During the past three decades, the oil industry has expended increasing efforts seeking improved drilling tools or systems to reduce drilling costs. The total cost of these efforts is unknown, but it certainly amounts to tens of millions of dollars. Most of the "new" systems that past and present investigators have sought to develop actually are old public information. In seeking to implement new-system concepts, investigators have tested the following: impact at frequencies ranging from 6 to 300 cycles per second; electrical, mechanical and hydraulic means of actuating percussors; bit rotary speeds up to 2,000 rpm; electric and hydraulic bottom-hole means of rotating bits; bottom-hole machines with power outputs up to 400 hp; shock waves; explosives; high-velocity pellets; flame; arc; grinding wheels; abrasive jets; erosion by high-velocity gases;chemical attack; electric current; magnetic waves; retractable rock bits; reelable drill pipe; continuous coring with reverse circulation; and automation of drilling rigs. Table 1 shows how these investigations are grouped for discussion purposes in this paper. In spite of these efforts to discover new and improved systems, rotary drilling maintains its economic leadership. Undoubtedly, rotary drilling costs will continue to be reduced by rigid application of the best available technology and by development of new rotary technology. In view of the extensive past development programs, however, significant long-range improvement appears to be a research, not a development problem. Research must postulate and prove theories and principles governing various subsurface rock-failure processes pertinent to both rotary and new systems. Also, research must produce physical and engineering data relative to these processes. When such information is available, earth boring will graduate from an art to a science. Major improvements in rotary drilling can then be expected, and the systematic evolution of an improved drilling method can be initiated-with a strong probability for success.

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