Most wellbore stability problems occur in shale formations. Unfortunately, shale properties range from very soft to very hard, and from very laminated to very intact. Several mechanisms cause wellbore instability problems (Figure 5-5); chemical and mechanical effects will be discussed in this section.
Chemical Effects
Ion-exchanging clays, such as illite, mica, smectite, chlorite, mixed-layerclays, and zeolites, can cause many wellbore instability problems. Engineers may erroneously try to model failure mechanisms with analytical or empirical mechanical models while the main mechanism may be failure because of chemical effects. The following failure mechanisms during wellbore construction can be related to chemical causes.
Clay Swelling (Hydration) and Migration
Most shale formations contain water-sensitive clay materials such as smectite, illite, and mixed-layer clays, which absorb water that induces an elevated localized pressure. This pressure reduces the effective stress around the wellbore, which causes the shale matrix to swell, disintegrate, and collapse (Dusseault and Gray, 1992). Mody and Hale (1993) developed a model that incorporated mechanical and chemical effects to evaluate the
drilling fluid on shale stability.
Ion Exchanging
Brines such as KCl can control clay swelling, but illite, chlorite, smectite, and mixed-layer clays can change the brine through ion-exchanging mechanisms and swell afterward.
Cementation Deterioration
When examining sand formations, engineers must study the degree and type of cementation. Mineralogical analysis, thin-section petrography, and fluid compatibility are viable testing methods for evaluating sand production.
Near-Wellbore Damage
Near-wellbore formation damage can occur because of paraffin deposits, scale deposits, fines migration caused by kaolinite and illite clays, asphaltene precipitation, sand production, emulsions induced by iron, formation of oil emulsions by acid in combination with soluble iron, iron-compound precipitation, and even emulsions formed from fracturing fluids during stimulation.
To overcome these chemical effects, engineers should select the type of drilling-fluid system based on its effect on formation strength. The effects of the chemical and physical properties of the drilling-fluid system on formation stability should be lumped and the drilling-fluid system should be evaluated on the basis of rock mechanics. The following example shows an easy technique that would lump all chemical effects and evaluate the drilling-fluid systems based on rock mechanics.
Example: Drilling-Fluid Selection—A Rock Mechanics Perspective
Available Data
Six drilling-fluid samples are being evaluated for use through a shale segment that exhibited many instability problems during drilling. Show how these systems can be evaluated on the basis of rock mechanics.
Solution
The core samples should be preserved after coring, and no cleaning or drying processes should be conducted. The samples should be brought to their estimated in-situ stress fields at a suggested value of the confining pressure (Pc = Pw - Pr). The same strain rate (for example, 10-4 sec-1) or the same loading rate (for example 5 to 10 psi/sec) should be used for all tests. The samples should be cut in the same manner and same direction (vertically or horizontally). Two samples for each drilling-fluid system and two samples with no drilling fluid should be tested for repeatability. Two samples should be saturated in each drilling-fluid system for the same length of time (for example, 1 month) in addition to the two other samples that should be left in closed jars as the base samples. This procedure is applied to optimize the drilling-fluid system based on the compressive strength and Young's modulus reduction obtained for these systems. The results are given in Figure 5-6.
Figure 5-6 The effect of different drilling fluid systems on the
mechanical properties of shale samples
System 5 was selected to drill the given shale section. Notice how both the compressive strength and Young's modulus were affected by the different drilling-fluid systems.
Mechanical Effects
Tensile and shear failure mechanisms should be considered for wellbore stability evaluation during drilling.
Tensile Failure
The effective stress at the wellbore exceeds the tensile strength of the formation and causes tensile failure. Therefore, an induced fracture can result because of drilling-fluid loss if
For an elastic medium, this is given by (Haimson and Fairhurst, 1967)
However, if a natural fracture exists, then the tensile strength, T, should be assumed to be zero.
Shear Failure
Once a wellbore is drilled and a stress concentration field is established, the rock will either withstand the stress field or yield, resulting in a near wellbore breakout zone that causes spalling, sloughing, and hole enlargement. An appropriate failure criterion should be used for evaluation of this type of failure.
Drilling-Fluid Weight
Drilling-fluid weight should be calculated as a means of preventing the initiation of tensile and shear (plastic) failures. In some formations, the drilling-fluid weight should prevent creeping in viscoplastic formations, such as salt rock. Drilling-fluid weight is an important consideration for treating wellbore instability problems. The drilling-fluid weight is limited by two boundaries:
• The upper boundary is the pressure that causes tensile failure and
drilling-fluid loss. This pressure can be determined in the field based
on Equation 5-44.
• The lower boundary is the pressure required to provide confining stress, which is removed during drilling. The confining stress prevents shear failure, the creation of a plastic zone, and plastic flow (creep).
The upper boundary is estimated from the in-situ stress field, and the tensile strength is measured in the laboratory. While the lower boundary is estimated from the in-situ stress field
0 comments:
Posting Komentar