cap plasticity model is employed to characterize the mechanical behavior of the weakly consolidated or unconsolidated shallow sediments, by which both plastic compaction deformation and plastic shear deformation can be considered. Possible penetration of drilling fluid into the formation and its coupling to deformation have also been accounted for in the model. Using this model, deformation, stress evolution, and failure characteristics of the formation around the wellbore are analyzed in detail. Results presented in this paper demonstrate the necessity of considering the plastic compaction capability of the formation during the wellbore stability analysis of shallow sediments in deepwater. For mud pressures lower than the in situ horizontal stress, excessive wellbore shrinkage may occur if the mud pressure is too low, which, however, can be effectively mitigated through properly increasing the mud pressure even fluid penetration into the near-wellbore region may occur. It is also evidenced that, if penetration of drilling fluid into the formation is prevented, fracturing of the wellbore will not occur even the mud pressure is very high. Instead, the wellbore will expand substantially due to plastic compaction, and the deformed wellbore radius could be several times larger than the original value. However, if drilling fluid can penetrate into the formation, high pore pressure will develop within the near-wellbore region, resulting in tensile hoop stress at the wellbore and thus fracturing of the wellbore along the radial direction. The numerical results and implications in this paper are anticipated to be beneficial for the drilling operation in the shallow portion of deepwater oil/gas wells.

scholarly journals Coupled THM Modelling of Wellbore Stability with Drilling Unloading, Fluid Flow, and Thermal Effects Considered

2019 ◽  
Vol 2019 ◽  
pp. 1-20
Author(s):  
Shanpo Jia ◽  
Caoxuan Wen ◽  
Fucheng Deng ◽  
Chuanliang Yan ◽  
Zhiqiang Xiao
Keyword(s):  
Fluid Flow ◽  
Pore Pressure ◽  
Thermal Effects ◽  
Process Analysis ◽  
Drilling Fluid ◽  
Wellbore Stability ◽  
Deep Well ◽  
Underbalanced Drilling ◽  
The Stability ◽  
Pressure Stress

Both overbalanced drilling and underbalanced drilling will lead to the change of pore pressure around wellbore. Existing research is generally based on hydraulic-mechanical (HM) coupling and assumes that pore pressure near the wellbore is initial formation pressure, which has great limitations. According to the coupled theory of mixtures for rock medium, a coupled thermal-hydraulic-mechanical (THM) model is proposed and derived, which is coded with MATLAB language and ABAQUS software as the solver. Then the wellbore stability is simulated with the proposed model by considering the drilling unloading, fluid flow, and thermal effects between the borehole and the formation. The effect of field coupling on pore pressure, stress redistribution, and temperature around a wellbore has been analyzed in detail. Through the study of wellbore stability in different conditions, it is found that (1) for overbalanced drilling, borehole with impermeable wall is more stable than that of ones with permeable wall and its stability can be improved by reducing the permeable ability of the wellbore wall; (2) for underbalanced drilling, the stability condition of permeable wellbore is much higher than that of impermeable wellbore; (3) the temperature has important influence on wellbore stability due to the variation of pore pressure and thermal stress; the wellbore stability can be improved with cooling drilling fluid for deep well. The present method can provide references for coupled thermal-hydraulic-mechanical-chemical (THMC) process analysis for wellbore.

Rheological Study of Nanosilica Based Drilling Fluid

2014 ◽  
Vol 575 ◽  
pp. 128-133 ◽  
Author(s):  
Nur Hashimah Alias ◽  
Nuurhani Farhanah Mohd Tahir ◽  
T.A.T. Mohd ◽  
N.A. Ghazali ◽  
E. Yahya ◽  
...  
Keyword(s):  
Xanthan Gum ◽  
Drilling Fluid ◽  
Gel Strength ◽  
Wellbore Stability ◽  
Potential Candidate ◽  
Drilling Mud ◽  
Well Completion ◽  
Strength Tests ◽  
Water Based ◽  
The Stability

