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Topic: Wellbore stability in shale
Number of pages needed: 10
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Date: Wellbore Stability in Shale 3 Abstract: An analysis approach to assess borehole stability following a hypothetical blowout from representative deep-water scenarios is presented. It addresses whether imposed underbalanced conditions cause sufficient instability that the borehole bridges-over and the well kills itself. The approach uses a series of interrelated analyses: (i) analyses of the kick and blowout development are performed predicting how bottom pressure and in-flow velocity changes over time; (ii) underbalanced wellbore failure in exposed shales and sands is then determined; (iii) caving and produced sand volumes are calculated from the estimated failure zone, and the transport of these materials in the borehole is determined from the predicted hydrocarbon flow rates; and (iv) bridging tendency is assessed by considering the concentration of caving in either the enlarged borehole or in flow-paths within the well casing or annuli. To research the ERW borehole stability, including mechanical model, shale hydration test and the effect of circulating pressure loss in this paper, rock mechanics theory and hydraulics principle were comprehensively applied . The results show that, the safer drilling azimuth of the ERW in normal fault lies in the minimum horizontal principle stress direction; hydration radius increases with the passage of time, and the hydration collapsed rock has important influence on cutting beds and circulating pressure loss in annulus; the upper limit value of safety mud density decreases with the well depth increases, and when it deceases to the equivalent mud density of collapse pressure, the limit depth of the ERW is obtained. Factors affecting the shale strength are discussed, and a sonic compressional velocity-log based correlation for strength is proposed. Recommendations for modeling and improving shale stability are described, based on the current understanding of shale stability. The mode of shale-stabilizing action of a wide variety of water-based fluid additives is discussed and the merits of various mud systems are ranked. It is shown that shale stabilization normally achieved using oilbased/synthetic-based muds is now becoming achievable with economical and environmentally friendly water-based drilling fluids. The field case presents a new challenge to the log-based wellbore stability interpretation routinely implemented in current drilling society. Being open-minded, closely monitoring and testing caving’s, and updating the model with drilling experience may be as important as the model development itself. Wellbore Stability in Shale 4 Introduction: Uncontrolled influxes of formation fluids into a borehole (a “kick”) develop into a blowout when the drilling fluid is fully displaced from the well and the formation fluid exits the well. In the case of subsea deep-water wells, the wellhead is at the sea-floor and is connected to the drill rig by a marine riser. An influx of hydrocarbons, especially gas, is more severe than an influx of over pressured water. Occurrences of over-pressured water (“shallow water flows”) or shallow gas influx are well understood from a shallow hazards perspective [1] . As a kick develops, the drilling fluid is displaced from the well by the influx of less dense fluids that have a formation pressure greater than the hydrostatic pressure exerted by the drilling fluid. The bottom-hole pressure in the wellbore thus reduces during the developing kick, thereby accelerating the influx. Shales make up over 75% of the drilled formations, and over 70% of the borehole problems are related to shale instability. The oil and gas industry still continues to fight borehole problems. The problems include hole collapse, tight hole, stuck pipe, poor hole cleaning, hole enlargement, plastic flow, fracturing, lost circulation, well control. Most of the drilling problems that drive up the drilling costs are related to wellbore stability. These problems are mainly caused by the imbalance created between the rock stress and strength when a hole is drilled. The stress-strength imbalance comes about as rock is removed from the hole, replaced with drilling fluid, and the drilled formations are exposed to drilling fluids. Wellbore stability is almost a trivial issue with oilbased and synthetics-based muds. Once mud weight and invert emulsion salinity are properly established, stability can virtually be guaranteed (except for a few cases such as fractured shale formations, which may be rapidly destabilized by such muds when they penetrate the fracture network, lubricate fracture surfaces, and equilibrate pore pressure with wellbore pressure) [2] . Moreover, oil and synthetic based muds in general drill wells much faster than water-based muds as they are much less prone to cause bit balling. Causes of Wellbore Instability: Wellbore instability manifests itself in different ways like hole pack off, excessive reaming, overpull, torque