A Physical Model for Stress Cages
- Mark W. Alberty (BP Exploration) | Michael R. McLean (BP Exploration)
- Document ID
- Society of Petroleum Engineers
- SPE Annual Technical Conference and Exhibition, 26-29 September, Houston, Texas
- Publication Date
- Document Type
- Conference Paper
- 2004. Society of Petroleum Engineers
- 1.7 Pressure Management, 2.4.3 Sand/Solids Control, 5.1 Reservoir Characterisation, 1.11.2 Drilling Fluid Selection and Formulation (Chemistry, Properties), 1.2.2 Geomechanics, 1.6 Drilling Operations, 5.1.2 Faults and Fracture Characterisation, 3 Production and Well Operations, 1.11 Drilling Fluids and Materials, 1.1.6 Hole Openers & Under-reamers, 2.5.2 Fracturing Materials (Fluids, Proppant)
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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.
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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