In drilling and well completion operations, drilling fluid is a crucial element as it is employed for the purposes of several functions. The main functions of drilling fluid are to control formation pressure, maintain the wellbore stability, transport the cuttings up to surface to clean the borehole bottom as well as to lubricate and cool the drill bit. Moreover, it is used to minimize the drilling damage to reservoir and suspend cuttings when the pumping is stop, hence it will not falling back down the borehole. The purpose of this study is to formulate new drilling mud formulation modified with nanosilica. Six samples of water based mud (WBM) were prepared using three types of polymers, (Xanthan Gum, Hydro Zan Plus and Hydro Star HT), starch and nanosilica. Basic rheological tests such as density, viscosity and pH were carried out. The density test was carried out using mud balance meanwhile the pH test was using pH meter. Theplasticviscosity, yield point and gel strength tests were carried out using viscometer. Besides that, physical observation was also performed for as the stability test. The results concluded that water based mud incorporated with polymer Hydro Zan Plus and nanosilica can be a potential candidate to be commercialized as a smart nanodrilling fluid.

scholarly journals Theoretical preconditions for modeling wellbore stability and predicting hydraulic fracturing

2021 ◽  
pp. 41-49
Author(s):  
A.N. Popov ◽  
◽  
R.A. Ismakov ◽  
F.N. Yangirov ◽  
A.R. Yakhin ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Drilling Fluid ◽  
Fluid Pressure ◽  
Polycrystalline Diamond ◽  
Wellbore Stability ◽  
Rotary Drilling ◽  
Factors Affecting ◽  
The Stability ◽  
Diamond Bit ◽  
The Given

One of the complex technological tasks in the process of drilling is to ensure the stability of the wellbore walls, as well as their modeling for further forecasting the state of the wellbore and the likelihood of hydraulic fracturing. This is due to the fact that most of the complications and factors affecting the equilibrium state of the wall are associated with external influences. The article discusses the mechanical and partially hydraulic aspects of solving the described problems associated with modeling the stability of the wellbore walls and predicting hydraulic fracturing. As a result of calculations, the necessary data are obtained for making a decision on the density of the drilling fluid for drilling the considered interval of rocks. The assumed model of the porous rock and the given calculation formulas make it possible to fully evaluate the influence of the formation fluid pressure on the mechanical processes in the rocks when they are opened by a well. Keywords: hydraulic fracturing; blade bit; steel ball-shaped toothed bit; polycrystalline diamond bit; laser drilling; impact rope drilling; rotary drilling.

scholarly journals Experimental investigation of rheological properties and formation damage of water-based drilling fluids in the presence of Al2O3, Fe3O4, and TiO2 nanoparticles

2020 ◽  
Vol 10 (4) ◽  
pp. 5886-5894
Keyword(s):  
Iron Oxide ◽  
Aluminum Oxide ◽  
Rheological Properties ◽  
Titanium Oxide ◽  
Filtration Rate ◽  
Drilling Fluid ◽  
Gel Strength ◽  
Wellbore Stability ◽  
Formation Damage ◽  
The Stability

The successful drilling of the oil and gas wells almost relies upon the drilling fluid properties. Maintaining wellbore stability, transportation, and releasing cuttings at the surface, and controlling formation pressure are the essential functions of the drilling fluid. Improving the rheological properties of the drilling fluid results in an increase in transport power and also provides better stability. One of the new methods to improve different properties of the drilling mud is the application of nanoparticles. Nanoparticles induce favorable effects on the rheological properties of the fluid. Improvement of mud properties yields in better cleaning of the well, the stability of the wellbore, higher drilling bit efficiency, and, consequently, a lower cost in the long run. Therefore, the present study investigates the effect of adding three different nanoparticles including aluminum oxide, iron oxide, and titanium oxide to the drilling fluid in several experiments by measuring rheological properties (plastic viscosity, yield point, filtration rate, gel strength) and also formation damage and permeability reduction. The number of experiments was determined by the experiment design method. The results of the experiments implied that in nanofluids with the weight of 70 pcf, rheological properties were relatively improved in most of the nanofluids samples concentrations. Samples containing iron oxide exhibited a decreasing filtration rate compare to base drilling fluid that indicates increasing stability in the fluid environment. The gel strength (GS) of titanium oxide and aluminum oxide samples has increased appropriately, which shows improvement in attractive forces in the fluid. For the case of the 80 pcf nanofluid, iron oxide indicates appropriate rheological properties and decreasing of filtration rate that all of them represent nanoparticle caused an increasing and improving the stability of fluid. But titanium oxide and aluminum oxide couldn't show significant effects. This phenomenon can be described by the lack of a uniform and thorough mixing of nanoparticles in the drilling fluid under field conditions. Besides, results obtained from the formation damage test equipment demonstrated the 54% reduction in initial permeability of the iron oxide nanoparticle that is the lowest damage between another nanofluid.