and drag, sometimes leading to stuck pipe that may require plugging and side tracking. This requires additional time to drill a hole, driving up the cost of reservoir development Wellbore Stability in Shale 5 significantly. In case of offshore fields, loss of hole is more critical due to a limited number of holes that can be drilled from a platform [3] . Wellbore instability is usually caused by a combination of factors which may be broadly classified as being either controllable or uncontrollable (natural) in origin. These factors are shown in table given below. Uncontrollable (Natural) Factors Controllable Factors Naturally Fractured or Faulted Formation Bottom Hole Pressure (Mud Density) Tectonically Stressed Formations Well Inclination and Azimuth High I-Situ Stresses Transient Pore Pressures Mobile Formations Physico/chemical Rock-Fluid interaction Unconsolidated Formations Drill String Vibrations Naturally Over-Pressured Shale Collapse Erosion Induced Over-pressured Shale Collapse Temperature 1. Uncontrollable factors Naturally fractured or faulted formations: A natural fracture system in the rock can often be found near faults. Rock near faults can be broken into large or small pieces. If they are loose, they can fall into the wellbore and jam the string in the hole. Even if the pieces are bonded together, impacts from the BHA due to drill string vibrations can cause the formation to fall into the wellbore. This type of sticking is particularly unusual in that stuck pipe can occur while drilling. This mechanism can occur in tectonically active zones, in prognosed fractured limestone, and as the formation is drilled. Drill string vibrations have to be minimized to help stabilize these formations. Holecollapse problems may become quite severe if weak bedding planes intersect a wellbore at unfavorable angles. Such fractures in shales may provide a pathway for mud or fluid invasion that can lead to time-depended strength degradation, softening and ultimately to hole collapse. The relationship between hole size and the fracture spacing will be important in such formations Wellbore Stability in Shale 6 Drilling through naturally fractured or faulted formations Tectonically Stressed Formations: Wellbore instability is caused when highly stressed formations are drilled and if exists a significant difference between the near wellbore stress and the restraining pressure provided by the drilling fluid density. Tectonic stresses build up in areas where rock is b eing compressed orstretched due movement of the earth´s crust. The rock in these areas is being buckled by the pressure of the moving tectonic plates. When a hole is drilled in an area of high tectonic stresses the rock around the wellbore will collapse into the wellbore and produce splintery cavings similar to those produced by over-pressured shale. In the tectonic stress case the hydrostatic pressure required to stabilize the wellbore may be much higher than the fracture pressure of the other exposed formations [4] . This mechanism usually occurs in or near mountainous regions. Planning to case off these formations as quickly as possible and maintaining adequate drilling fluid weight can help to stabilize these formations. Wellbore Stability in Shale 7 Drilling through tectonically stressed formations High in-situ stresses: Anomalously height in-situ stresses, such as may be found in the vicinity of salt domes, near faults, or in the inner limbs of a folds may give rise to wellbore instability. Stress concentrations may also occur in particularly stiff rocks such as quartzose sandstones or conglomerates. Only a few case histories have been described in the literature for drilling problems caused by local stress concentrations, mainly because of the difficulty in measuring or estimating such in situ stresses. Mobile formations: The mobile formation squeezes into the wellbore because it is being compressed by the overburden forces. Mobile formations behave in a plastic manner, deforming under pressure. The deformation results in a decrease in the wellbore size, causing problems of running BHA´s, logging tools and casing. A deformation occurs because the mud weight is not sufficient to prevent the formation squeezing into the wellbore. This mechanism normally occurs while drilling salt. An appropriate drilling fluid and maintaining sufficient drilling fluid weight are required to help stabilize these formations [5] . Unconsolidated formations: An unconsolidated formation falls into the wellbore because it is loosely packed with little or no bonding between particles, pebbles or boulders. The collapse of formations is caused by removing the supporting rock as the well is drilled. It happens in a wellbore when little or no filter cake is present. The un-bonded formation (sand, gravel, etc.) cannot be supported by hydro static overbalance as the fluid simply flows into the formations. Sand or gravel then falls into the hole and packs off the drill string. The effect can be a gradual increase in drag over a number of meters, or can be sudden. This mechanism is