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.

scholarly journals Probabilistic Approach in Wellbore Stability Analysis during Drilling

2016 ◽  
Vol 2016 ◽  
pp. 1-13 ◽  
Author(s):  
Mahmood R. Al-Khayari ◽  
Adel M. Al-Ajmi ◽  
Yahya Al-Wahaibi
Keyword(s):  
Deterministic Model ◽  
Drilling Fluid ◽  
Probabilistic Approach ◽  
Fluid Pressure ◽  
Wellbore Stability ◽  
Rock Properties ◽  
Well Drilling ◽  
Collapse Pressure ◽  
Wellbore Instability

In oil industry, wellbore instability is the most costly problem that a well drilling operation may encounter. One reason for wellbore failure can be related to ignoring rock mechanics effects. A solution to overcome this problem is to adopt in situ stresses in conjunction with a failure criterion to end up with a deterministic model that calculates collapse pressure. However, the uncertainty in input parameters can make this model misleading and useless. In this paper, a new probabilistic wellbore stability model is presented to predict the critical drilling fluid pressure before the onset of a wellbore collapse. The model runs Monte Carlo simulation to capture the effects of uncertainty in in situ stresses, drilling trajectories, and rock properties. The developed model was applied to different in situ stress regimes: normal faulting, strike slip, and reverse faulting. Sensitivity analysis was applied to all carried out simulations and found that well trajectories have the biggest impact factor in wellbore instability followed by rock properties. The developed model improves risk management of wellbore stability. It helps petroleum engineers and field planners to make right decisions during drilling and fields’ development.

The Effect of Water Activity in Shale on Wellbore Instability

2012 ◽  
Vol 616-618 ◽  
pp. 970-974
Author(s):  
Tian Tai Li ◽  
Ming Zhang
Keyword(s):  
Water Activity ◽  
Chemical Potential ◽  
Drilling Fluid ◽  
Water Flux ◽  
Wellbore Stability ◽  
Hydraulic Pressure ◽  
Pressure Balance ◽  
Wellbore Instability ◽  
Key Factor ◽  
The Difference

It is accepted that the water flux in/out of the shale during drilling is the key factor, which controls wellbore instability. This flow can be divided into two components:1) the hydraulic flow due to the difference between the wellbore and pore hydraulic pressure; 2) the osmotic flow due to the imbalance between activities of the shale and the drilling fluid. The former can be prevented by adjusting the wellbore hydraulic pressure balance in the well hole, while the latter is much more difficult to control . The water activity of shale is a controlling factor in many areas of drilling. It impacts all situations wherein the temperature or the stress state of a shale is altered such as in wellbore stability, drilling rate and hydraulic fracturing. This chemical “potential activity interaction” produces a mechanical failure due to the movement of water in/out of shales. In order to have no shale alteration, it requires that the chemical potential of each component must be the same in all phases. This is seldom the case. After a lot of studies the shale activity is shown to be a function of pressure and temperature. Results showed inverse relationship between the platelet distance and the shale water activity. This experimental method proves to be a reliable and efficient way for studying the relationships for the shale water activity, comfining pressure, temperature, and platelet distance.

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.

APPLICATION OF GUIDELINE CHARTS IN DECISIONMAKING ON WELL TRAJECTORY AND MUD WEIGHT PROGRAM

2001 ◽  
Vol 41 (1) ◽  
pp. 609
Author(s):  
X. Chen ◽  
C.P. Tan ◽  
C.M. Haberfield
Keyword(s):  
Stability Analysis ◽  
Case Studies ◽  
In Situ Stress ◽  
Wellbore Stability ◽  
Material Strength ◽  
Stress Regime ◽  
Wellbore Instability ◽  
Well Trajectory

To prevent or minimise wellbore instability problems, it is critical to determine the optimum wellbore profile and to design an appropriate mud weight program based on wellbore stability analysis. It is a complex and iterative decisionmaking procedure since various factors, such as in-situ stress regime, material strength and poroelastic properties, strength and poroelastic anisotropies, initial and induced pore pressures, must be considered in the assessment and determination.This paper describes the methodology and procedure for determination of optimum wellbore profile and mud weight program based on rock mechanics consideration. The methodology is presented in the form of guideline charts and the procedure of applying the methodology is described. The application of the methodology and procedure is demonstrated through two field case studies with different in-situ stress regimes in Australia and Indonesia.

