One of the biggest challenges when drilling in deep water is the excessive dependence of drilling fluid rheological properties on temperature. Conventional drilling fluids often have high viscosity at the seabed temperature, which increases the Equivalent Circulating Density (ECD) and surge pressures when running pipe or initiating circulation, elevating the risk of fracturing the wellbore. This paper describes the development of a drilling fluid for deep-water applications, with minimum viscosity variation with temperature. Multiple laboratory formulations were evaluated during the development of the new, non-aqueous based drilling fluid that meets deep-water's challenging rheological and barite suspension requirements. CaCl2 brine was used as the internal emulsion phase, and synthetic isomerized olefin as the base oil. The testing followed the API Recommended Practice for Field Testing Oil-based Drilling Fluids. Samples were aged at dynamic conditions for 16 hours at several temperatures. Then, rheological properties and high-pressure high-temperature (HPHT) fluid loss, emulsion stability, and dynamic sagging were tested. Static sag experiments were also carried out for up to seven days together with improved step down rheology tests. A low-impact, non-aqueous drilling fluid (LIDF) was designed to minimize ECD increases by reducing the effect of cold temperature on the fluid viscosity. The fluid offers a superior low viscosity profile and rapid-set, easy-break gel strengths, while maintaining low shear rate viscosity at high temperatures with optimal weight material suspension. The fluid is also compatible with all contaminants usually found during the drilling operation and meets all the regulatory requirements for the Gulf of Mexico and other deep-water operational areas. Field application demonstrated that LIDF reduced the effect of temperature on the fluid rheological properties and minimized the risk of induced formation losses. These same rheological features reduced non-productive time associated with cement displacement and barite sagging. Supporting laboratory and field data are presented to demonstrate the superior performance of the fluid in maintaining rheological and barite suspension properties over a wide range of temperatures. The properties of the LIDF are achieved by matching the effects of emulsifier, organophilic clay, and rheological modifiers to maintain correct rheological properties at low and high temperatures.
Drilling through shale is an inevitable endeavor for both conventional and unconventional oil and gas reservoirs, where for the latter acts as a source and trap rock – substantiating its position in operational difficulty. Shale formations tend to be anisotropic and typically characterized by high in-situ stresses. In certain shales, geomechanics is very important in understanding how to stabilize the wellbore. Overall, it can prescribe a correct mud weight (or rather the overbalance) to provide the mechanical stability (stress-induced). However, this over-balance can be rapidly destroyed due to the rise in shale pore pressure associated with the different potentials (hydro-, chemo-, thermo-) acting at the shale-fluid interface. These ‘potentials’ can have an effect on the borehole stability, where in several cases, create phenomena that are just recently being wholly understood. From a chemo-mechanical perspective, designing the proper fluid that will maintain the stability of shale formation, over time, requires the knowledge of membrane efficiency that is crucial for the geomechanical effects on the wellbore. However, in current industry practices there are limited studies that integrate geomechanics with comprehensive drilling fluid properties. Typically, inputs are arbitrary assumptions when utilizing geomechanical software. Classic workflow during geomechanics design includes selecting suitable mud-weight window which do not exceed the fracture gradient (to prevent losses) or remain well above the collapse pressure (or pore pressure) whichever is more suitable to prevent kicks or blowout. The work presented herein takes the workflow a step further, by introducing key parameters of relevant shale characteristics/behavior to current geomechanical software to provide more accurate wellbore stability simulations as a function of fluid properties (i.e. membrane efficiency). Two different shale types, Mancos and Pierre shale II, which significantly vary in their physical, chemical, mineralogical, and mechanical properties are selected for wellbore stability analysis. The methodology consisted of three phases, (1) shale characterization, (2) pore pressure transmission and membrane efficiency calculations, (3) wellbore stability simulations via geomechanics software. The software is an integrated software used to assess stress and wellbore stability by calculating a "borehole stress and failure orientation" module to perform concurrent simulations to determine stability parameters (mud weight, fluid activity, membrane efficiency) needed for drilling through complex shale.
Testing the interaction between drilling/completion fluids and the formation is the key critical concept to understand the fundamental mechanism to borehole stability. Unfortunately, most industry tests lack the down-hole conditions to give realistic results. However, there is one advanced testing that can be used to directly and quantitively provide realistic borehole stability interpretations. Specifically, the pore pressure transmission (PPT) test has increasingly gained popularity providing results on how to stabilize troublesome shales by facilitating proper fluid design. In this study, precipitating aluminum chemistry is employed to develop a high-performance water-based mud (HP-WBM) that is tremendously robust and versatile – demonstrating that it can stabilize multiple shale type formations. PPT evaluations on the alumiumum complex HP-WBM was performed at 250°F with a high simulated overbalanced 1000 psi pressure differential, to fully confirm that the system can withstand high pressure influx and prevent pressure transmission into the shale pore matrix, essentially reducing induced borehole instability. PPT testing was performed on two different types of shales, Pierre Type II and Mancos shale exhibit noteworthy differences in physical, chemical, mineralogical, and mechanical properties, making them ideal shales to study the versatility of the aluminum complex drilling fluid. Because of the pore-plugging capabilities, the fluid can establish, an improved semipermeable membrane, allowing for the counterbalance of hydraulic flow into the shale via osmotic backflow. When compared to the base (water-based mud), a significant delay factor is observed using the aluminum complex fluid, indicating significant reduction in pressure transmission into the shale pore matrix. An invert emulsion system was also tested for comparison and showed the Al-HPWBM's was able to perform similarly at stabilizing these shales. Advantages of precipitating aluminum chemistry over other methods will be further discussed.
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