normally associated with shallow formation. An adequate filter cake is required to help stabilize these formations. Wellbore Stability in Shale 8 Naturally Over-Pressured Shale Collapse: Naturally over-pressured shale is the one with a natural pore pressure greater than the normal hydrostatic pressure gradient. Naturally over pressured shales are most commonly caused by geological phenomena such as under-compaction, naturally removed overburden and uplift [6]. Using insufficient mud weight in these formations will cause the hole to become unstable and collapse. This mechanism normally occurs in prognosed rapid depositional shale sequences. The short time hole exposure and an adequate drilling fluid weight can help to stabilize these formations. Induced Over-Pressured Shale Collapse: Induced over-pressured shale collapse occurs when the shale assumes the hydrostatic pressure of the wellbore fluids after a number of days, exposures to that pressure. When this is followed by no increase or a reduction in hydrostatic pressure in the wellbore, the shale, which now has a higher internal pressure than the wellbore, collapse in a similar manner to naturally over-pressured shale. This mechanism normally occurs in water based drilling fluids, after a reduction in drilling fluid weight or after a long exposure time during which the drilling fluid was unchanged. 2. Controllable Factors: Bottom hole pressure (mud density): Depending upon the application, either the bottom hole pressure, the mud density or the equivalent circulating density (ECD), is usually the most important determinant of whether an open wellbore is stable. The supporting pressure offered by the static or dynamic fluid pressure during either drilling, stimulating, working over or producing of a well, will determine the stress concentration present in the near wellbore vicinity. Because rock failure is dependent on the effective stress the consequence for stability is highly dependent on whether and how rapidly fluid pressure penetrate the wellbore wall. That is not to say however, that high mud densities or bottom hole pressures are always optimal for avoiding instability in a given well. In the absence of an efficient filter cake, such as in fractured formations, a rise in a bottom hole pressure may be detrimental to stability and can compromise other criteria, e.g., formation damage, differential sticking risk, mud properties, or hydraulics. Well Inclination and Azimuth: Inclination and azimuthal orientation of a well with respect to the principal in-situ stresses can be an important factor affecting the risk of collapse and/or fracture breakdown occurring. This is particularly true for estimating the fracture breakdown pressure in tectonically stressed regions where there is strong stress anisotropy. Wellbore Stability in Shale 9 Transient wellbore pressures: Transient wellbore pressures, such as swab and surge effects during drilling, may cause wellbore enlargement. Tensile spalling can occur when the wellbore pressure across an interval is rapidly reduced by the swabbing action of the drill string for instance. If the formation has a sufficiently low tensile strength or is pre-fractured, the imbalance between the pore pressures in the rock and the wellbore can literally pull loose rock off the wall. Surge pressures can also cause rapid pore pressures increases in the near-wellbore area sometimes causing an immediate loss in rock strength which may ultimately lead to collapse. Other pore pressure penetration-related phenomena may help to initially stabilize wellbores, e.g. filter cake efficiency in permeable formations, capillary threshold pressures for oil-based muds and transient pore pressure penetration effects. Physical/chemical fluid-rock interaction: There are many physical/chemical fluid-rock interaction phenomena which modify the near-wellbore rock strength or stress. These include hydration, osmotic pressures, swelling, rock softening and strength changes, and dispersion. The significance of these effects depend on a complex interaction of many factors including the nature of the formation (mineralogy, stiffness, strength, pore water composition, stress history, temperature), the presence of a filter cake or permeability barrier is present, the properties and chemical composition of the wellbore fluid, and the extent of any damage near the wellbore. Drill string vibrations (during drilling): Drill string vibrations can enlarge holes in some circumstances. Optimal bottom hole assembly (BHA) design with respect to the hole geometry, inclination, and formations to be drilled can sometimes eliminate this potential contribution to wellbore collapse. Some authors claim that hole erosion may be caused due to a too high annular circulating velocity. This may be most significant in a yielded formation, a naturally fractured formation, or an unconsolidated or soft, dispersive sediment. The problem may be difficult to diagnose and fix in an inclined or horizontal well where high circulating rates are often desirable to ensure adequate hole cleaning. Drilling fluid