Borehole Stability in Shales
- G.M. Bol (Koninklijke Shell E&P Laboratorium) | S-W. Wong (Koninklijke Shell E&P Laboratorium) | C.J. Davidson (Shell Gabon) | D.C. Woodland (Petroleum Development Oman)
- Document ID
- Society of Petroleum Engineers
- SPE Drilling & Completion
- Publication Date
- June 1994
- Document Type
- Journal Paper
- 87 - 94
- 1994. Society of Petroleum Engineers
- 1.11 Drilling Fluids and Materials, 1.14 Casing and Cementing, 5.1 Reservoir Characterisation, 1.2.5 Drilling vibration management, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 1.2.2 Geomechanics, 1.6 Drilling Operations, 4.3.1 Hydrates, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 4.1.2 Separation and Treating, 1.11.2 Drilling Fluid Selection and Formulation (Chemistry, Properties), 4.1.5 Processing Equipment, 4.3.4 Scale
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Downhole mud/shale interaction can only be properly understood if rock mechanical, shale hydration, and fluid transport phenomena are taken into account. This paper presents a review of Koninklijke Shell E&P Laboratorium's research on borehole stability in shales. Mechanisms relevant to shale stability, including pore pressure penetration (the gradual increase in pore pressure resulting from high mud weight), capillary threshold pressures, compressive and tensile failure, postfailure stabilization, hydration stress, inhibition, and osmotic phenomena are discussed. We attempt to integrate these mechanisms into a comprehensive model for shale behavior.
Borehole instability in shales is a major source of trouble, time, and cost during drilling. Problems generally build up over time, beginning with fragmentation at the borehole wall, followed by transfer of fragments to the annulus, and culminating in such problems (if hole cleaning is insufficient) as a sticky or tight hole, packing off, hole fill, and stuck pipe. Consequences may include losing the hole, having to sidetrack, inability to log, and poor cementations because of excessive washouts.
New technologies (e.g., horizontal, slim-hole, and coiled-tubing drilling) will not resolve borehole instability problems; they will lead to at least as many problems as conventional drilling.
This paper addresses the mechanisms behind shale failure and the transfer of failed material to the annulus. A proper understanding and prediction of hole cleaning is equally important but requires separate treatment.1,2
Causes of Borehole Instability in Shale
Borehole instability in shale is a complex phenomenon. Five basic problem areas can be distinguished: (1) drilling through a naturally fractured shale, (2) drilling through a brittle shale and inducing fragmentation through drillstring vibrations, (3) causing shale failure with too high a mud weight (tensile fracturing), (4) causing shale failure in a compressive mode through insufficient mud-weight support, and (5) causing shale failure in a tensile mode through hydration stress.
In Case 1, the harm is already done, and only postfailure stabilization and optimum hole cleaning can help relieve problems. In Case 2, reduction of drillstring vibrations may offer additional relief.3,4 The third case, involving classic tensile fracturing, is not considered. This paper addresses the mechanisms underlying compressive and tensile failure and postfailure stabilization of shales.
First, the effect of low shale permeability on borehole stability is discussed, followed by presentation of a poroelastoplastic model for rock mechanical behavior. How postfailure stabilization may alleviate shale problems is discussed, and finally, mud/shale interaction in terms of the shale's intrinsic hydration stress is addressed.
Shales, like other materials, only fail if the effective stress state exceeds the failure envelope. This is valid for compressive and tensile failure at the borehole wall and also for failure of cuttings and cavings (disintegration, dispersion). Therefore, the models presented here are formulated in terms of downhole pressure, stress, and strength effects.
Shales are relatively ill-defined rocks and may include both highly cemented shaly siltstone and weak gumbo-type shales consisting primarily of hydratable clays. Major differences in shale behavior can be attributed to these differences in composition. We define shale as a low-permeability rock where the matrix consists, at least partially, of clays.
How Low Permeability Affects Shale Behavior
Hydraulic Flow Through Shale.
Shales have permeabilities ranging from ˜1×10-6 to 1×10-12 darcy. Because of these low permeabilities, no "normal" fluid loss occurs and no filter cake builds up on the borehole wall. Instead, gradual equilibration between mud and pore pressures takes place unless a barrier is present at the borehole wall. In the case of microfractures, a shale behaves as a dual-permeability medium, with high permeabilities in the microfractures and low permeabilities in the bulk of the material. With mud in overbalance, equilibration takes place from the wellbore to a semi-infinite medium and results in transient pore pressures, penetrating from the wellbore outward. Note that only a minor amount of filtrate invasion is required to raise the pore pressure over a considerable trajectory away from the wellbore. When drilling in overbalance, pore pressure penetration invariably leads to a less-stable situation at the borehole wall.
To measure the rate of mud-filtrate invasion as a function of filtrate and shale composition, we have developed the microfiltration cell (Fig. 1). The principle of the test is simple: a confined shale core sample is put into contact with a simulated pore fluid on one side and with mud on the other side. Overbalance is applied to the mud, and the rate of pressure increase at the pore-fluid side is measured. The method has been used to screen muds and mud additives for their capacity to reduce or to prevent pore pressure penetration. The pressures applied were 3.5 and 0.35 MPa on the mud and pore-fluid sides, respectively. Mud is preceded by distilled water as a baseline measurement. After a set period (from 1 to 7 days, depending on the test), the pressure is bled off, the water is replaced by mud, the fluids are repressurized, and the test continued. Tests carried out so far on Pierre shale cores have already yielded interesting results.
Fig. 2 shows the results of a test with a 3% KCl/bentonite/partially hydrolyzed polyacrylamide (PHPA) mud. The rate of pore pressure penetration is very similar to that of water. Micron-sized (and larger) particles and high-molecular-weight polymers apparently cannot plug off the shale surface, let alone invade the pore system. This can easily be understood because of the ˜1- to 10-nm pore size and the general rule of plugging by particles - one-third to one-seventh of the pore diameter.
Fig. 3 shows the results of a test with sodium silicate solution (water glass). In this case the "mud" can reduce the rate of pressure penetration to almost zero. The silicate reacts with the divalent ions present in the shale pore fluid to yield a gelatinous precipitate that plugs off the pore system.
Fig. 4 shows the results of a test with a 25% sucrose solution. Again, the rate of pressure penetration is significantly reduced. Apparently, the sugar molecules are small enough to enter the pore system and impart high viscosity to the invading filtrate. A similar advantageous effect of sugar was seen earlier in cutting-disintegration tests.5
Fig. 5 shows the results of a test with oil-based mud (OBM). Clearly, the OBM does not penetrate the shale. An explanation is given in the next paragraph.
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