scholarly journals Oil-Based Drilling Fluid Plugging Method for Strengthening Wellbore Stability of Shale Gas

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-13
Author(s):  
Pengcheng Wu ◽  
Chengxu Zhong ◽  
Zhengtao Li ◽  
Zhen Zhang ◽  
Zhiyuan Wang ◽  
...  
Keyword(s):  
Shale Gas ◽  
Drilling Fluid ◽  
Wellbore Stability ◽  
Drilling Fluids ◽  
Fluid System ◽  
Horizontal Drilling ◽  
Wellbore Instability ◽  
Filtration Loss ◽  
Treatment Agent ◽  
Stability Method

Finding out the reasons for wellbore instability in the Longmaxi Formation and Wufeng Formation and putting forward drilling fluid technical countermeasures to strengthen and stabilize the wellbore are very crucial to horizontal drilling. Based on X-ray diffraction, electron microscope scanning, linear swelling experiment, and hot-rolling dispersion experiment, the physicochemical mechanism of wellbore instability in complex strata was revealed, and thus, the coordinated wellbore stability method can be put forward, which is “strengthening plugging of micropores, inhibiting filtrate invasion, and retarding pressure transmission.” Using a sand bed filtration tester, high-temperature and high-pressure plugging simulation experimental device, and microporous membrane and other experimental devices, the oil-based drilling fluid treatment agent was researched and selected, and a set of an enhanced plugging drilling fluid system suitable for shale gas horizontal well was constructed. Its temperature resistance is 135°C and it has preferable contamination resistibility (10% NaCl, 1% CaCl2, and 8% poor clay). The bearing capacity of a 400 μm fracture is 5 MPa, and the filtration loss of 0.22 μm and 0.45 μm microporous membranes is zero. Compared with previous field drilling fluids, the constructed oil-based drilling fluid system has a greatly improved plugging ability and excellent performance in other aspects.

SUMHOLE DRILLING: WELLBORE STABILITY CONSIDERATIONS BASED UPON FIELD AND LABORATORY DATA

1996 ◽  
Vol 36 (1) ◽  
pp. 544
Author(s):  
M.A. Addis ◽  
R.G. Jeffrey
Keyword(s):  
Field Data ◽  
Drilling Fluid ◽  
Laboratory Data ◽  
Petroleum Industry ◽  
Cost Savings ◽  
Wellbore Stability ◽  
Wellbore Instability ◽  
Attractive Option ◽  
Different Diameters ◽  
Fluid Design

Slimhole drilling is becoming an attractive option as it provides significant cost savings in the petroleum industry. Furthermore, many of the technical obstacles in adapting slimhole drilling for the petroleum industry have been addressed, such as rig modifications, small volume kick detection, drilling fluid design, etc. However, wellbore stability in slimholes is largely taken for granted, when it could potentially increase costs dramatically. In this paper, a review of the available information on the effects of hole size on hole stability is presented. Wellbore stability in holes of different diameters is discussed qualitatively based on published laboratory data and unpublished field data. The quantitative assessment of wellbore instability in slimholes is addressed using observations of instability in a well in which the far field stresses were measured.The field data presented here suggest that slimhole wells are not more stable than conventional wells. The slimhole drilled in NSW shows that even using the most conservative prediction model, wellbore instability would not be predicted—instability was however, observed.

scholarly journals The Research on Influence of Unloading on Borehole Stability in Clay-Rich Shale Formation

2017 ◽  
Vol 10 (1) ◽  
pp. 204-219 ◽  
Author(s):  
Yi Ding ◽  
Xiangjun Liu ◽  
Pingya Luo ◽  
Lixi Liang
Keyword(s):  
Stress State ◽  
Influence Factor ◽  
Wellbore Stability ◽  
Clay Shale ◽  
New Model ◽  
Rock Structure ◽  
Well Trajectory ◽  
Shale Formation ◽  
Mud Pressure