temperature: Drilling fluid temperatures, and to some extent, bottom hole producing temperatures can give rise to thermal concentration or expansion stresses which may be detrimental to wellbore stability. The reduced mud temperature causes a reduction in the nearwellbore stress concentration, thus preventing the stresses in the rock from reaching their limiting strength. Wellbore Stability in Shale 10 Understanding Subsurface Shale The term shale is normally used for the entire class of fine grained sedimentary rocks that contain substantial amount of clay minerals. Sedimentologists find shale hard to work with since shale is fine grained, lacks well-known sedimentary structure (so useful in sandstones), and readily applicable tools and models are not available to study shale. The distinguishing features of shale (of interest to oil industry) are its clay content, low permeability (independent of porosity) due to poor pore connectivity through narrow pore throats (typical pore diameters range 3 nm-100 nm with largest number of pores having 10 nm diameter), and large difference in the coefficient of thermal expansion between water and the shale matrix constituents. To understand drilling fluid interaction with shale, one must start from basic properties of in situ shale (e.g. pre-existing water in shale, mineralogy, porosity), and then analyze the impact of changes in stress environment on the properties of shale [7] . Knowing the in-situ stresses and having predicted the mechanical properties of the formation, wellbore instability in exposed shale formations may be evaluated using conventional time-dependent (poroelastic) wellbore stability analysis. Here an analysis performed for the midheight of the open borehole is considered representative of failure of the entire interval. Figure 1 illustrates the results from the wellbore stability model once the initial underbalance pressure is applied to the exposed shale formations due to the riser disconnecting. Figure 2 shows the extent of wellbore instability when the kick is fully developed, having reached the seabed. Here the borehole pressure is assumed to reduce from 11,170 psi to 6,934 psi over a 20 minute period. Hole Instability in shale when the Riser is disconnected (t=0 minute) (Figure 1) Hole Instability in shale when the Riser reaches the wellhead (Figure 2) Wellbore Stability in Shale 11 The plots on the left-hand side of Figs. 1 and 2 show the pore pressure profile around the well. The right-hand plots show, for a given location around the well, the minimum rock strength (UCS) that is required to prevent wellbore failure. By specifying the formation strength, the black line shows the extent to which the formation surrounding the borehole is expected to fail; i.e. the line presents a contour of required rock strength equivalent to that specified in the analysis. Locations within the black line are predicted to fail and cause extensive breakouts. It is seen by comparing the left-hand plot in Figs. 1 and 2 that the majority of the borehole failure is predicted to occur at the time that the riser breaks; the failure zone increases only slowly over time as the bottom-hole pressure reduces during the kick development. Upon losing the riser the radial extent of the failure zone is 1.2 times the borehole radius; this suggests a 10.2-inch diameter enlarged borehole for an 8½-inch drilled borehole. After 22 minutes, as the kick develops, the failure zone extent extends to 1.28 times the borehole radius (10.9 inches for an 8½-inch borehole). Shale Problems and Solutions: Three types of shale problems and their unique solutions are now discussed: (1) cuttings disintegration, (2) wellbore instability and (3) bit balling. From a mud engineering standpoint, the challenge is to whatever kind of inhibitors are used (remark that inhibitors were defined earlier as agents that reduce the swelling pressure) [8] . The reason for this is that in intact, non-fractured shales, the inhibitor-diffusion front lags behind the pore-pressure front. Instability cannot be prevented in the zone with elevated pore-pressure between the two fronts as the inhibitor will not have reached this zone yet. Assuming that the pore-pressure has been equilibrated to the mud pressure (i.e. Ppore = Pm) in the mud pressure invasion zone not yet reached by inhibitor diffusion, the effective radial stress acting in this zone becomes: Improving Shale Stability Thus far, we have seen that there are several mechanisms which cause or affect shale/fluid interaction. There is an intense effort under way in the oil industry to get a better understanding of each of these mechanisms. The stakes are high in that understanding and quantification of each of these phenomena is critical for designing benign drilling fluids which would stabilize shales. Rapid progress is being made and more results will become available in the near future [9]. The current understanding of various mechanisms responsible for shale/fluid interaction indicate certain basic principles for improving shale stability. Based on current understanding of various