An experimental investigation was begun to understand fundamental borehole stability mechanisms. This laboratory study was directed toward understanding why and how drilling-fluid chemistry affects borehole stability. The ability of drilling-fluid chemistry to alter shale mechanical behavior and the borehole stress state as a result of shale water content alteration was investigated. Experimental results demonstrate the influence of various drilling-fluid parameters (e.g., salt concentration, salt type, and diesel/water ratio) in @il-based drilling fluids on the water content, compressive strength, and mechanical properties of five shales. The influences of temperature and drilling-fluid exposure time on shale strength alteration also are addressed. The results are explained on the basis of chemical potential differences between oil-based drilling fluid and shale. The change in the shale water content caused by these differences is identified as the predominant factor leading to alteration of shale mechanical behavior and hence borehole stability.

Summary. Previous attempts to predict the effects of drilling fluids on borehole stability in shale have been unsatisfactory. This paper describes laboratory equipment capable of simulating downhole conditions to permit evaluation of drilling fluids by testing the alteration of natural shale specimens when drilled and exposed to drilling fluid under an annular flow regime for an extended period of time. The paper discusses ramifications of the shale alteration relative to such operational problems as torque, drag, and stuck pipe. Introduction Borehole stability is a critical factor in the cost of drilling and completing a well. Some of the problems caused by an unstable borehole are high torque, drag, bridging, and fill; stuck pipe; difficulty with directional control; slow rate of penetration, high mud costs; cementing failures and high cementing costs; and failure to obtain logs and poor log interpretation. Most borehole instability occurs when water-based muds are used to drill shale formations. Such borehole instability is related to hydration and dispersion mechanisms, which in turn are related to the interaction of shale with the drilling fluid. Laboratory and field studies have shown that shale hydration and borehole instability can be avoided by the use of oil mud with activity of the emulsified internal water phase equal to or less than the in-situ activity of the water in the shale formation. Environmental considerations, however, often preclude the use of oil mud. Efforts to characterize shales and to predict stability in different types of water-based drilling fluids have met with little success. This lack of success can be attributed to the complexity of the shale/drilling-fluid interactions that include surface hydration, osmotic swelling, cation exchange, anion adsorption, and alkali-alteration phenomena. Borehole conditions created by these interactions, in turn, depend on exposure time, temperature, and stresses of the shale, as well as shear stress and shear rate of the fluid at the shale surface. With so many factors involved, the tendency has been to rely on simple tests, such as those for shale swelling by Chenevert, shale dispersion by Anderson and Edwards, and capillary suction time by Wilcox and Fisk as guides to drilling-fluid selection. While useful as part of an overall laboratory or field study, these tests of unconfined, unstressed shale at ambient conditions of temperature and pressure can be very misleading if used alone to predict the effects of a drilling fluid or additive on shale stability. A problem as complex as shale stability can best be addressed by studies of shales exposed to drilling fluids under simulated downhole conditions. Previous studies of this general type have provided much-needed guidance, but each study has failed to simulate one or more significant parameters. For example, the model borehole studies reported by Darley and Clark et al. simulated vertical stress, radial stress, and mud pressure, but not downhole temperatures. Studies reported by Simpsons included simulation of downhole temperature, but not vertical stress. With laboratory evaluations that are limited in scope and often misleading, the present tendency of drilling personnel is to look for improved shale stability from water-based drilling fluids on a trial-and-error basis. A research project was organized under the auspices of the Drilling Engineering Assoc. to develop a laboratory method to predict shale stability under simulated downhole conditions. The downhole simulation cell (DSC) equipment described below resulted from that program and now provides the industry with the means to evaluate drilling-fluids performance without the time, expense, and risk of a series of blind field trials. DSC Equipment The DSC equipment shown schematically in Fig. 1 and by photograph in Fig. 2 provides laboratory simulation of overburden stress and confining pressure, as well as downhole temperature, fluid circulating pressure, and shear rate at the wall of the hole during drilling and circulating through a rock specimen. Downhole conditions can thus be simulated for a variety of studies of fluid/rock interactions. For example, in addition to the borehole-stability studies discussed in this paper, the DSC equipment has been used to study dynamic filtration during drilling of permeable rock. Key elements of the DSC system are identified in Fig. 1 and discussed below. Not indicated in Fig. 1 is the PC data-acquisition system for monitoring drilling parameters and collection of time-based information during the testing. Sample Vessel and Drilling Subsystem. The sample vessel, shown in the left center background of Fig. 2, allows the use of rock specimens up to 7 in. [17.8 cm] in diameter and 9 in. [22.9 cm] in length. A hydraulic ram is used to provide overburden stress on the specimen, with a maximum stress of approximately 10,000 psi [69 MPa] possible on specimens with 6.4-in.[16.3-cm] OD. Heat-transfer oil is used as confining fluid inside the specimen chamber. The maximum allowable confining pressure is 7,000 psi [48.3 MPa]. A bit-position/drilling-force hydraulic cylinder, which provides bit motion and force on bit during drilling, is used to drill completely through the rock specimen. Rotation of the bit shaft is provided by two hydraulic motors. Mud flow through the bit is obtained by means of a swivel seal in the vessel base. Provisions are made for mud circulation through the specimen after the hole has been drilled and the bit and drill shaft have been retracted. Mud is circulated through the ram piston on the top of the vessel. Cuttings removal and mud return circulation are provided by 0.75-in.[1.9-cm] tubing going to the cuttings catch vessels. This vessel is heated with 480-V band heaters. Copper coils embedded in the outer periphery of the vessel provide cooling. Water is flowed through the cooling coils at the end of the shale exposure testing to cool the specimen sufficiently for removal from the vessel. A caliper assembly was devised to measure borehole enlargement while testing was in progress. The mode of rock deterioration usually observed, however, has been softening or weakening of the shale, rather than hole erosion. This finding led to the use of the caliper shaft as an assembly placed in the hole to create an annulus for flow during the test, without extensive use of the caliper function. The annular velocity and circulating information in Table 1 is based on the 1.0-in. [2.54-cm]diameter of the caliper assembly and a 1.25-in. [3.18-cm] hole diameter. Circulation Pump. A balanced piston pump, designated "mud pump" in Fig. 1 and shown in the center of Fig. 2, is used to circulate the fluid through the rest of the system. The pump consists of a liner with a reciprocating shaft and attached piston. The shaft motion is provided by a large hydraulic cylinder. Four air-actuated valves are controlled electronically to provide circulation of the drilling fluid in a single direction with a minimum of pressure surging.

