Well designs are constrained by the variation of both the pore pressure and fracture gradients throughout the depth of the well. Each hole section is designed such that the pressure profile within the hole at any time during drilling will not exceed the fracture pressure profile at any point throughout that section. The maximum pressures catered for in the design are invariably dictated by permeable formations with the highest pore pressure gradient. The casing depths are set to put behind pipe formations with too weak a fracture gradient to resist the planned pressure profile expected during drilling. This prevents a weak formation from failing and cross flow occurring between that failed zone and any high pressure permeable formations within the same hole section. The fracture gradient is typically determined by measuring the pressure at which losses begin to occur in the hole section and converting the downhole pressure into an equivalent mud weight. Most operators and mud companies have observed that the addition of some mud additives has influenced the pressure at which these induced losses begin. However, the use of those additives has been unreliable in many instances. Recent work at BP has resulted in the development of a physical model that describes the mechanism that allows the fracture resistance to increase above conventional minimum horizontal stress through the addition of mud additives. These additives result in the formation of a "stress cage" which is a near wellbore region of high stress induced by propping open and sealing shallow fractures at the wellbore/formation interface. With the development of the physical model it is now possible to analyze the effects of different drilling practices upon the reliability and stability of those induced stress cages. The development of stress cages is influenced by a number of properties including the diameter of the borehole, the width of fractures induced in a formation, the range of particle sizes which can be used as proppant in the fracture, the sealing properties of the mud, and the permeability of the formation. The successful implementation of the stress cage mechanism is dependent upon the use of appropriate constructive drilling practices and avoidance of detrimental practices which may destabilize the stress cages. Introduction Operators and mud companies have observed for many years that the addition of certain products to the mud appeared to reduce the frequency and severity of lost circulation events. It has become common practice in many areas to simply include additives such as sized calcium carbonate and graphite to the mud system as a preventative and pre-emptive measure. However, results from the use of these additives have not appeared to be consistent. Hole sections drilled with a pilot bit may not experience losses while the same hole section re-drilled with an underreamer experiences severe looses even though equivalent circulating density is the same. Holes that withstand pressures in an apparent stable environment are not able to withstand similar hydrostatic pressure once losses are initiated. The industry has lacked a physical model to explain why the addition of mud additives, such as calcium carbonate and graphite, has apparently increased the fracture resistance of common rocks. A physical model has now been proposed to describe what is occurring when these additives are used and a numerical model developed to quantify the size of fractures, the impact of those fractures upon concentric stresses to the wellbore, and the concentration of particles necessary to plug the fracture and capture the induced stresses as an increase in apparent fracture resistance. Physical Model Description Typically, large fluid losses to a formation will be via a fracture which has been induced through drilling operations or was a pre-existing natural facture. If pre-existing, the fracture may be permanently open, in which case losses to the formation may occur at mud column pressures only nominally in excess of the formation pressure. This work and model is associated with induced fractures resulting from excessive mud pressures. Many publications make reference to the standard geomechanical approach to determining a fracture gradient1,2. These centre on adopting equations first published by Leeman and Hayes3 or Hubbert and Willis4 if basing the fracturing process on the near wellbore stress state, or using an Eaton5 and/or Daines6 approach if basing fracturing on the least principal earth stress.

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There is a clear advantage to drilling if we could strengthen the wellbore and drill at higher mud weights without losing fluid. A major prize is accessing difficult reserves in depleted reservoirs. Another application is in deep water drilling where the drilling window between pore pressure and fracture gradient is often narrow. This paper describes the approach taken by BP to produce a ‘designer mud’ which effectively increases fracture resistance whilst drilling, and which can be applied in both shale and sandstone. It works by forming a stress cage using particle bridging and an ultra-low fluid loss mud system. The theory is described and laboratory data show how the fluid system was developed. Field data are shown which quantify the increase in fracture resistance and demonstrate the value of the system. Logistics issues are discussed. Introduction Mud losses are a frequent problem encountered during drilling. Induced losses occur when the mud weight, required for well control and to maintain a stable wellbore, exceeds the fracture resistance of the formations. A particular challenge is the case of depleted reservoirs. There is a drop in pore pressure as the reserves decline, which weakens hydrocarbon-bearing rocks, but neighbouring or inter-bedded low permeability rocks (shales) may maintain their pore pressure. This can make the drilling of certain depleted zones virtually impossible - the mud weight required to support the shale exceeds the fracture resistance of the sands and silts. The potential prize is clear if we could devise a way to strengthen the weak zones and thereby access these difficult reserves. In fact, the value of wellbore strengthening is much more wide-ranging and includes the following applications/benefits:Access to additional reserves (depleted zones)Reduced mud losses in deepwater drillingLoss avoidance when running casing or cementingImproved well controlElimination of casing stringsAn alternative option to expandable casing This paper describes development work at BP to produce a drilling fluid that effectively strengthens the wellbore whilst drilling. The fluid can also be used in pill form. The effect is achieved by changing the stress state rather than by altering the strength of the rock itself. Such a system will have great utility if it can be engineered in a practical way. Previous studies have investigated wellbore strengthening with a view to preventing mud losses. One method1 suggests using temperature changes to alter the stress state around the wellbore. Mud heaters can be used to heat the circulating fluid and increase near-wellbore stresses, thereby giving a strengthening effect. However, this method might be difficult to control and would not be suitable in wells with an already-high bottom hole temperature. The 1992 paper by Fuh2 discusses the concept of adding granular particles to the mud to seal fractures and prevent losses; it is stated this could only work in permeable rocks where leak-off into the rock allows a cake to build in the fracture. Other work has discussed the concept of using fractures to cause stress changes in the rock - introducing the idea that fractures could increase the hoop stress around the wellbore. This is discussed by Morita and Messenger3,4. Alberty and McLean5 discuss how mud cake deposition in the fractures can affect near-wellbore stresses, and they give field examples suggesting large increases in fracture resistance. Recent papers by Sweatman et al6,7 have taken this concept and developed chemical treatments which could be squeezed into fractures to prop them open and seal them. Theoretical Approach In developing the above ideas, the approach we have taken is to actually allow small fractures to form in the wellbore wall, and to hold them open using bridging particles near the fracture opening. The bridge must have a low permeability that can provide pressure isolation. Provided the induced fracture is bridged at or close to the wellbore wall this method creates an increased hoop stress around the wellbore, which we refer to as a ‘stress cage’ effect. The aim is to be able to achieve this continuously during drilling by adding appropriate materials to the mud system, to produce what we have termed a ‘designer mud’. The concept is illustrated in Figure 1.