shale/fluid Wellbore Stability in Shale 12 interaction mechanisms, we can discuss some general principles for improving shale stability. The main objective to improve shale stability is to prevent, minimize, delay or use to our advantage the interaction of the drilling fluid with shale. As our understanding of the various interaction mechanisms improves, so will the mud systems designed to improve shale stability. We can list the following means of improving shale stability corresponding to various mechanisms contributing to shale/fluid interaction: For fractured shale stability, use effective sealing agents, thixotropic drilling fluid (high viscosity for low shear rates), and lower mud weight /ECD. This would minimize fluid penetration into fractures. ` Slow down the rate of fluid transport and pressure diffusion rate. It is difficult to balance water activity of shale with mud exactly everywhere in a well because shale activity is not known and varies with depth and mineralogy. We can, nevertheless, control parameters that enable us to reduce the fluid transport and pressure diffusion rates by increasing the fluid viscosity and reducing the permeability of shales. Regarding the viscosity increase, the problem is to find solutes that increase the fluid viscosity significantly and yet can pass through the narrow shale pore space to maintain high viscosity. Most mud polymers are too large to enter shale but some low molecular weight polymers might achieve the desired results. As regards reducing permeability, one solution is to form permeability barrier at shale surface or within micro-fractures. Oil base mud achieves this as water is made to diffuse through continuous oil phase to reach the shale [10]. Silicate and ALPLEX muds, for example, attempt to reduce the permeability. Cationic polymers, which are strongly adsorbing, can also act in the same way. In the extreme, shale formation could be completely isolated by creating an impermeable hydrophobic seal, using asphaltine derivatives like gilsonite. Use of charged emulsifiers for binding the oil droplets of oil-in-water emulsions to the clay surface and organophilic clays in oil base muds could achieve similar results. Although changing the clay cation with less hydratable K+ or Ca2 + can reduce intrinsic swelling, these ions lead to more open structure and thus increase permeability. Work is currently underway to formulate drilling fluids containing cesium, Ce+ for stabilizing the shale. While this fluid would be very expensive to formulate, increased stability and rate of penetration could compensate for this cost. · Preserve mechanical integrity of the shale cuttings. As damage control, certain measures can be taken to limit the dispersion of cuttings or spallings by binding the clay particles together, if shale failure or erosion is initiated. Polymers that can reduce shale disintegration must adsorb Wellbore Stability in Shale 13 onto clay platelet surface and have high enough energy to resists mechanical or hydraulic forces pulling them apart. PHPA and strongly adsorbing cationic polymers and components like polyglycerol can limit the dispersion of shale cuttings or spallings in the well. To achieve similar results within the shale formation, polymer must be able to diffuse into the bulk shale, requiring short flexible chains. Future work on shale stability and understanding shale/fluid interaction is bound to lead to better means to stabilize shales and design of environmentally acceptable effective mud systems. As new additives for drilling fluids are studied to stabilize shales, major challenge would be to make them compatible with preserving other desirable mud properties such as, rheology, drilled solids compatibility and drilling rates [11] . Finally, even if we could design the best mud system for shale formations, continuous monitoring and control of drilling muds are critical elements for successful drilling. The mud composition continually changes as it circulates and interacts with formations and drilled solids. Unless concentrations of various mud additives are continually monitored (as opposed to the current practice of periodically monitoring just rheological and simple properties) and maintained, the desired results could not be achieved. The development and introduction of improved monitoring techniques for chemical measurements should proceed simultaneously with the development of more effective mud systems for shale stability, based on improved understanding of shale/fluid interaction. Conclusion: Key parameters that influence wellbore instability discussed are rock properties, in-situ stresses, pore pressure, wellbore trajectory, drilling fluid and drilling practices. Wellbore instability problems still exist today due to unknowns (values of rock data) and differences information drilled. Total prevention of wellbore instability is unrealistic. Reason is that we caused it and we cannot restore the in-situ rock conditions. Combined analysis (integrated approach) of wellbore stresses, mud chemistry, and excellent drilling practices is the key to minimizing wellbore instability. Nonetheless, although we cannot control what the drillers do, we can influence them and gaincredibility with them by understanding their problems, speaking their language, and letting them understand the consequences of their actions. With adequate planning and supervision the problems can be minimized. Wellbore Stability in Shale 14 References: 1. N. A. Ogolo , M. A. Onyekonwu and J. AAjienka, Application of Nanotechnology in the oil and gas industry (Port Harcourt: Institute of Petroleum Studies, 2011,pp.15– 16. 