While oil-base muds have given satisfactory performance in the past, environmental concerns performance in the past, environmental concerns motivate the further development of water-base muds. Often associated with water-base muds are operational problems such as bit balling, high torque, and stuck problems such as bit balling, high torque, and stuck pipe. Tests commonly used to evaluate muds are pipe. Tests commonly used to evaluate muds are typically conducted on nonpreserved, unstressed shale and disparate formations. There is a need, therefore, for means of evaluating non-oil mud systems in the laboratory to predict relative performance under field conditions. This paper describes two methods of testing water-base muds on preserved, stressed shale specimens. One test method utilizes the Microbit Drilling Rig (MDR) to study bit balling characteristics of shale in a given mud system. The test results showed that the clay matrix of the rock can influence balling. The type of cations present are critical, whereas cation exchange capacity present are critical, whereas cation exchange capacity and moisture content are not directly correlatable to bit balling. Analysis of the rock to determine composition and plasticity can be used to determine the tendency of a given formation to ball the bit. The second method utilizes the Downhole Simulation Cell (DSC) to study wellbore instability resulting from exposure of shale to drilling muds under downhole temperature and stress conditions. An elasto-plastic model is presented showing how mud type can affect wellbore stability. These results caution against reliance on tests of unconfined shale particles (cuttings) or even unconsolidated shale specimens when studying effects of muds on shale instability. Tests results from the MDR and DSC test equipment can be used to develop data bases for the selection of mud system and bit type and to suggest hydraulics to prevent balling of PDC bits. The data has been applied prevent balling of PDC bits. The data has been applied to the selection of a water-base mud that reduced both mud and operation costs when drilling deviated wells in the Gulf of Mexico. Introduction In previously reported investigations, bit balling has been explained in terms of mechanical and chemical factors. Mechanical explanations relate balling to differential sticking of the cuttings to the cutter due to the difficulty in getting fluid between the cutter and the cutting and to differential sticking due to dilatancy in the shear zone of the cutting causing a drop in cutting pore pressure. Chemical explanations relate balling to the tendency of the drilling fluid to wet the surface of the bit, allowing the cutting to stick, differential sticking of the cuttings due to swelling as hydrophilic cuttings attempt to imbibe water, and the reactivity of the clay as measured by its Cation Exchange Capacity (CEC). These chemical theories imply that shales should ball badly if they have (1) high CEC, (2) small particle size, (3) large surface area, and (4) high smectite content, especially sodium smectite. P. 393

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