Introduction: Unloading phenomenon happens in the beginning of drilling and is able to change stress state around borehole. This change of stress state causes impact on rock structure and strength, thus affecting the evaluation of wellbore stability. Especially for determining initial mud pressure, unloading is a significant influence factor. Clay-rich shale formation is well-known for high risk of borehole collapsing, appropriate mud pressure is necessary to stabilize wellbore. Therefore, the unloading influence needs to be considered when it comes to selection of initial mud pressure. Materials and Methods: In this paper, based on the triaxial test, unloading situation has been simulated to investigate the influence of unloading on rock mechanical property. It is shown that clay-shale strength declines with increasing unloading range. Also, note that in comparison with internal friction angle, cohesion has larger decline caused by unloading. Results: Taking account of the unloading influence, new model has been established to investigate wellbore stability. These results demonstrate that unloading creates variable strength decrease at the wall of borehole due to different in-situ stress and well trajectory. This strength decrease gives rise to increasing collapse pressure. In particular, unloading has relatively larger impact in the formation with strong anisotropy and high in-situ stress. Besides, inappropriate well trajectory will increase unloading impact. Conclusion: Finally, this model has been applied to several cases in clay-shale formation, Northern China. And the new model in each case is well consistent with oilfield experience, indicating its practicability and proving unloading is a non-negligible factor for the assessment of wellbore stability.

Treatment of Prodigious Reactive Shale in the Permian Basin Using High-Performance Drilling Fluid: A Successful Case Study

2021 ◽  
Author(s):  
Almostafa Alhadi ◽  
Musaab Magzoub
Keyword(s):  
Emulsion Stability ◽  
Drilling Fluid ◽  
Treatment Plan ◽  
Wellbore Stability ◽  
Wetting Agent ◽  
Water Phase ◽  
Permian Basin ◽  
Wellbore Instability ◽  
Hole Cleaning ◽  
Rock Samples

Abstract In the Permian basin, Spraberry Trend is one of the formations that markedly contribute to the unconventional shale production in the U.S. lately. Unusual shale reactivity was encountered while drilling several horizontal wells, leading to wellbore instability issues. Consequently, shakers’ screens blockage increased the mud losses and drilling time, leading to an increased non-productive time (NPT). This paper addresses the challenges and causes of the formation instability issues resulted from shale interaction with the used drilling fluid and presents the timely actions taken to mitigate such problems. During the drilling operation, several rock samples were collected at different depth intervals from the shale shaker. Rock samples were analyzed to identify the clay and minerals contents in the formations. The collected samples were first cleaned to remove the mud, dried, ground, and then characterized by an X-ray diffraction test (XRD) and microscopic imaging. After identifying the possible reasons for the wellbore instability, several timely actions were taken to mitigate this issue. These actions include: 1) increasing the emulsion stability, 2) increasing the water phase salinity (WPS), 3) decreasing the water phase volume, 4) adding wetting agent, 5) using wider screens for the shaker, and 6) controlling drilling parameters such as weight on bit and rotational speed. Afterward, wellbore stability, well control problem indicators, and drilling fluid properties, especially rheology, were closely monitored to identify any subsequent or unusual events. The geological and mineralogy studies show that the drilled formation contains high smectite and illite clay content, up to 49%, which was believed to be the main reason for the unusual shale reactivity. Replacing the existing screens (200 API) with wider screens (160 and 140 API) showed an insignificant effect in mitigating the screens blockage. The adopted method of reducing the rate of penetration (ROP) and increasing the circulation time helped significantly alleviate the screens blockage by reducing the cuttings production and giving more time for hole cleaning. Furthermore, the optimal hole cleaning successfully increased the formation's stability. Adding a wetting agent to the drilling mud did not impact the cuttings aggregations; however, it led to a decrease in the rheological properties; thus, adding more concentration of the viscosifier was required to maintain the fluid rheology. Increasing the water phase salinity (WPS) to over 230k ppm and the emulsion stability to over 700 mV was considered the backbone of the treatment plan that significantly resolved the issue by inhibiting the clay. Eventually, the critical considerations were pointed out.

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