2. On the physical and chemical stability of shales By, Eric van Oort, Shell E&P Company, New Orleans, LA, USA 3. Understanding Wellbore Stability Challenges in Horn River Basin By Safdar Khan*, Sajjad Ansari, Hongxue Han and Nader Khosravi, Schlumberger Canada 4. Shale Stability: Drilling Fluid Interaction and Shale Strength By Manohar Lal, SPE, BP Amoco 5. Borehole Stability in Shale Formation for Extended Reach Wells By Zhao Kai*, Deng Jin-Gen, Tan Qiang, Yu Bao-Hua, Yuan Jun-Liang, Zhu Hai-Yan and Wang Ying 6. A Wellbore Stability Approach for Self-Killing Blowout Assessment By Stephen M. Willson, Apache Corporation, Houston, TX 7. E. N. Wami , Drilling Fluid Technology. Lecture notes, Port Harcourt, Rivers State University of Science and Technology, 2012 8. O. Osisanya, Practical Approach to Solving wellbore instability problems, SPE Distinguished Lecture series, Port Harcourt, 2012 9. B. Pasic, N. Gaurina and D. Mantanovic, Wellbore instability: Causes and Consequences, Rud-geol,Zb, vol. 19, 2007, pp. 87 – 98 10. W. Bradley, Bore Hole Failure near Salt Domes, paper SPE 7503 presented at the 53th Annual Technical conference and Exhibition of the SPE of AIME, Houston, Texas, 1-3 October, 1978 11. Tan and C.M. Haber field, A Comprehensive Practical Approach for Wellbore Instability Management, paper SPE 48898 presented at the 1998 SPE International Conference and Exhibition in China, Beijing,2-6 November, 1998.
Abstract:
An analysis approach to assess borehole stability following a hypothetical blowout from representative deep-water scenarios is presented. It addresses whether imposed underbalanced conditions cause sufficient instability that the borehole bridges-over and the well kills itself. The approach uses a series of interrelated analyses: (i) analyses of the kick and blowout development are performed predicting how bottom pressure and in-flow velocity changes over time; (ii) underbalanced wellbore failure in exposed shales and sands is then determined; (iii) caving and produced sand volumes are calculated from the estimated failure zone, and the transport of these materials in the borehole is determined from the predicted hydrocarbon flow rates; and (iv) bridging tendency is assessed by considering the concentration of caving in either the enlarged borehole or in flow-paths within the well casing or annuli.
To research the ERW borehole stability, including mechanical model, shale hydration test and the effect of circulating pressure loss in this paper, rock mechanics theory and hydraulics principle were comprehensively applied . The results show that, the safer drilling azimuth of the ERW in normal fault lies in the minimum horizontal principle stress direction; hydration radius increases with the passage of time, and the hydration collapsed rock has important influence on cutting beds and circulating pressure loss in annulus; the upper limit value of safety mud density decreases with the well depth increases, and when it deceases to the equivalent mud density of collapse pressure, the limit depth of the ERW is obtained. Factors affecting the shale strength are discussed, and a sonic compressional velocity-log based correlation for strength is proposed. Recommendations for modeling and improving shale stability are described, based on the current understanding of shale stability.
The mode of shale-stabilizing action of a wide variety of water-based fluid additives is discussed and the merits of various mud systems are ranked. It is shown that shale stabilization normally achieved using oilbased/synthetic-based muds is now becoming achievable with economical and environmentally friendly water-based drilling fluids. The field case presents a new challenge to the log-based wellbore stability interpretation routinely implemented in current drilling society. Being open-minded, closely monitoring and testing caving’s, and updating the model with drilling experience may be as important as the model development itself.
Introduction:
Uncontrolled influxes of formation fluids into a borehole (a “kick”) develop into a blowout when the drilling fluid is fully displaced from the well and the formation fluid exits the well. In the case of subsea deep-water wells, the wellhead is at the sea-floor and is connected to the drill rig by a marine riser. An influx of hydrocarbons, especially gas, is more severe than an influx of over pressured water. Occurrences of over-pressured water (“shallow water flows”) or shallow gas influx are well understood from a shallow hazards perspective [1].
