Wellbore instability in shales is a major problem costing the petroleum industry US$900 million annually, according to conservative estimates. Water-based drilling fluids are being increasingly used to drill through troublesome shale formations. Major drivers for using water-based drilling fluids over oil-based drilling fluids are their cost-effectiveness and greater environmental acceptability. Despite these incentives to use water-based drilling fluids, improper application of such fluids while drilling sensitive shale formations can lead to costly wellbore instability problems. For correct application of water-based drilling fluids, an in-depth understanding of their physico-chemical interaction with the shale formations being drilled is important. Shale stabilization with water-based drilling fluids can be achieved through a combination of osmotic outflow of pore fluid (chemical potential mechanism) and minimization of mud pressure penetration. Mud pressure penetration can either be prevented by generating an isolation membrane on the borehole wall or be reduced by minimizing hydraulic diffusivity. To help ensure adequate outflow and/or minimize hydraulic diffusivity with water-based drilling fluids, an efficient semi-permeable membrane should be generated within the shale. Several membrane generation mechanisms with varying degrees of effectiveness, depending on shale properties, are described in this paper. Mechanisms described involve chemical reactions between the drilling fluid and shale pore fluid, generation of electrical charges on exposed shale surface to selectively restrict ion movement and modification of clay structure by chemical and mechanical means. Laboratory experiments on shale samples under realistic downhole conditions exposed to a range of water-based drilling fluids are presented to emphasize the time-dependent nature of membrane generation. The experiments showed that maintenance of shale stability with a new generation of water-based drilling fluids can be achieved through significant increase in membrane efficiencies (greater than 80%) within relatively short exposure times. A fundamental understanding of the osmotic membrane generation in shales and the application of experimental data have resulted in the development of a new generation of water-based drilling fluids designed to successfully achieve drilling objectives through shale stabilization. Guidelines presented here for drilling of shales should help to significantly reduce shale stability-related non-productive time during drilling. Introduction Clay-bearing formations account for about 75% of drilled sections in oil and gas wells and cause approximately 90% of wellbore instability-related problems during drilling operations. The formations include shales, mudstones, siltstones and claystones. The drilling of these formations can result in a variety of problems ranging from tight hole to washout and complete hole collapse. With increasing drilling cost, the need to drill extended-reach wells with long open hole intervals has also increased. In the past, oil-based muds have been the system of choice for difficult drilling. As environmental concerns restrict the use of such muds, the petroleum service industry should provide innovative means to obtain oil-based mud performance without negatively impacting the environment. Water-based muds are attractive replacements from a direct cost viewpoint. But conventional water-based mud systems have failed to meet key performance measures that are met with oil-based mud systems, especially while drilling high angle extended-reach wells going through troublesome shale formations.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractA major collaborative project was undertaken to develop novel environmentally acceptable water-based drilling fluids with high membrane efficiency to help meet the future requirements of the petroleum industry. This paper describes the rationale of the project, the fundamental understanding of osmotic membrane generation in shale that lead to the development of the drilling fluids, and the practical guidelines for maintaining shale stability with the drilling fluids. Specialised test equipment, including membrane efficiency screening equipment, and test procedures were developed for simulation of key drilling fluid-shale interaction mechanisms. More than 300 membrane efficiency screening tests were performed on Pierre II shale samples to screen a wide range of novel compounds for their membrane generation capacity in the shale. Typical examples of the tests conducted with three novel compounds that generated moderately and highly efficient membranes are presented and discussed. The results demonstrate that some of the compounds are capable of generating membrane efficiencies of between 55% and 85%. The new generation of water-based drilling fluids that have been developed performs essentially like oil-based muds in terms of shale stabilisation. Practical mud design guidelines that have been developed can be used to optimise the drilling fluid design, in terms of mud weight, salt type and salt concentration, to manage efficiently time-dependent wellbore instability in troublesome shale formations.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractA major collaborative project was undertaken to develop novel environmentally acceptable water-based drilling fluids with high membrane efficiency to meet the future requirements of the petroleum industry. This paper describes various geomechanical considerations in the development and performance verification of the drilling fluids. Specialised test equipment, including a membrane efficiency screening equipment, an autonomous triaxial cell and a high pressure triaxial test equipment and associated test procedures, were either developed or modified for simulation of key drilling fluid-shale interaction mechanisms. More than 300 pressure transmissionchemical potential tests were performed on Pierre II shale samples to screen a wide range of novel chemical compounds for their membrane generation capacity in shales. Three of the compounds, which are capable of generating high membrane efficiency in the shale, were subsequently used to develop new generation water-based drilling fluids. Typical examples of the membrane efficiency screening tests conducted with novel compounds that generated highly and moderately efficient membranes are presented. The reasons for the difference in the membrane generation capacity of the compounds are discussed. The results demonstrate that the new generation waterbased drilling fluids are capable of generating membrane efficiencies of between 55% and 85%. The shale stabilising capacity of the new generation drilling fluids developed was demonstrated and verified through a series of borehole collapse tests. Results of the borehole collapse tests are presented and discussed. The results clearly demonstrate the shale stabilising capacity of the new drilling fluids in comparison with the reference test which was not subjected to the mud pressure penetration and chemical potential stages with the drilling fluids.

Summary Pore-pressure (PP) and fracture-gradient (FG) predictions were prepared for Prelude development wells in the Browse basin in offshore northwest Australia. The PP forecasts were based on resistivity- and sonic-based models calibrated with pressure measurements and drilling events, such as kicks from existing wells. FGs were based on leakoff tests and loss events from offset wells and were not necessarily equal to either the minimum compressive principal stress (often considered a lower bound to FG) or the formation-breakdown pressure (often considered an upper bound to FG that includes effects of formation tensile strength and near-wellbore hoop stress). The minimum compressive horizontal stress was calculated from lithology-dependent effective-stress ratios. Maximum horizontal stress was inferred from observed breakouts. PP and stresses were combined with formation properties from well logs and laboratory rock-mechanics tests to provide input for elastoplastic (shales) and poroelastic (sands) borehole-stability (BHS) models. These techniques are applicable to exploration, appraisal, or early-development wells that have potential for encountering geopressured formations in high-angle well sections requiring good predrill estimates to adequately plan the casing and drilling programs and determine BHS. The predrill studies can be extended to provide integrated real-time PP and BHS while drilling, and the models can be recalibrated after each well to provide updated predictions for subsequent wells. There are only minor deviations in the predicted PP and FG among the different well locations considered. Common features include potential loss zones in the shallow overburden, pressure ramp within the Jamieson, pressure regression below the Aptian, and near-hydrostatic pressure within the Upper Swan and below. The BHS models indicate that minimum-required mud weight in deviated sections could be up to 20% higher than that required to balance formation PP. In one well that would cross a suspected fault, the risk of fault reopening or reactivation is low.

No abstract