Geopressured water sands near the mudline in deep water, greater than 1,000 ft, have been shown to be hazards when these sands are permitted to flow outside structural and 20-in. conductor pipe. Special drilling practices are required to contain the pressure during drilling and casing operations.Four mechanisms have been identified as causes of shallow waterflows: ͑1͒ induced fractures, ͑2͒ induced storage, ͑3͒ geopressured sands and ͑4͒ transmission of geopressure through cement channels. Geoscience techniques have been developed to aid in the detection of the shallow waterflow mechanisms, prior to drilling. These techniques include seismic stratigraphic interpretation of shallow hazard airgun data and specially processed threedimensional surveys, and special pore pressure and fracture gradient prediction methods.Drilling and cementing practices have been developed to minimize the risk of inducing flow behind structural and conductor casings. Each of these flow mechanisms require adapted drilling and cementing practices to prevent potentially damaging flow.This paper presents best practices developed by this operator along with our contractors to detect, drill, case, and cement shallow waterflows in the deepwater Gulf of Mexico. These practices should be transferable to other similar sites around the world.

The increase in complexity and associated costs with wells as a result of infield drilling, drilling below old fields and striving for deeper targets has generated industry interest and attention in wellbore strengthening. This heightened interest is demonstrated in the number of recent publications that have been prepared on the subject. These have primarily focused on and described methods that are effective in raising the fracture resistance of permeable formations such as sands. However, a much bigger impact can be made on the overall drilling operation if it is also possible to strengthen low permeability rocks such as shale along with the sands. The industry has seen this as a major challenge and to date the technology and expertise required to achieve this has not been consistent or reliable. This paper will demonstrate that wellbore strengthening in shale is indeed feasible. A treatment pill was developed in the laboratory and successfully field tested at a US land-based location. The treatment consisted of a blend of particulates (known as stress cage solids) and proprietary cross-linked gelling polymers which set with time. Properties of the system such as compressive strength, adhesion to shale and the sensitivity to temperature and pressure were evaluated, and modeling work was done to engineer the size and concentration of bridging solids required. Field testing was carried out in a 50-ft section of competent shale below the 9"-in. shoe in an operation where oil-based mud was being used. The initial fracture gradient was measured using leak-off tests to establish the native formation strength. The treatment was squeezed and allowed to set under pressure before drilling out, leaving a strengthened wellbore. Formation Integrity Tests (FIT) were conducted to confirm the presence of the strengthening effect. The robustness of the treatment was demonstrated by circulating drilling fluid for increasing periods of time and performing further FIT tests. The well was left in a strengthened state at the end of the test period. This trial demonstrates that by using appropriate technologies and methods it is indeed possible to reliably raise shale fracture resistance. Introduction Emphasis on "Wellbore Strengthening" has been growing over the past few years, as reflected by the increase in frequency and variety of technologies that have been applied to this goal. Options ranging from cement and chemical resins to tools (i.e., expandable casing, casing drilling) have been employed to strengthen wellbores. The primary impetus of these endeavors has been time and cost (actually one in the same), although extending the drilling envelope has been becoming increasingly important. Drilling in depleted zones, or intervals where high pressured formations are interbedded with normally and abnormally pressured layers, has given rise to the need for implementation of these strengthening technologies. The goal is to raise the fracture resistance of weaker formations and thereby avoid whole mud losses, wellbore instabilities and potential loss of the drilled interval. The primary consequences of these undesired events are an increase in the well non-productive time (NPT) and associated costs. In addition to avoiding these problems, the economic benefits that wellbore strengthening can provide is the possible elimination of a casing string or more importantly, the ability to reach deeper reservoir targets.