As a kick develops, the drilling fluid is displaced from the well by the influx of less dense fluids that have a formation pressure greater than the hydrostatic pressure exerted by the drilling fluid. The bottom-hole pressure in the wellbore thus reduces during the developing kick, thereby accelerating the influx. Shales make up over 75% of the drilled formations, and over 70% of the borehole problems are related to shale instability. The oil and gas industry still continues to fight borehole problems. The problems include hole collapse, tight hole, stuck pipe, poor hole cleaning, hole enlargement, plastic flow, fracturing, lost circulation, well control. Most of the drilling problems that drive up the drilling costs are related to wellbore stability. These problems are mainly caused by the imbalance created between the rock stress and strength when a hole is drilled. The stress-strength imbalance comes about as rock is removed from the hole, replaced with drilling fluid, and the drilled formations are exposed to drilling fluids.
Wellbore stability is almost a trivial issue with oilbased and synthetics-based muds. Once mud weight and invert emulsion salinity are properly established, stability can virtually be guaranteed (except for a few cases such as fractured shale formations, which may be rapidly destabilized by such muds when they penetrate the fracture network, lubricate fracture surfaces, and equilibrate pore pressure with wellbore pressure) [2]. Moreover, oil and synthetic based muds in general drill wells much faster than water-based muds as they are much less prone to cause bit balling.
Causes of Wellbore Instability:
Wellbore instability manifests itself in different ways like hole pack off, excessive reaming, overpull, torque and drag, sometimes leading to stuck pipe that may require plugging and side tracking. This requires additional time to drill a hole, driving up the cost of reservoir development significantly. In case of offshore fields, loss of hole is more critical due to a limited number of holes that can be drilled from a platform [3]. Wellbore instability is usually caused by a combination of factors which may be broadly classified as being either controllable or uncontrollable (natural) in origin. These factors are shown in table given below.
Uncontrollable (Natural) Factors
Controllable Factors
Naturally Fractured or Faulted Formation
Bottom Hole Pressure (Mud Density)
Tectonically Stressed Formations
Well Inclination and Azimuth
High I-Situ Stresses
Transient Pore Pressures
Mobile Formations
Physico/chemical Rock-Fluid interaction
Unconsolidated Formations
Drill String Vibrations
Naturally Over-Pressured Shale Collapse
Erosion
Induced Over-pressured Shale Collapse
Temperature
1.
Uncontrollable factors
Naturally fractured or faulted formations: A natural fracture system in the rock can often be found near faults. Rock near faults can be broken into large or small pieces. If they are loose, they can fall into the wellbore and jam the string in the hole. Even if the pieces are bonded together, impacts from the BHA due to drill string vibrations can cause the formation to fall into the wellbore. This type of sticking is particularly unusual in that stuck pipe can occur while drilling. This mechanism can occur in tectonically active zones, in prognosed fractured limestone, and as the formation is drilled. Drill string vibrations have to be minimized to help stabilize these formations. Holecollapse problems may become quite severe if weak bedding planes intersect a wellbore at unfavorable angles. Such fractures in shales may provide a pathway for mud or fluid invasion that can lead to time-depended strength degradation, softening and ultimately to hole collapse. The relationship between hole size and the fracture spacing will be important in such formations
Drilling through naturally fractured or faulted formations
Tectonically Stressed Formations: Wellbore instability is caused when highly stressed formations are drilled and if exists a significant difference between the near wellbore stress and the restraining pressure provided by the drilling fluid density. Tectonic stresses build up in areas where rock is being compressed orstretched due movement of the earth´s crust. The rock in these areas is being buckled by the pressure of the moving tectonic plates. When a hole is drilled in an area of high tectonic stresses the rock around the wellbore will collapse into the wellbore and produce splintery cavings similar to those produced by over-pressured shale. In the tectonic stress case the hydrostatic pressure required to stabilize the wellbore may be much higher than the fracture pressure of the other exposed formations [4]. This mechanism usually occurs in or near mountainous regions. Planning to case off these formations as quickly as possible and maintaining adequate drilling fluid weight can help to stabilize these formations.
Drilling through tectonically stressed formations
High in-situ stresses: Anomalously height in-situ stresses, such as may be found in the vicinity of salt domes, near faults, or in the inner limbs of a folds may give rise to wellbore instability. Stress concentrations may also occur in particularly stiff rocks such as quartzose sandstones or conglomerates. Only a few case histories have been described in the literature for drilling problems caused by local stress concentrations, mainly because of the difficulty in measurin