A New Extreme-HP/HT Viscometer for New Drilling-Fluid Challenges

Abstract

Summary Growing demand for natural gas in North America is driving the exploration and production industry to look for new resources in previously unexplored areas, and the deep Gulf of Mexico (GOM) continental shelf is currently attracting substantial attention. Several current deep-shelf high-pressure/high-temperature (HP/HT) wells have anticipated bottomhole temperatures that significantly exceed the operating limits of existing measuring-while-drilling and logging-while-drilling (MWD/LWD) tools; therefore, downhole annular-pressure measurements will not be available for pressure management. This leaves temperature and hydraulic models as the best, if not the only, source of downhole-pressure information for these wells. These models depend on accurate surface inputs and laboratory-measured fluid properties under downhole conditions. Unfortunately, these anticipated temperatures and pressures also exceed the operating limits of conventional HP/HT viscometers. This lack of measured fluid properties under these extreme conditions will severely limit the ability of hydraulic models to predict downhole pressures. A new extreme-HP/HT (XHP/HT) concentric-cylinder viscometer was designed and built to fill this important technology gap for GOM deep-shelf HP/HT wells. The instrument is capable of measuring typical drilling-fluid viscosities up to 600°F (316°C) and 40,000 psig (276.0 MPa) and is capable of accurate property measurements for drilling fluids containing ferromagnetic materials. Subsequent verification and validation proved that the new viscometer compares favorably to commercially available field viscometers and more-sophisticated laboratory rheometers and therefore lends itself to widespread industry use. This paper reviews the development of the instrument and associated automated control system and explores health, safety, and environment (HSE) issues related to testing drilling fluids at these extreme conditions. The paper also presents results of verification and validation testing on invert-emulsion drilling fluids. Introduction Developing deep-shelf gas requires overcoming some formidable drilling and drilling-fluid challenges. Rigs capable of drilling to these depths are larger, more robust, and more expensive than ordinary rigs. Penetration rates tend to be low, extending time on location and adding to drilling costs. The extreme pressures, temperatures, and acid-gas levels limit downhole tool, material, and fluid selection. During the planning stage for several potential record-depth deep-gas wells, a technology gap was recognized for the measurement of fluid viscosity at the expected downhole temperatures and pressures. HP/HT-viscometer technology at the time was limited to measurements at =500°F (260°C) and =20,000 psig (138.0 MPa). Some of the deep-shelf HP/HT wells had anticipated bottomhole conditions approaching 600°F (316°C) and 40,000 psig (276.0 MPa). Mathematical extrapolations of fluid properties could result in significant inaccuracies in hydraulic models because fluid behavior has never been evaluated under these extreme conditions. Because current MWD/LWD tools are unusable under these extreme conditions, measurement of valid fluid properties for input into hydraulic models is critical for determination of the best available predicted values of downhole annular pressures. Because of these limitations, it was apparent that a new HP/HT viscometer would have to be developed for the industry. Oilfield Couette Viscometers Specialized concentric-cylinder, or Couette, viscometers are used throughout the oilfield industry to determine the rheological properties of drilling fluids, cement slurries, and fracturing fluids. International Standards Organization (ISO)/American Petroleum Institute (API) standards [ISO 10414-2:2002, ISO 10414-1:2002, API RP 13B-2 (2005)] exist that define and recommend test conditions, methods, bob and rotor geometries, and shear rates for determining fluid characteristics. From the results of these tests, the apparent viscosity of the sample is calculated at each shear rate and test condition. The data modeling methods differ with the fluid being tested, as most of these fluids do not exhibit Newtonian behavior. The term "Couette flow" originated from Maurice Frédéric Alfred Couette, professor of physics at the University of Angers in France during the 19th century (Couette 1890). He described laminar flow of a liquid in the space between coaxial cylinders, now known as "Couette flow" in his honor. Equations used to calculate values for shear stress, shear rate, and viscosity for Couette flow are included in Appendix A. A coaxial-cylinder, or Couette, viscometer consists of an outer cylinder that rotates around a stationary inner cylinder. The outer component is known as the "rotor," and the inner cylinder is known as the "bob." A shear gap exists in the annular space between the bob and the rotor. In the interest of industry standardization, the diameters and lengths of the bob and rotor are defined by applicable ISO/API recommended practices [ISO 10414-2:2002, ISO 10414–1:2002, API RP 13B-2 (2005)]. The bob and rotor are immersed in the target fluid. As the rotor turns at standard speeds ranging from 1 to 600 RPM, creating a specific fluid shear rate in the annular gap at each speed, the torque induced on the stationary bob by the fluid is measured accurately. The torque transducer connected to the bob is calibrated to indicate shear stress using known viscosities of Newtonian oils over the desired range of shear rates. Viscosity at a given shear rate is determined as the ratio of shear stress to shear rate.

Nanoparticle‐stabilised invert emulsion drilling fluids for deep‐hole drilling of oil and gas

“…A drilling fluid serves several, often contradictory but essential, functions. [3] In such extreme conditions, oil-based drilling fluids are preferred because they have better thermal stability, are less affected by salt and other contaminants and resist gas hydrate formation, allowing for faster drilling. [1] In order to be able to suspend solids, the mud must have a high viscosity, and this is usually attained by thickening a base fluid, such as water or oil.…”

“…However, as the depth of the drilling wells keeps increasing, temperatures can be expected to exceed 315 • C and the pressure to reach 276 MPa. [3] In such extreme conditions, oil-based drilling fluids are preferred because they have better thermal stability, are less affected by salt and other contaminants and resist gas hydrate formation, allowing for faster drilling. [1,4,5] OBMs are usually three-phase systems since the base liquid is typically an emulsion of water in oil, commonly called an invert emulsion.…”

Optimization and Process Modeling of Viscosity of Oil Based Drilling Muds

“…Depending on the base materials/fluids used, drilling muds are classified into three major types; water based mud (WBM), oil based mud (OBM), and synthetic based mud (SBM). Compared to other types of drilling muds, OBM has the prominent advantages of higher penetration rate, thermal stability in deep high-temperature wells, increased lubricity in deviated offshore wells, and hole stability in thick, water-sensitive shales [7,8]. Well friction is lowered with oil-based drilling fluids.…”