No abstract
Accurate knowledge of drilling fluid behavior under actual conditions is required to maximize operational efficiency and to minimize cost and drilling fluid related risks on extreme high-pressure / high-temperature (HP/HT) wells. This paper identifies and discusses the major HP/HT drilling fluid challenges, recent innovations in fluid viscosity measurements under HP/HT conditions, drilling fluid designs stable to extreme HP/HT conditions, and other considerations in HP/HT drilling. Introduction Worldwide demand for energy continues to increase and is projected to average 2.0% per year out to 2030. Demand is widespread geographically but the most rapid growth is projected for nations outside the Organization for Economic Cooperation and Development (non-OECD nations) averaging 3.7% per year for non-OECD Asia.1 Providing adequate supply is driving the industry to explore areas previously unexplored, or minimally explored. A subset of this activity is HP/HT drilling. HP/HT drilling is not rigorously pursued during times of price uncertainty or low commodity pricing due to the relatively high lifting cost. The resurgence in HP/HT drilling stretches globally and encompasses areas such as the deep Gulf of Mexico Continental Shelf, northern India, Saudi Arabia, and Brunei. Historical HP/HT basins such as Indonesia, Thailand and northern Malaysia have also seen a selective increase in HP/HT activity. Several factors have combined to make deep gas increasingly attractive worldwide:Abundant infrastructure in the way of platforms, producing facilities, and pipelines that would allow new production to flow quickly to market.New technology such as 3D seismic and faster computers to locate potential formations. Drilling and Drilling Fluid Challenges Developing HP/HT prospects can require overcoming some formidable drilling challenges. Rigs capable of HP/HT drilling are larger due to requirements such as hook load, mud pumps, drill pipe and surface mud capacity to name a few. Due to these requirements, these rigs are more expensive. HP/HT wells, by definition, require a higher density fluid which typically requires high solids loading. High solids loading, the resulting higher pressures, combined with the competency of rock at depth, lead to low penetration rates, extending time on location and added drilling costs. In extreme cases, pressure, temperature, and acid gas levels can limit the selection and function of down-hole tools and fluid selection. These limitations can be so severe that MWD/LWD tools become unusable, rendering down-hole annular pressure measurements used for pressure management, unavailable. This places additional demands on the drilling fluid and temperature/hydraulic models as they become our best, if not our only source for down-hole pressure information. These models are based on surface inputs and laboratory measured fluid properties under down-hole conditions. During the planning stage for several potential record depth deep gas wells currently drilling or recently TD'd, not only did this information not exist, laboratory equipment capable of operation at the required temperatures and pressures didn't exist. Pressure/Volume/Temperature (PVT) Down-hole pressures are commonly calculated using TVD (true vertical depth) and surface measured mud weight reported from the rig. While this approach is adequate for less demanding wells, critical applications such as HP/HT and deepwater wells require adjustments for the pressure and temperature driven compression and expansion characteristics of the whole drilling fluid. These compression and expansion effects are quantified in fluid PVT measurement under expected down-hole conditions which, until recently, ranged from 15 psi/75°F to about 20,000 psi/350°F which covered industry needs. HP/HT drilling pressures and temperatures, however, can far exceed this envelope. Figure 1 illustrates isobaric PVT results on a commonly used base-fluid.
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.
Growing demand for natural gas in North America is driving the E&P industry to look for new resources in previously unexplored areas and the deep Gulf of Mexico (GOM) Continental Shelf is currently attracting a lot of attention. Several of the current deep shelf HP/HT wells have anticipated bottom-hole temperatures that significantly exceed the limits of existing MWD/LWD tools; therefore, down-hole annular pressure measurements will not be available for pressure management. This leaves temperature/hydraulic models as our best, if not our only source of down-hole pressure information. These models depend on accurate surface inputs and laboratory measured fluid properties under down-hole 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 down-hole pressures. A new extreme HP/HT (XHP/HT) concentric cylinder viscometer was designed and built to fill this important technology gap for the 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 measurements of drilling fluid properties containing ferromagnetic materials. Subsequent verification and validation testing proved the new viscometer compares favorably to commercially available field viscometers and more sophisticated laboratory rheometers and therefore lends itself towards widespread industry use. This paper reviews the development of the instrument, automated control system and HS&E issues related to testing drilling fluids at these extreme conditions. The paper will also present results of the verification and validation testing on invert-emulsion drilling fluids. Introduction Developing deep shelf gas requires overcoming some formidable drilling, as well as drilling fluid challenges. Rigs capable of drilling to these depths are larger, more robust and more expensive. Penetration rates tend to be low, extending time on location and adding to drilling costs. The extreme pressures, temperatures and acid gas levels limit down-hole 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 down-hole temperatures and pressures. HP/HT viscometer technology at the time was limited to measurements at =500°F (260°C), =20,000 psig (138.0 MPa). Some of the deep shelf HP/HT wells had anticipated bottom-hole conditions approaching 600°F (316°C) and 40,000 psig (276.0 MPa). Mathematical extrapolations of fluid properties could result in significant inaccuracies in hydraulics models, as fluid behavior has never been evaluated at these extreme conditions. Since present MWD/LWD tools are unusable at these extreme conditions, measurement of valid fluid properties for input into hydraulic models is critical for determination of the best available prediction of down-hole annular pressures. Based on these limitations, it was apparent that a new high temperature, high pressure viscometer would have to be developed for the industry. Oilfield Couette Viscometers Specialized concentric cylinder couette viscometers are used throughout the oilfield industry to determine the rheological properties of drilling fluids, cement slurries and fracturing fluids. ISO/API standards[1,2,3] exist to define and recommend test conditions, methods, bob and rotor geometries and shear rates used to determine the fluid characteristics. From these results, apparent viscosity of the sample is calculated at each shear rate and test condition. The data modeling methods differ with the nature of 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 French provincial University of Angers during the 19th Century[4]. 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 the Appendix.
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