This paper discusses the systematic design and development of high performance water-based muds and provides insight into the unique chemistry and inhibition characteristics of various amine inhibitors. Equally important, performance correlations of inhibitive systems in laboratory testing as compared to state-of-the-art inhibitive systems are included. Invert emulsion drilling fluids have long been effective in drilling reactive shale. Developing high performance (highly inhibitive) water-based drilling fluid that would perform like invert emulsion drilling fluid has long been cited as the ultimate technical goal of the drilling industry. Progressive development of inhibitive water-based drilling fluids based on amine chemistry has made some impact on reaching this goal. Amine-based inhibitive drilling fluids have steadily gained popularity with service and oil companies. However, these fluids have not always been completely successful in inhibiting the hydration of highly water-sensitive clays. The short-comings are particularly evident when drilling highly complicated and reactive shale formations. Keeping this in mind, an innovative highly inhibitive water-based drilling fluid has been systematically designed with the performance characteristics of oil-based muds. The newly developed high performance water-based mud (HPWBM) comprises a unique polymeric amine shale intercalator for shale inhibition, an amphoteric polymeric shale encapsulator, a high performance lubricant/antiaccretion agent and a specialized fluid-loss additive. The newly developed HPWBM performed like an oil-based mud in laboratory testing as well as in offset wells using invert emulsion drilling fluids (OBM) due to highly complicated and reactive shale formations. Introduction To address the drilling problems associated with shale instability various non-aqueous drilling fluids (NADF) such as mineral oils, saturated and unsaturated poly alpha olefins and esters have been developed and utilized in the field.1–4 Along with the shale stability benefits of these NADF, various other benefits like lubricity, temperature stability, and anti-accretion are attributed to NADF. These distinguished benefits of NADF usually are cited as the technical goal of an ultimate HPWBM. Along with those advantages, NADF have disadvantages, such as high cost, environmental limitations, disposal problems, health and safety issues and detrimental effects on the drilling and completion of the pay zone. Consequently, a water-based drilling fluid which performs like an oil-based mud has been an ambitious goal of the drilling industry. Two characteristics of the HPWBM have been identified that contribute significantly to performance of the drilling fluid - shale stabilization and lubricity properties. These OBM characteristics serve as design targets to many researchers of aqueous-based systems striving to achieve the performance of OBM system when using a WBM.5–8 When water-sensitive shale is exposed to conventional water-based drilling fluids, shale has an immediate tendency to take up water from the drilling fluid. Depending upon the chemical characteristics of the shale, this can result in a rapid swelling or dispersion of the shale. Consequently typical problems such as bit-balling, disintegration of cuttings, borehole wash-out, high torque and drag, and stuck pipe are often encountered as a result of water adsorption by water sensitive shale.9–10 For more than the past five decades, various chemicals have been used for inhibition of water-sensitive shales. Among the earliest and most widely used method relies on the use of high concentration of salts such as potassium chloride, sodium chloride and divalent brines. These salts through a variety of mechanisms might be claimed to somehow retard swelling. The early development of the shale inhibition fluids included sodium chloride/starch muds,11 silicate muds,12 lime-muds and calcium sulfate-based gyp muds.

This report was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof, The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States Government or any agency thereof.

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Ultrahigh-temperature/ultrahigh-pressure (uHT/uHP) conditions have a different definition, depending on the region, the operator, and the service company. In this paper, the definition used for uHT/uHP fluid performance is that the fluid be able to perform above 500 F and 30,000 psi. This paper describes the development of innovative drilling fluids that are specific to these well conditions.When bottomhole temperatures exceed 400 F, the design and engineering of drilling fluids can be challenging. Drilling fluids that destabilize can cause a variety of fluid-control problems that could lead to drilling and completion issues. With invert-emulsion fluids, the major challenges encountered with these conditions are related to the thermal degradation of the emulsifier and wetting package that can lead to gelation and syneresis. Another challenge is fluid loss that is related to the emulsion stability and to the degradation of the fluid-loss-control additives. Finally, efficient control of the rheological properties-critical to the success of any well-also can be challenging when effects from emulsion instability, filtration-control degradation, and rheology-control-additive degradation are coupled with increases in drilled solids, rapidly leading to rheological instability. This can manifest itself as high-fluctuating rheologies and gelation or the loss of rheological properties that can give rise to sag of weight material, both potentially leading to associated well-control problems.The paper describes the development of the new fluid system designed for such uHT/uHP environments (highlighting the chemical differences) and compares the test data of the system with more-conventional high-temperature/high-pressure (HT/HP) invert-emulsion fluids. Data are presented that show the stability and performance of the new fluid with extended exposure to temperature >500 F, demonstrating a tolerance to various contaminations and showing the rheological behavior and stability to 600 F and 40,000 psi.

Viscoelastic properties of drilling fluids are not often measured due to a lack of understanding of their impact on fluid performance as well as a lack of field equipment suitable for such measurements. A study has been conducted recently to evaluate the viscoelastic properties of xanthan gum and invert drilling fluids and their impact on barite suspension quality and rheology. Both a Brookfield YR-1 rheometer and a Bohlin Gemini 150 rheometer were used to generate data for comparison. The impact of viscoelasticity on steady-state rheology, thixotropy and shear thinning was evaluated using a multi-speed rheometer. A soon-to-be-adopted API recommended procedure was used to measure the barite sag tendency under dynamic conditions. Aqueous solutions of xanthan gum showed that viscoelasticity, shear thinning and thixotropy increased with increasing polymer concentration. When the solutions were weighed up with barite, they became more viscoelastic, slightly more thixotropic, but less shear thinning. Proper suspension of barite was observed at a xanthan gum concentration of 2 lb/bbl without any other additives. Compared to xanthan-barite suspensions, invert drilling fluids of similar density exhibited a greater viscoelasticity but less thixotropy and shear thinning. Treatment of invert drilling fluids with viscoelastic polymers resulted in a further enhancement of viscoelasticity and thixotropy, but a slight deterioration in shear thinning. Barite suspension quality showed a certain degree of correlation with viscoelasticity as well as steady-state rheology; however, these properties were temperature dependent for invert drilling fluids. Hydraulic analyses indicated that viscoelastic additives can impact fluid viscosity thus affecting pressure loss, equivalent circulating density and hole cleaning. Viscoelasticity enhancement may be used to improve barite suspension quality under certain conditions, but its impact on hydraulics must be carefully considered.