A borehole-stability model that uniquely couples the mechanical and chemical aspects of drilling-fluid/shale interactions was developed. The model allows the user to determine the optimum drilling parameters (e.g., mud weight and salt concentration) to alleviate borehole-stability-related problems with oil-or water-based drilling-fluid systems. Chemically induced stress alteration based on the thermodynamics of differences in water molar free energies of the drilling fluid and shale is combined with mechanically induced stress. These two potentials are coupled by use of the framework of poroelasticity theory to formulate the physiochemical basis of this borehole-stability model. IntroductionShales make up more than 75 % of drilled formations and cause more than 90 % of wellbore-instability problems. 1 Drilling shale can result in a variety of problems, ranging from washout to complete hole collapse. More typical drilling problems in shales are bit balling, sloughing, or creep. The problems are severe and have been estimated conservatively to be a $500 million/ yr problem for the industry. 2 These engineering problems are closely connected with the "bulk properties" ofthe shale, such as strength and deformation as a function of depositional environment, porosity, water content, clay content, composition, and compaction rates. The drilling-fluid bulk properties (such as the chemical makeup and concentration of the continuous phase of the mud; the composition and type of an internal phase, if present; the type of additives associated with the continuous phase; and the maintenance of the system) also are of utmost engineering importance. Other factors-in-situ stresses, pore pressure, temperature, time in open hole, depth and length of openhole interval, surrounding geological environment (salt stringers, dome, etc.)-also directly affect drilling and completion operations and must be integrated into any model and new mud system development. These variables are interconnected and influence the overall behavior of shales during drilling.Understanding the influence of these factors on shale behavior is necessary before 'Now with Baroid Drilling Fluids Inc.

Summary Transport of water and ions in shales and its impact on shale stability were studied to facilitate the improvement of water-based muds as shale drilling fluids. Transport parameters associated with flows driven by gradients in pressure and chemical potential were quantified in key laboratory and full-scale experiments. The experimental results show that the low-permeability matrices of intact, clay-rich shales can act as imperfect or "leaky" membranes that will sustain osmotic flow of water. Moreover, the ability of shales to act as osmotic membranes is shown to provide a powerful new means for stabilizing these rocks when exposed to water-based drilling fluids. Guidelines are presented for effective exploitation of shale membrane action and induced osmotic flows through optimized water-based drilling fluid formulation. In addition, special attention is given to induced electro-osmotic water flow in shales driven by electric potential gradients, which may provide an exciting, new, environmentally benign means for stabilizing shale formations. Introduction Borehole instability in shales is the prime technical problem area in oil and gas well drilling, with lost-time and trouble costs for the drilling industry conservatively estimated at $500 million/year. Moreover, the industry is currently facing new technical and environmental challenges associated with drilling increasingly difficult wells (e.g., horizontal multilaterals and extended reach wells) and replacement of poorly biodegradable oil-based muds (OBM's) that are technically superior but environmentally unacceptable. Waterbased muds (WBM's) are attractive replacements from a direct cost point-of-view, but conventional WBM systems have shown poor shale drilling performance in the past and in general have failed to meet other performance criteria associated with ROP, bit- and stabilizer balling, lubricity, filter cake quality, and thermal stability. Shale stability has greatly suffered from a lack of understanding of shale/drilling fluid interactions. Drilling problems have too often been approached on a trial-and-error basis, going through a costly multiwell learning curve before arriving at satisfying solutions. With the arrival of sophisticated new shale test techniques, new understanding of shale instability has emerged, enabling a more proactive approach to the design and application of water-based shale drilling fluids.

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.

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This paper presents a huff-n-puff gas injection method to increase condensate production in an Eagle Ford gas condensate reservoir using a simulation approach. The simulation study suggests that the huff time and puff time should be the same. Because of higher compressibility of a gas condensate fluid, either huff or puff time required will be longer than that for a shale oil reservoir. For the studied reservoir, an optimum huff or puff time is about 600 days. However, a shorter time of 300 days is preferable for recouping the cost for facilities. To improve the overall liquid condensate recovery performance, during the last half of the development period, the huff-n-puff may be changed to pressure depletion so that the energy injected earlier can be fully utilized. Other effects such as those of initial water saturation, injection pressure, and gas composition, are also investigated in this paper. The methodology presented in this paper is applicable to other gas condensate reservoirs, and some of results or conclusions may be typical of gas condensate reservoirs.