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.

THE EFFECTS OF DRILLING FLUID-SHALE INTERACTIONS ON WELLBORE STABILITY

1995 ◽  
Vol 35 (1) ◽  
pp. 678 ◽  
Author(s):  
C.P Tan ◽  
E.M. Zeynaly-Andabily ◽  
S.S. Rahman
Keyword(s):  
Chemical Potential ◽  
Drilling Fluid ◽  
Wellbore Stability ◽  
Chemical Potential Difference ◽  
Wellbore Instability ◽  
Laboratory Techniques ◽  
In Situ Stresses ◽  
Physico Chemical ◽  
Mud Pressure

Wellbore instability, experienced mainly in shale sections, has resulted in significant drilling delays and suspension of wells in major Australian petroleum basins. These instabilities may be induced by either in-situ stresses that are high relative to the strength of the formations or physico-chemical interactions of the drilling fluid with the shales.This paper describes fundamental concepts of mud pressure penetration and flow of water between the wellbore and formation due to their chemical potential difference, and associated mud support changes as the drilling fluid interacts with shales. Due to the low permeability of shales, the penetration of the drilling fluid filtrate would result in an increase in pore pressure over a considerable distance from the wellbore. This instability mechanism strongly depends on properties of the drilling fluid filtrate and pore fluid, and the rock material composition.In addition to mud pressure penetration, water would be induced to either flow into or out of the formation depending on the relative chemical potential of the drilling fluid and the formation. A more stable wellbore condition could be achieved by optimising the chemical potential of drilling fluids.Drilling fluid and shale properties required for the models, which are determined using analytical and laboratory techniques, are presented herein. The effects of the time-dependent mechanisms on wellbore stability are demonstrated for a polyacrylamide, an ester-based and an oil-based mud. The results demonstrate that a more effective mud support can be obtained by optimising the adhesion and viscosity of the drilling fluid filtrate, and chemical potential of the drilling fluid.

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%.

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.

Organosilicon Drilling Fluid System for HT Deep Gas Wells

2009 ◽  
Author(s):  
Yuxue Sun ◽  
Yanfen Zhang ◽  
Jingyuan Zhao
Keyword(s):  
Drilling Fluid ◽  
Gas Wells ◽  
Fluid System

Experimental Evaluation of Separation Methods for a Riser Dilution Approach to Dual Density Drilling

2009 ◽  
Author(s):  
John Shelton ◽  
John Rogers Smith ◽  
Anuj Gupta
Keyword(s):  
Emulsion Stability ◽  
Drilling Fluid ◽  
Feed Stream ◽  
Separation System ◽  
Qualitative Comparison ◽  
Deepwater Drilling ◽  
Drilling System ◽  
The Stability ◽  
Dual Gradient ◽  
Laboratory Centrifuge

A dual gradient, deepwater drilling system based on dilution of riser mud requires economically separating the riser mud into a low density dilution fluid and a higher density drilling fluid. This study investigated the practicality of accomplishing this separation using hydrocyclones and centrifuges and examined the possible benefits and efficiency of each. The separation experiments were conducted using a laboratory centrifuge and 2 inch hydrocyclones. The laboratory centrifuge was able to separate the riser mud into near ideal densities for dilution and drilling fluid. However, the dense slurry retained in the centrifuge had lower emulsion stability than the feed stream. The hydrocyclones achieved much less contrast in density between the low and high density discharges, but consistently resulted in a beneficial increase in the stability of the mud emulsion in all of the flow streams and had more desirable rheological properties. A qualitative comparison indicates that the hydrocyclone separation system may offer a feasible and desirable alternative to centrifuge separation system.

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